<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, 1997
                                          -----------------------

                                      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 and non-voting securities held by non-
affiliates of the Registrant on February 27, 1998 was approximately $6,545,000.
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. $1.13, and the middle market price of Common Stock on
the London Stock Exchange Limited was U.K. 20 pence.

As of February 27, 1998, 31,482,716 shares of Registrant's Common Stock were
outstanding, of which 10,336,835 shares of Common Stock were represented by
Depositary Shares.

                      DOCUMENTS INCORPORATED BY REFERENCE

                                     None.
<PAGE>
 
                         TABLE OF CONTENTS TO FORM 10-K
 
                                                                            Page
                                                                            ----
Part I

  Item  1. Business
              General.......................................................  1
              Current Operations............................................  1
              Risks Associated with the Company's Business..................  2
              Products, Markets and Methods of Distribution.................  3
              Regulation....................................................  4
              Competition...................................................  8
              Employees.....................................................  8
  Item 2.  Properties
              Productive Wells and Drilling Activity........................  8
              Undeveloped Acreage...........................................  9
              Title to Properties...........................................  9
              Federal Leases................................................ 10
              Reserves and Future Net Cash Flows............................ 10
              Production, Sales Prices and Costs............................ 10
              Significant Properties
                 Colombia................................................... 11
                 United States.............................................. 13
  Item 3.  Legal Proceedings................................................ 14
  Item 4.  Submission of Matters to a Vote of Security Holders.............. 14

Part II

  Item 5.  Market for Registrant's Common Equity and Related
           Stockholder Matters
              Price Range of Depositary Shares and Common Stock............. 15
              Dividend History and Restrictions............................. 16
  Item 6.  Selected Financial Data.......................................... 17
  Item 7.  Management's Discussion and Analysis of Financial Condition
              and Results of Operations
              Results of Operations......................................... 18
              Year 2000..................................................... 20
              Liquidity and Capital Resources............................... 20
  Item 8.  Financial Statements and Supplementary Data...................... 22
  Item 9.  Changes in and Disagreements with Accountants on
              Accounting and Financial Disclosure........................... 22

Part III

  Item 10. Directors and Executive Officers of the Registrant
              Directors of the Company...................................... 23
              Executive Officers of the Company............................. 24
              Meetings and Committees of the Board of Directors............. 24
              Compliance with Section 16(a) of the Securities
              Exchange Act of 1934.......................................... 24
  Item 11. Executive Compensation
              Summary Compensation Table.................................... 25
              Directors' Fees............................................... 25
              Option Grants During 1997..................................... 25
              Option Exercises During 1997 and Year End Option Values....... 25

                                      (i)
<PAGE>
 
                   TABLE OF CONTENTS TO FORM 10-K (CONTINUED)
 
                                                                           Page
                                                                           ----
              Compensation Committee Interlocks and Insider Participation
                in Compensation Decisions................................... 25
              Employment Contracts.......................................... 26
              Compensation Committee Report on Executive Compensation....... 26
              Performance Graph............................................. 26
  Item 12. Security Ownership of Certain Beneficial Owners and Management
              Security Ownership of Certain Beneficial Owners............... 27
              Security Ownership of Management.............................. 28
  Item 13. Certain Relationships and Related Transactions................... 28

Part IV

  Item 14. Exhibits, Financial Statement Schedules and Reports
           on Form 8-K...................................................... 29

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

                                      (ii)
<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 concession.

  Twenty-one wells have been drilled on the Santana concession.  Of the thirteen
exploratory wells, seven have been productive and six were dry holes. Of the
eight development wells, seven have been productive.  Four fields have been
discovered and have been declared commercial by Ecopetrol.  Gross production
from the Santana concession has totaled approximately 12.2 million barrels
during the period from April 1992, when production commenced, through December
1997.  The Company's share of this production totaled approximately 1.9 million
barrels.

  The contracts for the La Fragua concession, which adjoins Santana to the
north, and the Yuruyaco concession, which adjoins Santana and La Fragua to the
east, were approved by Ecopetrol in June 1992 and September 1995, respectively.
The acquisition of all seismic data required under these contracts has been
completed.  The Company has determined, however, that further exploration on
these concessions is not technically justified.  Accordingly, the Company has
filed with Ecopetrol applications for formal relinquishment, acceptance of which
are expected in due course.

  The Aporte Putumayo block produced from 1976 until March 1995, when declining
production caused the block to be unprofitable under the terms of the contract.
The Company has filed with Ecopetrol an application for formal relinquishment,
which is expected to occur following abandonment and restoration operations on
certain old wells in the block.
 
  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,

                                       1
<PAGE>
 
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 17 wells located in the Gulf of
Mexico offshore Louisiana, at Main Pass 41 and Breton Sound 31 fields.  AAI is
the operator of these fields.  The Company acquired its interests in these
fields through the acquisition of Charterhall Oil North America PLC in 1990.

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 further exploration and development of such
properties. Even if the results of such activities are favorable, further
drilling at significant costs may be required to determine the extent of and to
produce the recoverable reserves.  Failure to fund 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 intent to use its existing working capital and cash
flow from production in Colombia, to the extent available, to finance its
planned exploration and development activities.  Garnet has indicated, however,
that it does not expect its working capital and cash flow from operations to be
sufficient to repay the principal amount ($15 million) of its subordinated
debentures at maturity in December 1998, and that it must consummate a
restructuring transaction prior to their maturity in order to avoid non-
compliance with its obligations under the debentures.  If no restructuring
transaction is consummated, Garnet will be required to renegotiate the terms of
the debentures to extend the maturity date so that the debentures may be repaid
out of cash flow from operations over time.  There can be no assurance that
Garnet will be successful in consummating a restructuring transaction or
renegotiating the terms of the debentures.

  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, 

                                       2
<PAGE>
 
environmental controls and other laws, regulations or international developments
that may adversely affect the Company's properties. The Company does not
maintain political risk insurance.

  Exploration and development of the Company's Colombian properties are
dependent upon obtaining appropriate governmental approvals and permits.  
See "-- Regulation."  The Company's Colombian operations are also subject 
to price risk.  See "-- Products, Markets and Methods of Distribution."

  There are logistical problems, costs and risks in conducting oil and gas
activities in remote, rugged and primitive regions in Colombia.  The Company's
operations are also exposed to potentially detrimental activities by the leftist
guerrillas who have operated within Colombia for many years.  The guerrillas in
the Putumayo area, where the Company's property is located, have damaged the
Company's assets in the past.  Although the Company's losses on those occasions
have been substantially recovered through insurance, there can be no assurance
that such coverage will remain available or affordable. The Colombian army
guards the Company's operations, however, there can be no assurance that the
Company's operations will not be the target of guerrilla attacks in the future.

  United States.    The Company's activities in the United States are subject to
  -------------                                                                 
a variety of risks.  The  U.S. properties could, in certain circumstances,
require expenditure of significant amounts of capital.  Failure to fund its
share of such costs could result in a diminution of value of, or under
applicable operating agreements forfeiture of, the Company's interest.  The
Company's ability to fund such expenditures is also dependent upon the ability
of the other working interest owners to fund their share of the costs.  If such
working interest owners fail to do so, the Company could be required to pay its
proportionate share or forego further development of such properties.  The
Company's activities in the United States are subject to various environmental
regulations and to price risk.  See "-- Regulation" and "-- Products, Markets
and Methods of Distribution."

  Information concerning the amounts of revenue, operating loss and identifiable
assets attributable to each of the Company's geographic areas is set forth in
Note 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, 1997, the Company received
the majority of its revenue from Ecopetrol.  Sales to Ecopetrol accounted for
$7,405,000, or 76.1% of oil and gas revenue for 1997, $9,437,000, or 68.6% of
oil and gas revenue for 1996 and $7,132,000, or 65.3% of oil and gas revenue for
1995, 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 1997, 1996 and 1995, the Company received more than 10% of its revenue
from one domestic purchaser.  Such revenue accounted for $1,516,000, or 15.6% of
oil and gas revenue for 1997, $1,609,000, or 11.7% of oil and gas revenue for
1996 and $1,422,000, or 13.0% of oil and gas revenue for 1995.  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, 

                                       3
<PAGE>
 
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.

Regulation

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

       Colombia.  Any significant exploration or development of the Company's
       --------                                                              
Colombian concessions, such as conducting a seismic program, the drilling of an
exploratory or developmental well or the construction of a pipeline, requires
environmental review and the advance issuance of environmental permits by the
Colombian government.  In 1993, Instituto de Recursos Naturales y Ambiente
("Inderena"),  the Colombian federal environmental agency, began reviewing the
environmental standards and permitting processes for the oil industry in
general, and in 1994 a new Ministry of the Environment was organized.  In
connection with its review, Inderena requested that additional environmental
studies be submitted for the Company's area of operations north of the Caqueta
River.  See "Item 2. Properties -- Significant Properties -- Colombia -- Santana
Concession."  As a result of the review and requests for additional
environmental studies, the Company's operations north of the Caqueta River were
suspended 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 its domestic operations are
       -------------                                                         
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.

  The Oil Pollution Act of 1990 ("OPA '90") and regulations thereunder impose a
variety of requirements on "responsible parties" related to the prevention of
oil spills and liability for damages resulting from such spills in waters of the
United States. A "responsible party" includes the owner or operator of an
onshore facility, vessel or pipeline, or the lessee or permittee of the area in
which an offshore facility is located. OPA '90 assigns liability to each
responsible party for oil spill removal costs and a variety of public and
private damages from oil spills. While liability 

                                       4
<PAGE>
 
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.

  With amendments to OPA '90 signed into law by President Clinton on October 19,
1996, OPA '90 now requires owners and operators of offshore facilities that have
a worst case oil spill of more than 1,000 barrels to demonstrate financial
responsibility in amounts ranging from $10 million in specified state waters to
$35 million in federal outer continental shelf water, with higher amounts of up
to $150 million in certain limited circumstances where the U.S. Minerals
Management Service ("MMS") believes such a level is justified by the risks posed
by the quantity or quality of oil that is handled by the facility.  The
Company's two U.S. properties, Main Pass Block 41 field, a federal lease on the
outer continental shelf ("OCS") offshore Louisiana, and Breton Sound Block 31
field, on state leases offshore Louisiana, are subject to OPA '90 as amended.
On March 25, 1997, the MMS promulgated a proposed rule implementing these OPA
'90 financial responsibility requirements.  The Company believes that it
currently has established adequate proof of financial responsibility for its
offshore facilities.  However, the Company cannot predict whether these
financial responsibility requirements under the OPA '90 amendments or the
proposed rule will result in the imposition of significant additional annual
costs to the Company in the future or otherwise have a material adverse effect
on the Company.  The impact of financial responsibility requirements is not
expected to be any more burdensome to the Company than it will be to other
similarly or less capitalized owners or operators in the Gulf of Mexico.

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

  With respect to the Federal Water Pollution Control Act, the United States
Environmental Protection Agency ("EPA") issued regulations prohibiting the
discharge of produced water and produced sand derived from oil and gas
operations in certain coastal areas (primarily state waters) of Louisiana and
Texas, effective February 8, 1995.  In connection with these regulations,
however, the EPA also issued an administrative order that effectively delayed
compliance with the no discharge requirement for produced water until January 1,
1997.  Effective August 27, 1996, the Louisiana Department of Environmental
Quality ("LDEQ") officially assumed responsibility for compliance and
enforcement issues for produced water as they relate to the Company's Breton
Sound Block 31 facilities with the EPA operating in an oversight capacity.  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.  In July 1997, in response to an
earlier request made by the Company, the LDEQ authorized in writing an extension
of the produced water deadline until December 1, 1997.  The LDEQ has since
authorized an extension of this deadline beyond December 1, 1997, while the
Company and agency work on a produced water termination plan involving the
installation of a reinjection well at the Breton Sound Block 31 facilities on or
before April 1, 1998.  In the event that the Company and the LDEQ fail to reach
agreement on a produced water termination plan or the Company otherwise fails to
timely install and commence operation of the reinjection well, the Company may
be forced to immediately cease discharges of produced waters which could involve
limiting or even ceasing operations temporarily or permanently at the Breton
Sound Block 31 facilities.

  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 

                                       5
<PAGE>
 
resources, and it is not uncommon for neighboring landowners and other third
parties to file claims for personal injury, property damage and recovery of
response costs allegedly caused by the hazardous substances released into the
environment. The Company has not received any notification nor is it otherwise
aware of circumstances indicating that it may be potentially responsible for
cleanup costs under CERCLA.

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

  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.

  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 ("NGPA"), as amended.  In
1989, the Natural Gas Wellhead Decontrol Act was enacted.  This act amended the
NGPA to remove both price and non-price controls from natural gas sold in "first
sales" as of January 1, 1993.  While sales by producers of natural gas, such as
the Company, can currently be made at uncontrolled market prices, Congress could
reenact price controls in the future.

  The Company's sales of natural gas are affected by the availability, terms and
cost of transportation.  The price and terms for access to pipeline
transportation remain subject to extensive federal and state regulation.
Several major regulatory changes have been implemented by Congress and the
Federal Energy Regulatory Commission ("FERC") from 1985 to the present that
affect the economics of natural gas production, transportation and sales.  In
addition, the FERC continues to promulgate revisions to various aspects of the
rules and regulations affecting those segments of the natural gas industry, most
notably interstate natural gas transmission companies, that remain subject to
the FERC's jurisdiction.  These initiatives may also affect the intrastate
transportation of gas under certain circumstances.  The stated purpose of many
of these regulatory changes is to promote competition among the various sectors
of the natural gas industry and these initiatives generally reflect more light-
handed regulation of the natural gas industry.  The ultimate impact of the
complex rules and regulations issued by the FERC since 1985 cannot be predicted.
In addition, many aspects of these regulatory developments have not become final
but are still pending judicial and FERC final decisions.

