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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, 1998
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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
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Title of each class on which registered
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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 American Stock Exchange has advised the Company that it will delist the
Company's Depositary Shares, each of which represents five shares of Company
Common Stock, 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 26, 1999 was approximately $1,763,000.
As of such date, the last sale price on the American Stock Exchange of a
Depositary Share representing five shares of Common Stock, without par value
("Common Stock"), was U.S. $0.20, and the middle market price of Common Stock on
the London Stock Exchange Limited was U.K. 5.5 pence.
As of February 26, 1999, 46,700,132 shares of Registrant's Common Stock were
outstanding, of which 24,354,215 shares of Common Stock were represented by
Depositary Shares.
DOCUMENTS INCORPORATED BY REFERENCE
None.
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TABLE OF CONTENTS TO FORM 10-K
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Part I
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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....................................... 13
Item 3. Legal Proceedings........................................... 14
Item 4. Submission of Matters to a Vote of Security Holders......... 14
Part II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters
Price Range of Depositary Shares and Common Stock......... 15
Dividend History and Restrictions......................... 16
Item 6. Selected Financial Data..................................... 17
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations
Results of Operations..................................... 18
Year 2000................................................. 20
New Accounting Pronouncements............................. 21
Liquidity and Capital Resources........................... 21
Item 7A. Quantitative and Qualitative Disclosure about Market Risk... 23
Item 8. Financial Statements and Supplementary Data................. 23
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure................................... 23
Part III
Item 10. Directors and Executive Officers of the Registrant
Directors of the Company.................................. 24
Executive Officers of the Company......................... 24
Meetings and Committees of the Board of Directors......... 25
Compliance with Section 16(a) of the Securities Exchange
Act of 1934.............................................. 25
Item 11. Executive Compensation
Summary Compensation Table................................ 26
Directors' Fees........................................... 26
Option Grants During 1998................................. 26
Option Exercises During 1998 and Year End Option Values... 26
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TABLE OF CONTENTS TO FORM 10-K (CONTINUED)
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Compensation Committee Interlocks and Insider
Participation in Compensation Decisions...................... 27
Employment Contracts......................................... 27
Compensation Committee Report on Executive Compensation...... 27
Performance Graph............................................ 28
Item 12. Security Ownership of Certain Beneficial Owners and Management
Security Ownership of Certain Beneficial Owners.............. 29
Security Ownership of Management............................. 30
Item 13. