<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, 1999
                                          ------------------------

                                      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

*The Company's Depositary Shares were delisted by the American Stock Exchange
effective as of April 9, 1999.

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 29, 2000 was approximately $545,000.
As of such date, the last sale price of a Depositary Share representing five
shares of Common Stock, without par value ("Common Stock"), was U.S. $0.0625, as
quoted on the OTC Bulletin Board.

As of February 29, 2000, 46,900,132 shares of Registrant's Common Stock were
outstanding, of which 25,483,690 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

  Important Information - Going Concern Risk..............................  1
  Item 1.  Business
               General....................................................  1
               Garnet Merger..............................................  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.............................................. 12
               Papua New Guinea........................................... 12
  Item 3.  Legal Proceedings.............................................. 13
  Item 4.  Submission of Matters to a Vote of Security Holders............ 13

Part II

  Item 5.  Market for Registrant's Common Equity and Related
               Stockholder Matters
               Price Range of Depositary Shares and Common Stock.......... 14
               Dividend History and Restrictions.......................... 15
  Item 6.  Selected Financial Data........................................ 16
  Item 7.  Management's Discussion and Analysis of Financial
               Condition and Results of Operations
               Results of Operations...................................... 17
               Year 2000.................................................. 19
               New Accounting Pronouncements.............................. 19
               Liquidity and Capital Resources............................ 19
  Item 7A. Quantitative and Qualitative Disclosure about Market Risk...... 21
  Item 8.  Financial Statements and Supplementary Data.................... 21
  Item 9.  Changes in and Disagreements with Accountants on Accounting
               and Financial Disclosure................................... 21
Part III

  Item 10. Directors and Executive Officers of the Registrant
            Directors of the Company...................................... 22
            Executive Officers of the Company............................. 22
            Meetings and Committees of the Board of Directors............. 23
            Compliance with Section 16(a) of the Securities
               Exchange Act of 1934....................................... 23
  Item 11. Executive Compensation
               Summary Compensation Table................................. 24
               Directors' Fees............................................ 24
               Option Grants During 1999.................................. 24
               Option Exercises During 1999 and Year End
               Option Values.............................................. 24

                                      (i)
<PAGE>

                  TABLE OF CONTENTS TO FORM 10-K (Continued)

                                                                          Page
                                                                          ----
               Compensation Committee Interlocks and Insider Participation
                  in Compensation Decisions............................... 25
               Employment Contracts....................................... 25
               Compensation Committee Report on Executive Compensation.... 25
               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................................................................ 31


                                      (ii)
<PAGE>

                                    PART I


                             IMPORTANT INFORMATION
                              GOING CONCERN RISK

  If the Company is unable to consummate the debt restructuring discussed
herein, then, in the absence of another business transaction or debt
restructuring, the Company cannot achieve compliance with or make principal
payments required by its bank credit facilities and, accordingly, the lenders
could declare a default, accelerate all amounts outstanding and attempt to
realize upon the collateral securing the debt (which comprises substantially all
the Company's assets).  As a result of this uncertainty, management believes
there is substantial doubt about the Company's ability to continue as a going
concern.  See "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations - - Liquidity and Capital Resources" and
Note 2 of the Notes to Consolidated Financial Statements contained elsewhere
herein.

ITEM 1. BUSINESS


General

  Aviva Petroleum Inc. (referred to collectively with its consolidated
subsidiaries as the "Company"), a Texas corporation, through its subsidiaries,
is engaged in the exploration for and production and development of oil and gas
in Colombia, offshore in the United States, and in Papua New Guinea. The Company
was incorporated in 1973 and the common stock, without par value ("Common
Stock"), of the Company was traded on the London Stock Exchange Limited (the
"London Stock Exchange") from 1982 to 1999.  On May 6, 1999, trading of the
Common Stock was suspended on the London Stock Exchange due to the Company's
financial difficulties.  Depositary shares ("Depositary Shares"), each
representing the beneficial ownership of five shares of Common Stock, trade on
the OTC Bulletin Board under the symbol "AVVPP.OB."   The Company's principal
executive offices are located in Dallas, Texas, and the Company maintains a
regional office in Bogota, Colombia.

Garnet Merger

  On October 28, 1998, the Company acquired Garnet Resources Corporation
("Garnet") in exchange for the issuance, in the aggregate, of approximately 14
million shares of the Company's Common Stock.  Pursuant to the Agreement and
Plan of Merger dated as of June 24, 1998, an indirect, wholly owned subsidiary
of the Company was merged with and into Garnet.  Garnet's $15 million of 9 1/2%
Convertible Subordinated Debentures were acquired and canceled, and the
outstanding bank debt of Garnet and the Company was refinanced under a $15
million credit facility.  As a result of the merger, the Company has been able
to effect cost savings, particularly in Colombia where each company had an
interest in the same properties.

Current Operations

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

  The Company's Colombian activities have been carried out by the Company's
wholly owned subsidiary, Neo Energy, Inc. ("Neo"), and Argosy Energy
International ("Argosy"), which operates the Colombian properties and is a
subsidiary of Garnet.  Prior to December 31, 1998, Neo had a 45% interest and
Argosy had the remaining 55% interest in the contracts.  Effective December 31,
1998, the net assets of Neo were transferred into Argosy.  Argosy is currently
party to two contracts with Ecopetrol called Santana and Aporte Putumayo.  Both
contract areas are located in the Putumayo Basin of southwestern Colombia.  The
Company's exploration and development activities are currently concentrated in
the Santana contract area.

  Twenty-one wells have been drilled on the Santana concession.  Of 13
exploratory wells, seven have been productive and six were dry holes. Of eight
development wells, seven have been productive.  Four fields have been discovered
and have been declared commercial by Ecopetrol.  Gross production from the
Santana concession has

                                       1
<PAGE>

totaled approximately 15.5 million barrels during the period from April 1992,
when production commenced, through December 1999.

  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.
Ecopetrol has accepted the Company's request for relinquishment, which is
pending 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.  Both 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, Argosy has the right to proceed with development and production at
its own expense until such time as it has recovered 200% of the costs incurred,
at which time Ecopetrol is entitled to back in for a 50% working interest in the
field without payment or reimbursement of any historical costs. Exploration
costs (as defined in the contracts) incurred by Argosy prior to the declaration
of commerciality are recovered by means of retention by Argosy of 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 Breton Sound 31 field.  Effective January 1, 1999, the Company
relinquished operatorship of Main Pass 41 field.  The Company acquired its
interests in these fields through the acquisition of Charterhall Oil North
America PLC in 1990.

  Papua New Guinea.     In Papua New Guinea the Company, through its wholly
  ----------------
owned subsidiary, Garnet PNG Corporation ("Garnet PNG"), is engaged in the
exploration for oil and gas attributable to its 2% carried working interest in
Petroleum Prospecting License No. 206 ("PPL-206").  The Company acquired Garnet
PNG as part of the merger with Garnet.  See "-- Garnet Merger. "

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 may
expend additional capital for further exploration and development of such
properties. Even if the results of such activities are favorable, further
drilling at significant costs may be required to determine the extent of and to
produce the recoverable reserves.  Failure to fund certain 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."

  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

                                       2
<PAGE>

claims, expropriation, adverse changes in currency values, foreign exchange
controls, import and export regulations, environmental controls and other laws,
regulations or international developments that may adversely affect the
Company's properties. The Company does not maintain political risk insurance.

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

  There are logistical problems, costs and risks in conducting oil and gas
activities in remote, rugged and primitive regions in Colombia.  The Company's
operations are also exposed to potentially detrimental activities by the leftist
guerrillas who have operated within Colombia for many years.  The guerrillas in
the Putumayo area, where the Company's property is located, have as recently as
August 3, 1998, significantly damaged the Company's assets.  Although the
Company's losses were 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 significant 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 12 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 a sales contract with
  --------
Ecopetrol.  The contract provides for cancellation by either party with notice.
In the event of cancellation by Ecopetrol, the Company may export its oil
production.    Ecopetrol has historically purchased the Company's production,
but there can be no assurance that it will continue to do so, nor can there be
any assurance of ready markets for the Colombian production if Ecopetrol does
not elect to purchase the production.  The Company currently produces no natural
gas in Colombia.  See "Item 2.  Properties."

  During each of the three years ended December 31, 1999, the Company received
the majority of its revenue from Ecopetrol.  Sales to Ecopetrol accounted for
$5,683,000, or 84% of oil and gas revenue for 1999, $2,632,000, or 79.0% of oil
and gas revenue for 1998 and $7,405,000, or 76.1% of oil and gas revenue for
1997.  The foregoing amounts represent the Company's entire Colombian oil
revenue.  If Ecopetrol were to elect not to purchase the Company's Colombian oil
production, the Company believes that other purchasers could be found for such
production.

  United States.   The Company does not refine or otherwise process domestic
  -------------
crude oil and condensate production.  The domestic oil and condensate it
produces are sold to 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 1998 and 1997, the Company received more than 10% of its revenue from
one domestic purchaser.  Such revenue accounted for $479,000, or 14.4% of oil
and gas revenue for 1998 and $1,516,000, or 15.6% of oil and gas revenue for
1997.  During 1999, the Company did not receive more than 10% of its revenue
from any one domestic purchaser.

  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. It is possible that under market
conditions prevailing in the future, the production and sale of oil or gas, if
any, from the Company's properties in Papua New Guinea may not be commercially
feasible. The availability of a ready market and the prices received for oil and
gas produced depend upon numerous factors beyond the control of the Company
including, without limitation, adequate transportation facilities (such as
pipelines), marketing of competitive fuels, fluctuating market demand,
governmental regulation and world political and economic developments. World oil
and gas markets are highly volatile and shortage or surplus conditions
substantially affect prices. As a result, there have been dramatic swings in
both oil and gas prices in recent years. From time to time there may exist a
surplus of oil or natural gas supplies, the effect of which may be to reduce the
amount or price of hydrocarbons that the Company may produce and sell while such
surplus exists.

Regulation

  Environmental Regulation.  The Company's operations are subject to foreign,
  ------------------------
federal, state, and local laws and regulations governing the discharge of
materials into the environment or otherwise relating to environmental
protection.  These laws and regulations may require the acquisition of a permit
by operators before drilling commences; restrict the types, quantities, and
concentration of various substances that can be released into the environment in
connection with drilling and production activities; limit or prohibit drilling
activities on certain lands lying within wilderness areas, wetlands, and other
protected areas; require remedial measures to mitigate pollution from former
operations, such as plugging and abandoning wells; and impose substantial
liabilities for pollution resulting from the Company's operations.  The
regulatory burden on the oil and gas industry increases the cost of doing
business and consequently affects its profitability.  Changes in environmental
laws and regulations occur frequently, and any revision or reinterpretation of
existing laws and regulations or adoption of new laws and regulations that
result in more stringent and costly waste handling, disposal, remedial,
drilling, permitting, or operational requirements could have a material adverse
impact on the operating costs of the Company, as well as significantly impair
the Company's ability to compete with larger, more highly capitalized companies.
Management believes that the Company is in substantial compliance with current
applicable environmental laws and regulations and that continued compliance with
existing requirements will not have a material adverse impact on the Company's
operations, capital expenditures, and earnings.  Management further believes,
however, that risks of substantial costs and liabilities are inherent in oil and
gas operations, and there can be no assurance that significant costs and
liabilities, including administrative, civil and 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 for
a period of approximately 10 months in 1994 pending review and approval of
additional environmental studies submitted by the Company. Since the lifting of
the above referenced suspension, the Company has received subsequent permits,
without substantial delay. 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.  Over the past few years, the Company has
incurred significant costs to make capital improvements, including the drilling
and completion of a salt water injection well at Breton Sound 31 field and the
upgrading and modification of production and water treatment facilities at Main
Pass 41 field, in order to maintain compliance with these U.S. environmental
laws or regulations.  There can be no assurance that the Company will not expend
additional significant amounts in the future to maintain such compliance.

  The Oil Pollution Act of 1990, as amended ("OPA '90"), and regulations
thereunder impose a variety of requirements on "responsible parties" related to
the prevention of oil spills and liability for damages resulting from

                                       4
<PAGE>

such spills in waters of the United States. A "responsible party" includes the
owner or operator of a vessel, pipeline, or onshore facility, or the lessee or
permittee of the area in which an offshore facility is located. OPA '90 assigns
liability to each responsible party for oil spill removal costs and a variety of
public and private damages from oil spills. While liability limits apply in some
circumstances, a party cannot take advantage of liability limits if the spill is
caused by gross negligence or willful misconduct, the spill resulted from
violation of a federal safety, construction, or operating regulation, or a party
fails to report a spill or to cooperate fully in the cleanup. Few defenses exist
to the liability imposed under OPA '90 for oil spills. The failure to comply
with these requirements or inadequate cooperation in a spill event may subject a
responsible party to civil or criminal enforcement actions. Management of the
Company is currently unaware of any oil spills for which the Company has been
designated as a responsible party under OPA '90 and that will have a material
adverse impact on the Company or its operations. OPA '90 also imposes ongoing
requirements on facility operators, such as the preparation of an oil spill
contingency plan. The Company has such plans in place.

  The Company's 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.
Under OPA '90 and a final rule adopted by the U.S. Minerals Management Service
("MMS") in August 1998, owners and operators of covered offshore facilities that
have a worst case oil spill of more than 1,000 barrels must demonstrate
financial responsibility in amounts ranging from $10 million in specified state
waters to $35 million in federal outer continental shelf waters, with higher
amounts of up to $150 million in certain limited circumstances where the MMS
believes such a level is justified by the risks posed by operations at such
covered offshore facilities or if the worst case oil-spill discharge volumes
possible at such facilities may exceed the applicable threshold volumes
specified under the MMS final rule.  The Company believes that it currently has
established adequate proof of financial responsibility for its covered offshore
facilities.  However, the Company cannot predict whether these financial
responsibility requirements under the OPA '90 amendments or the final rule will
result in the imposition of significant additional annual costs to the Company
in the future or otherwise have a material adverse effect on the Company.  The
impact of financial responsibility requirements is not expected to be any more
burdensome to the Company than it will be to other similarly or less capitalized
owners or operators in the Gulf of Mexico.