  The Company cannot predict what further action the FERC will take on these
matters; however, the Company does not believe that it will be affected by any
action taken materially differently than other natural gas producers, gatherers
and marketers with which it competes.  The natural gas industry historically has
been very heavily regulated; therefore, there is no assurance that the less
stringent regulatory approach recently pursued by the FERC and Congress will
continue.

                                       6
<PAGE>
 
  A portion of the Company's operations are located on federal oil and gas
leases, which are administered by the MMS.  Such leases are issued through
competitive bidding, contain relatively standardized terms and require
compliance with detailed MMS regulations and orders pursuant to the OCSLA (which
are subject to change by the MMS).  For offshore operations, lessees must obtain
MMS approval for exploration plans and development and production plans prior to
the commencement of such operations.  In addition to permits required from other
agencies, lessees must obtain a permit from the MMS prior to commencement of
drilling.  The MMS has promulgated regulations requiring offshore production
facilities located on the OCS to meet stringent engineering and construction
specifications.  The MMS also has regulations restricting the flaring or venting
of natural gas and has recently proposed to amend such regulations to prohibit
the flaring of liquid hydrocarbons and oil without prior authorization.
Similarly, the MMS has promulgated other regulations governing the plugging and
abandonment of wells located offshore and the removal of all production
facilities.  To cover the various obligations of lessees on the OCS, the MMS
generally requires that lessees post substantial bonds or other acceptable
assurances that such obligations will be met.  The cost of such bonds or other
surety can be substantial and there is no assurance that bonds or other surety
can be obtained in all cases.  Under certain circumstances, the MMS may require
Company operations on federal leases to be suspended or terminated.  Any such
suspension or termination could materially and adversely affect the Company's
financial condition and operations.

  The MMS has issued a notice of proposed rulemaking in which it proposes to
amend its regulations governing the calculation of royalties and the valuation
of crude oil produced from federal leases.  This proposed rule would modify the
valuation procedures for both arm's length and non-arm's length crude oil
transactions to decrease reliance on oil posted prices and assign a value to
crude oil that better reflects its market value, establish a new MMS form for
collecting differential data, and amend the valuation procedure for the sale of
federal royalty oil.  The Company cannot predict what action the MMS will take
on this matter, nor can it predict how the Company will be affected by any
change to this regulation.

  In April 1997, after two years of study, the MMS withdrew proposed changes to
the way it values natural gas for royalty payments.  These proposed changes
would have established an alternative market-based method to calculate royalties
on certain natural gas sold to affiliates or pursuant to non-arm's length sales
contracts.  Informal discussions among the MMS and industry officials are
continuing, although it is uncertain whether, and what changes may be proposed
regarding gas royalty valuation.  In addition, MMS has recently approved its
intention to issue a proposed rule that would require all but the smallest
producers to be capable of reporting production information electronically by
the end of 1998.

  Sales of crude oil, condensate and gas liquids by the Company are not
currently regulated and are made at market prices.  The FERC has issued a series
of rules (Order Nos. 561 and 561-A) establishing an indexing system under which
oil pipelines will be able to change their transportation rates, subject to
prescribed ceiling levels.  The indexing system, which allows or may require
pipelines to make rate changes to track changes in the Producer Price Index for
Finished Goods, minus one percent, became effective January 1, 1995.  The FERC's
decision in this matter was recently affirmed by the Court.  The Company is not
able at this time to predict the effects of Order Nos. 561 and 561-A, if any, on
the transportation costs associated with oil production from the Company's oil
producing operations; however, the Company does not believe it will be affected
by these orders materially differently than other oil producers with which it
competes.

  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.

  State Regulation.  Production of any domestic oil and gas by the Company is
  ----------------                                                           
affected by state regulations.  Many states in which the Company has operated
have statutory provisions regulating the production and sale of oil and gas,
including provisions regarding deliverability.  Such statutes, and the
regulations promulgated in connection therewith, are generally intended to
prevent waste of oil and gas and to protect correlative rights to produce oil
and gas between owners of a common reservoir.  Such regulations include
requiring permits for the drilling of wells, maintaining bonding requirements in
order to drill or operate wells, and regulating the location of wells, the
method of drilling and casing wells, the surface use and restoration of
properties upon which wells are drilled, the plugging and abandoning of wells,
and the disposal of fluids used in connection with operations.

                                       7
<PAGE>
 
  The Company's operations are also subject to various conservation laws and
regulations including the regulation of the size of drilling and spacing units
or proration units, the density of wells that may be drilled, and the
unitization or pooling of oil and gas properties.  In addition, state
conservation laws establish maximum rates of production from oil and natural gas
wells, generally prohibit the venting or flaring of natural gas, and impose
certain requirements regarding the ratability of production.  The effect of
these regulations may limit the amount of oil and natural gas that the Company
can produce from its wells and may limit the number of wells or the locations at
which the Company can drill.  Inasmuch as such laws and regulations are
periodically expanded, amended and reinterpreted, the Company is unable to
predict the future cost or impact of complying with such regulations; however,
the Company does not believe it will be affected by these laws and regulations
materially differently than the other oil and natural gas producers with which
it competes.

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, 1997, Aviva had 10 full-time employees, all in the United
States.



ITEM 2. PROPERTIES


Productive Wells and Drilling Activity

  The following table summarizes the Company's developed acreage and productive
wells at December 31, 1997.  "Gross" refers to the total acres or wells in which
the Company has a working interest, and "net" refers to gross acres or wells
multiplied by the percentage working interest owned by the Company.
 
Developed Acreage /(1)/
                                        Gross                   Net
                                      -------               -------
         United States                  3,880                 1,565
         Colombia/(2)/                  3,706                   585
                                      -------               -------
                                        7,586                 2,150
                                      =======               =======
 
Productive Wells /(3)/
                                       Oil                    Gas
                              ------------------      -----------------
 
                                Gross        Net        Gross       Net
                              -------    -------      -------    ------
 
        United States /(4)/        10       5.29            7      2.87
        Colombia                   14       2.21            -         -
                              -------    -------      -------    ------
                                   24       7.50            7      2.87
                              =======    =======      =======    ======

(1)  Developed acreage is acreage assignable to productive wells.
(2)  Excludes Aporte Putumayo acreage pending relinquishment.
(3)  Productive wells represent producing wells and wells capable of producing.
(4)  Two of the oil wells and one of the gas wells are dually completed.

                                       8
<PAGE>
 
  During the periods indicated, the Company drilled or participated in the
drilling of the following development and exploratory wells.

                                        Net Wells Drilled
                                        -----------------
 
                              Development               Exploratory
                         ----------------------     ------------------
 
                         Productive         Dry     Productive     Dry
                         ----------        ----     ----------    ----
 
  1997   United States            -           -              -       -
         Colombia               0.5           -              -       -
                               ----        ----           ----    ----
         Total                  0.5           -              -       -
                               ====        ====           ====    ====
 
  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
                               ====        ====           ====    ====
 

  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. The Company expects to relinquish all
undeveloped acreage associated with the La Fragua and Yuruyaco concessions
during 1998.  No further relinquishments are required for the Santana concession
until the expiration of the concession agreement in 2015.  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, 1997.  Undeveloped acreage is acreage on which wells
have not been drilled or completed to a point that would permit the production
of commercial quantities of oil and gas, regardless of whether such acreage
contains proved reserves.
 
                                            Undeveloped Acres
                                            -----------------
 
                                         Gross             Net
                                      --------        --------
 
                   Santana              48,636          21,887
                   La Fragua            32,377          14,570
                   Yuruyaco             38,663          17,398
                                      --------        --------
                                       119,676          53,855
                                      ========        ========

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 

                                       9
<PAGE>
 
that none of such burdens materially detracts from the value of such properties
or its interest therein or will materially interfere with the use of the
properties in the operation of the Company's business.

Federal Leases

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

Reserves and Future Net Cash Flows

  See Supplementary Information Related to Oil and Gas Producing Activities in
"Item 8.  Financial Statements and Supplementary Data" for information with
respect to the Company's reserves and future net cash flows.

  The Company will file with the Department of Energy (the "DOE") a statement
with respect to the Company's estimate of proved oil and gas reserves as of
December 31, 1997, that is not the same as that included in the estimate of
proved oil and gas reserves as of December 31, 1997, as set forth in "Item 8.
Financial Statements and Supplementary Data" elsewhere herein.  The information
filed with the DOE includes the estimated proved reserves of the properties of
which the Company is the operator, whereas the estimated proved reserves
contained in Item 8 hereof include only the Company's percentage share of the
estimated proved reserves of all properties in which the Company has an
interest.

Production, Sales Prices and Costs

  The following table summarizes the Company's oil production in thousands of
barrels and natural gas production in millions of cubic feet for the years
indicated:
 
                                          Year ended December 31,
                                       ------------------------------
 
                                          1997        1996       1995
                                       -------     -------    -------
 
Oil /(1)/  United States                    76          94        106
           Colombia                        426         476        435
 
Gas        United States                   316       1,146      1,184
           Colombia                          -           -          -

(1)  Includes crude oil and condensate.

                                       10
<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)/
                                                              ---------------------------------
<S>                                          <C>              <C>          <C>         <C> 
                                                                  1997         1996        1995
                                                              --------     --------    --------
 
Average sales price per barrel of oil /(2)/  United States    $  19.17     $  20.68    $  16.78
                                             Colombia         $  17.39     $  19.82    $  16.39
                                                                                        
Average sales price per MCF of gas           United States    $   2.73     $   2.07    $   1.70
                                             Colombia         $      -     $      -    $      -
                                                                                        
Average production cost per dollar of                                                   
  oil and gas revenue                        United States    $   0.54     $   0.45    $   0.52
                                             Colombia         $   0.40     $   0.31    $   0.44
Average production cost per barrel of                                                   
  oil equivalent                             United States    $   9.81     $   6.76    $   6.46
                                             Colombia         $   6.98     $   6.11    $   7.15
</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 Santana concession, which
now consists of approximately 52,000 acres and contains 14 producing wells, has
been in effect since 1987 and is the focus of the Company's exploration and
development activities.

  The Aporte Putumayo concession, which consists of approximately 77,000 acres
and contains three shut-in wells, has been in effect since 1972.  The La Fragua
concession consists of approximately 32,000 acres and has been in effect since
1992.  The Yuruyaco concession was acquired in 1995 and consists of
approximately 39,000 acres.  The Company has filed with Ecopetrol applications
for formal relinquishment of the Aporte Putumayo, La Fragua and Yuruyaco
concessions.  Such formal relinquishments are expected to occur during 1998.

  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 10% (7% for 1998 and thereafter).  Payment of the
remittance tax may be deferred under certain circumstances if Neo reinvests such
income in Colombia.  See Note 7 of the Notes to Consolidated Financial
Statements contained elsewhere herein.

                                       11
<PAGE>
 
  The Colombian government also imposes a production tax which averaged
approximately $1.29 per barrel during 1997 and was equal to 7% of the oil price
in effect through December 1997 for three of the four fields in the Santana
concession.  For these three fields the production tax has been eliminated for
1998 and thereafter.  For the remaining field, the Miraflor 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 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 five producing wells in the Linda field. During
1995, a 3-D seismic survey covering the Toroyaco and Linda fields was completed.
Based on this survey, one development well was drilled in each field during 1996
and one additional development well was drilled in the Linda field in 1997.   No
further drilling is anticipated for these fields.

  The Company 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.

  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 was completed over the Mary and Miraflor fields during early 1997. This
survey confirms the presence of several prospects and leads previously
identified from two-dimensional seismic data.  The most promising prospect, Mary
West, appears to be an extension of the Mary field.  The drilling of an
exploratory well on this prospect has been deferred pending environmental
permits and appropriate financing.  The survey also confirmed that additional
development drilling is not required for the Miraflor field.

  The Co-owners have fulfilled all the initial exploration obligations required
by the Santana risk-sharing contract.  The contract requires that the Co-owners
submit a work program for approval by Ecopetrol for one additional contract
year.  The current work program contemplates the recompletion of certain
existing wells and the construction of a micro-refinery to produce diesel fuel
for the Company's operations.

  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 was
made in 1997 such that all remaining contract areas except for those areas
within five kilometers of a commercial field were relinquished.

  Production from the Santana concession has been sold to Ecopetrol pursuant to
a sales contract that became effective February 1, 1997, and was extended
through December 31, 1998.  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) a deduction of $0.56 per barrel for the
quality of the overall pipeline 

                                       12
<PAGE>
 
blend at the point of sale as compared with the quality of Cano Limon crude (the
"Cano Limon Adjustment"). In 1997, Ecopetrol exported the crude each month and
the sales price averaged $17.39 per barrel.

  At December 31, 1997, 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 $14.30 per barrel
(which does not include the Cano Limon adjustment).  If Ecopetrol had not been
exporting the crude oil at December 31, 1997,  the price used for determining
the standardized measure applicable to the Company's Colombian reserves at
December 31, 1997, would have been approximately $14.80  per barrel.

  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 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, objected to the
proposed exploratory work and the Co-owners were not able to comply with the new
commitment.  The Co-owners requested and Ecopetrol has agreed to allow the Co-
owners to surrender the concession without further expenditure.  Formal
relinquishment is expected in 1998.

  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 would increase from 50% to 75%,  based on a
measure of profitability as defined in the contract.

  Seismic obligations for the first two years of the Yuruyaco concession have
also been satisfied with the completion of a 2-D seismic program in January
1997.  The interpretation of this seismic data failed to establish any
significant prospects and, accordingly, the Co-owners decided to surrender the
concession rather than proceeding into the third contract year.  The Co-owners
have filed an application for formal relinquishment which is expected in 1998.

  Aporte Putumayo Concession.  The discoveries on the Aporte Putumayo concession
  --------------------------                                                    
were not declared commercial by Ecopetrol and the properties were operated by
Argosy and Neo without participation by Ecopetrol.  There are no remaining
exploration obligations under this contract.  Ecopetrol has accepted the Co-
owner's request for 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.  There are currently five productive
wells in the field.  The field's 1997 production averaged 79 barrels of oil per
day and 799 MCF per day, net to the Company's interest, from six completions in
four sands between 6,000 and 7,500 feet.  The Company owns a 35% interest in
this field.  Main Pass Block 41 represents approximately 71% of the Company's
total net U.S. proved reserves at January 1, 1998.

  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 1997, seven wells averaged 130 barrels of oil per day and 66 MCF
of gas per day, net to the Company's interest, from two sands completed between
5,500 feet and 6,500 feet. The 

                                       13
<PAGE>
 
Company's interests in the leases comprising the field vary from 41% to 67%.
Breton Sound Block 31 field represents approximately 29% of the Company's total
net proved U.S. reserves at January 1, 1998.

  The interpretation of 3-D seismic data in 1996 identified two deep and several
shallow prospects in the Breton Sound Block 31 field.  The Company is continuing
its efforts to secure an industry partner to farm-in to the Company's acreage by
drilling one or more exploratory wells that would test the deep prospects.  As
for the shallow prospects, the Company anticipates that it will drill at least
one exploratory well once suitable financing has been secured.

  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 annual lease payments for these offices are $77,000.



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, 1997.

                                       14
<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 traded on the Primary List of the American
Stock Exchange since May 31, 1995 and prior to that on the Emerging Company
Marketplace of the American Stock Exchange since November 14, 1994 (collectively
the "ASE").  In addition, the Company's Common Stock has been traded on the
London Stock Exchange since 1982 and has been quoted in the National Quotation
Bureau's Daily Quotation Sheets (known as the "pink sheets") since December
1993.

  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 1997, only an aggregate
of 1,132,000 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 1997 was approximately 45,000 shares.  The
London Stock Exchange prices indicated in the table are the middle market prices
for the Common Stock as published in the Daily Official List and do not
represent actual transactions.  Prices on the London Stock Exchange are
expressed in British pounds sterling, and, accordingly, the prices for the
Common Stock traded on the London Stock Exchange included in the following table
are similarly expressed.  For ease of reference, these prices are also expressed
in U.S. dollars, having been converted using the exchange rate in effect on the
first day on which the stock price attained the high or low price indicated.

                                       15
<PAGE>
 
<TABLE>
<CAPTION>
                                            1997                             1996                              1995
                                   ----------------------          -------------------------          ------------------------
<S>                      <C>              <C>              <C>               <C>              <C>              <C> 
                                    High              Low              High              Low             High              Low
                                 -------          -------          --------          -------          -------          -------
 
ASE
---
Depositary Shares /(1)/
-----------------------
First Quarter            $          4.13  $          2.88  $           4.38  $          3.88  $          6.13  $          5.13
Second Quarter           $          3.00  $          1.63  $          11.38  $          3.50  $          7.38  $          5.13
Third Quarter            $          4.13  $          1.63  $           6.25  $          3.00  $          5.38  $          4.00
Fourth Quarter           $          2.06  $          0.98  $           5.75  $          3.00  $          4.88  $          4.25
 
 
London Stock Exchange
---------------------
Common Stock
------------
 
First Quarter
     (Pounds)            (Pounds)   0.42  (Pounds)   0.28  (Pounds)    0.46  (Pounds)   0.34  (Pounds)   0.55  (Pounds)   0.47
     US$                 $          0.69  $          0.45  $           0.71  $          0.52  $          0.87  $          0.73
 
Second Quarter
     (Pounds)            (Pounds)   0.32  (Pounds)   0.27  (Pounds)    0.41  (Pounds)   0.25  (Pounds)   0.58  (Pounds)   0.53
     US$                 $          0.51  $          0.44  $           0.63  $          0.38  $          0.93  $          0.84
 
Third Quarter
     (Pounds)            (Pounds)   0.30  (Pounds)   0.21  (Pounds)    0.34  (Pounds)   0.25  (Pounds)   0.53  (Pounds)   0.45
     US$                 $          0.50  $          0.34  $           0.53  $          0.38  $          0.85  $          0.71
 
Fourth Quarter
     (Pounds)            (Pounds)   0.25  (Pounds)   0.17  (Pounds)    0.41  (Pounds)   0.28  (Pounds)   0.55  (Pounds)   0.38
     US$                 $          0.40  $          0.28  $           0.67  $          0.43  $          0.85  $          0.59
</TABLE>

(1) Representing five shares of Common Stock.

  As of February 27, 1998, the Company had approximately 5,700 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."

                                       16
<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,
1997, which should be read in conjunction with the Consolidated Financial
Statements included elsewhere herein.
                                                 
<TABLE>
<CAPTION>
                                                      For the Years Ended
                                                          December 31,      
                                   ------------------------------------------------------------
                                       1997         1996         1995         1994         1993  
                                   --------      -------      -------      -------      -------
                                   (in thousands, except per share, per barrel and per MCF data)                      
<S>                                <C>           <C>          <C>          <C>          <C>                                 
For the period                                                                                 
  Revenues                         $  9,726      $13,750      $10,928      $ 8,546      $10,682
  Loss before extraordinary                                                                    
    item and cumulative effect                                                           
    of accounting change           $(22,482)     $  (937)     $(2,689)     $(2,460)     $(1,963)
  Extraordinary item -                                                                         
    debt extinguishment            $      -      $     -      $     -      $     -      $  (341)
  Cumulative effect to                                                                         
    January 1, 1993 of change                                                                  
    in accounting for taxes        $      -      $     -      $     -      $     -      $  (330)
  Net loss                         $(22,482)     $  (937)     $(2,689)     $(2,460)     $(2,634)
  Loss before extraordinary                                                                    
    item and cumulative                                                                        
    effect of accounting change                                                          
    per common share               $  (0.71)     $ (0.03)     $ (0.09)     $ (0.08)     $ (0.08)
  Basic and diluted net loss                                                                               
    per common share               $  (0.71)     $ (0.03)     $ (0.09)     $ (0.08)     $ (0.11)
  Weighted average                                                                             
    shares outstanding               31,483       31,483       31,483       31,483       24,756
  Cash dividends per                                                                           
    common share                   $      -      $     -      $     -      $     -      $     -
  Total annual net oil                                                                         
    production (barrels)                                                                       
      Colombia                          426          476          435          250          279
      United States                      76           94          106           99          109
                                   --------      -------      -------      -------      -------
       Total                            502          570          541          349          388
                                   --------      -------      -------      -------      -------
                                                                                               
  Total annual net gas                                                                         
    production (MCF)                                                                           
      United States                     316        1,146        1,184        1,839        2,324
                                                                                               
  Average price per barrel                                                                     
    of oil                                                                                     
      Colombia                     $  17.39      $ 19.82      $ 16.39      $ 13.60      $ 14.02
      United States                $  19.17      $ 20.68      $ 16.78      $ 15.40      $ 16.90
  Average price per MCF of                                                                     
    Gas - United States            $   2.73      $  2.07      $  1.70      $  1.97      $  2.12
                                                                                               
At period end                                                                                  
  Total assets                     $ 16,445      $42,944      $45,460      $42,383      $45,017
  Long term debt, including                                                                    
    current portion                $  7,690      $ 7,990      $13,067      $ 6,640      $ 5,476
  Stockholders' equity             $  3,748      $26,230      $27,167      $29,856      $32,316
</TABLE>

  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 ceiling test write-downs of oil and gas
properties of $19,953,000 in 1997 (see Note 1 of Notes to Consolidated Financial
Statements).

                                       17
<PAGE>
 
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
 
1997 versus 1996
----------------
                                  United States     Colombia
                                  Oil       Gas        Oil      Total
                                 ------   -------    -------   -------
       (Thousands)
 
       Revenue - 1996            $1,940   $ 2,373    $ 9,437   $13,750
 
       Volume variance             (366)   (1,782)      (995)   (3,143)
 
       Price variance              (115)      223     (1,037)     (929)
 
       Other                          -        48          -        48
                                 ------   -------    -------   -------
 
       Revenue - 1997            $1,459   $   862    $ 7,405   $ 9,726
                                 ======   =======    =======   =======
 
  Colombian oil volumes were 426,000 barrels in 1997, a decrease of 50,000
barrels from 1996.  Such decrease is the result of a 68,000 barrel decrease due
to the Company's net revenue interest declining from 18% to 12.6% in June 1996
when cumulative production from the Santana concession reached the 7 million
barrel threshold specified in the risk-sharing contract, and a 119,000 barrel
decrease resulting from normal production declines, partially offset by a
136,000 barrel increase primarily due to the completion of two development wells
in the latter part of 1996 and one development well completed in June 1997.

  U.S. oil volumes were 76,000 barrels in 1997, down 18,000 barrels from 1996.
This decrease resulted primarily from the sale of the Company's U.S. onshore
properties on December 23, 1996.  U.S. gas volumes before gas balancing
adjustments were 274,000 thousand cubic feet ("MCF") in 1997, down 862,000 MCF
from 1996.  Such decrease is the result of an 896,000 MCF decrease resulting
from the U.S. onshore property sale, and normal production declines partially
offset by new production from a development well completed at Main Pass 41
during October 1996.

  Colombian oil prices averaged $17.39 per barrel during 1997.  The average
price for the same period in 1996 was $19.82 per barrel.  The Company's average
U.S. oil price decreased to $19.17 per barrel in 1997, down from $20.68 in 1996.
U.S. gas prices averaged $2.73 per MCF in 1997 compared to $2.07 per MCF in
1996.

  In addition to the above-mentioned variances, U.S. gas revenue increased
approximately $48,000 as a result of gas balancing adjustments.

  Operating costs decreased by $599,000, or 12%.  Of such decrease,
approximately $845,000 resulted from the sale of the U.S. onshore properties,
offset by a $181,000 increase for the U.S. offshore properties and a $65,000
increase for the Colombian properties.

  Depreciation, depletion and amortization ("DD&A") decreased $1.3 million, or
17%, mainly due to lower production levels.

  The Company recorded write-downs to the carrying amounts of its U.S. and
Colombian oil and gas properties of $2,124,000 and $17,829,000, respectively,
during 1997.  The U.S. write-down was primarily due to lower prices.  The
Colombian write-down resulted primarily from lower prices and, to a somewhat
lesser extent, downward revisions of proved oil reserves.

                                       18
<PAGE>
 
  General and administrative ("G&A") expense decreased $44,000 mainly due to
reductions in the number of employees, officers, directors and related fees and
expenses which resulted in cost savings of approximately $262,000 during 1997.
These savings were partially offset by increases in legal and consulting fees
aggregating $201,000.  Such increases were primarily related to the Company's
restructuring plan.  See "- -Liquidity and Capital Resources."

  Interest and other income (expense) decreased mainly due to the absence in
1997 of a $641,000 gain recorded in 1996 relating to the sale of the U.S.
onshore oil and gas properties.

  Interest expense was $156,000 lower, primarily as a result of lower average
balances outstanding.

  Income taxes were lower in 1997 primarily due to Colombian deferred tax
benefits resulting from the write-down of the carrying amount of the Company's
Colombian oil and gas properties.
 
1996 versus 1995
----------------
                                  United States     Colombia
                                  Oil       Gas       Oil     Total
                                 ------   ------     ------  -------
       (Thousands)
 
       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
                                 ======   ======     ======  =======
 

  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 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 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.

  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. 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.

                                       19
<PAGE>
 
  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 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.

Year 2000

  Based on a preliminary study, the Company expects to spend approximately $0.1
million from 1998 through 1999 to modify its computer information systems
enabling proper processing of transactions relating to the year 2000 and beyond.
The Company continues to evaluate appropriate courses of corrective action,
including replacement of certain systems whose associated costs would be
recorded as assets and amortized.  Accordingly, the Company does not expect the
amounts required to be expensed over the next two years to have a material
effect on its financial position or results of operations.

Liquidity and Capital Resources

  During the period 1995 through 1997, costs incurred in oil and gas property
acquisition, exploration and development activities by the Company totaled
approximately $18.8 million.  Of this figure, approximately $3.3 million was for
exploration predominantly in Colombia and $15.5 million pertained to development
costs in the United States (23%) and Colombia (77%).  The Company's sources of
funds during this period were: (i) cash provided by operating activities - 1997
- $1.7 million; 1996 - $8.9 million; and 1995 - $2.9 million;  (ii) net cash
provided by investing activities (before property and equipment expenditures) -
1997 - $0.02 million; 1996 - $2.7 million; and 1995 - $0.1 million; and  (iii)
net cash provided by (used in) financing activities - 1997 - $(0.3) million;
1996 - $(5.1) million; and 1995 - $6.4 million.

  In the U.S., the Company is currently engaged in the conversion of a shutin
well into a saltwater disposal well at its Breton Sound 31 field facilities.
The cost to convert and equip such a well is estimated at $0.3 million, net to
the Company's interest.  Additionally, the Company is upgrading certain
equipment at its Main Pass 41 field facilities, the cost of which is expected to
aggregate $0.1 million, net to the Company's interest.

  The Company is also engaged in the recompletion of certain existing wells, the
construction of a micro-refinery for production of diesel fuel, and various
miscellaneous projects in Colombia.  The Company's share of the estimated future
costs of these development activities is approximately $0.8 million at December
31, 1997.  Failure to fund certain capital expenditures could result in the
forfeiture of all or part of the Company's interest in the concessions.