  The 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. 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.  In connection with the issuance of these
regulations by the EPA, and following various extensions granted by the LDEQ,
the Company drilled and completed a saltwater injection well at the Breton Sound
Block 31 facilities in October 1998.

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

                                       5
<PAGE>

  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.  The heavy and increasing regulatory burdens on
the oil and gas industry increase the costs of doing business and, consequently,
affect profitability.

  Historically, the transportation and sale for resale of natural gas in
interstate commerce have been regulated pursuant to the Natural Gas Act of 1938
("NGA"), the Natural Gas Policy Act of 1978 ("NGPA") and the regulations
promulgated thereunder by the Federal Energy Regulatory Commission ("FERC").  In
the past, the federal government has regulated the prices at which gas could be
sold.  In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which
removed all NGA and NGPA price and non-price controls affecting wellhead sales
of natural gas effective January 1, 1993.  Congress could, however, 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 FERC
from 1985 to the present that affect the economics of natural gas production,
transportation and sales.  In addition, the FERC is continually proposing and
implementing new 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.

  For example, the FERC recently issued Order No. 637, which, among other
things, (i) lifts the cost-based cap on pipeline transportation rates in the
capacity release market until September 30, 2002, for releases of pipeline
capacity of less than one year, (ii) permits pipelines to charge different
maximum cost-based rates for peak and off-peak times, (iii) encourages auctions
for pipeline capacity, (iv) requires pipelines to implement imbalance management
services, (v) restricts the ability of pipelines to impose penalties for
imbalances, overruns, and non-compliance with operational flow orders, and (vi)
implements a number of new pipeline reporting requirements.  Order No. 637 also
requires the FERC Staff to analyze whether the FERC should implement additional
fundamental policy changes, including, among other things, whether to pursue
performance-based ratemaking or other non-cost based ratemaking techniques and
whether the FERC should mandate greater standardization in terms and conditions
of service across the interstate pipeline grid.  In addition, the FERC recently
implemented new regulations governing the procedure for obtaining authorization
to construct new pipeline facilities and has issued a policy statement, which it
largely affirmed in a recent order on rehearing, establishing a presumption in
favor of requiring owners of new pipeline facilities to charge rates based
solely on the costs associated with such new pipeline facilities.

                                       6
<PAGE>

  The Company cannot predict what further action the FERC will take on these
matters.  However, some of the FERC's more recent proposals may adversely affect
the availability and reliability of interruptible transportation service on
interstate pipelines.  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.

  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 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 proposal 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 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.

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

  The Company cannot accurately predict the effect that any of the
aforementioned orders or the challenges to the orders will have on the Company's
operations.  Additional proposals and proceedings that might affect the oil and
natural gas industries are pending before Congress, the FERC and the courts.
The Company cannot accurately predict when or whether any such proposals or
proceedings may become effective.

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

  The Company's operations are also subject to various conservation laws and
regulations including the regulation of the size of drilling and spacing units
or proration units, the density of wells that may be drilled, and the
unitization or pooling of oil and gas properties.  In addition, state
conservation laws establish maximum rates of production from oil and natural gas
wells, generally prohibit the venting or flaring of natural gas, and impose
certain requirements regarding the ratability of production.  The effect of
these regulations may limit the amount of oil and natural gas

                                       7
<PAGE>

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.

  Other Regulations - Papua New Guinea.     The Company's operations in Papua
  ------------------------------------
New Guinea are currently governed by the Department of Petroleum and Energy,
which has jurisdiction over all petroleum exploration in that country.  In the
event the Company develops and operates a petroleum business in Papua New
Guinea, the Company will be subject to regulation by the Investment Promotion
Authority, which regulates almost all business operations with significant
foreign equity or with foreign management control.

Competition

  The Company encounters strong competition from other independent operators and
from major oil companies in acquiring properties suitable for exploration, in
contracting for drilling equipment and in securing trained personnel.  Many of
these competitors have financial and other resources substantially greater than
those available to the Company.

  The Company's ability to discover reserves in the future depends on its
ability to select, generate and acquire suitable prospects for future
exploration.  The Company does not currently generate its own prospects and
depends exclusively upon external sources for the generation of oil and gas
prospects.

Employees

  As of December 31, 1999, Aviva had 61 full-time employees including 7 in the
United States and 54 in Colombia.


ITEM 2. PROPERTIES

Productive Wells and Drilling Activity

  The following table summarizes the Company's developed acreage and productive
wells at December 31, 1999.  "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  1,296
                                -----  -----
                                7,586  2,861
                                =====  =====

Productive Wells (3)
                                           Oil                     Gas
                                 -----------------------  ----------------------

                                   Gross          Net       Gross          Net
                                 ---------      --------  ---------      -------

             United States (4)          10          5.29          7         2.87
             Colombia                   14          4.90          -            -
                                 ---------      --------  ---------      -------
                                        24         10.19          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
                           ----------  -----------  ----------  ----------

   1999    United States            -            -           -           -
           Colombia                 -            -           -           -
                           ----------  -----------  ----------  ----------
           Total                    -            -           -           -
                           ==========  ===========  ==========  ==========

   1998    United States            -            -           -           -
           Colombia                 -            -           -           -
                           ----------  -----------  ----------  ----------
           Total                    -            -           -           -
                           ==========  ===========  ==========  ==========

   1997    United States            -            -           -           -
           Colombia               0.5            -           -           -
                           ----------  -----------  ----------  ----------
           Total                  0.5            -           -           -
                           ==========  ===========  ==========  ==========


  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 the Santana
contract with the Colombian government. The Company relinquished all undeveloped
acreage associated with the La Fragua and Yuruyaco contracts in December 1998.
No further relinquishments are required for the Santana contract until the
expiration of the contract in 2015.  See "-- Significant Properties."

  The Company's undeveloped acreage in Papua New Guinea is held pursuant to PPL-
206.  See "-- Significant Properties."

  The Company does not have an undeveloped acreage position in the United States
because of the costs of maintaining such a position.  Oil and gas leases in the
United States generally can be acquired by the Company for specific prospects on
reasonable terms either directly or through farmout arrangements.

  The following table shows the undeveloped acreage held by the Company at
December 31, 1999.  Undeveloped acreage is acreage on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of oil and gas, regardless of whether such acreage contains proved
reserves.

                                            Undeveloped Acres
                                            -----------------
                                              Gross     Net
                                            ---------  ------

                        Colombia               48,636  48,636
                        Papua New Guinea    1,228,187  24,564
                                            ---------  ------
                                            1,276,823  73,200
                                            =========  ======
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, 1999, that is not the same as that included in the estimate of
proved oil and gas reserves as of December 31, 1999, 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,
                                         -----------------------

                                         1999     1998      1997
                                         ----     ----      ----

Oil (1)    United States                   57       44        76
           Colombia                       365      255       426

Gas        United States                   53       68       316
           Colombia                         -        -         -

(1)  Includes crude oil and condensate.

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

<TABLE>
<CAPTION>
                                                                 Year ended December 31, (1)
                                                            -------------------------------------

                                                             1999            1998           1997
                                                            ------          ------         ------
<S>                                       <C>              <C>          <C>             <C>
Average sales price per barrel of oil (2)    United States  $17.13          $12.03         $19.17
                                             Colombia       $15.57          $10.31         $17.39

Average sales price per MCF of gas           United States  $ 2.42          $ 2.42         $ 2.73
                                             Colombia       $    -          $    -         $    -

Average production cost per dollar of
  oil and gas revenue                        United States  $ 1.05          $ 1.80         $ 0.54
                                             Colombia       $ 0.42          $ 0.86         $ 0.40
</TABLE>


                                       10
<PAGE>

<TABLE>
<S>                                     <C>               <C>            <C>             <C>
Average production cost per barrel of
  oil equivalent                             United States  $17.69          $22.54         $ 9.81
                                             Colombia       $ 6.58          $ 8.88         $ 6.98
</TABLE>
(1)  All amounts are stated in United States dollars.
(2)  Includes crude oil and condensate.

Significant Properties

  Colombia.
  --------

  The Company's Colombian properties currently consist of two contracts, both 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's
interest in each of the contracts is subject to certain reversionary interests
in favor of Ecopetrol as described below.  Argosy, as operator of the
properties, carries out the program of operations for the two concessions.  The
program is determined by Argosy and approved by Ecopetrol.  The Santana
contract, which now consists of approximately 52,000 acres and contains 14
productive wells, has been in effect since 1987 and is the focus of the
Company's exploration and development activities.

  The Aporte Putumayo contract, which consists of approximately 77,000 acres and
contains three shut-in wells, has been in effect since 1972.  The Company has
filed with Ecopetrol an application for formal relinquishment of the Aporte
Putumayo contract.  Such formal relinquishment is expected to occur during 2000.

  Production from the Santana concession is sold pursuant to a sales contract
with Ecopetrol.  The contract provides 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.

  The Company's pretax income from Colombian sources, as defined under Colombian
law, is subject to Colombian income taxes at a statutory rate of 35%, although a
"presumptive" minimum income tax based on net assets, as defined under Colombian
law, may apply in years of little or no net income.  The Company's income after
Colombian income taxes is subject to a Colombian remittance tax that accrues at
a rate of 7% (10% prior to 1998).  Payment of the remittance tax may be deferred
under certain circumstances if the Company reinvests such income in Colombia.
See Note 8 of the Notes to Consolidated Financial Statements contained elsewhere
herein.

  The Colombian government also imposed a production tax which was equal to 7%
of the oil price in effect through December 1997.  The production tax was,
however, eliminated for 1998 and thereafter.

  Santana Contract.  The Santana block is held pursuant to a "risk-sharing"
  ----------------
contract for which Ecopetrol has the option to participate on the basis of a 30%
working interest in exploration activities in the contract area.  If a
commercial field is discovered, Ecopetrol's working interest increases to 50%
and the costs theretofore incurred and attributable to the 20% working interest
differential will be recouped by the Company from Ecopetrol's share of
production on a well by well basis.  The risk-sharing contract provides that,
when 7 million barrels of cumulative production from the concession have been
attained, Ecopetrol's revenue interest and share of operating costs increases to
65% but it remains obligated for only 50% of capital expenditures.  In June
1996, the 7 million barrel threshold was reached.  At that time, Argosy's and
Neo's aggregate revenue interest in the contract declined from 40% to 28% and
their share of operating expenses declined from 50% to 35%.

  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 four producing wells in the Linda field. During
1995, a 3-D seismic survey covering the Toroyaco and Linda fields was completed.
Based on this survey, one development well was drilled in each field during 1996
and one additional development well was drilled in the Linda field in 1997.   No
further drilling is anticipated for these fields.

  The Company constructed a 42-kilometer pipeline (the "Uchupayaco Pipeline")
which was completed and commenced operations during 1994 to transport oil
production from the Toroyaco and Linda fields to the Trans-Andean Pipeline owned
by Ecopetrol, through which the Company's production is transported to the port
of Tumaco on the Pacific coast of Colombia.

                                       11
<PAGE>

  Two additional fields, the Mary and Miraflor fields, were discovered north of
the Caqueta River and were declared commercial by Ecopetrol during 1993.  Except
for oil produced during production tests of wells located in these fields, the
production was shut-in until the first quarter of 1995 when construction of a
pipeline was completed and commercial production began.  Completion of this
pipeline provided the Company with direct pipeline access from all of its fields
to the Pacific coast port of Tumaco.  There are currently four producing wells
in the Mary field and one producing well in the Miraflor field.  A 3-D seismic
survey was completed over the Mary and Miraflor fields during early 1997. 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 Company has fulfilled all the exploration obligations required by the
Santana risk-sharing contract.  The Company's current work program contemplates
the recompletion of certain existing wells to increase production therefrom.

  The Santana contract has a term of 28 years and expires in 2015.  In 1993, the
Company relinquished 50% of the original Santana area in accordance with the
terms of the contract.  In July 1995, an additional 25% of the original contract
area was relinquished.  A final relinquishment was made in 1997 such that all
remaining contract areas except for those areas within five kilometers of a
commercial field were relinquished.

  Under the terms of a contract with Ecopetrol, all oil produced from the
Santana contract area is sold to Ecopetrol.  If Ecopetrol exports the oil, the
price paid is the export price received by Ecopetrol, adjusted for quality
differences, less a marketing fee of $0.165 per barrel.  If Ecopetrol does not
export the oil, the price paid is based on the price received from Ecopetrol's
Cartagena refinery, adjusted for quality differences, less Ecopetrol's cost to
transport the crude to Cartagena and a marketing fee of $0.165 per barrel.  In
1999, Ecopetrol exported the crude each month and the sales price averaged
$15.57 per barrel.

  Aporte Putumayo Contract.  The discoveries on the Aporte Putumayo contract
  ------------------------
were not declared commercial by Ecopetrol and the properties were operated by
Argosy without participation by Ecopetrol.  There are no remaining exploration
obligations under this contract.  Ecopetrol has accepted the Company's request
for relinquishment, which is pending 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.
The Breton Sound 31 field is operated by the Company.  The Company relinquished
operatorship of the Main Pass 41 field effective January 1, 1999.

  Main Pass Block 41 is a federal lease located approximately 25 miles east of
Venice, Louisiana, in 50 feet of water.  There are currently four productive
wells in the field.  The field's 1999 production averaged 57 barrels of oil per
day and 79 MCF per day, net to the Company's interest, from four completions in
three sands between 6,000 and 7,500 feet.  The Company owns a 35% interest in
this field.

  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 1999, five wells averaged 101 barrels of oil per day and 65 MCF
of gas per day, net to the Company's interest, from three sands completed
between 3,850 feet and 6,500 feet. The Company's interests in the leases
comprising the field vary from 41% to 67%.

  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, following consummation of the proposed debt restructuring.
See "Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Liquidity and Capital Resources."