  The Company plans to fund these development activities through cash provided
from operations.  Any substantial decreases in the borrowing base as hereinafter
defined or increases in the amounts of these required expenditures could
adversely affect the Company's ability to fund these development activities.
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 

                                       20
<PAGE>
 
1996, however, devaluation of the peso was substantially lower than the rate of
inflation of the peso, resulting in an effective inflation rate in excess of
that of the U.S. dollar. There can be no assurance that this condition will not
occur again or that, in such event, there will not be substantial increases in
future capital expenditures as a result. Due to Colombian exchange controls and
restrictions and the lack of an effective market, it is not feasible to hedge
against the risk of net peso inflation against the U.S. dollar and the Company
has not done so. Depending on the results of future exploration and development
activities, substantial expenditures which have not been included in the
Company's cash flow projections may be required. 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 development
activities.

  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, 1997, the borrowing base permitted,
and the outstanding loan balance was, $7,690,000.  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 February 1998, the Company entered into an agreement with ING Capital
pursuant to which the outstanding loan balance was paid down to $7,440,000 from
$7,690,000, the interest rate was increased to the prime rate, as defined, plus
1.5%, or at the option of the Company, a fixed rate based on the London
Interbank Offered Rate plus 3%, and the repayment schedule was amended to
require monthly payments of 80% of defined monthly cash flows until October 1,
1999, at which time the remaining balance is due and payable.  Additionally, ING
Capital reduced to $2 million the minimum amount of consolidated tangible net
worth that the Company is required to maintain.

  The Company's internal projections of its consolidated cash flow indicate that
the Company's consolidated cash flow and working capital will be adequate to
fund both the estimated development expenditures for 1998 and 1999 and the
monthly debt service relating to the ING Capital credit agreement as amended in
February 1998.  The Company does not, however project that, at current levels,
its cash flows will be sufficient to repay the remaining balance under the ING
Capital credit agreement that will be due and payable on October 1, 1999.
Accordingly, the Company may be required to further extend the maturity of the
debt or raise additional capital through equity issues or by sales of assets to
retire the debt.  The ultimate outcome of these matters cannot be projected with
certainty.

  The above referenced internal cash flow projections assume (i) crude oil sales
prices of $11.56 per barrel for Colombian production and $13.89 per barrel for
United States production and natural gas sales prices of $2.25 per MCF for
United States production, (ii) successful recompletion of four existing 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 activities, may adversely affect the Company's ability to
fund such development expenditures or to meet its existing debt service
obligations.  Depending on the results of the Company's future 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."

  The aforementioned oil and gas prices used in the Company's internal cash flow
projections are indicative of the prices the Company expects to receive for its
production in March 1998.  These prices are substantially lower than the prices
prevailing at December 31, 1997, which were used in the Company's yearend
ceiling limitation test for capitalized costs.  If prices remain at current
levels and do not recover substantially prior to the issuance of the Company's
financial statements for the first quarter of 1998, the Company expects that it
will incur additional ceiling test write-downs for both its U.S. and Colombian
cost centers that, in the aggregate, will have a significant adverse effect on
the Company's results of operations and could result in the elimination of the
Company's net equity.  Moreover, such write-downs could result in the Company's
failure to maintain the minimum consolidated tangible net worth of $2 million
required by the latest amendment to the Company's credit agreement with ING
Capital. In the past, ING Capital has amended or waived compliance with the
Company's minimum consolidated tangible net worth

                                       21
<PAGE>
 
covenant when the Company has been unable to meet such requirements. There can
be no assurance, however, that ING Capital will continue to make similar
concessions in the future.

  On July 8, 1997, the Company engaged Merrick Capital Corporation ("Merrick")
to act as its financial advisor in order to identify and accomplish certain
strategic corporate objectives (the "Restructuring Plan").  Such objectives
included the private placement of $5 million of common stock, the procurement of
$15 million of mezzanine financing and the negotiation of a $25 million oil and
gas reserve based credit facility.  The Restructuring Plan could not be
completed in the current climate of depressed oil prices and other
uncertainties.  Accordingly, on February 13, 1998, the Company terminated
Merrick's engagement as the Company's financial advisor and the Board of
Directors of the Company is pursuing other alternatives to enhance shareholder
value.

  With the exception of historical information, the matters discussed in this
annual report to shareholders contain forward-looking statements that involve
risks and uncertainties.  Although the Company believes that its expectations
are based on reasonable assumptions, it can give no assurance that its goals
will be achieved.  Important factors that could cause actual results to differ
materially from those in the forward-looking statements herein include, among
other things, general economic conditions, volatility of oil and gas prices, the
impact of possible geopolitical occurrences world-wide and in Colombia,
imprecision of reserve estimates, changes in laws and regulations, unforeseen
engineering and mechanical or technological difficulties in drilling, working-
over and operating wells during the periods covered by the forward-looking
statements, as well as other factors described in "Item 1. Business - Risks
Associated with the Company's Business."



ITEM 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.

                                       22
<PAGE>
 
                                   PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT


Directors of the Company

  The by-laws of the Company provide that the number of directors may be fixed
by the Board of Directors at a number between one and seven, except that a
decrease in the number of directors shall not have the effect of reducing the
term of any incumbent director.  On July 30, 1997, the Board of Directors, by
resolution, increased the number of directors from four to five.

  The information set forth below, furnished to the Company by the respective
individuals, shows as to each individual his name, age and principal positions
with the Company.
 
       NAME               AGE              POSITIONS              DIRECTOR SINCE
       ----               ---              ---------              --------------
 
Ronald Suttill             66  President, Chief Executive Officer      1985
                               and Director
 
Eugene C. Fiedorek         66  Director                                1997
 
John J. Lee                61  Director                                1993
 
Elliott Roosevelt, Jr.     61  Director                                1994
 
James E. Tracey            49  Director                                1992

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

  RONALD SUTTILL has been a director of the Company since August 1985 and has
been President and Chief Executive Officer of the Company since January 1992.
In December 1991, Mr. Suttill was appointed President and Chief Operating
Officer and prior to that served as Executive Vice President of the Company.

  EUGENE C. FIEDOREK has been a director of the Company since July 1997.  Mr.
Fiedorek is a Managing Director of EnCap Investments, L.C., a company he co-
founded in 1988.  He was previously associated with RepublicBank Dallas for more
than 20 years, most recently as the Managing Director in the Energy Department
in charge of all energy-related commercial lending and corporate finance
activities.  Prior to joining RepublicBank, Mr. Fiedorek was with Shell Oil
Company as an Exploitation Engineer.  Mr. Fiedorek currently serves on the
boards of Energy Capital Investment Company PLC, Apache Corporation and
privately held Matador Petroleum Corporation.

  JOHN J. LEE has been a director of the Company since August 1993, and is
Chairman, President and Chief Executive Officer of Hexcel Corporation, an
advanced materials manufacturer. Mr. Lee joined the Board of Hexcel Corporation
in May 1993 as an outside independent director.  In August 1993, Mr. Lee was
asked to become the Chairman and Co-Chief Executive Officer of Hexcel
Corporation, which was experiencing financial difficulties, in order to effect a
consensual reorganization.  In December 1993, having concluded that a consensual
reorganization could not be accomplished, Hexcel Corporation filed for
protection under Chapter 11 of the Federal Bankruptcy Code and appointed Mr. Lee
sole Chief Executive Officer to effect a Plan of Reorganization.  The
reorganization was completed in February 1995 and Hexcel emerged from Chapter
11.  Mr. Lee has been Chairman, President and Chief Executive Officer of Lee
Development Corporation, a corporation providing investment and merchant banking
services, since 1987 and was a director of XTRA Corporation, a Massachusetts-
based transportation and equipment leasing company, from 1990 through January
1995.  Mr. Lee also served as Chairman and Chief Executive Officer of Seminole
Corporation, a fertilizer manufacturer, from July 1989 through April 1993 and
director of Tosco Corporation, a refiner, from April 1988 through April 1993 and
was President and Chief Operating Officer of Tosco Corporation from April 1990
through April 1993.  Mr. Lee is an advisor to the Clipper Group, a New York
Merchant Banking group and is a trustee of Yale University.

                                       23
<PAGE>
 
  ELLIOTT ROOSEVELT, JR. has been a director of the Company since January 1994
and has been President of E.R. Operating Co., a private oil and gas company,
since 1989.  Mr. Roosevelt has more than 30 years of experience in the oil
business with several public and private companies.

  JAMES E. TRACEY has been a director of the Company since June 1992.  Mr.
Tracey was a senior executive with The Royal Bank of Scotland plc ("RBS") until
1996, when he retired.  Mr. Tracey was employed by RBS for 31 years.

Executive Officers of the Company

  The following table lists the names and ages of each of the executive officers
of the Company and their principal occupations for the past five years.

NAME AND AGE                    POSITIONS
------------                    ---------

Ronald Suttill, 66              President and Chief Executive Officer since
                                January 1992, President and Chief Operating
                                Officer from December 1991 to January 1992 and
                                Executive Vice President prior to that.

James L. Busby, 37              Treasurer since May 1994, Secretary since June
                                1996, Controller since November 1993 and a
                                Senior Manager with the accounting firm of KPMG
                                Peat Marwick LLP prior to that.

Meetings and Committees of the Board of Directors

  The Board of Directors of the Company held nine meetings during 1997.  Each
director attended at least 75% of the aggregate of (i) the total number of
meetings of the Board of Directors held during the period in which he was a
director and (ii) the total number of meetings held by all committees on which
he served.

  The Audit Committee and the Compensation Committee are the only standing
committees of the Board of Directors, and the members of such committees are
appointed at the initial meeting of the Board of Directors each year.  The
Company does not have a formal nominating committee; the Board of Directors
performs this function.

  The Audit Committee, which is comprised of Messrs. Roosevelt and Tracey,
consults with the independent accountants of the Company and such other persons
as the committee deems appropriate, reviews the preparations for and scope of
the audit of the Company's annual financial statements, makes recommendations as
to the engagement and fees of the independent accountants and performs such
other duties relating to the financial statements of the Company as the Board of
Directors may assign from time to time.  The Audit Committee held two meetings
during 1997.

  The Compensation Committee, which is comprised of Messrs. Lee, Roosevelt and
Tracey, makes recommendations to the Board of Directors regarding the
compensation of executive officers of the Company, including salary, bonuses,
stock options and other compensation.   The Compensation Committee held no
meetings during 1997.

Compliance with Section 16(a) of the Securities Exchange Act of 1934

  Section 16(a) of the Securities Exchange Act of 1934, as amended
(the "Exchange Act"), requires officers, directors and holders of more than 10%
of the Common Stock (collectively, "Reporting Persons") to file reports of
ownership and changes in ownership of the Common Stock with the SEC within
certain time periods and to furnish the Company with copies of all such reports.
Based solely on its review of the copies of such reports furnished to the
Company by such Reporting Persons or on the written representations of such
Reporting Persons, the Company believes that, during the year ended December 31,
1997, all of the Reporting Persons complied with their Section 16(a) filing
requirements.

                                       24
<PAGE>
 
ITEM 11. EXECUTIVE COMPENSATION


Summary Compensation Table

  The following table sets forth certain information regarding compensation
earned in each of the last three fiscal years by the President and Chief
Executive Officer of the Company (the "Named Executive Officer").

<TABLE>
<CAPTION>
                                      Summary Compensation Table
                                      --------------------------
                                                                           Long Term
                                                                          Compensation
                           Annual Compensation                       Awards             Payouts
                      -------------------------              ----------------------------------
                                                 Other
                                                 Annual      Restricted    Securities
Name and                                         Compen-       Stock       Underlying     LTIP     All Other
Principal                   Salary               sation       Award(s)      Options/     Payouts   Compensa-
Position              Year      ($)   Bonus ($)      ($)           ($)       SARs (#)       ($)    tion ($)
--------------------  ----  -------   ---------  -------     ----------   ------------   -------   ---------
<S>                   <C>   <C>       <C>        <C>         <C>          <C>            <C>       <C>
 
Ronald Suttill/(1)/
   President and CEO  1997  185,000          -         -              -              -         -       4,750
   President and CEO  1996  200,000          -         -              -              -         -       4,750
   President and CEO  1995  200,000          -         -              -              -         -       4,620
 
</TABLE>

/(1)/ The amounts reported for all other compensation for Mr. Suttill represent
      matching contributions made under the Aviva Petroleum Inc. 401(k)
      Retirement Plan (the "401(k) Plan").

Directors' Fees

  Messrs. Fiedorek, Lee, Roosevelt and Tracey each receive $20,000 per year for
their services as directors and are reimbursed for travel and lodging expenses.
Mr. Suttill receives no compensation as a director but is reimbursed for travel
and lodging expenses incurred to attend meetings.

Option Grants During 1997

  There were no options granted to the Named Executive Officer during 1997.  No
stock appreciation rights have been issued by the Company.


Option Exercises During 1997 and Year End Option Values

  The following table provides information related to options exercised by the
Named Executive Officers during 1997 and the number and value of options held at
year-end.  No stock appreciation rights have been issued by the Company.

<TABLE>
<CAPTION>
                                                                       Number of Securities           Value of Unexercised
                                                                      Underlying Unexercised          In-the-Money Options
                                                                      Options at FY-End (#)             at FY-End ($) (1)
                                Shares Acquired     Value      ----------------------------------  --------------------------
Name                            on Exercise (#)  Realized ($)  Exercisable      Unexercisable      Exercisable  Unexercisable
----                            ---------------  ------------  -----------  ---------------------  -----------  -------------
<S>                             <C>              <C>           <C>          <C>                    <C>          <C>
 
Ronald Suttill                          none          none       270,000                     -             -              -
 
</TABLE>

/(1)/ No values are ascribed to unexercised options of the Named Executive
      Officer at December 31, 1997 because the fair market value of a share of
      the Company's Common Stock at December 31, 1997 ($0.33) did not exceed the
      exercise price of any such options.

Compensation Committee Interlocks and Insider Participation in Compensation
Decisions

  As indicated above, the Compensation Committee, none of the members of which
is an employee of the Company, makes recommendations to the Board of Directors
regarding the compensation of the executive officers of the Company, 

                                       25
<PAGE>
 
including salary, bonuses, stock options and other compensation. There are no
Compensation Committee interlocks. Until this committee was originally appointed
in 1993, the compensation of the executive officers was established by the Board
of Directors as a whole, including Mr. Suttill.

Employment Contracts

  Each executive officer serves at the discretion of the Board of Directors,
except that, effective in January 1995, the Company entered into an employment
contract with Mr. Suttill.  Mr. Suttill's contract provides for annual
compensation of not less than $200,000 if his employment is terminated for any
reason other than death, disability or cause, as defined in the contract.  Mr.
Suttill's  contract was automatically renewed for one-year periods on January 1,
1996, 1997 and 1998.

Compensation Committee Report on Executive Compensation

  The Company currently employs only two executive officers, the names of whom
are set forth above under "Election of Directors - Executive Officers of the
Company." Decisions regarding compensation of the executive officers are made by
the Board of Directors, after giving consideration to recommendations made by
the Compensation Committee.

  The Company's compensation policies are designed to provide a reasonably
competitive level of compensation within the industry in order to attract,
motivate, reward and retain experienced, qualified personnel with the talent
necessary to achieve the Company's performance objectives.  These objectives are
to increase oil and gas reserves and to control costs, both objectives selected
to increase shareholder value.  These policies were implemented originally by
the entire Board of Directors, and, following its establishment, were endorsed
by the Compensation Committee.  It is the intention of the Compensation
Committee and the Board of Directors to balance compensation levels of the
Company's executive officers, including the Chief Executive Officer, with
shareholder interests.  The incentive provided by stock options and bonuses, in
particular, is intended to promote congruency of interests between the executive
officers and the shareholders.  Neither the Compensation Committee nor the Board
of Directors, however, believes that it is appropriate to rely on a formulaic
approach, such as profitability, revenue growth or return on equity, in
determining executive officer compensation because of the nature of the
Company's business.  The Company's business objectives include overseeing a
significant exploration and development effort in Colombia and the maintenance
of oil and gas production levels and offshore operations in the United States.
Success in one such area is not measurable by the same factors as those used in
the other.  Accordingly, the Compensation Committee and the Board of Directors
rely primarily on their assessment of the success of the executive officers,
including the Chief Executive Officer, in fulfilling the Company's performance
objectives.  The Board of Directors also considers the fact that the Company
competes with other oil and gas companies for qualified executives and therefore
it considers available information regarding compensation levels for executives
of companies similar in size to the Company.

  Compensation for the Company's executive officers during 1997 was comprised of
salary and matching employer contributions made pursuant to the Company's 401(k)
Plan.  There were no bonuses paid to the executive officers during or for 1997.
The Company's 401(k) Plan is generally available to all employees after one year
of service.  The Company makes matching contributions of 50% of the amount
deferred by the employee, up to 3% of an employee's annual salary.

                                       Compensation Committee

                                       J.J. Lee
                                       E. Roosevelt, Jr.
                                       J.E. Tracey


Performance Graph

  The following line-graph presentation compares five-year cumulative
shareholder returns on an indexed basis with a broad equity market index and a
published industry index.  The Company has selected the American Stock Exchange
Market Value Index as a broad equity market index, and the SIC Index "Crude
Petroleum and Natural Gas" as a published industry index.

                                       26
<PAGE>
 
              COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN OF THE
                   COMPANY, INDUSTRY INDEX AND BROAD MARKET
                                        
----------------------------- FISCAL YEAR ENDING -------------------------------
COMPANY                         1992    1993    1994    1995    1996    1997

AVIVA PETROLEUM INC.             100     215.38  264.10  225.64  200.00   84.62
INDUSTRY INDEX                   100     119.15  124.87  137.33  182.60  185.09
BROAD MARKET                     100     118.81  104.95  135.28  142.74  171.76


ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT


Security Ownership of Certain Beneficial Owners

  The following table sets forth certain information as to each person who, to
the knowledge of the Company, is the beneficial owner of more than five percent
of the outstanding Common Stock of the Company.  Unless otherwise noted, the
information is furnished as of February 27, 1998.
 
NAME AND ADDRESS OF            AMOUNT AND NATURE OF
BENEFICIAL OWNER OR GROUP     BENEFICIAL OWNERSHIP /(1)/  PERCENT OF CLASS /(2)/
-------------------------     --------------------------  ----------------------
 
Lehman Brothers Inc./(3)/              2,966,876                  9.42%
3 World Financial Center
11th Floor
New York, NY 10285
 
Fidelity International Limited         2,780,000                  8.83%
and Edward C. Johnson III/(4)/
P.O. Box HM670
Hamilton, HMCX, Bermuda
 
Yale University/(5)/                   2,551,886                  8.11%
230 Prospect Street
New Haven, CT 06511

/(1)/  Except as set forth below, to the knowledge of the Company, each
       beneficial owner has sole voting and sole investment power.
/(2)/  Based on 31,482,716 shares of the Common Stock issued and outstanding on
       February 27, 1998.
/(3)/  Information regarding Lehman Brothers Inc. is based on information
       received from Lehman Brothers Inc. on March 16, 1998.
/(4)/  Information regarding Fidelity International Limited is based on an
       amended notification of disclosable interests, dated July 25, 1996,
       pursuant to the U.K. Companies Act. Fidelity International Limited is the
       parent holding company for various direct and indirect subsidiaries that
       hold these interests. Mr. Edward C. Johnson III is a principal
       shareholder and chairman of Fidelity International Limited.
/(5)/  Information regarding Yale University is based on a Schedule 13G dated
       March 11, 1994 filed by Yale University with the Securities and Exchange
       Commission ("SEC").

                                       27
<PAGE>
 
Security Ownership of Management

  The following table sets forth certain information as of February 27, 1998,
concerning the Common Stock of the Company owned beneficially by each director,
by the Named Executive Officer listed in the Summary Compensation Table above,
and by directors and executive officers of the Company as a group:
 
NAME AND ADDRESS OF                AMOUNT AND NATURE
BENEFICIAL OWNER              OF BENEFICIAL OWNERSHIP/(1)/ PERCENT OF CLASS/(2)/
----------------              ---------------------------- ---------------------
 
Ronald Suttill                           1,275,050 /(3)(4)/         4.00%
8235 Douglas Avenue, Suite 400
Dallas, TX 75225
 
Eugene C. Fiedorek                         262,153                      *
3811 Turtle Creek Blvd., Suite 1080
Dallas, TX 75219
 
John J. Lee                              1,124,428 /(5)(6)/         3.53%
Two Stamford Plaza
281 Tresser Blvd., 16th Floor
Stamford, CT 06901
 
Elliott Roosevelt, Jr.                      60,000 /(5)/                *
2626 Cole Avenue, Suite 600
Dallas, TX 75204
 
James E Tracey                             965,550 /(4)(5)/         3.03%
3, Grey Close
Hampstead Garden Suburb
London, NW11 3QG
 
All directors and executive officers
as a group (6 persons)                   2,782,791 /(7)/            8.73%

/(1)/ Except as noted below, each beneficial owner has sole voting power and
      sole investment power.
/(2)/ Based on 31,482,716 shares of Common Stock issued and outstanding on
      February 27, 1998. Treated as outstanding for purposes of computing the
      percentage ownership of each director, the Named Executive Officer and
      all directors and executive officers as a group are shares issuable upon
      exercise of vested stock options granted pursuant to the Company's stock
      option plans.
/(3)/ Included are options for 270,000 shares exercisable on or within 60 days
      of February 27, 1998.
/(4)/ Includes the entire ownership of AMG Limited, a limited liability company
      of which Messrs. Suttill and Tracey are members, as of February 27, 1998,
      of 935,550 shares of Common Stock.
/(5)/ Included are options for 30,000 shares exercisable on or within 60 days of
      February 27, 1998.
/(6)/ Included are 1,094,428 shares owned by Lee Development Corporation, which
      Mr. Lee controls.
/(7)/ Included are 935,550 shares beneficially owned through AMG Limited and
      options for 388,000 shares exercisable on or within 60 days of February
      27, 1998.
*     Less than 1% of the outstanding Common Stock.


ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

  None.

                                       28
<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 Shane
                McKnight, Douglas W. Fry, P-5 Ltd., GO-DEO, Inc., Dale E.
                Armstrong, Richard Shane McKnight, The Yvonne McKnight Trust,
                and William Gaskin, as limited partners (filed as exhibit 10.5
                to the Company's Registration Statement on Form10, File No. 0-
                22258, and incorporated herein by reference).

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

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

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

         *10.9  Purchase Sale - Transportation and Commercialization of the
                Santana Crude between Ecopetrol, Argosy and Neo (filed as
                exhibit 10.9 to the Company's Registration Statement on Form10,
                File No. 0-22258, and incorporated herein by reference).

                                       29
<PAGE>
 
         *10.10 La Fragua Association Contract dated June 1, 1992 between
                Ecopetrol, Argosy and Neo (filed as exhibit 10.10 to the
                Company's Registration Statement on Form10, File No. 0-22258,
                and incorporated herein by reference).

         *10.11 Operating Agreement for the La Fragua Area between Argosy
                and Neo dated April 15, 1992 (filed as exhibit 10.11 to the
                Company's Registration Statement on Form10, File No. 0-22258,
                and incorporated herein by reference).

         *10.12 Employment Agreement between the Company and Ronald Suttill
                dated November 29, 1991 (filed as exhibit 10.12 to the Company's
                Registration Statement on Form10, File No. 0-22258, and
                incorporated herein by reference).

         *10.13 Employee Stock Option Plan of the Company (filed as exhibit
                10.13 to the Company's Registration Statement on Form10, File
                No. 0-22258, and incorporated herein by reference).

         *10.14 Letter agreement dated January 6, 1993 between NationsBank
                Investment Banking and the Company (filed as exhibit 10.14 to
                the Company's Registration Statement on Form10, File No. 0-
                22258, and incorporated herein by reference).

         *10.15 Letter agreement dated March 3, 1993 between EnCap
                Investments L.C. and the Company (filed as exhibit 10.15 to the
                Company's Registration Statement on Form10, File No. 0-22258,
                and incorporated herein by reference).

         *10.16 Credit Agreement dated August 6, 1993 between the Company,
                Aviva America, Inc. ("Aviva America"), Neo and Internationale
                Nederlanden Bank N.V., New York Branch ("ING Capital") (filed as
                exhibit 10.16 to the Company's Registration Statement on Form10,
                File No. 0-22258, and incorporated herein by reference).

         *10.17 Subordination Agreement dated August 6, 1993 between the
                Company, Aviva America, Aviva Operating Company ("Aviva
                Operating"), Neo and ING Capital (filed as exhibit 10.17 to the
                Company's Registration Statement on Form10, File No. 0-22258,
                and incorporated herein by reference).

         *10.18 Stock Pledge Agreement dated August 6, 1993 between the
                Company and ING Capital (filed as exhibit 10.18 to the Company's
                Registration Statement on Form10, File No. 0-22258, and
                incorporated herein by reference).

         *10.19 Stock Pledge Agreement dated August 6, 1993 between Aviva
                America and ING Capital (filed as exhibit 10.19 to the Company's
                Registration Statement on Form10, File No. 0-22258, and
                incorporated herein by reference).

         *10.20 Guaranty dated August 6, 1993 made by the Company in favor
                of ING Capital (filed as exhibit 10.20 to the Company's
                Registration Statement on Form10, File No. 0-22258, and
                incorporated herein by reference).

         *10.21 Guaranty dated August 6, 1993 made by Aviva America in favor
                of ING Capital (filed as exhibit 10.21 to the Company's
                Registration Statement on Form10, File No. 0-22258, and
                incorporated herein by reference).

         *10.22 Guaranty dated August 6, 1993 made by Aviva Operating in
                favor of ING Capital (filed as exhibit 10.22 to the Company's
                Registration Statement on Form10, File No. 0-22258, and
                incorporated herein by reference).

         *10.23 Form of Subscription Agreement dated June 18, 1993 between
                the Company and purchasers of 12,884,207 shares of common stock
                ("Purchasers") (filed as exhibit 10.23 to the Company's
                Registration Statement on Form10, File No. 0-22258, and
                incorporated herein by reference).

         *10.24 Option Agreement between RBS and Aviva Energy Inc. ("Aviva
                Energy") dated July 1, 1993 (filed as exhibit 10.24 to the
                Company's Registration Statement on Form10, File No. 0-22258,
                and incorporated herein by reference).

         *10.25 Option Agreement between Aviva Energy and Purchasers dated
                July 1, 1993 (filed as exhibit 10.25 to the Company's
                Registration Statement on Form10, File No. 0-22258, and
                incorporated herein by reference).

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

         *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).

                                       30
<PAGE>
 
         *10.28 Letter from Ecopetrol dated February 24, 1994 and Resolution
                dated February 18, 1994 revising pipeline tariff (filed as
                exhibit 10.28 to the Company's annual report on Form 10-K for
                the year ended December 31, 1993, File No. 0-22258, and
                incorporated herein by reference).

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

         *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).

                                       31
<PAGE>
 
         *10.46 Aviva Petroleum Inc. 1995 Stock Option Plan (filed as
                exhibit 10.5 to the Company's quarterly report on Form 10-Q for
                the quarter ended September 30, 1995, File No. 0-22258, and
                incorporated herein by reference).

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

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

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

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

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

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

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

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

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

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

         *10.57 Amendment to the ING Capital Credit Agreement dated November
                22, 1996 (filed as exhibit 10.57 to the Company's annual report
                on Form 10-K for the year ended December 31, 1996, File No. 0-
                22258, and incorporated herein by reference).

         *10.58 Purchase and Sale Agreement dated November 22, 1996 between
                BWAB Incorporated and Aviva America (filed as exhibit 10.58 to
                the Company's annual report on Form 10-K for the year ended
                December 31, 1996, File No. 0-22258, and incorporated herein by
                reference).