  Papua New Guinea.
  ----------------

  The area covered by PPL-206 is located in the Western, Gulf and Southern
Highland Provinces of Papua New Guinea.  The northern section of the area is in
a mountainous tropical rain forest while the southern section of the

                                       12
<PAGE>

area is predominantly lowlands, jungle and coastal swamps. In 1986 oil was
discovered approximately 20 kilometers from the northern border of PPL-206 in an
adjoining license area and in 1999 gas was discovered approximately 20
kilometers southwest of the western border.

  In accordance with the terms of the agreement governing PPL-206, the parties
have performed surface geological work and completed a seismic program during
late 1997 and early 1998.  The parties have submitted to the Department of
Petroleum and Energy a request to carry out a second seismic program in 2000 and
to defer the drilling of an exploratory well until 2001.  A decision regarding
the drilling of an exploratory well will be made following evaluation of the
second seismic program.  The Company is not obligated to pay any of the costs
relative to the work presently underway.  Should the parties decide to drill an
exploratory well, the Company will have no obligation to pay its share of the
drilling, testing and completion costs of this well pursuant to its 2% carried
working interest.

  Under the provisions of PPL-206 the terms of any oil and gas development are
set forth in a Petroleum Agreement with the Government of Papua New Guinea.  The
Petroleum Agreement provides that the operator must carry out an appraisal
program after a discovery to determine whether the discovery is of commercial
interest.  If the appraisal is not carried out or the discovery is not of
commercial interest, the license may be forfeited.  If the discovery is of
commercial interest, the operator must apply for a Petroleum Development
License.  The Government retains a royalty on production equal to 1.25% of the
wellhead value of the petroleum and, at its election, may acquire up to a 22.5%
interest in the petroleum development after recoupment by the operator of the
project costs attributable thereto out of production.  In addition, income from
petroleum operations is subject to a Petroleum Income Tax at the rate of 50% of
net income, which is defined as gross revenue less royalties, allowances for
depreciation, interest deductions, operating costs and previous tax losses
carried forward.  An Additional Profits Tax of 50% of cash flow (after deducting
ordinary income tax payments) is also payable when the accumulated value of net
cash flows becomes positive.  For annual periods in which net cash flows are
negative, the cumulative amount is carried forward and increased at an annual
accumulation of 27%.  The Additional Profits Tax is calculated separately for
each Petroleum Development License.  In calculating the applicable tax, interest
expenses paid by Garnet PNG prior to the issuance of a Petroleum Development
License and, thereafter, to the extent that Garnet PNG's debt to equity ratio
exceeds two-to-one, are not deductible.

  The Company leases corporate office space in Dallas, Texas containing
approximately 5,100 square feet pursuant to a lease which expires in January
2002.  The annual lease payments for these offices are approximately $102,000.


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, 1999.

                                       13
<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, traded on the American Stock Exchange (the "ASE")
from November 14, 1994 through April 8, 1999.  On April 9, 1999, the Depositary
Shares were delisted from the ASE due to the Company's financial difficulties.
On May 13, 1999, the Depositary Shares began trading on the OTC Bulletin Board
(the "OTCBB") under the symbol "AVVPP.OB".  During 1999, an aggregate of
1,589,000 and 465,000 Depositary Shares were traded on the ASE and the OTCBB,
respectively.

  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.  In the United Kingdom,
the average daily trading volume of the Common Stock on the London Stock
Exchange during 1999 was approximately 58,000 shares until May 6, 1999, when
trading of the Common Stock was suspended due to the Company's financial
difficulties.

  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 OTCBB and the high and low prices for the Common Stock on the
London Stock Exchange.  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.

                                       14
<PAGE>

<TABLE>
<CAPTION>

-------------
                                              1999                             1998                               1997
                                     ----------------------            ----------------------            ----------------------

                                      High             Low             High              Low             High              Low
                                     -----            -----            -----            -----            -----            -----
<S>                               <C>             <C>              <C>               <C>             <C>             <C>
Depositary Shares (1):
---------------------

  ASE
  ---
  First Quarter                      $0.41            $0.09            $1.75            $1.00            $4.13            $2.88
  Second Quarter                     $0.22            $0.09            $1.19            $0.69            $3.00            $1.63
  Third Quarter                      $ n/a            $ n/a            $1.00            $0.13            $4.13            $1.63
  Fourth Quarter                     $ n/a            $ n/a            $0.31            $0.06            $2.06            $0.98


  OTC Bulletin Board
  ------------------
  First Quarter                      $ n/a            $ n/a            $ n/a            $ n/a            $ n/a            $ n/a
  Second Quarter                     $0.31            $0.06            $ n/a            $ n/a            $ n/a            $ n/a
  Third Quarter                      $0.22            $0.06            $ n/a            $ n/a            $ n/a            $ n/a
  Fourth Quarter                     $0.22            $0.03            $ n/a            $ n/a            $ n/a            $ n/a


Common Stock
------------

  London Stock Exchange
  ---------------------
  First Quarter
    (Pounds)               (Pounds)   0.06  (Pounds)   0.03  (Pounds)   0.28  (Pounds)   0.12  (Pounds)   0.42  (Pounds)   0.28
    US$                              $0.10            $0.05            $0.45            $0.20            $0.69            $0.45

  Second Quarter
    (Pounds)               (Pounds)   0.06  (Pounds)   0.05  (Pounds)   0.14  (Pounds)   0.10  (Pounds)   0.32  (Pounds)   0.27
    US$                              $0.10            $0.08            $0.22            $0.16            $0.51            $0.44

  Third Quarter
    (Pounds)               (Pounds)    n/a  (Pounds)    n/a  (Pounds)   0.10  (Pounds)   0.05  (Pounds)   0.30  (Pounds)   0.21
    US$                              $ n/a            $ n/a            $0.17            $0.08            $0.50            $0.34

  Fourth Quarter
    (Pounds)               (Pounds)    n/a  (Pounds)    n/a  (Pounds)   0.06  (Pounds)   0.04  (Pounds)   0.25  (Pounds)   0.17
    US$                              $ n/a            $ n/a            $0.10            $0.07            $0.40            $0.28
</TABLE>

(1) Representing five shares of Common Stock.

  As of February 29, 2000, the Company had approximately 6,000 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 October 1998, the Company entered into a restated 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."

                                       15
<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,
1999, which should be read in conjunction with the Consolidated Financial
Statements included elsewhere herein.


<TABLE>
<CAPTION>
                                                         For the Years Ended December 31,
                                                ----------------------------------------------------
                                                  1999       1998       1997       1996       1995
                                                ---------  ---------  ---------  ---------  --------
                                             (in thousands, except per share, per barrel and per MCF data)

<S>                                          <C>           <C>        <C>        <C>        <C>
For the period
  Revenues                                       $  6,797   $  3,332   $  9,726    $13,750   $10,928
  Loss before extraordinary item                 $   (403)  $(16,881)  $(22,482)   $  (937)  $(2,689)
  Extraordinary item - debt extinguishment       $      -   $   (197)  $-          $-        $-
  Net loss                                       $   (403)  $(17,078)  $(22,482)   $  (937)  $(2,689)
  Loss before extraordinary item
    per common share                             $  (0.01)  $  (0.49)  $  (0.71)   $ (0.03)  $ (0.09)
  Basic and diluted net loss
    per common share                             $  (0.01)  $  (0.50)  $  (0.71)   $ (0.03)  $ (0.09)
  Weighted average shares outstanding              46,813     34,279     31,483     31,483    31,483
  Cash dividends per common share                $      -   $      -   $      -    $     -   $     -
  Total annual net oil production (barrels)
      Colombia                                        365        255        426        476       435
      United States                                    57         44         76         94       106
                                                 --------   --------   --------    -------   -------
       Total                                          422        299        502        570       541
                                                 --------   --------   --------    -------   -------

  Total annual net gas production (MCF)
      United States                                    53         68        316      1,146     1,184

  Average price per barrel of oil
      Colombia                                   $  15.57   $  10.31   $  17.39    $ 19.82   $ 16.39
      United States                              $  17.13   $  12.03   $  19.17    $ 20.68   $ 16.78
  Average price per MCF of
    Gas - United States                          $   2.42   $   2.42   $   2.73    $  2.07   $  1.70

At period end
  Total assets                                   $  8,986   $ 11,422   $ 16,445    $42,944   $45,460
  Long term debt, including
    current portion                              $ 14,495   $ 14,805   $  7,690    $ 7,990   $13,067
  Stockholders' equity (deficit)                 $(11,483)  $(11,083)  $  3,748    $26,230   $27,167
</TABLE>

In connection with the application of the full cost method, the Company recorded
ceiling test write-downs of oil and gas properties of $12,343,000 in 1998 and
$19,953,000 in 1997 (see Note 1 of Notes to Consolidated Financial Statements).

                                       16
<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

1999 versus 1998
----------------
                            United States    Colombia
                             Oil      Gas      Oil      Total
                          ---------  -----   --------  -------
       (Thousands)

       Revenue - 1998      $    535  $ 165    $ 2,632  $ 3,332

       Volume variance          158    (29)     1,130    1,259

       Price variance           294     10      1,921    2,225

       Other                      -    (19)         -      (19)
                          ---------  -----   --------  -------

       Revenue - 1999      $    987  $ 127    $ 5,683  $ 6,797
                          =========  =====   ========  =======


  Colombian oil volumes were 365,000 barrels in 1999, an increase of 110,000
barrels from 1998.  Such increase is due to a 148,000 barrel increase resulting
from the acquisition of Garnet effective October 28, 1998, and an increase of
23,000 barrels due to continuous production in 1999 (1998 production was
interrupted by guerrilla attacks that damaged oil processing and storage
facilities), partially offset by a 61,000 barrel decrease resulting from
production declines.

  U.S. oil volumes were 57,000 barrels in 1999, an increase of 13,000 barrels as
compared to 1998.  An increase of approximately 15,000 barrels was due to
continuous production from the Company's Main Pass 41 field (shut in for
approximately 187 days during 1998 due to upgrading and modification of
production and water treatment facilities and adverse weather), and an increase
of approximately 9,000 barrels was due to continuous production from the
Company's Breton Sound 31 field (shut-in during the months of September and
October and a portion of November 1998 due to the drilling and completion of a
saltwater disposal well and adverse weather), partially offset by a 11,000
barrel decrease resulting from normal production declines.  U.S. gas volumes
before gas balancing adjustments were 51,000 MCF in 1999, down 3,000 MCF from
1998.  Of such decrease, approximately 122,000 MCF was due to production
declines, partially offset by 119,000 MCF due to the aforementioned continuous
production of the Main Pass 41 field.

  Colombian oil prices averaged $15.57 per barrel during 1999.  The average
price for the same period of 1998 was $10.31 per barrel.  The Company's average
U.S. oil price increased to $17.13 per barrel in 1999, up from $12.03 per barrel
in 1998.  In 1999 prices have been higher than in 1998 due to a dramatic
increase in world oil prices.  U.S. gas prices averaged $2.42 per MCF in 1999
and 1998.

  In addition to the above-mentioned variances, U.S. gas revenue decreased
approximately $19,000 as a result of gas balancing adjustments.

  Operating costs increased approximately 1.5%, or $50,000, primarily due to the
increase in ownership of the Colombian properties following the Garnet Merger,
almost entirely offset by cost reductions in Colombia achieved after the Company
merged with Garnet and took over operatorship of the Colombian properties.

  Depreciation, depletion and amortization ("DD&A") decreased by 68%, or
$2,152,000, primarily due to a decrease in costs subject to amortization
resulting from property write-downs during 1998.

  The Company recorded write-downs of $10,556,000 and $1,787,000 to the carrying
amounts of its Colombian and U.S. oil and gas properties, respectively, as a
result of ceiling test limitations on capitalized costs during 1998.  No such
write-downs were required during 1999.

                                       17
<PAGE>

  General and administrative ("G&A") expenses increased $171,000 mainly due to a
$193,000 decrease in administrative overhead fees recovered from joint interest
partners in properties where the Company serves as the operator.  This decrease
in administrative overhead fees resulted primarily because the Company
relinquished operatorship of the Main Pass 41 field effective January 1, 1999.

  The Company incurred severance expense of $62,000 during 1999 related to
Colombian operations.  The Company has taken significant cost cutting measures
in Colombia since it merged with Garnet and took over operatorship of the
Colombian properties.

  Interest and other income decreased $786,000 from 1998.  During 1998 the
Company realized a $720,000 gain on the settlement of litigation involving the
administration of a take or pay contract settlement.  No such gain was recorded
in 1999.

  Interest expense increased $648,000 from 1998 as a result of higher
outstanding balances of long-term debt and higher interest rates.

  Income taxes were $286,000 higher in 1999 principally due to higher Colombian
presumptive income taxes resulting from the increased ownership of the Colombian
properties for a full year in 1999 compared to only two months of full ownership
in 1998.

1998 versus 1997
----------------
                               United States      Colombia
                                 Oil       Gas       Oil      Total
                              ----------  ------  ---------  --------
       (Thousands)

       Revenue - 1997          $   1,459  $  862  $   7,405  $  9,726

       Volume variance              (606)   (572)    (3,613)   (4,791)

       Price variance               (318)    (74)    (1,427)   (1,819)

       Garnet revenue                  -       -        267       267

       Other                           -     (51)         -       (51)
                              ----------  ------  ---------  --------

       Revenue - 1998          $     535  $  165  $   2,632  $  3,332
                              ==========  ======  =========  ========


  Colombian oil volumes were 255,000 barrels in 1998, a decrease of 171,000
barrels from 1997.  Such decrease is due to a 185,000 barrel decrease resulting
from production declines and a 23,000 barrel decrease due to lost production
caused by guerilla attacks in August that damaged oil processing and storage
facilities and caused production from various wells to be shut-in for periods
ranging from 6 to 57 days, partially offset by a 37,000 barrel increase due to
the acquisition of Garnet effective October 28, 1998.

  U.S. oil volumes were 44,000 barrels in 1998, down approximately 32,000
barrels from 1997.  Of such decrease, approximately 9,000 barrels was due to the
Company's Breton Sound 31 field being shut-in during the months of September and
October and a portion of November due to the drilling and completion of a
saltwater disposal well and adverse weather, approximately 15,000 barrels was
due to the Company's Main Pass 41 field being shut-in for approximately 187 days
during 1998 due to upgrading and modification of production and water treatment
facilities and adverse weather, and 8,000 barrels resulted from normal
production declines.  U.S. gas volumes before gas balancing adjustments were
54,000 MCF in 1998, down 219,000 MCF from 1997.  Of such decrease, approximately
119,000 MCF was due to the aforementioned shut-in of the Main Pass 41 field and
38,000 MCF was due to the suspension of production of one of the wells at Main
Pass 41 from January 9 to August 27, 1998.  The remaining 62,000 MCF was due to
production declines.

  Colombian oil prices averaged $10.31 per barrel during 1998.  The average
price for the same period of 1997 was $17.39 per barrel.  The Company's average
U.S. oil price decreased to $12.03 per barrel in 1998, down from $19.17 per

                                       18
<PAGE>

barrel in 1997.  In 1998 prices were lower than in 1997 due to a dramatic
decrease in world oil prices.  U.S. gas prices averaged $2.42 per MCF in 1998
compared to $2.73 per MCF in 1997.

  In addition to the above-mentioned variances, U.S. gas revenue decreased
approximately $51,000 as a result of gas balancing adjustments.

  Operating costs decreased approximately 17%, or $710,000, primarily due to
lower operating costs in Colombia.  Such decreases have resulted mainly from the
elimination of the production tax on the majority of the Company's Colombian
production and lower pipeline tariffs resulting from lower volumes.

  DD&A decreased by 48%, or $2,915,000, primarily due to a decrease in costs
subject to amortization resulting from property write-downs and lower levels of
production.

  The Company recorded write-downs of $10,556,000 and $1,787,000 to the carrying
amounts of its Colombian and U.S. oil and gas properties, respectively, as a
result of ceiling test limitations on capitalized costs during 1998.

  G&A expenses declined $436,000 mainly due to a $159,000 decrease in legal
fees, a $127,000 decrease in directors' fees and expenses, and a $191,000
reduction in payroll.  These savings were partially offset by lower amounts of
capitalized G&A.

  In December 1998 the Company recorded a $420,000 provision for doubtful
accounts receivable due from joint-venture partners.

  Interest and other income increased $923,000 from 1997 as the Company realized
a $720,000 gain on the settlement of litigation involving the administration of
a take or pay contract settlement.

  Income taxes were $89,000 higher in 1998 principally as a result of Colombian
deferred tax benefits recorded in the second quarter of 1997, partially offset
by lower presumptive income taxes in 1998.  The deferred tax benefits in 1997
resulted from the write-down of the carrying amount of the Company's Colombian
oil properties.

Year 2000

  The conversion from calendar year 1999 to calendar year 2000 occurred without
any disruption to the Company's critical business systems.  Since early 1999,
the Company has been upgrading its information systems with Year 2000 ("Y2K")
compliant software and hardware.  These actions have minimized Y2K related
capital costs and expenses, which is estimated at less than $200,000.  The
Company will continue to monitor Y2K related exposures both internally and with
its suppliers, customers and other business partners.  Such monitoring will be
ongoing and encompassed in normal operations and associated costs are not
expected to be significant.

New Accounting Pronouncements

  The Company is assessing the reporting and disclosure requirements of SFAS No.
133, Accounting for Derivative Instruments and Hedging Activities.  This
statement establishes accounting and reporting standards for derivative
instruments and hedging activities.  The statement is effective for financial
statements for fiscal years beginning after June 15, 2000.  The Company believes
SFAS No. 133 will not have a material impact on its financial statements or
accounting policies.  The Company will adopt the provisions of SFAS No. 133 in
the first quarter of 2001.

Liquidity and Capital Resources

  During the last quarter of calendar year 1997 and throughout calendar year
1998, world oil prices declined dramatically.  This decline in oil prices was
particularly severe in Colombia.  Colombian oil prices, during the twenty-four
month period ended December 31, 1998, fell from a high of $22.71 per barrel in
January 1997 to $7.50 per barrel in December 1998.  Whereas the sale price for
crude oil from the Santana contract averaged $19.82 per barrel in 1996 and
$17.39 per barrel in 1997, the sale price averaged $10.31 per barrel during
calendar year 1998 and $15.57 per barrel during calendar year 1999.

  These price declines have materially and adversely affected the results of
operations and the financial position of the Company.  During the years ended
December 31, 1999, 1998 and 1997, the Company reported net losses of $0.4

                                       19
<PAGE>

million, $17.1 million and $22.5 million, respectively, and declining amounts of
net cash provided by (used in) operating activities of $(0.5) million, $(0.05)
million and $1.7 million, respectively. The Company's stockholders' deficit was
approximately $11.5 million as of December 31, 1999.

  Although world oil prices have recovered during the latter part of 1999, the
Company remains highly leveraged with $14.5 million in current debt as of
December 31, 1999, pursuant to bank credit facilities with ING (U.S.) Capital
Corporation ("ING Capital") and the U.S. Overseas Private Investment Corporation
("OPIC"), as more fully described in Note 5 of the Notes to Consolidated
Financial Statements contained elsewhere herein.

  The Company is not in compliance with various covenants under the bank credit
facilities nor is it in compliance with the minimum escrow balance required
thereunder.  As a result, the lender has the right to accelerate payment on the
debt and, therefore, the Company has classified all long-term debt as current in
the December 31, 1999 consolidated balance sheet.  Furthermore, the Company was
unable to pay the principal payment of $5.7 million due on April 30, 1999, and
subsequent monthly principal payments of $281,250 (an aggregate of $7,950,000
through December 31, 1999).  The Company did pay $150,000 of principal during
the second quarter of 1999 and all of the interest through June 30, 1999;
however, interest due subsequent to this date in the amount of $864,000 has not
been paid.  Assuming no change in its capital structure, the Company will not
have the financial resources to pay the $8,664,000 of principal and interest
which is in arrears and future minimum monthly principal payments of $281,250
due through December 31, 2001.

  The Company's management has been in more or less continuous discussions with
the Company's lenders regarding a restructuring of its debt for more than two
years.  During that period, the Company has attempted to negotiate several
transactions and has engaged financial advisers to locate equity investors to
participate in recapitalization and debt restructuring transactions.  Except for
the Garnet merger in October 1998, none of such proposals has come to fruition,
primarily because of the inability of equity participants, lenders and the
Company to agree on financial terms.

  Management of the Company is again in discussions with the Company's lenders
and a group of investors concerning a restructuring of the Company.  Such a
restructuring may involve the sale of a substantial portion of the Company's oil
and gas assets and a significant reduction of the Company's outstanding debt.
While management is optimistic that a restructuring can be achieved that will
provide the Company with the liquidity necessary to continue operations, there
can be no assurance that this will be the case.

  Although management of the Company is pursuing the restructuring assiduously,
its ability to effect such a restructuring is dependent upon the Company being
able to reach an agreement between the Company, the Company's lenders and the
potential investors, matters that are beyond the control of the Company.  The
Company's lenders have not yet and may not ever agree to a restructuring of the
Company's debt.  In addition, the potential investors may insist on financial
terms that are viewed by the Company's board of directors as inconsistent with
continued operations.  If the Company is unable to consummate a restructuring,
then, in the absence of another business transaction, the Company cannot achieve
compliance with or make payments required by the bank credit facilities.
Accordingly, the lenders could declare a default, accelerate all amounts
outstanding, and attempt to realize upon the collateral securing the debt.  As a
result of this uncertainty, management believes there is substantial doubt about
the Company's ability to continue as a going concern.

  During the period 1997 through 1999, costs incurred in oil and gas property
acquisition, exploration and development activities by the Company totaled
approximately $12.6 million.  Of this figure, approximately $0.7 million was for
exploration predominantly in Colombia, $3.7 million pertained to development
costs in the United States (35%) and Colombia (65%), and $8.3 million relates to
the acquisition of Garnet.  The Company's sources of funds during this period
were: (i) cash provided by (used in) operating activities - 1999 - $(0.5)
million; 1998 - $(0.05) million; and 1997 - $1.7 million; (ii) net cash provided
by investing activities (before property and equipment expenditures) - 1999 -
$0.04 million; 1998 - $1.4 million; and 1997 - $0.02 million; and (iii) net cash
provided by (used in) financing activities - 1999 - $(0.3) million; 1998 - $1.1
million; and 1997 - $(0.3) million.

  The Company plans to recomplete certain existing wells and engage in various
other projects in Colombia.  The Company's current share of the estimated future
costs of these development activities is approximately $0.6 million at December
31, 1999.  Failure to fund certain expenditures could result in the forfeiture
of all or part of the Company's interest in the concessions.

                                       20
<PAGE>

  The Company expects to fund these activities using cash provided from
operations.  Any substantial increases in the amounts of these required
expenditures could adversely affect the Company's ability to fund these
activities.  Delays in obtaining the required environmental approvals and
permits on a timely basis, as described above under "Item 1. Business --
Regulation," and other delays could, through the impact of inflation, increase
the required expenditures.  Cost overruns resulting from factors other than
inflation could also increase the required expenditures.  Historically, the
inflation rate of the Colombian peso has been in the range of 15-30% per year.
Devaluation of the peso against the U.S. dollar has historically been slightly
less than the inflation rate in Colombia.  The Company has historically funded
capital expenditures in Colombia by converting U.S. dollars to pesos at such
time as the expenditures have been made.  As a result of the interaction between
peso inflation and devaluation of the peso against the U.S. dollar, inflation,
from the Company's perspective, had not been a significant factor.  During 1994,
the first half of 1995 and 1996, however, devaluation of the peso was
substantially lower than the rate of inflation of the peso, resulting in an
effective inflation rate in excess of that of the U.S. dollar.  There can be no
assurance that this condition will not occur again or that, in such event, there
will not be substantial increases in future capital expenditures as a result.
Due to Colombian exchange controls and restrictions and the lack of an effective
market, it is not feasible to hedge against the risk of net peso inflation
against the U.S. dollar and the Company has not done so.  Depending on the
results of future exploration and development activities, substantial
expenditures which have not been included in the Company's cash flow projections
may be required. The outcome of these matters cannot be projected with
certainty.

  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 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

  The Company is exposed to market risk from changes in interest rates on debt
and changes in commodity prices.

  The Company's exposure to interest rate risk relates to variable rate loans
that are benchmarked to LIBOR interest rates.  The Company does not use
derivative financial instruments to manage overall borrowing costs or reduce
exposure to adverse fluctuations in interest rates.  The impact on the Company's
results of operations of a one-point interest rate change on the outstanding
balance of the variable rate debt as of December 31, 1999 would be $145,000 per
year.

  The Company produces and sells crude oil and natural gas.  These commodities
are sold based on market prices established with the buyers.  The Company does
not use financial instruments to hedge commodity prices.


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.

                                       21
<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.  Effective October 28, 1998, the Board of
Directors, by resolution, decreased the number of directors from five to three.

  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         68  President, Chief Executive Officer            1985
                           and Director

Eugene C. Fiedorek     68  Director                                      1997

Robert J. Cresci       56  Director                                      1998


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

  Ronald Suttill has been a director of the Company since August 1985 and has
been President and Chief Executive Officer of the Company since January 1992.
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 was a Managing Director of EnCap Investments, L.C., a company he co-
founded in 1988, until its sale in March 1999 to El Paso Energy Corporation.  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 Apache Corporation and
privately held Matador Petroleum Corporation.

  Robert J. Cresci has been a director of the Company since October 1998.  Mr.
Cresci has been a Managing Director of Pecks Management Partners, Ltd., an
investment management firm, since September 1990.  Mr. Cresci currently serves
on the boards of Sepracor, Inc., Film Roman, Inc., Quest Education Corporation,
Castle Dental Centers, Inc., JFax.Com, Inc., Candlewood Hotel Co., Inc.,
SeraCare, Inc., E-Stamp Corporation  and several private companies.

Executive Officers of the Company

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

Name and Age                    Positions
------------                    ---------

Ronald Suttill, 68              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.

                                       22
<PAGE>

James L. Busby, 39              Treasurer since May 1994, Secretary since June
                                1996, Controller since November 1993 and a
                                Senior Manager with the accounting firm of KPMG
                                LLP prior to that.

Meetings and Committees of the Board of Directors

  The Board of Directors of the Company held no formal meetings during 1999,
however, business was conducted via telephone conferences and written unanimous
consents. Each director attended at least 75% of the aggregate of (i) the total
number of meetings of the Board of Directors held during the period in which he
was a director and (ii) the total number of meetings held by all committees on
which he served.

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

  The Audit Committee, of which Mr. Fiedorek is the sole member, consults with
the independent accountants of the Company and such other persons as the
committee deems appropriate, reviews the preparations for and scope of the audit
of the Company's annual financial statements, 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 one meeting
during 1999.

  The Compensation Committee, which is comprised of Messrs. Fiedorek and Cresci,
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 1999.

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,
1999, all of the Reporting Persons complied with their Section 16(a) filing
requirements.

                                       23
<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    1999  150,000          -         -              -              -         -       4,500
 President and CEO    1998  157,500          -         -              -              -         -       4,750
 President and CEO    1997  185,000          -         -              -              -         -       4,750
</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

  The directors of the Company are no longer paid a cash fee.  Directors are,
however, reimbursed for travel and lodging expenses.  Mr. Suttill receives no
compensation as a director but is reimbursed for travel and lodging expenses
incurred to attend meetings.

  On July 1 each year, non-employee directors who have served in such capacity
for at least the entire proceeding calendar year each receives an option to
purchase 5,000 shares of the Company's Common Stock pursuant to the Aviva
Petroleum Inc. 1995 Stock Option Plan, as amended.

Option Grants During 1999

  There were no options granted to the Named Executive Officer during 1999.  No
stock appreciation rights have been issued by the Company.