         *10.59 Purchase and Sale Agreement dated December 6, 1996 between
                Lomak Petroleum Inc. and Aviva America (filed as exhibit 10.59
                to the Company's annual report on Form 10-K for the year ended
                December 31, 1996, File No. 0-22258, and incorporated herein by
                reference).

         *10.60 Santana Crude Sale and Purchase Agreement dated February 10,
                1997 (filed as exhibit 10.60 to the Company's annual report on
                Form 10-K for the year ended December 31, 1996, File No. 0-
                22258, and incorporated herein by reference).

         *10.61 Aviva Petroleum Inc. 1995 Stock Option Plan, as amended
                (filed as Appendix A to the Company's definitive Proxy Statement
                for the Annual Meeting of Shareholders dated June 10, 1997, and
                incorporated herein by reference).

         *10.62 Amendment to the ING Capital Credit Agreement dated August
                12, 1997 (filed as exhibit 10.2 to the Company's quarterly
                report on Form 10-Q for the quarter ended June 30, 1997, File
                No. 0-22258, and incorporated herein by reference).

         *10.63 Amended and Restated Aviva Petroleum Inc. Severance Benefit
                Plan dated September 30, 1997 (filed as exhibit 10.3 to the
                Company's quarterly report on Form 10-Q for the quarter ended
                September 30, 1997, File No. 0-22258, and incorporated herein by
                reference).

        **10.64 Amendment to the ING Capital Credit Agreement dated
                December 29, 1997.
        
        **10.65 Amendment to the Santana Crude Sale and Purchase Agreement
                dated January 5, 1998.
    
        **10.66 Amendment to the ING Capital Credit Agreement dated
                February 13, 1998.

                                       32
<PAGE>
 
         *21.1  List of subsidiaries of Aviva Petroleum Inc.

        **27.1  Financial Data Schedule.
 
 

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



b. Reports on Form 8-K
   -------------------

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

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


   December 31, 1997          Submitted a copy of the Company's Press Release
                              dated December 31, 1997, reporting on the
                              Company's Restructuring Plan.

   February 16, 1998          Submitted a copy of the Company's Press Release
                              dated February 16, 1998, reporting on the
                              Company's Restructuring Plan.
 

                                       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 23, 1998
-------------------------- and Director (principal executive 
Ronald Suttill             officer)



/s/ James L. Busby         Treasurer and Secretary                March 23, 1998
-------------------------- (principal financial and accounting
James L. Busby             officer)




/s/ Eugene C. Fiedorek     Director                               March 23, 1998
--------------------------                                                  
Eugene C. Fiedorek



/s/ John J. Lee            Director                               March 23, 1998
--------------------------                                        
John J. Lee



/s/ Elliott Roosevelt, Jr. Director                               March 23, 1998
--------------------------                                                  
Elliott Roosevelt, Jr.



/s/ James E. Tracey        Director                               March 23, 1998
--------------------------                                                  
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, 1997 and 1996...    37
 
Consolidated Statement of Operations for the years
     ended December 31, 1997, 1996 and 1995...................    38
 
Consolidated Statement of Cash Flows for the years
     ended December 31, 1997, 1996 and 1995...................    39
 
Consolidated Statement of Stockholders' Equity for the years
     ended December 31, 1997, 1996 and 1995...................    40
 
Notes to Consolidated Financial Statements....................    41
 
Supplementary Information Related to Oil and Gas Producing
     Activities (Unaudited)...................................    52
 

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

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

In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Aviva Petroleum Inc.
and subsidiaries as of December 31, 1997 and 1996, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 1997, in conformity with generally accepted accounting
principles.





                                     /s/ KPMG Peat Marwick LLP



Dallas, Texas
February 27, 1998

                                       36
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
                          CONSOLIDATED BALANCE SHEET
                          DECEMBER 31, 1997 AND 1996
                    (in thousands, except number of shares)

 
 
                                                               1997       1996
                                                           --------  ---------
ASSETS                                                     
                                                           
Current assets:                                            
 Cash and cash equivalents                                 $    690   $  2,041
 Accounts and notes receivable (note 8):                   
   Oil and gas revenue                                        1,108      1,699
   Trade                                                        518      1,674
   Other                                                        177        377
 Inventories                                                    602        721
 Prepaid expenses and other                                     203        282
                                                           --------   --------
                                                           
   Total current assets                                       3,298      6,794
                                                           --------   --------
                                                           
Property and equipment, at cost (note 3):                  
 Oil and gas properties and equipment (full cost method)     61,036     58,324
 Other                                                          606        613
                                                           --------   --------
                                                             61,642     58,937
 Less accumulated depreciation, depletion                  
   and amortization                                         (49,873)   (23,991)
                                                           --------   --------
                                                             11,769     34,946
Other assets (note 2)                                         1,378      1,204
                                                           --------   --------
                                                           
                                                           $ 16,445   $ 42,944
                                                           ========   ========
                                                           
LIABILITIES AND STOCKHOLDERS' EQUITY                       
                                                           
Current liabilities:                                       
 Current portion of long term debt (note 3)                $    480   $  2,780
 Accounts payable                                             3,091      6,271
 Accrued liabilities                                            356        357
                                                           --------   --------
   Total current liabilities                                  3,927      9,408
                                                           --------   --------
                                                           
Long term debt, excluding current portion (note 3)            7,210      5,210
Gas balancing obligations and other (note 10)                 1,560      1,404
Deferred foreign income taxes (note 7)                            -        692
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*                                       (31,202)    (8,720)
                                                           --------   --------
                                                           
   Total stockholders' equity                                 3,748     26,230
                                                           
Commitments and contingencies (note 9)                     
                                                           --------   --------
                                                           $ 16,445   $ 42,944
                                                           ========   ========

*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, 1997, 1996 AND 1995
                     (in thousands, except per share data)
 
 
                                                       1997      1996      1995
                                                   --------   -------   -------
                                                   
Oil and gas sales (note 8)                         $  9,726   $13,750   $10,928
                                                   --------   -------   -------
                                                   
Expense:                                           
 Production                                           4,235     4,834     5,072
 Depreciation, depletion and amortization             6,067     7,339     5,755
 Write-down of oil and gas properties (note 1)       19,953         -         -
 General and administrative                           1,510     1,554     2,316
 Severance (note 6)                                       -       196         -
                                                   --------   -------   -------
                                                   
   Total expense                                     31,765    13,923    13,143
                                                   --------   -------   -------
                                                   
Other income (expense):                            
 Interest and other income (expense), net (note 4)      122     1,061       495
 Interest expense                                      (658)     (814)     (558)
 Debt refinancing expense (note 3)                        -      (100)        -
                                                   --------   -------   -------
                                                   
   Total other income (expense)                        (536)      147       (63)
                                                   --------   -------   -------
                                                   
   Loss before income taxes                         (22,575)      (26)   (2,278)
Income (taxes) benefits (note 7)                         93      (911)     (411)
                                                   --------   -------   -------
                                                   
   Net loss                                        $(22,482)  $  (937)  $(2,689)
                                                   ========   =======   =======
 

Weighted average common shares outstanding           31,483    31,483    31,483
                                                   ========   =======   =======


Basic and diluted net loss per common share        $  (0.71)  $ (0.03)  $ (0.09)
                                                   ========   =======   =======

See accompanying notes to consolidated financial statements.

                                       38
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
                     CONSOLIDATED STATEMENT OF CASH FLOWS
                 YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
                                (in thousands)
 
 
                                                    1997      1996       1995
                                                --------   -------   --------
                                                
Net loss                                        $(22,482)  $  (937)  $ (2,689)
Adjustments to reconcile net loss to            
 net cash provided by operating activities:     
 Depreciation, depletion and amortization          6,067     7,339      5,755
 Write-down of oil and gas properties             19,953         -          -
 Deferred foreign income taxes                      (692)      195         (5)
 Loss (gain) on sale of assets, net                   15      (651)         2
 Foreign currency exchange loss (gain), net           75        16       (164)
 Other                                              (217)     (253)      (168)  
 Changes in assets and liabilities:             
   Accounts and notes receivable                   1,934      (916)       767
   Inventories                                       118        88        212
   Prepaid expenses and other                         79       406         (6)
   Accounts payable and accrued liabilities       (3,119)    3,656       (843)
                                                 -------   -------   --------
                                                
     Net cash provided by operating activities     1,731     8,943      2,861
                                                 -------   -------   --------
                                                
Cash flows from investing activities:           
 Property and equipment expenditures              (2,757)   (8,667)    (7,457)
 Proceeds from sale of assets                         19     2,729         73
 Other                                                 -       (46)         -
                                                 -------   -------   --------
                                                
     Net cash used in investing activities        (2,738)   (5,984)    (7,384)
                                                 -------   -------   --------
                                                
Cash flows from financing activities:           
 Proceeds from long term debt                          -         -      7,100
 Principal payments on long term debt               (300)   (5,077)      (673)
                                                 -------   -------   --------
                                                
     Net cash provided by (used in) financing   
       activities                                   (300)   (5,077)     6,427
                                                 -------   -------   --------
                                                
Effect of exchange rate changes on cash and     
 cash equivalents                                    (44)      (41)       314
                                                 -------   -------   --------
                                                
Net increase (decrease) in cash and cash        
 equivalents                                      (1,351)   (2,159)     2,218
Cash and cash equivalents at beginning of year     2,041     4,200      1,982
                                                 -------   -------   --------
                                                
Cash and cash equivalents at end of year         $   690   $ 2,041   $  4,200
                                                 =======   =======   ========

See accompanying notes to consolidated financial statements.

                                       39
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
                 CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
                  YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
                    (in thousands, except number of shares)
 
 
                       Common Stock      
                    -------------------  Additional                   Total 
                    Number of              Paid-in    Accumulated  Stockholders'
                      Shares    Amount     Capital      Deficit       Equity
                    ----------  -------  -----------  -------------  --------
                    
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
                    
Net loss                     -        -            -        (22,482)   (22,482)
                    ----------  -------  -----------       --------   --------
                    
Balances at         
 December 31, 1997  31,482,716   $1,574      $33,376       $(31,202)  $  3,748
                    ==========  =======  ===========       ========   ========
 

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
     $127,000 in 1997, $129,000 in 1996 and $156,000 in 1995.

     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 $1,199,000 of which $814,000 has been provided through
     December 31, 1997.

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

                          1997           1996            1995
                         ------          ------          -----
 
        United States    $ 7.32          $ 5.93          $4.12
 
        Colombia         $11.59          $11.49          $9.79

     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. During 1997 the Company
     wrote down the carrying amount of its U.S. and Colombian oil and gas
     properties by $2,124,000 and $17,829,000, respectively, as a result of
     ceiling limitations on capitalized costs.

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

     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
     $251,000 and $1,066,000 were excluded from amortization at December 31,
     1997 and 1996, respectively.  Unevaluated properties are assessed quarterly
     to determine whether any impairment has occurred.  The unevaluated costs at
     December 31, 1997 represent exploration costs and were incurred primarily
     during the two-year period ended December 31, 1997. Such costs are expected
     to be evaluated and included in the amortization computation within the
     next two years.

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

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

     Gas Balancing
     The Company uses the entitlements method of accounting for gas sales. Gas
     production taken by the Company in excess of amounts entitled is recorded
     as a liability to the other joint owners. Excess gas production taken by
     others is recognized as income to the extent of the Company's proportionate
     share of the gas sold and a related receivable is recorded from the other
     joint owners.

     Interest Expense
     The Company capitalizes interest costs on qualifying assets, principally
     unevaluated oil and gas properties. During 1997, 1996 and 1995, the Company
     capitalized $91,000, $189,000 and $295,000 of interest, respectively.

     Loss Per Common Share
     The Company adopted Statement of Financial Accounting Standards No. 128
     ("SFAS 128") during the fourth quarter of 1997. Under SFAS 128, basic
     earnings per share ("EPS") is computed by dividing income available to
     common shareholders by the weighted-average number of common shares
     outstanding for the period. Diluted EPS reflects the potential dilution
     that could occur if securities or other contracts to issue common stock
     were exercised or converted into common stock or resulted in the issuance
     of common stock that then shared in the earnings of the entity. For the
     years presented herein, basic and diluted EPS are the same since the
     effects of potential common shares (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.

                                       42
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                        
     Statement of Cash Flows
     The Company considers all highly liquid debt instruments with original
     maturities of three months or less to be cash equivalents. The Company paid
     interest, net of amounts capitalized, of $641,000 in 1997, $834,000 in 1996
     and $591,000 in 1995 and paid income taxes of $212,000 in 1997, $111,000 in
     1996 and $178,000 in 1995.

     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.

(2)  OTHER ASSETS

 
     A summary of other assets follows:
                                                           December 31
                                                         ---------------
                                                           (thousands)
                                                           1997     1996
                                                         ------   ------
     Abandonment funds for U.S. offshore properties      $1,272   $  853
     Deferred financing charges                             102      225
     Other                                                    4      126
                                                         ------   ------
 
                                                         $1,378   $1,204
                                                         ======   ======

(3)  LONG TERM DEBT

     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, 1997, the borrowing base permitted, and the
     outstanding loan balance was, $7,690,000. The outstanding loan balance has
     been subject to interest at the prime rate, as defined, (8.50% at December
     31, 1997) plus 1% or, at the option of the Company, a fixed rate, based on
     the London Interbank Offered Rate ("LIBOR") plus 2.75%, for a portion or
     portions of the outstanding debt from time to time. 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.

                                       43
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     In February 1998, the Company entered into an agreement with ING Capital
     pursuant to which the outstanding loan balance was paid down to $7,440,000
     from $7,690,000, the interest rate was increased to the prime rate, as
     defined, plus 1.5%, or at the option of the Company, a fixed rate based on
     LIBOR plus 3%, and the repayment schedule was amended to require monthly
     payments of 80% of defined monthly cash flows until October 1, 1999, at
     which time the remaining balance is due and payable. Additionally, ING
     Capital reduced to $2 million the minimum amount of consolidated tangible
     net worth that the Company is required to maintain.