Option Exercises During 1999 and Year End Option Values

  The following table provides information related to options exercised by the
Named Executive Officer during 1999 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       250,000                      -            -              -

</TABLE>

                                       24
<PAGE>

(1) No values are ascribed to unexercised options of the Named Executive Officer
    at December 31, 1999 because the fair market value of a share of the
    Company's Common Stock at December 31, 1999 ($0.01) 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, including
salary, bonuses, stock options and other compensation.  There are no
Compensation Committee interlocks.

Employment Contracts

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

Compensation Committee Report on Executive Compensation

  The Company currently employs only two executive officers, the names of whom
are set forth above under "Item 10. Directors and Executive Officers of the
Registrant--Executive Officers of the Company." Decisions regarding compensation
of the executive officers are made by the Board of Directors, after giving
consideration to recommendations made by the Compensation Committee.

  The Company's compensation policies are designed to provide a reasonably
competitive level of compensation within the industry in order to attract,
motivate, reward and retain experienced, qualified personnel with the talent
necessary to achieve the Company's performance objectives.  These objectives are
to increase oil and gas reserves and to control costs, both objectives selected
to increase shareholder value.  These policies were implemented originally by
the entire Board of Directors, and, following its establishment, were endorsed
by the Compensation Committee.  It is the intention of the Compensation
Committee and the Board of Directors to balance compensation levels of the
Company's executive officers, including the Chief Executive Officer, with
shareholder interests.  The incentive provided by stock options and bonuses, in
particular, is intended to promote congruency of interests between the executive
officers and the shareholders.  Neither the Compensation Committee nor the Board
of Directors, however, believes that it is appropriate to rely on a formulaic
approach, such as profitability, revenue growth or return on equity, in
determining executive officer compensation because of the nature of the
Company's business.  The Company's business objectives include 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 1999 was comprised of
salary, bonus and matching employer contributions made pursuant to the Company's
401(k) Plan.  The Company's 401(k) Plan is generally available to all employees
after one year of service.  The Company makes matching contributions of 100% of
the amount deferred by the employee, up to 6% of an employee's annual salary.

                                       Compensation Committee

                                       E. C. Fiedorek
                                       R. J. Cresci

                                       25
<PAGE>

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.

              Comparison of 5 Year Cumulative Total Return of the
                   Company, Industry Index and Broad Market

                               FISCAL YEAR ENDING
COMPANY/INDEX/MARKET    1994   1995    1996    1997    1998    1999

AVIVA PETROLEUM INC.     100   85.44   75.73   32.04    1.94     .97
INDUSTRY INDEX           100  109.98  146.24  148.22  118.73  145.03
BROAD MARKET             100  128.90  136.01  163.66  161.44  201.27


                                       26
<PAGE>

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 29, 2000.

<TABLE>
<CAPTION>

Name and Address of                     Amount and Nature of
Beneficial Owner or Group             Beneficial Ownership (1)          Percent of Class (2)
-------------------------             ------------------------          --------------------
<S>                                   <C>                               <C>

Wexford Management LLC(3)                            5,438,639                 11.24%
411 West Putnam Avenue
Greenwich, Connecticut 06830

Pecks Management Partners Ltd. (4)                   5,155,108                 10.65%
One Rockefeller Plaza
New York, New York 10020

Lehman Brothers Inc.(5)                              2,966,876                  6.13%
3 World Financial Center
11th Floor
New York, New York 10285

ING (U.S.) Capital Corporation(6)                    2,700,000                  5.58%
135 East 57th Street
New York, New York 10022

Yale University(7)                                   2,551,886                  5.27%
230 Prospect Street
New Haven, Connecticut 06511
</TABLE>

(1)  Except as set forth below, to the knowledge of the Company, each beneficial
     owner has sole voting and sole investment power.
(2)  Based on 46,900,132 shares of the Common Stock issued and outstanding on
     February 29, 2000, plus warrants for 1,500,000 shares held by ING (U.S.)
     Capital Corporation.
(3)  Information regarding Wexford Management LLC ("Wexford Management") is
     based on a Schedule 13D dated November 12, 1998 filed by Wexford Management
     with the SEC. The shares are held by four investment funds. Wexford
     Management serves as investment advisor to three of the funds and as sub-
     investment advisor to the fourth fund which is organized as a corporation.
     Wexford Advisors, LLC ("Wexford Advisors") serves as the investment advisor
     to the corporate fund and as general partner to the remaining funds which
     are organized as limited partnerships. One of the limited partnerships,
     Wexford Special Situations 1996 L.P., holds more than 5% of Aviva Common
     Stock. Wexford Management shares voting and dispositive power with respect
     to these shares with each of the funds, with Wexford Advisors, and with
     Charles E. Davidson and Joseph M. Jacob, each of whom is a controlling
     person of Wexford Management and Wexford Advisors.
(4)  Based on the number of shares issued on October 28, 1998, in connection
     with the acquisition of Garnet Resources Corporation. The shares are held
     by three investment advisory clients of Pecks Management Partners Ltd.
     ("Pecks"). One such client, Delaware State Employees' Retirement Fund,
     holds more than 5% of Aviva's Common Stock. Pecks has sole investment and
     dispositive power with respect to these shares.
(5)  Information regarding Lehman Brothers Inc. is based on information received
     from Lehman Brothers Inc. on March 16, 1998.
(6)  Based on 1,200,000 shares held by ING, plus warrants to acquire an
     additional 1,500,000 shares.
(7)  Information regarding Yale University is based on a Schedule 13G dated
     March 11, 1994 filed by Yale University with the SEC.

                                       27
<PAGE>

Security Ownership of Management

     The following table sets forth certain information as of February 29, 2000,
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:

<TABLE>
<CAPTION>

Name and Address of                           Amount and Nature
Beneficial Owner                          of Beneficial Ownership(1)          Percent of Class(2)
----------------                          --------------------------          -------------------
<S>                                       <C>                                 <C>
Ronald Suttill                                     2,129,939(3)(4)                   4.33%
8235 Douglas Avenue, Suite 400
Dallas, TX 75225

Eugene C. Fiedorek                                   926,542                         1.88%
5407 Creek Arbor Court
Dallas, TX 75287

Robert J. Cresci                                      10,000(5)                         *
Pecks Management Partners Ltd.
One Rockefeller Plaza
New York, NY 10020

All directors and executive officers
as a group (4 persons)                             3,713,900(6)                      7.54%

</TABLE>

(1)  Except as noted below, each beneficial owner has sole voting power and sole
     investment power.
(2)  Based on 46,900,132 shares of Common Stock issued and outstanding on
     February 29, 2000.  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 and 1,500,000 shares represented by warrants issued to ING
     Capital.
(3)  Included are options for 250,000 shares exercisable on or within 60 days of
     February 29, 2000.
(4)  Includes the entire ownership of AMG Limited, a limited liability company
     of which Mr. Suttill is a member, as of February 29, 2000, of 935,550
     shares of Common Stock.
(5)  Does not include shares owned by Pecks, of which Mr. Cresci is a managing
     director.  For information with respect to such shares, see note (4) under
     "Security Ownership of Certain Beneficial Owners."
(6)  Included are 935,550 shares beneficially owned through AMG Limited and
     options for 414,667 shares exercisable on or within 60 days of February 29,
     2000.
*    Less than 1% of the outstanding Aviva 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:

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

                                       29
<PAGE>

          *10.10    Deposit Agreement dated September 15, 1994 between the
                    Company and Chemical Shareholder Services Group, Inc. (filed
                    as exhibit 10.29 to the Company's Registration Statement on
                    Form S-1, File No. 33-82072, and incorporated herein by
                    reference).
          *10.11    Letter from Ecopetrol dated December 28, 1994, accepting
                    relinquishment of Putumayo (filed as exhibit 10.38 to the
                    Company's annual report on Form 10-K for the year ended
                    December 31, 1994, File No. 0-22258, and incorporated herein
                    by reference).
          *10.12    Amendment to the Incentive and Nonstatutory Stock Option
                    Plan of the Company (filed as exhibit 10.4 to the Company's
                    quarterly report on Form 10-Q for the quarter ended
                    September 30, 1995, File No. 0-22258, and incorporated
                    herein by reference).
          *10.13    Santana Block B 25% relinquishment dated October 2, 1995
                    (filed as exhibit 10.51 to the Company's annual report on
                    Form 10-K for the year ended December 31, 1995, File No. 0-
                    22258, and incorporated herein by reference).
          *10.14    Aviva Petroleum Inc. 1995 Stock Option Plan, as amended
                    (filed as Appendix A to the Company's definitive Proxy
                    Statement for the Annual Meeting of Shareholders dated June
                    10, 1997, and incorporated herein by reference).
          *10.15    Restated Credit Agreement dated as of October 28, 1998,
                    between Neo Energy, Inc., Aviva Petroleum Inc. and ING
                    (U.S.) Capital Corporation (filed as exhibit 99.1 to the
                    Company's Form 8-K dated October 28, 1998, File No. 0-22258,
                    and incorporated herein by reference).
          *10.16    Joint Finance and Intercreditor Agreement dated as of
                    October 28, 1998, between Neo Energy, Inc., Aviva Petroleum
                    Inc., ING (U.S.) Capital Corporation, Aviva America, Inc.,
                    Aviva Operating Company, Aviva Delaware Inc., Garnet
                    Resources Corporation, Argosy Energy Incorporated, Argosy
                    Energy International, Garnet PNG Corporation, the Overseas
                    Private Investment Corporation, Chase Bank of Texas, N.A.
                    and ING (U.S.) Capital Corporation as collateral agent for
                    the creditors (filed as exhibit 99.2 to the Company's Form
                    8-K dated October 28, 1998, File No. 0-22258, and
                    incorporated herein by reference).
          *10.17    Amendment to the Santana Crude Sale and Purchase Agreement
                    dated February 16, 1999 (filed as exhibit 10.70 to the
                    Company's annual report on Form 10-K for the year ended
                    December 31, 1998, File No. 0-22258, and incorporated herein
                    by reference).
          **10.18   Amended and Restated Aviva Petroleum Inc. Severance Benefit
                    Plan dated December 31, 1999.
          **10.19   Santana Crude Sale and Purchase Agreement dated January 3,
                    2000.
          **10.20   Employment Agreement between the Company and Ronald Suttill
                    dated February 1, 2000.
          **10.21   Employment Agreement between the Company and James L. Busby
                    dated February 1, 2000.
          **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 did not file any Current Reports on Form 8-K during and
     subsequent to the end of the fourth quarter.

                                       30
<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          March 29, 2000
-------------------------    Officer and Director                --------------
Ronald Suttill               (principal executive officer)



/s/ James L. Busby           Treasurer and Secretary             March 29, 2000
-------------------------    (principal financial and            --------------
James L. Busby               accounting officer)



/s/ Eugene C. Fiedorek       Director                            March 29, 2000
-------------------------                                        --------------
Eugene C. Fiedorek



/s/ Robert J. Cresci         Director                            March 29, 2000
-------------------------                                        --------------
Robert J. Cresci

                                       31
<PAGE>

        INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES


                                                                        Page
                                                                        ----

Independent Auditors' Report.........................................     33

Consolidated Balance Sheet as of December 31, 1999 and 1998..........     34

Consolidated Statement of Operations for the years
     ended December 31, 1999, 1998 and 1997..........................     35

Consolidated Statement of Cash Flows for the years
     ended December 31, 1999, 1998 and 1997..........................     36

Consolidated Statement of Stockholders' Equity (Deficit) for
     the years ended December 31, 1999, 1998 and 1997................     37

Notes to Consolidated Financial Statements...........................     38

Supplementary Information Related to Oil and Gas Producing
     Activities (Unaudited)..........................................     49


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.

                                       32
<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, 1999 and 1998, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 1999, in conformity with generally accepted accounting
principles.

The accompanying financial statements have been prepared assuming that the
Company will continue as a going concern.  As discussed in Note 2 to the
financial statements, the Company has suffered recurring losses from operations
and has a net capital deficiency, which conditions raise substantial doubt about
its ability to continue as a going concern.  Management's plans in regard to
these matters are also described in Note 2.  The financial statements do not
include any adjustments that might result from the outcome of this uncertainty.


                                         /s/   KPMG LLP

Dallas, Texas
March 10, 2000

                                       33
<PAGE>

                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
                           Consolidated Balance Sheet
                           December 31, 1999 and 1998
                    (in thousands, except number of shares)

<TABLE>
<CAPTION>


                                                                   1999       1998
                                                               --------   --------
<S>                                                            <C>        <C>
ASSETS

Current assets:
 Cash and cash equivalents                                     $    846   $  1,712
 Restricted cash (note 5)                                             4        417
 Accounts receivable (note 9):
   Oil and gas revenue                                              716        363
   Trade                                                            633        554
   Other                                                            301        586
 Inventories                                                        724        836
 Prepaid expenses and other                                         236        627
                                                               --------   --------
   Total current assets                                           3,460      5,095
                                                               --------   --------

Property and equipment, at cost (note 5):
 Oil and gas properties and equipment (full cost method)         68,462     68,636
 Other                                                              584        612
                                                               --------   --------
                                                                 69,046     69,248
 Less accumulated depreciation, depletion
   and amortization                                             (65,081)   (64,440)
                                                               --------   --------
                                                                  3,965      4,808
Other assets (note 4)                                             1,561      1,519
                                                               --------   --------
                                                               $  8,986   $ 11,422
                                                               ========   ========
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)

Current liabilities:
 Current portion of long term debt (note 5)                    $ 14,495   $ 14,805
 Accounts payable                                                 3,081      5,526
 Accrued liabilities                                              1,024        308
                                                               --------   --------
   Total current liabilities                                     18,600     20,639
                                                               --------   --------
Gas balancing obligations and other (note 11)                     1,869      1,866

Stockholders' deficit (notes 5 and 7):
 Common stock, no par value, authorized 348,500,000 shares;
   issued 46,900,132 in 1999 and 46,700,132 shares in 1998        2,345      2,335
 Additional paid-in capital                                      34,855     34,862
 Accumulated deficit*                                           (48,683)   (48,280)
                                                               --------   --------
   Total stockholders' deficit                                  (11,483)   (11,083)

Commitments and contingencies (note 10)
                                                               --------   --------
                                                               $  8,986   $ 11,422
                                                               ========   ========
</TABLE>

*Accumulated deficit of $70,057 was eliminated at December 31, 1992 in
 connection with a quasi-reorganization. See note 7.

See accompanying notes to consolidated financial statements.

                                       34
<PAGE>

                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
                      Consolidated Statement of Operations
                  Years Ended December 31, 1999, 1998 and 1997
                     (in thousands, except per share data)
<TABLE>
<CAPTION>


                                                                           1999       1998       1997
                                                                        -------   --------   --------
<S>                                                                     <C>       <C>        <C>
Oil and gas sales (note 9)                                              $ 6,797   $  3,332   $  9,726
                                                                        -------   --------   --------

Expense:
 Production                                                               3,575      3,525      4,235
 Depreciation, depletion and amortization                                 1,000      3,152      6,067
 Write-down of oil and gas properties (note 1)                                -     12,343     19,953
 General and administrative                                               1,245      1,074      1,510
 Provision for (recovery of) losses on accounts
    receivable                                                             (101)       420          -
 Severance                                                                   62          -          -
                                                                        -------   --------   --------

   Total expense                                                          5,781     20,514     31,765
                                                                        -------   --------   --------

Other income (expense):
 Interest and other income (expense), net (note 6)                          259      1,045        122
 Interest expense                                                        (1,396)      (748)      (658)
                                                                        -------   --------   --------

   Total other income (expense)                                          (1,137)       297       (536)
                                                                        -------   --------   --------

   Loss before income taxes and extraordinary item                         (121)   (16,885)   (22,575)

Income (taxes) benefits (note 8)                                           (282)         4         93
                                                                        -------   --------   --------

   Loss before extraordinary item                                          (403)   (16,881)   (22,482)

Extraordinary item - debt extinguishment                                      -       (197)         -
                                                                        -------   --------   --------

   Net loss                                                             $  (403)  $(17,078)  $(22,482)
                                                                        =======   ========   ========

Weighted average common shares outstanding                               46,813     34,279     31,483
                                                                        =======   ========   ========

Basic and diluted net loss per common share                             $ (0.01)  $  (0.50)  $  (0.71)
                                                                        =======   ========   ========
</TABLE>

See accompanying notes to consolidated financial statements.

                                       35
<PAGE>

                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
                      Consolidated Statement of Cash Flows
                  Years Ended December 31, 1999, 1998 and 1997
                                 (in thousands)
<TABLE>
<CAPTION>
                                                           1999       1998       1997
                                                        -------   --------   --------
<S>                                                     <C>       <C>        <C>
Net loss                                                $  (403)  $(17,078)  $(22,482)
Adjustments to reconcile net loss to
 net cash provided by operating activities:
 Depreciation, depletion and amortization                 1,000      3,152      6,067
 Write-down of oil and gas properties                         -     12,343     19,953
 Provision for (recovery of) losses on accounts
    receivable                                             (101)       420          -
 Deferred foreign income taxes                                -          -       (692)
 Loss (gain) on sale of assets, net                         (11)         -         15
 Foreign currency exchange loss (gain), net                (193)        (1)        75
 Other                                                      247       (275)      (217)
 Changes in assets and liabilities:
   Escrow account                                           413       (417)         -
   Accounts receivable                                      120        825      1,934
   Inventories                                              112        195        118
   Prepaid expenses and other                                38       (196)        79
   Accounts payable and accrued liabilities              (1,703)       983     (3,119)
                                                        -------   --------   --------
     Net cash provided by (used in) operating
       activities                                          (481)       (49)     1,731
                                                        -------   --------   --------
Cash flows from investing activities:
 Property and equipment expenditures                       (285)    (1,405)    (2,757)
 Proceeds from sale of assets                                37          -         19
 Other                                                        -      1,421          -
                                                        -------   --------   --------
     Net cash provided by (used in) investing
       activities                                          (248)        16     (2,738)
                                                        -------   --------   --------
Cash flows from financing activities:
 Proceeds from long term debt                                 -      1,560          -
 Principal payments on long term debt                      (300)      (400)      (300)
 Other                                                        -        (97)         -
                                                        -------   --------   --------
     Net cash provided by (used in) financing
       activities                                          (300)     1,063       (300)
                                                        -------   --------   --------
Effect of exchange rate changes on cash and
 cash equivalents                                           163         (8)       (44)
                                                        -------   --------   --------

Net increase (decrease) in cash and cash equivalents       (866)     1,022     (1,351)
Cash and cash equivalents at beginning of year            1,712        690      2,041
                                                        -------   --------   --------

Cash and cash equivalents at end of year                $   846   $  1,712   $    690
                                                        =======   ========   ========
 </TABLE>

See accompanying notes to consolidated financial statements.

                                       36
<PAGE>

                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
           Consolidated Statement of Stockholders' Equity (Deficit)
                 Years Ended December 31, 1999, 1998 and 1997
                    (in thousands, except number of shares)
<TABLE>
<CAPTION>


                                      Common Stock
                                   ------------------  Additional                         Total
                                    Number of             Paid-in   Accumulated        Stockholders'
                                       Shares  Amount     Capital       Deficit      Equity (Deficit)
                                   ----------  ------  ----------   -----------      ----------------
<S>                                <C>         <C>     <C>          <C>              <C>
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

Issuance of common stock
 pursuant to amendments
 of credit agreement
 (note 5)                           1,200,000      60          49             -               109

Issuance of common stock
 pursuant to the acquisition of
 Garnet Resources Corporation
 (note 3)                          14,017,416     701       1,437             -             2,138

Net loss                                    -       -           -       (17,078)          (17,078)
                                   ----------  ------  ----------   -----------      ------------
Balances at
 December 31, 1998                 46,700,132   2,335      34,862       (48,280)          (11,083)


Issuance of common stock
 pursuant to investment
 banking agreement                    200,000      10          (7)            -                 3

Net loss                                    -       -           -          (403)             (403)
                                   ----------  ------  ----------   -----------          --------

Balances at
 December 31, 1999                 46,900,132  $2,345   $  34,855    $  (48,683)      $   (11,483)
                                   ==========  ======  ==========   ===========      ============
</TABLE>

See accompanying notes to consolidated financial statements.

                                       37
<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 principally one U.S. purchaser (See notes 9 and 12).

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

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

     Principles of Consolidation
     The consolidated financial statements include the accounts of Aviva
     Petroleum Inc. and its subsidiaries. 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
     $46,000 in 1999, $60,000 in 1998 and $127,000 in 1997.

     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 $1,479,000.

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

                                          1999       1998      1997
                                       -------   --------   -------
                    United States      $  1.10   $  27.00   $  7.32
                    Colombia           $  2.40   $   5.98   $ 11.59

     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. The Company recorded write-
     downs of $10,556,000 and

                                       38
<PAGE>

                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
            Notes to Consolidated Financial Statements (Continued)


     $1,787,000 to the carrying amounts of its Colombian and U.S. oil and gas
     properties, respectively, as a result of ceiling limitations on capitalized
     costs during 1998. In 1997, the Company recorded write-downs of $17,829,000
     and $2,124,000, respectively, to its Colombian and U.S. oil and gas
     properties. No such write-downs were required during 1999.

     Depletion expense and limits on capitalized costs are based on estimates of
     oil and gas reserves which are inherently imprecise and assume current
     prices for future net revenues. Accordingly, it is reasonably possible that
     the estimates of reserves quantities and future net revenues could differ
     materially in the near term from amounts currently estimated. Moreover, a
     future decrease in the prices the Company receives for its oil and gas
     production or downward reserve adjustments could, for the Colombian cost
     center, 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
     $553,000 and $532,000 were excluded from amortization at December 31, 1999
     and 1998, respectively.  Unevaluated properties are assessed quarterly to
     determine whether any impairment has occurred.  The unevaluated costs at
     December 31, 1999 represent exploration costs and were incurred primarily
     during the four-year period ended December 31, 1999. Such costs are
     expected to be evaluated and included in the amortization computation
     within the next three years.

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

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

     Interest Expense
     The Company capitalizes interest costs on qualifying assets, principally
     unevaluated oil and gas properties.  During 1999, 1998 and 1997, the
     Company capitalized $59,000, $29,000 and $91,000 of interest, respectively.

     Loss Per Common Share
     Basic earnings per share ("EPS") is computed by dividing income
     available to common shareholders by the weighted-average number of common
     shares outstanding for the period.  Diluted EPS reflects the potential
     dilution that could occur if securities or other contracts to issue common
     stock were exercised or converted into common stock or resulted in the
     issuance of common stock that then shared in the earnings of the entity.
     For the years presented herein, basic and diluted EPS are the same since
     the effects of potential common shares (notes 5 and 7) are antidilutive.

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

     Statement of Cash Flows
     The Company considers all highly liquid debt instruments with original
     maturities of three months or less to be cash equivalents.  The Company
     paid interest, net of amounts capitalized, of $547,000 in 1999, $860,000 in
     1998 and $641,000 in 1997 and paid income taxes of $201,000 in 1999,
     $117,000 in 1998 and $212,000 in 1997.

                                       39
<PAGE>

                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
            Notes to Consolidated Financial Statements (Continued)

     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.

     Comprehensive Income
     Effective January 1, 1998, the Company adopted Statement of Financial
     Accounting Standards No. 130, "Reporting Comprehensive Income" which
     establishes standards for reporting and display of comprehensive income in
     a full set of general-purpose financial statements. Comprehensive income
     includes net income and other comprehensive income which is generally
     comprised of changes in the fair value of available-for-sale marketable
     securities, foreign currency translation adjustments and adjustments to
     recognize additional minimum pension liabilities. For each period presented
     in the accompanying consolidated statement of operations, comprehensive
     income and net income are the same amount.

(2)  Liquidity

     During the last quarter of calendar year 1997 and throughout calendar year
     1998, world oil prices declined dramatically.  This decline in oil prices
     was particularly severe in Colombia.  Colombian oil prices, during the
     twenty-four month period ended December 31, 1998, fell from a high of
     $22.71 per barrel in January 1997 to $7.50 per barrel in December 1998.
     Whereas the sale price for crude oil from the Santana contract averaged
     $19.82 per barrel in 1996 and $17.39 per barrel in 1997, the sale price
     averaged $10.31 per barrel during calendar year 1998 and $15.57 per barrel
     during calendar year 1999.

     These price declines have materially and adversely affected the results of
     operations and the financial position of the Company.  During the years
     ended December 31, 1999, 1998 and 1997, the Company reported net losses of
     $0.4 million, $17.1 million and $22.5 million, respectively, and declining
     amounts of net cash provided by (used in) operating activities of $(0.5)
     million, $(0.05) million and $1.7 million, respectively. The Company's
     stockholders' deficit was approximately $11.5 million as of December 31,
     1999.

     Although world oil prices have recovered during the latter part of 1999,
     the Company remains highly leveraged with $14.5 million in current debt as
     of December 31, 1999, pursuant to bank credit facilities with ING (U.S.)
     Capital Corporation ("ING Capital") and the U.S. Overseas Private
     Investment Corporation ("OPIC"), as more fully described in note 5.

     The Company is not in compliance with various covenants under the bank
     credit facilities nor is it in compliance with the minimum escrow balance
     required thereunder. As a result, the lender has the right to accelerate
     payment on the debt and, therefore, the Company has classified all long-
     term debt as current in the December 31, 1999 consolidated balance sheet.
     Furthermore, the Company was unable to pay the principal payment of $5.7
     million due on April 30, 1999, and subsequent monthly principal payments of
     $281,250 (an aggregate of $7,950,000 through December 31, 1999). The
     Company did pay $150,000 of principal during the second quarter of 1999 and
     all of the interest through June 30, 1999; however, interest due subsequent
     to this date in the amount of $864,000 has not been paid. Assuming no
     change in its capital structure, the Company

                                       40
<PAGE>

                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
            Notes to Consolidated Financial Statements (Continued)

     will not have the financial resources to pay the $8,664,000 of principal
     and interest which is in arrears and future minimum monthly principal
     payments of $281,250 due through December 31, 2001.

     The Company's management has been in more or less continuous discussions
     with the Company's lenders regarding a restructuring of its debt for more
     than two years.  During that period, the Company has attempted to negotiate
     several transactions and has engaged financial advisers to locate equity
     investors to participate in recapitalization and debt restructuring
     transactions.  Except for the Garnet merger in October 1998, none of such
     proposals has come to fruition, primarily because of the inability of
     equity participants, lenders and the Company to agree on financial terms.

     Management of the Company is again in discussions with the Company's
     lenders and a group of investors concerning a restructuring of the Company.
     Such a restructuring may involve the sale of a substantial portion of the
     Company's oil and gas assets and a significant reduction of the Company's
     outstanding debt. While management is optimistic that a restructuring can
     be achieved that will provide the Company with the liquidity necessary to
     continue operations, there can be no assurance that this will be the case.

     Although management of the Company is pursuing the restructuring
     assiduously, its ability to effect such a restructuring is dependent upon
     the Company being able to reach an agreement between the Company, the
     Company's lenders and the potential investors, matters that are beyond the
     control of the Company.  The Company's lenders have not yet and may not
     ever agree to a restructuring of the Company's debt.  In addition, the
     potential investors may insist on financial terms that are viewed by the
     Company's board of directors as inconsistent with continued operations.  If
     the Company is unable to consummate a restructuring, then, in the absence
     of another business transaction, the Company cannot achieve compliance with
     or make payments required by the bank credit facilities.  Accordingly, the
     lenders could declare a default, accelerate all amounts outstanding, and
     attempt to realize upon the collateral securing the debt.  As a result of
     this uncertainty, management believes there is substantial doubt about the
     Company's ability to continue as a going concern.

(3)  Garnet Merger

     On October 28, 1998, the Company completed the merger of Garnet Resources
     Corporation ("Garnet") with one of the Company's subsidiaries.  As a result
     of the merger, the Company now owns over 99% of the Colombian joint
     operations.  Additionally, the Company now holds a 2% carried working
     interest in an oil and gas Petroleum Prospecting License in Papua New
     Guinea.