     The aggregate maturities of long term debt at December 31, 1997 are: 1998 -
     $480,000 and 1999 - $7,210,000.

     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:

                                                       (thousands)
                                               1997         1996     1995
                                             ------       ------   ------
     Interest income                         $  138       $  231   $  157
     Foreign currency exchange gain (loss)      (75)         (16)     164
     Gain (loss) on sale of assets, net         (15)         651       (2)
     Other, net                                  74          195      176
                                             ------       ------   ------
                                             $  122       $1,061   $  495
                                             ======       ======   ======

(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, 1997, 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):
 
                                               1997       1996      1995
                                             ---------  --------  --------
 
          Net loss          As reported      $(22,482)  $  (937)  $(2,689)
 
                            Pro forma        $(22,506)  $  (947)  $(2,805)
 
          Loss per share    As reported      $  (0.71)  $ (0.03)  $ (0.09)
 
                            Pro forma        $  (0.71)  $ (0.03)  $ (0.09)

                                       44
<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.

     At the Annual Meeting of Shareholders held on June 10, 1997, the Company's
     shareholders approved the amendment of the Current Plan. The amendment
     increased the 200,000 shares reserved for options to be awarded to non-
     employee directors to 400,000 shares. In addition, the amendment provides
     for the grant, on July 1, 1997, and on each subsequent July 1, to each non-
     employee director who has served in such capacity for at least the entire
     preceding calendar year of an option to purchase 5,000 shares of the
     Company's common stock (the "Annual Option Awards"), exercisable as to
     2,500 shares on the first anniversary of the date of grant and as to the
     remaining shares on the second anniversary thereof. Except for the vesting
     provisions relating to the Annual Options Awards, the provisions of the
     Plan relating to vesting of such options, the determination of the exercise
     prices thereof and other terms of such options remain unchanged.

     As a result of the adoption of the Current Plan, during 1995 the Company's
     former Incentive and Non-Statutory Stock Option Plan was terminated as to
     the grant of new options, but options then outstanding for 335,000 shares
     of the Company's common stock remain in effect as of December 31, 1997.

     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:

 
                                                 1997    1996    1995
                                               ------  ------  ------
                Expected life (years)            10.0     5.0     7.3
                Risk-free interest rate           6.6%    7.0%    7.0%
                Volatility                       71.0%   77.0%   77.0% 
                Dividend yield                    0.0%    0.0%    0.0%

                                       45
<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, 1997, 1996, and 1995, and changes during the years ended on
     those dates is presented below:

<TABLE>
<CAPTION>
 
                                     1997                 1996               1995
                              ------------------  ------------------  ------------------

                                       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           530  $    1.80      716  $    1.60      543  $    1.82
     Granted                       45        .52       20        .74      173        .95
     Exercised                      -          -        -          -        -          -
     Forfeited                    (25)      4.95     (206)      1.25        -          -
                              -------             -------             -------
     Outstanding at
      end of year                 550       1.53      530       1.80      716       1.60
                              =======             =======             =======
     Options exercisable
      at year-end                 445                 401                 403
     Weighted-average fair
      value of options
      granted during
      the year                $   .42             $   .50             $   .72
 
</TABLE>


     The following table summarizes information about fixed stock options
     outstanding at December 31, 1997:

<TABLE>
<CAPTION>
 
                                 Options Outstanding                      Options Exercisable
                    --------------------------------------------    ------------------------------
    Range              Number     Weighted-Avg.                       Number
     of             Outstanding    Remaining        Weighted-Avg.   Exercisable     Weighted-Avg.
Exercise Prices     at 12/31/97  Contractual Life  Exercise Price   at 12/31/97     Exercise Price
----------------    -----------  ----------------  --------------   -----------     --------------
<S>                 <C>          <C>                <C>             <C>             <C>
$ .51  to    .98        233,000      5.4  years         $ 0.85          128,667          $ 0.93
 1.08  to   2.77        295,000      4.5                  1.45          295,000            1.45
 9.08  to   9.90         21,500      0.2                  9.85           21,500            9.85
----------------    -----------                                     -----------
$ .51  to   9.90        549,500      4.7                  1.53          445,167            1.71
================    ===========                                     ===========
</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.

     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 $587,000 in
     1997, $709,000 in 1996 and $398,000 in 1995 and deferred Colombian income
     taxes (benefit) of $(692,000) in 1997, $195,000 in 1996 and $(5,000) in
     1995. Income tax expense also includes $12,000, $7,000 and $18,000 of state
     income taxes in 1997, 1996 and 1995, respectively.

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

     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, 1997 and 1996 follow:

<TABLE>
<CAPTION>
                                                                                      (thousands)
                                                                                      1997         1996
                                                                               -----------  -----------
<S>                                                                            <C>          <C>
 
         Deferred tax assets - principally net operating loss carryforwards    $    42,053  $    41,604
          Less valuation allowance                                                  42,053       36,126
                                                                               -----------  -----------
 
          Net deferred tax assets                                                        -        5,478
 
         Deferred tax liabilities - property and equipment                               -        6,170
                                                                               -----------  -----------
 
          Net deferred tax liability                                           $         -  $       692
                                                                               ===========  ===========
</TABLE>


     The valuation allowance for deferred tax assets at January 1, 1995 was
     $35,543,000. The net change in the valuation allowance was a $5,927,000
     increase in 1997, a $2,998,000 decrease in 1996 and a $3,581,000 increase
     in 1995. 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, 1997, the Company and its subsidiaries have aggregate net
     operating loss carryforwards for U.S. federal income tax purposes of
     approximately $116,000,000, expiring from 1998 through 2012, 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.

     Ecopetrol has an option to purchase all of the Company's production in
     Colombia. For the years ended December 31, 1997, 1996 and 1995, Ecopetrol
     exercised that option and sales to Ecopetrol accounted for $7,405,000
     (76.1%), $9,437,000 (68.6%) and $7,132,000 (65.3%), respectively, of the
     Company's aggregate oil and gas sales.

     For the years ended December 31, 1997, 1996 and 1995, sales to one U.S.
     purchaser accounted for $1,516,000 (15.6%), $1,609,000 (11.7%) and
     $1,422,000 (13.0%), respectively, of oil and gas sales.

(9)  COMMITMENTS AND CONTINGENCIES

     In the U.S., the Company is currently engaged in the conversion of a shutin
     well into a saltwater disposal well at its Breton Sound 31 field
     facilities. The cost to convert and equip such a well is estimated at $0.3
     million, net to the Company's interest. Additionally, the Company is
     upgrading certain equipment at its Main Pass 41 field facilities, the cost
     of which is expected to aggregate $0.1 million, net to the Company's
     interest.

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

     The Company, along with its co-owner (referred to collectively as the "Co-
     owners"), is also engaged in an ongoing development program on the Santana
     concession in Colombia. The contract obligations of the Santana concession
     have been met. The Co-owners currently anticipate, however, the
     recompletion of four existing wells, the construction of a micro-refinery
     for production of diesel fuel for the Company's operations and various
     miscellaneous projects. The Company's share of the estimated future costs
     of these development activities is approximately $0.8 million at December
     31, 1997. Failure to fund certain of these capital expenditures could,
     under either the concession agreement or joint operating agreement with the
     Company's co-owner, or both, result in the forfeiture of all or part of the
     Company's interest in this concession.

     The Company's aggregate remaining estimated development expenditures for
     1998 and 1999 were $1.2 million at December 31, 1997. Any substantial
     increases in the amounts of the above referenced expenditures could
     adversely affect the Company's ability to meet these obligations.

     The Company plans to fund these development activities using cash provided
     from operations. Risks that could adversely affect funding of such
     activities include, among others, a decrease in the Company's borrowing
     base, delays in obtaining the required environmental approvals and permits,
     cost overruns, failure to produce the reserves as projected or a further
     decline in the sales price of oil. Depending on the results of future
     exploration and development activities, substantial expenditures which have
     not been included in the Company's cash flow projections may be required.

     The Company's internal projections of its consolidated cash flow indicate
     that the Company's consolidated cash flow and working capital will be
     adequate to fund both the estimated development expenditures for 1998 and
     1999 and the monthly debt service relating to the ING Capital credit
     agreement as amended in February 1998. The Company does not, however
     project that, at current levels, its cash flows will be sufficient to repay
     the remaining balance under the ING Capital credit agreement that will be
     due and payable on October 1, 1999. Accordingly, the Company may be
     required to further extend the maturity of the debt or raise additional
     capital through equity issues or by sales of assets to retire the debt. The
     ultimate outcome of these matters cannot be projected with certainty.

     The aforementioned internal cash flow projections assume crude oil prices
     of $11.56 per barrel for Colombian production and $13.89 per barrel for
     U.S. production and natural gas sales prices of $2.25 per MCF for U.S.
     production. These prices are indicative of the prices the Company expects
     to receive for its production in March 1998. These prices are substantially
     lower than the prices prevailing at December 31, 1997, which were used in
     the Company's yearend ceiling limitation test for capitalized costs. If
     prices remain at current levels and do not recover substantially prior to
     the issuance of the Company's financial statements for the first quarter of
     1998, the Company expects that it will incur additional ceiling test write-
     downs for both its U.S. and Colombian cost centers that, in the aggregate,
     will have a significant adverse effect on the Company's results of
     operations and could result in the elimination of the Company's net equity.
     Moreover, such write-downs could result in the Company's failure to
     maintain the minimum consolidated tangible net worth of $2 million required
     by the latest amendment to the Company's credit agreement with ING Capital.
     In the past, ING Capital has amended or waived compliance with the
     Company's minimum consolidated tangible net worth covenant when the Company
     has been unable to meet such requirements. There can be no assurance,
     however, that ING Capital will continue to make similar concessions in the
     future.

     Under the terms of the contracts with Ecopetrol, 25% of all revenues from
     oil sold to Ecopetrol is paid in Colombian pesos which may only be utilized
     in Colombia. To date, the Company has experienced no difficulty in
     repatriating the remaining 75% of such payments, which are payable in U.S.
     dollars.
 
     Activities of the Company with respect to the exploration, development and
     production of oil and natural gas are subject to stringent foreign,
     federal, state and local environmental laws and regulations, including but
     not limited to the Oil Pollution Act of 1990, the Outer Continental Shelf
     Lands Act, the Federal Water Pollution Control Act, the Resource
     Conservation and Recovery Act and the Comprehensive Environmental Response,
     Compensation, and Liability Act. Such laws and regulations have increased
     the cost of planning, designing, drilling, operating and abandoning wells.
     In most instances, the statutory and regulatory requirements relate to air
     and water pollution control procedures and the handling and disposal of
     drilling and production wastes.

                                       48
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     Although the Company believes that compliance with environmental laws and
     regulations will not have a material adverse effect on the Company's
     operations or earnings, risks of substantial costs and liabilities are
     inherent in oil and gas operations and there can be no assurance that
     significant costs and liabilities, including civil or criminal penalties
     for violations of environmental laws and regulations, will not be incurred.
     Moreover, it is possible that other developments, such as stricter
     environmental laws and regulations or claims for damages to property or
     persons resulting from the Company's operations, could result in
     substantial costs and liabilities. The Company's policy is to accrue
     environmental and restoration related costs once it is probable that a
     liability has been incurred and the amount can be reasonably estimated.

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

     The Company has one lease for office space in Dallas, Texas, which expires
     in January 1999. Rent expense relating to the lease was $83,000, $84,000
     and $90,000 for 1997, 1996 and 1995, respectively. Future minimum payments
     under the lease are $83,000, primarily due in 1998.

(10) GAS BALANCING

     As of December 31, 1997 and 1996, other joint owners had sold net gas with
     a volume equivalent of approximately 2,000 thousand cubic feet ("MCF")
     (with an estimated value of $4,000 included in other assets), for which the
     Company is generally entitled to be repaid in volumes ("underproduced"). As
     of December 31, 1997 and 1996, the Company had sold net gas with a volume
     equivalent of approximately 458,000 MCF and 353,000 MCF (with an estimated
     value of $748,000 and $724,000 included in gas balancing obligations and
     other), respectively, for which the other joint owners are entitled
     generally to be repaid in volumes ("overproduced"). In certain instances
     the parties have the option of requesting payment in cash.

     In connection with the sale of the Company's U.S. onshore properties in
     December 1996, approximately 384,000 MCF for which the Company was
     underproduced and approximately 337,000 MCF for which the Company was
     overproduced were assumed by the buyer of such properties.

     In 1997, the Company reacquired from the aforementioned buyer approximately
     196,000 MCF for which the Company was overproduced for $98,000 in cash.