     The merger arrangements included Aviva refinancing Garnet's 99.24% owned
     subsidiary's net outstanding debt to Chase Bank of Texas, N.A. ("Chase")
     which is guaranteed by the U.S. Overseas Private Investment Corporation
     ("OPIC"), issuing approximately 1.1 million and 12.9 million new Aviva
     common shares to Garnet shareholders and Garnet debenture holders,
     respectively, and canceling Garnet's $15 million of 9.5% subordinated
     debentures due December 21, 1998. (See note 5 for further details.)

     The merger was accounted for as a "purchase" of Garnet for financial
     accounting purposes with Aviva's subsidiary as the surviving entity.  The
     purchase price of Garnet, approximately $9.9 million, consists of $2.4
     million related to the issuance of 14 million shares of Aviva's common
     stock at $0.167 per share plus merger costs and the assumption of
     approximately $6.0 million of net debt and $1.5 million of current and
     other liabilities.

     A summary of the assets acquired and liabilities assumed as of October 28,
     1998 follows (in thousands):

               Current assets                            $   1,659
               Oil and gas properties                        8,250
               Current liabilities                          (1,169)
               Long term debt                               (5,954)
               Other liabilities                              (346)
                                                         ---------
                  Fair value of net assets acquired      $   2,440
                                                         =========

                                       41
<PAGE>

                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
            Notes to Consolidated Financial Statements (Continued)

(4)  Other Assets

     A summary of other assets follows:
                                                             December 31
                                                         ------------------
                                                             (thousands)
                                                             1999      1998
                                                         --------  --------
     Abandonment funds for U.S. offshore properties      $  1,502  $  1,402
     Deferred financing charges                                55       113
     Other                                                      4         4
                                                         --------  --------
                                                         $  1,561  $  1,519
                                                         ========  ========

(5)  Long Term Debt

     On October 28, 1998, concurrently with the consummation of the Garnet
     merger, Neo Energy, Inc., an indirect subsidiary of the Company, and the
     Company entered into a Restated Credit Agreement with ING Capital.  ING
     Capital, Chase and OPIC also entered into a Joint Finance and Intercreditor
     Agreement (the "Intercreditor Agreement") with the Company.  ING Capital
     agreed to loan Neo Energy, Inc. an additional $800,000, bringing the total
     outstanding balance due ING Capital to $9,000,000.  The outstanding balance
     due to Chase was paid down to $6,000,000 from the $6,350,000 balance owed
     by Garnet prior to the merger.

     The Chase loan was unconditionally guaranteed by OPIC.  On September 1,
     1999, the Chase loan was assigned and transferred to OPIC pursuant to this
     guarantee.

     The ING Capital loan and the OPIC loan (the "Bank Credit Facilities") are
     guaranteed by the Company and its material domestic subsidiaries.  Both
     loans are also secured by the Company's consolidated interest in the
     Santana contract and related assets in Colombia, a first mortgage on the
     United States oil and gas properties of the Company and its subsidiaries, a
     lien on accounts receivable of the Company and its subsidiaries, and a
     pledge of the capital stock of the Company's subsidiaries.

     Borrowings under the ING Capital loan bear interest at the prime rate (as
     defined in the Restated Credit Agreement) plus 3% per annum.  Borrowings
     under the OPIC loan bear interest at 10.27% per annum.

     Borrowings under the Bank Credit Facilities are payable as follows:
     $5,700,000 in April 1999, and thereafter $281,250 per month until final
     maturity on December 31, 2001.  The terms of the Bank Credit Facilities,
     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.  As of December 31, 1999,
     the Company is not in compliance with various covenants under the Bank
     Credit Facilities.  Moreover, the Company did not pay the $5,700,000
     principal payment that was due April 30, 1999, and subsequent monthly
     principal payments of $281,250.  As a result, the lender has the right to
     accelerate payment on the debt and, therefore, the Company has classified
     all long-term debt as current in the December 31, 1999 consolidated balance
     sheet.

     The Company is also required to maintain an escrow account pursuant to the
     Bank Credit Facilities.  On March 31, 1999 and thereafter, the escrow
     account must contain the total of the following for the next succeeding
     three-month period: (i) the amount of the minimum monthly principal
     payments (as defined in the loan documents), plus (ii) the interest
     payments due on the combined loans, plus (iii) the amount of all fees due
     under the loan documents and under the Intercreditor Agreement.  The
     Company is not in compliance with the requirements of the escrow account.
     See management's plans to restructure the debt in note 2.

     Subsequent to consummation of the Garnet merger, Aviva issued to ING
     Capital 800,000 shares of Aviva common stock and warrants to purchase
     1,500,000 shares of Aviva common stock at an exercise price of $0.50 per
     share in payment of financial advisory fees. The 800,000 shares were valued
     at their quoted market value on October 28, 1998, the date on which the
     Bank Credit Facilities were consummated. The warrants were

                                       42
<PAGE>

                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
            Notes to Consolidated Financial Statements (Continued)

     valued using the Black-Scholes option-pricing model. Both amounts are
     included in debt extinguishment costs in the 1998 consolidated statement of
     operations.

(6)  Interest and Other Income (Expense)

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

<TABLE>
<CAPTION>
                                                                (thousands)
                                                         1999         1998         1997
                                                   ----------   ----------   ----------
          <S>                                      <C>          <C>          <C>
          Gain on settlement of litigation         $        -   $      720   $        -
          Interest income                                  94           70          138
          Foreign currency exchange gain (loss)           193            1          (75)
          Gain (loss) on sale of assets, net               11            -          (15)
          Other, net                                      (39)         254           74
                                                   ----------   ----------   ----------
                                                   $      259   $    1,045   $      122
                                                   ==========   ==========   ==========
</TABLE>

     In January 1998, the Company realized a $720,000 gain on the settlement of
     litigation involving the administration of a take or pay contract
     settlement.

(7)  Stockholders' Equity

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

     Stock Option Plans
     At December 31, 1999, the Company has two stock option plans, which are
     described below.  The Company applies APB Opinion No. 25 and related
     Interpretations in accounting for its plans.  Accordingly, no compensation
     cost has been recognized for its stock option plans.  Had compensation cost
     for the Company's stock option plans been determined consistent with FASB
     Statement No. 123, the Company's net loss and loss per share would have
     been increased to the pro forma amounts indicated below (in thousands,
     except per share data):

<TABLE>
<CAPTION>
                                           1999      1998       1997
                                           ----      ----       ----
<S>                         <C>          <C>      <C>        <C>

          Net loss          As reported  $ (403)  $(17,078)  $(22,482)

                            Pro forma    $ (413)  $(17,095)  $(22,506)

          Loss per share    As reported  $(0.01)  $  (0.50)  $  (0.71)

                            Pro forma    $(0.01)  $  (0.50)  $  (0.71)

</TABLE>

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

                                       43
<PAGE>

                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
            Notes to Consolidated Financial Statements (Continued)

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

     As a result of the adoption of the Current Plan, during 1995 the Company's
     former Incentive and Non-Statutory Stock Option Plan was terminated as to
     the grant of new options, but options then outstanding for 258,000 shares
     of the Company's common stock remain in effect as of December 31, 1999.

     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:

<TABLE>
<CAPTION>
                                            1999          1998          1997
                                            -----         -----         -----
     <S>                                    <C>           <C>           <C>
          Expected life (years)             10.0          10.0          10.0
          Risk-free interest rate            5.8%          4.8%          6.6%
          Volatility                        87.0%         77.0%         71.0%
          Dividend yield                     0.0%          0.0%          0.0%
</TABLE>

     A summary of the status of the Company's two fixed stock option plans as of
     December 31, 1999, 1998 and 1997, and changes during the years ended on
     those dates is presented below:

<TABLE>
<CAPTION>
                                               1999              1998               1997
                                      -----------------   -----------------   -----------------
                                               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                    1,148   $    .53      550   $   1.53      530   $   1.80
Granted                                    5        .01      675        .06       45        .52
Forfeited                                (81)       .74      (77)      3.60      (25)      4.95
                                      ------              ------              ------
Outstanding at
  end of year                          1,072        .51    1,148        .53      550       1.53
                                      ======              ======              ======
Options exercisable
  at year-end                            825                 655                 445
Weighted-average fair
  value of options
  granted during
  the year                            $  .01              $  .05              $  .42
</TABLE>

The following table summarizes information about fixed stock options outstanding
at December 31, 1999:

<TABLE>
<CAPTION>
                                            Options Outstanding                           Options Exercisable
                              --------------------------------------------------    ------------------------------
      Range                      Number       Weighted-Avg.                            Number
       of                     Outstanding       Remaining          Weighted-Avg.    Exercisable     Weighted-Avg.
Exercise Prices               at 12/31/99   Contractual Life      Exercise Price    at 12/31/99     Exercise Price
--------------------          -----------   -----------------     --------------    -----------     --------------
<S>                           <C>           <C>                   <C>               <C>             <C>
$   .01   to     .17             659,000        8.84 years           $   .06            422,167        $    .06
    .51   to     .98             163,000        5.12                     .81            153,000             .83
   1.08   to    2.71             250,000        3.24                    1.47            250,000            1.47
--------------------          ----------                                            -----------
$   .01   to    2.71           1,072,000        6.97                     .51            825,167             .63
====================          ==========                                            ===========

</TABLE>

                                       44
<PAGE>

                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
            Notes to Consolidated Financial Statements (Continued)

(8)  Income Taxes

     Income tax expense includes current Colombian income taxes (benefit)
     of $282,000 in 1999,  $(4,000) in 1998 and $587,000 in 1997 and deferred
     Colombian income taxes (benefit) of $-0- in 1999 and 1998 and $(692,000) in
     1997.  Income tax expense also includes state income taxes of $-0- in 1999
     and 1998 and $12,000 in 1997.

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

     The Company has deferred tax assets of $44,332,000 and $46,028,000 at
     December 31, 1999 and 1998, respectively, consisting principally of net
     operating loss carryforwards. The valuation allowance for deferred tax
     assets at January 1, 1997 was $36,126,000. The net change in the valuation
     allowance was a $1,696,000 decrease in 1999, a $3,975,000 increase in 1998
     and a $5,927,000 increase in 1997. 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, 1999, the Company and its subsidiaries have aggregate net
     operating loss carryforwards for U.S. federal income tax purposes of
     approximately $109,000,000, expiring from 2000 through 2019, which are
     available to offset future federal taxable income.  The utilization of a
     portion of these net operating losses is subject to an annual limitation of
     approximately $2,400,000 and a portion may only be utilized by certain
     subsidiaries of the Company.

(9)  Financial Instruments and Credit Risk Concentrations

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

     The carrying values of cash equivalents, accounts receivable and accounts
     payable approximate fair value due to the current maturities of these
     financial instruments.  The fair value of the Company's debt cannot be
     reasonably determined due to uncertainties surrounding the Company's
     ability to repay (see note 2).

     Ecopetrol has an option to purchase all of the Company's production in
     Colombia. For the years ended December 31, 1999, 1998 and 1997, Ecopetrol
     exercised that option and sales to Ecopetrol accounted for $5,683,000
     (83.6%), $2,632,000 (79.0%) and $7,405,000 (76.1%), respectively, of the
     Company's aggregate oil and gas sales.

     For the years ended December 31, 1998 and 1997, sales to one U.S.
     purchaser accounted for $479,000 (14.4%) and $1,516,000 (15.6%),
     respectively, of oil and gas sales.

(10) Commitments and Contingencies

     The Company is engaged in ongoing operations on the Santana contract in
     Colombia. The contract obligations have been met; however, the Company
     plans to recomplete certain existing wells and engage in various other
     projects. The Company's current share of the estimated future costs of
     these activities is approximately $0.6 million at December 31, 1999. Any
     substantial increase in the amount of the above referenced expenditures
     could adversely affect the Company's ability to meet these obligations.

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

                                       45
<PAGE>

                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
            Notes to Consolidated Financial Statements (Continued)

       to fund certain expenditures could result in the forfeiture of all or
       part of the Company's interest in this contract.

       On August 3, 1998, leftist Colombian guerrillas inflicted significant
       damage on the Company's oil processing and storage facilities at the Mary
       field, and to a lesser extent, at the Linda facilities. Since that time
       the Company has been subject to lesser attacks on its pipelines and
       equipment resulting in only minor interruptions of oil sales. The
       Colombian army guards the Company's operations; however, there can be no
       assurance that the Company's operations will not be the target of
       additional guerrilla attacks in the future. The damages resulting from
       the above referenced attacks were covered by insurance. There can be no
       assurance that such coverage will remain available or affordable.

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

       Activities of the Company with respect to the exploration, development
       and production of oil and natural gas are subject to stringent foreign,
       federal, state and local environmental laws and regulations, including
       but not limited to the Oil Pollution Act of 1990, the Outer Continental
       Shelf Lands Act, the Federal Water Pollution Control Act, the Resource
       Conservation and Recovery Act and the Comprehensive Environmental
       Response, Compensation, and Liability Act. Such laws and regulations have
       increased the cost of planning, designing, drilling, operating and
       abandoning wells. In most instances, the statutory and regulatory
       requirements relate to air and water pollution control procedures and the
       handling and disposal of drilling and production wastes. Although the
       Company believes that compliance with environmental laws and regulations
       will not have a material adverse effect on the Company's future
       operations or earnings, risks of substantial costs and liabilities are
       inherent in oil and gas operations and there can be no assurance that
       significant costs and liabilities, including 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 2002. Rent expense relating to the lease was $94,000,
       $90,000 and $83,000 for 1999, 1998 and 1997, respectively. Future minimum
       payments under the lease are: 2000 - $102,000; 2001 - $102,000; and
       2002 - $9,000.

(11)   Gas Balancing

       As of December 31, 1999 and 1998, 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, 1999 and 1998, the Company had sold
       net gas with a volume equivalent of approximately 441,000 MCF and 444,000
       MCF (with an estimated value of $708,000 and $725,000 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.

                                       46
<PAGE>

                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
            Notes to Consolidated Financial Statements (Continued)

(12)   Geographic Area Information

       The Company is engaged in the business of exploring for, developing and
       producing oil and gas in the United States and Colombia. Information
       about the Company's operations in different geographic areas as of and
       for the years ended December 31, 1999, 1998 and 1997 follows:

<TABLE>
<CAPTION>

       (Thousands)
                                                       United
                                                       States   Colombia     Total
                                                      -------   --------   -------
<S>                                                   <C>       <C>        <C>
       1999
       ----
       Oil and gas sales                              $ 1,114   $  5,683   $ 6,797
                                                      -------   --------   -------

       Expense:
         Production                                     1,173      2,402     3,575
         Depreciation, depletion and amortization          59        941     1,000
         General and administrative                     1,148         97     1,245
         Recovery of losses on accounts receivable       (101)         -      (101)
         Severance                                          -         62        62
                                                      -------   --------   -------
                                                        2,279      3,502     5,781
                                                      -------   --------   -------


         Interest and other income (expense), net         154        105       259
         Interest expense                                (397)      (999)   (1,396)
                                                      -------   --------   -------

         Income (loss) before income taxes             (1,408)     1,287      (121)
         Income taxes                                       -       (282)     (282)
                                                      -------   --------   -------

         Net earnings (loss)                          $(1,408)  $  1,005   $  (403)
                                                      =======   ========   =======

         Total assets                                 $ 1,908   $  7,078   $ 8,986
                                                      =======   ========   =======
</TABLE>

                                       47
<PAGE>

                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
            Notes to Consolidated Financial Statements (Continued)
<TABLE>
<CAPTION>

(Thousands)
                                                         United
                                                         States   Colombia      Total
                                                        -------   --------   --------
<S>                                                     <C>       <C>        <C>
1998
----
Oil and gas sales                                       $   700   $  2,632   $  3,332
                                                        -------   --------   --------
Expense:
     Production                                           1,259      2,266      3,525
     Depreciation, depletion and amortization             1,556      1,596      3,152
     Write-down of oil and gas properties                 1,787     10,556     12,343
     General and administrative                           1,042         32      1,074
     Provision for losses on accounts receivable            420          -        420
                                                        -------   --------   --------
                                                          6,064     14,450     20,514
                                                        -------   --------   --------


Interest and other income (expense), net                    768        277      1,045
Interest expense                                           (346)      (402)      (748)
                                                        -------   --------   --------

Loss before income taxes and extraordinary item          (4,942)   (11,943)   (16,885)
Income tax benefit                                            -          4          4
                                                        -------   --------   --------


Loss before extraordinary item                           (4,942)   (11,939)   (16,881)
Extraordinary item - debt extinguishment                      -       (197)      (197)
                                                        -------   --------   --------

Net loss                                                $(4,942)  $(12,136)  $(17,078)
                                                        =======   ========   ========

Total assets                                            $ 3,002   $  8,420   $ 11,422
                                                        =======   ========   ========

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)
                                                        =======   ========   ========

Total assets                                            $ 4,110   $ 12,335   $ 16,445
                                                        =======   ========   ========
</TABLE>

                                       48
<PAGE>

                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
     Supplementary Information Related to Oil and Gas Producing Activities
                                  (Unaudited)

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

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

<TABLE>
<CAPTION>

(Thousands)
                                           United
                                           States      Colombia       Total
                                         ---------    ----------    ---------
<S>                                      <C>        <C>         <C>
December 31, 1999
-----------------

Unevaluated oil and gas properties       $     175    $      379    $     554
Proved oil and gas properties               13,199        54,709       67,908
                                         ---------    ----------    ---------

  Total capitalized costs                   13,374        55,088       68,462

Less accumulated depreciation
  depletion and amortization                13,992        50,600       64,592
                                         ---------    ----------    ---------

  Capitalized costs, net                 $    (618)   $    4,488    $   3,870
                                         =========    ==========    =========


December 31, 1998
-----------------

Unevaluated oil and gas properties       $     158    $      374    $     532
Proved oil and gas properties               13,114        54,990       68,104
                                         ---------    ----------    ---------

  Total capitalized costs                   13,272        55,364       68,636

Less accumulated depreciation,
  depletion and amortization                13,947        49,947       63,894
                                         ---------    ----------    ---------

  Capitalized costs, net                 $    (675)   $    5,417    $   4,742
                                         =========    ==========    =========
</TABLE>

                                       49
<PAGE>

                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
     Supplementary Information Related to Oil and Gas Producing Activities
                            (Unaudited) (Continued)

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

<TABLE>
<CAPTION>

(Thousands)
                                        United
                                        States   Colombia      Total
                                      --------   --------   --------
<S>                                   <C>        <C>        <C>
1999
----

Exploration                           $     17   $     41   $     58
Development                                 85         81        166
                                      --------   --------   --------
  Total costs incurred                $    102   $    122   $    224
                                      ========   ========   ========

1998
----

Exploration                           $     15   $    136   $    151
Development                              1,039        209      1,248
Acquisition of Garnet properties             -      8,250      8,250
                                      --------   --------   --------
  Total costs incurred                $  1,054   $  8,595   $  9,649
                                      ========   ========   ========

1997
----

Exploration                           $     25   $    470   $    495
Development                                176      2,085      2,261
                                      --------   --------   --------
  Total costs incurred                $    201   $  2,555   $  2,756
                                      ========   ========   ========
</TABLE>

                                       50
<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 and gas reserves in Colombia and the United States
were determined by independent petroleum engineers, Huddleston & Co., Inc. and
Netherland, Sewell & Associates, Inc., respectively.  The figures presented are
estimates of reserves which may be expected to be recovered commercially at
current prices and costs.  Estimates of proved developed reserves include only
those reserves which can be expected to be recovered through existing wells with
existing equipment and operating methods.  Estimates of proved undeveloped
reserves include only those reserves which are expected to be recovered on
undrilled acreage from new wells which are reasonably certain of production when
drilled or from presently existing wells which could require relatively major
expenditures to effect recompletion.

<TABLE>
<CAPTION>


                                            Changes in the Estimated Quantities of Reserves
                                            -----------------------------------------------
                                                  United
                                                  States           Colombia           Total
                                            ------------      ------------     ------------
<S>                                         <C>              <C>               <C>
Year ended December 31, 1999
----------------------------

Oil (Thousands of barrels)
Proved reserves:
  Beginning of period                                  8             2,352            2,360
  Revisions of previous estimates                    193               221              414
  Discoveries and extensions                           -                 -                -
  Sales of reserves                                    -                 -                -
  Production                                         (57)             (365)            (422)
                                            ------------      ------------     ------------

  End of period                                      144             2,208            2,352
                                            ============      ============     ============

Proved developed reserves, end of period             144             2,208            2,352
                                            ============      ============     ============

Gas (Millions of cubic feet)
Proved reserves:
  Beginning of period                                  4                 -                4
  Revisions of previous estimates                    150                 -              150
  Discoveries and extensions                           -                 -                -
  Sales of reserves                                    -                 -                -
  Production                                         (53)                -              (53)
                                            ------------      ------------     ------------

  End of period                                      101                 -              101
                                            ============      ============     ============

Proved developed reserves, end of period             101                 -              101
                                            ============      ============     ============

</TABLE>

                                       51
<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, 1998
----------------------------

Oil (Thousands of barrels)
Proved reserves:
  Beginning of period                                195             1,476            1,671
  Revisions of previous estimates                   (143)             (200)            (343)
  Acquisition of Garnet                                -             1,331            1,331
  Production                                         (44)             (255)            (299)
                                            ------------      ------------     ------------

  End of period                                        8             2,352            2,360
                                            ============      ============     ============

Proved developed reserves, end of period               8             2,352            2,360
                                            ============      ============     ============

Gas (Millions of cubic feet)
Proved reserves:
  Beginning of period                              1,119                 -            1,119
  Revisions of previous estimates                 (1,047)                -           (1,047)
  Production                                         (68)                -              (68)
                                            ------------      ------------     ------------

  End of period                                        4                 -                4
                                            ============      ============     ============

Proved developed reserves, end of period               4                 -                4
                                            ============      ============     ============
</TABLE>

                                       52
<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, 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>

                                       53
<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, 1999:
---------------------

Future gross revenues                       $      3,708      $     53,112     $     56,820
Future production costs                           (2,792)          (15,195)         (17,987)
Future development costs, including
  abandonment of U.S. offshore platforms            (970)           (1,075)          (2,045)
                                            ------------      ------------     ------------
Future net cash flows before
  income taxes                                       (54)           36,842           36,788
Future income taxes                                    -                 -                -
                                            ------------      ------------     ------------
Future net cash flows after
  income taxes                                       (54)           36,842           36,788

Discount at 10% per annum                            171            (8,699)          (8,528)
                                            ------------      ------------     ------------
Standardized measure of discounted
  future net cash flows                     $        117      $     28,143     $     28,260
                                            ============      ============     ============


At December 31, 1998:
---------------------

Future gross revenues                       $         78      $     17,645     $     17,723
Future production costs                              (77)          (10,242)         (10,319)
Future development costs, including
  abandonment of U.S. offshore platforms            (969)             (570)          (1,539)
                                            ------------      ------------     ------------
Future net cash flows before
  income taxes                                      (968)            6,833            5,865
Future income taxes                                    -                 -                -
                                            ------------      ------------     ------------
Future net cash flows after
  income taxes                                      (968)            6,833            5,865

Discount at 10% per annum                            136            (1,382)          (1,246)
                                            ------------      ------------     ------------
Standardized measure of discounted
  future net cash flows                     $       (832)     $      5,451     $      4,619
                                            ============      ============     ============
</TABLE>

                                       54
<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, 1997:
---------------------

Future gross revenues                       $      6,009      $     21,124     $     27,133
Future production costs                           (3,548)           (7,709)         (11,257)
Future development costs, including
  abandonment of U.S. offshore platforms            (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>

                                       55
<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)
                                                         1999              1998             1997
                                                 ------------      ------------     ------------
<S>                                              <C>               <C>              <C>

Sales of oil and gas, net of production costs    $     (3,222)     $        192     $     (5,491)
Sales of reserves in place                                  -                 -                -
Development costs incurred that reduced
  future development costs                                  -                 -              801
Accretion of discount                                     462             1,142            4,547
Discoveries and extensions                                  -                 -                -
Purchase of reserves in place                               -             2,998                -
Revisions of previous estimates:
  Changes in price                                     24,161            (9,585)         (24,154)
  Changes in quantities                                 4,103              (539)          (7,054)
  Changes in future development costs                     297              (448)           1,175
  Changes in timing and other changes                  (2,160)             (561)          (3,878)
  Changes in estimated income taxes                         -                 -              874
                                                 ------------      ------------     ------------

  Net increase (decrease)                              23,641            (6,801)         (33,180)

Balances at beginning of year                           4,619            11,420           44,600
                                                 ------------      ------------     ------------

Balances at end of year                          $     28,260      $      4,619     $     11,420
                                                 ============      ============     ============
</TABLE>

                                       56
<PAGE>

                               INDEX TO EXHIBITS
                                                                   Sequentially
                                                                     Numbered
Number                 Description of Exhibit                          Page
------                 ----------------------                      ------------

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

<PAGE>

                               INDEX TO EXHIBITS
                                                                   Sequentially
                                                                     Numbered
Number                 Description of Exhibit                          Page
------                 ----------------------                      ------------

 *10.12   Amendment to the Incentive and Nonstatutory Stock Option
          Plan of the Company (filed as exhibit 10.4 to the
          Company's quarterly report on Form 10-Q for the quarter
          ended September 30, 1995, File No. 0-22258, and
          incorporated herein by reference).
 *10.13   Santana Block B 25% relinquishment dated October 2, 1995
          (filed as exhibit 10.51 to the Company's annual report on
          Form 10-K for the year ended December 31, 1995, File
          No. 0-22258, and incorporated herein by reference).
 *10.14   Aviva Petroleum Inc. 1995 Stock Option Plan, as amended
          (filed as Appendix A to the Company's definitive Proxy
          Statement for the Annual Meeting of Shareholders dated
          June 10, 1997, and incorporated herein by reference).
 *10.15   Restated Credit Agreement dated as of October 28, 1998,
          between Neo Energy, Inc., Aviva Petroleum Inc. and ING
          (U.S.) Capital Corporation (filed as exhibit 99.1 to the
          Company's Form 8-K dated October 28, 1998, File
          No. 0-22258, and incorporated herein by reference).
 *10.16   Joint Finance and Intercreditor Agreement dated as of
          October 28, 1998, between Neo Energy, Inc., Aviva
          Petroleum Inc., ING (U.S.) Capital Corporation, Aviva
          America, Inc., Aviva Operating Company, Aviva Delaware
          Inc., Garnet Resources Corporation, Argosy Energy
          Incorporated, Argosy Energy International, Garnet PNG
          Corporation, the Overseas Private Investment Corporation,
          Chase Bank of Texas, N.A. and ING (U.S.) Capital
          Corporation as collateral agent for the creditors (filed
          as exhibit 99.2 to the Company's Form 8-K dated
          October 28, 1998, File No. 0-22258, and incorporated
          herein by reference).
 *10.17   Amendment to the Santana Crude Sale and Purchase
          Agreement dated February 16, 1999 (filed as exhibit 10.70
          to the Company's annual report on Form 10-K for the year
          ended December 31, 1998, File No. 0-22258, and
          incorporated herein by reference).
**10.18   Amended and Restated Aviva Petroleum Inc. Severance
          Benefit Plan dated December 31, 1999.
**10.19   Santana Crude Sale and Purchase Agreement dated January 3, 2000.
**10.20   Employment Agreement between the Company and Ronald Suttill dated
          February 1, 2000.
**10.21   Employment Agreement between the Company and James L. Busby dated
          February 1, 2000.
**21.1    List of subsidiaries of Aviva Petroleum Inc.
**27.1    Financial Data Schedule.


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