                                       49
<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, 1997, 1996 and 1995 follows:

<TABLE>
<CAPTION>
 
(Thousands)
                                                             United
                                                             States          Colombia          Total
                                                           --------        ----------       --------
<S>                                                        <C>             <C>              <C>
     1997
     ----
     Oil and gas sales                                     $  2,321        $    7,405       $  9,726
                                                           --------        ----------       --------
     Expense:
      Production                                              1,262             2,973          4,235
      Depreciation, depletion and amortization                1,009             5,058          6,067
      Write-down of oil and gas properties                    2,124            17,829         19,953 
      General and administrative                              1,499                11          1,510
                                                           --------        ----------       --------
                                                              5,894            25,871         31,765
                                                           --------        ----------       --------
 
     Interest and other income (expense), net                    92                30            122
     Interest expense                                          (399)             (259)          (658)
                                                           --------        ----------       --------

     Loss before income taxes                                (3,880)          (18,695)       (22,575)
     Income (taxes) benefit                                     (12)              105             93
                                                           --------        ----------       --------

     Net loss                                              $ (3,892)       $  (18,590)      $(22,482)
                                                           ========        ==========       ========

     Identifiable assets                                   $  3,789        $   11,966       $ 15,755
                                                           ========        ==========       
     Corporate assets-cash and cash equivalents                                                  690
                                                                                            --------

     Total assets                                                                           $ 16,445
                                                                                            ========
</TABLE>

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

<TABLE>
<CAPTION>
 
(Thousands)
                                                             United
                                                             States          Colombia          Total
                                                           --------        ----------       --------
<S>                                                        <C>             <C>              <C>
     1996
     ----
     Oil and gas sales                                     $  4,313        $    9,437       $ 13,750
                                                           --------        ----------       -------- 
                                                                                    
     Expense:                                                                       
      Production                                              1,926             2,908          4,834
      Depreciation, depletion and amortization                1,750             5,589          7,339
      General and administrative                              1,539                15          1,554
      Severance                                                 196                 -            196
                                                           --------        ----------       --------  
                                                              5,411             8,512         13,923
                                                           --------        ----------       --------  

     Interest and other income (expense), net                   894               167          1,061
     Interest expense                                          (355)             (459)          (814)
     Debt refinancing expense                                     -              (100)          (100)
                                                           --------        ----------       --------  
                                                                                      
     Income (loss) before income taxes                         (559)              533            (26)
     Income taxes                                                (7)             (904)          (911)
                                                           --------        ----------       --------   

     Net loss                                              $   (566)       $     (371)      $   (937)
                                                           ========        ==========       ======== 
                                                                                      
     Identifiable assets                                   $  6,838        $   34,065       $ 40,903
                                                           ========        ==========       
                                                                                     
     Corporate assets-cash and cash equivalents                                                2,041
                                                                                            --------
                                                                                      
     Total assets                                                                           $ 42,944
                                                                                            ========
                                                                                      
     1995                                                                           
     ----                                                                           
     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
                                                                                            ========
  </TABLE>

                                       51
<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:

(Thousands)
                                         United
                                         States     Colombia        Total
                                       --------   ----------     --------
December 31, 1997
-----------------
 
Unevaluated oil and gas properties     $    142     $    109      $   251
Proved oil and gas properties            12,075       48,710       60,785
                                       --------     --------      -------
 
 Total capitalized costs                 12,217       48,819       61,036
 
Less accumulated depreciation
  depletion and amortization             10,622       38,725       49,347
                                       --------     --------      -------
 
 Capitalized costs, net                $  1,595     $ 10,094      $11,689
                                       ========     ========      =======
 
 
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
                                       ========     ========      =======
 

                                       52
<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:
 
(Thousands)
                           United
                           States   Colombia   Total
                          -------  ---------  ------
1997
----
 
Exploration               $    25  $     470  $  495
Development                   176      2,085   2,261
                          -------  ---------  ------ 
 Total costs incurred     $   201  $   2,555  $2,756
                          =======  =========  ====== 
                          
                          
                          
1996                      
----
                          
Exploration               $     -  $   1,382  $1,382
Development                 3,239      4,030   7,269
                          -------  ---------  ------  
 Total costs incurred     $ 3,239  $   5,412  $8,651
                          =======  =========  ====== 
                          
                          
                          
1995                      
----
                          
Exploration               $     -  $   1,477  $1,477
Development                   172      5,784   5,956
                          -------  ---------  ------  
 Total costs incurred     $   172  $   7,261  $7,433
                          =======  =========  ====== 
 

                                       53
<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, 1997
----------------------------
 
Oil (Thousands of barrels)
Proved reserves:
 Beginning of period                                 305              2,817             3,122
 Revisions of previous estimates                     (34)              (915)             (949)
 Production                                          (76)              (426)             (502)
                                             -----------       ------------        ----------
 
 End of period                                       195              1,476             1,671
                                             ===========       ============        ==========
 
Proved developed reserves, end of period             195              1,476             1,671
                                             ===========       ============        ========== 
 
 
Gas (Millions of cubic feet)
Proved reserves:
 Beginning of period                               1,682                  -             1,682
 Revisions of previous estimates                    (247)                 -              (247)
 Production                                         (316)                 -              (316)
                                             -----------       ------------        ----------
 
 End of period                                     1,119                  -             1,119
                                             ===========       ============        ==========
 
Proved developed reserves, end of period           1,119                  -             1,119
                                             ===========       ============        ==========
</TABLE>

                                       54
<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, 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>

                                       55
<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>

                                       56
<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, 1997:
--------------------
 
Future gross revenues                    $ 6,009    $21,124   $ 27,133
Future production costs                   (3,548)    (7,709)   (11,257)
Future development costs                    (970)      (555)    (1,525)
                                         -------    -------   --------
Future net cash flows before
income taxes                               1,491     12,860     14,351
Future income taxes                            -          -          -
                                         -------    -------   --------
Future net cash flows after
income taxes                               1,491     12,860     14,351
 
Discount at 10% per annum                    (38)    (2,893)    (2,931)
                                         -------    -------   --------
Standardized measure of discounted
future net cash flows                    $ 1,453    $ 9,967   $ 11,420
                                         =======    =======   ========
</TABLE>

                                       57
<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, 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
                                        ========   ========   ========
 
 
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
                                        ========   ========   ========
</TABLE>

                                       58
<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)
                                                     1997      1996      1995
                                                 --------  --------  --------
<S>                                              <C>        <C>       <C>
 
Sales of oil and gas, net of production costs    $ (5,491)  $(8,916)  $(5,856)
Sales of reserves in place                              -    (3,924)      (44)
Development costs incurred that reduced
 future development costs                             801     3,043     3,713
Accretion of discount                               4,547     3,577     4,009
Discoveries and extensions                              -        87     4,521
Revisions of previous estimates:
 Changes in price                                 (24,154)   13,468     2,263
 Changes in quantities                             (7,054)      153    (7,582)
 Changes in future development costs                1,175       (86)     (723)
 Changes in timing and other changes               (3,878)    2,303    (4,623)
 Changes in estimated income taxes                    874      (540)    2,248
                                                 --------   -------   -------
 
 Net increase (decrease)                          (33,180)    9,165    (2,074)
 
Balances at beginning of year                      44,600    35,435    37,509
                                                 --------   -------   -------
 
Balances at end of year                          $ 11,420   $44,600   $35,435
                                                 ========   =======   =======
 
</TABLE>

                                       59
<PAGE>
 
                               INDEX TO EXHIBITS
<TABLE>
<CAPTION> 
                                                                              Sequentially
                                                                              Numbered
Number                          Description of Exhibit                           Page
------                          ----------------------                        ------------
<S>      <C>                                                                  <C>  
 *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
         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 Form10, File No. 0-22258, and
         incorporated  herein by reference).

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

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

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

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

*10.9    Purchase Sale - Transportation and Commercialization of the Santana
         Crude between Ecopetrol, Argosy and Neo (filed as exhibit 10.9 to the
         Company's Registration Statement on Form10, File No. 0-22258, and
         incorporated herein by reference).

*10.10   La Fragua Association Contract dated June 1, 1992
         between Ecopetrol, Argosy and Neo (filed as exhibit 10.10 to the
         Company's Registration Statement on Form10, File No. 0-22258, and
         incorporated herein by reference).

*10.11   Operating Agreement for the La Fragua Area between Argosy and Neo
         dated April 15, 1992 (filed as exhibit 10.11 to the Company's
         Registration Statement on Form10, File No. 0-22258, and incorporated
         herein by reference).

*10.12   Employment Agreement between the Company and Ronald Suttill dated
         November 29, 1991 (filed as exhibit 10.12 to the Company's Registration
         Statement on Form10, File No. 0-22258, and incorporated herein by
         reference).

*10.13   Employee Stock Option Plan of the Company (filed as exhibit 10.13
         to the Company's Registration Statement on Form10, File No. 0-22258,
         and incorporated herein by reference).

</TABLE> 
<PAGE>
 
<TABLE>
<CAPTION> 
                                                                              Sequentially
                                                                              Numbered
Number                          Description of Exhibit                           Page
------                          ----------------------                        ------------
<S>      <C>                                                                  <C>  
*10.14   Letter agreement dated January 6, 1993 between NationsBank
         Investment Banking and the Company (filed as exhibit 10.14 to the
         Company's Registration Statement on Form10, File No. 0-22258, and
         incorporated herein by reference).

*10.15   Letter agreement dated March 3, 1993 between EnCap Investments L.C.
         and the Company (filed as exhibit 10.15 to the Company's Registration
         Statement on Form10, File No. 0-22258, and incorporated herein by
         reference).

*10.16   Credit Agreement dated August 6, 1993 between the Company, Aviva
         America, Inc. ("Aviva America"), Neo and Internationale Nederlanden
         Bank N.V., New York Branch ("ING Capital") (filed as exhibit 10.16 to
         the Company's Registration Statement on Form10, File No. 0-22258, and
         incorporated herein by reference).

*10.17   Subordination Agreement dated August 6, 1993 between the Company,
         Aviva America, Aviva Operating Company ("Aviva Operating"), Neo and ING
         Capital (filed as exhibit 10.17 to the Company's Registration Statement
         on Form10, File No. 0-22258, and incorporated herein by reference).

*10.18   Stock Pledge Agreement dated August 6, 1993 between the Company and
         ING Capital (filed as exhibit 10.18 to the Company's Registration
         Statement on Form10, File No. 0-22258, and incorporated herein by
         reference).

*10.19   Stock Pledge Agreement dated August 6, 1993 between Aviva America
         and ING Capital (filed as exhibit 10.19 to the Company's Registration
         Statement on Form10, File No. 0-22258, and incorporated herein by
         reference).

*10.20   Guaranty dated August 6, 1993 made by the Company in favor of ING
         Capital (filed as exhibit 10.20 to the Company's Registration Statement
         on Form10, File No. 0-22258, and incorporated herein by reference).

*10.21   Guaranty dated August 6, 1993 made by Aviva America in favor of ING
         Capital (filed as exhibit 10.21 to the Company's Registration Statement
         on Form10, File No. 0-22258, and incorporated herein by reference).

*10.22   Guaranty dated August 6, 1993 made by Aviva Operating in favor of
         ING Capital (filed as exhibit 10.22 to the Company's Registration
         Statement on Form10, File No. 0-22258, and incorporated herein by
         reference).

*10.23   Form of Subscription Agreement dated June 18, 1993 between the
         Company and purchasers of 12,884,207 shares of common stock
         ("Purchasers") (filed as exhibit 10.23 to the Company's Registration
         Statement on Form10, File No. 0-22258, and incorporated herein by
         reference).

*10.24   Option Agreement between RBS and Aviva Energy Inc. ("Aviva Energy")
         dated July 1, 1993 (filed as exhibit 10.24 to the Company's
         Registration Statement on Form10, File No. 0-22258, and incorporated
         herein by reference).

*10.25   Option Agreement between Aviva Energy and Purchasers dated July 1,
         1993 (filed as exhibit 10.25 to the Company's Registration Statement on
         Form10, File No. 0-22258, and incorporated herein by reference).

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

*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).

</TABLE> 
<PAGE>
 
<TABLE>
<CAPTION> 
                                                                              Sequentially
                                                                              Numbered
Number                          Description of Exhibit                           Page
------                          ----------------------                        ------------
<S>      <C>                                                                  <C>  

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

*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).

</TABLE> 
<PAGE>
 
<TABLE>
<CAPTION> 
                                                                              Sequentially
                                                                              Numbered
Number                          Description of Exhibit                           Page
------                          ----------------------                        ------------
<S>      <C>                                                                  <C>  

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

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

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

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

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

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

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

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

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

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

*10.57   Amendment to the ING Capital Credit Agreement dated November 22,
         1996 (filed as exhibit 10.57 to the Company's annual report on Form 10-
         K for the year ended December 31, 1996, File No. 0-22258, and
         incorporated herein by reference).

*10.58   Purchase and Sale Agreement dated November 22, 1996 between BWAB
         Incorporated and Aviva America (filed as exhibit 10.58 to the Company's
         annual report on Form 10-K for the year ended December 31, 1996, File
         No. 0-22258, and incorporated herein by reference).

*10.59   Purchase and Sale Agreement dated December 6, 1996 between Lomak
         Petroleum Inc. and Aviva America (filed as exhibit 10.59 to the
         Company's annual report on Form 10-K for the year ended December 31,
         1996, File No. 0-22258, and incorporated herein by reference).

*10.60   Santana Crude Sale and Purchase Agreement dated February 10, 1997
         (filed as exhibit 10.60 to the Company's annual report on Form 10-K for
         the year ended December 31, 1996, File No. 0-22258, and incorporated
         herein by reference).

*10.61   Aviva Petroleum Inc. 1995 Stock Option Plan, as amended (filed as
         Appendix A to the Company's definitive Proxy Statement for the Annual
         Meeting of Shareholders dated June 10, 1997, and incorporated herein by
         reference).

*10.62   Amendment to the ING Capital Credit Agreement dated August 12, 1997
         (filed as exhibit 10.2 to the Company's quarterly report on Form 10-Q
         for the quarter ended June 30, 1997, File No. 0-22258, and incorporated
         herein by reference).

</TABLE> 
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*10.63   Amended and Restated Aviva Petroleum Inc. Severance Benefit Plan
         dated September 30, 1997 (filed as exhibit 10.3 to the Company's
         quarterly report on Form 10-Q for the quarter ended September 30, 1997,
         File No. 0-22258, and incorporated herein by reference).
**10.64  Amendment to the ING Capital Credit Agreement dated December 29,
         1997.
**10.65  Amendment to the Santana Crude Sale and Purchase Agreement dated
         January 5, 1998.
**10.66  Amendment to the ING Capital Credit Agreement dated February 13,
         1998.
 *21.1   List of subsidiaries of Aviva Petroleum Inc.
**27.1   Financial Data Schedule.
</TABLE> 
 
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*   Previously Filed
**  Filed Herewith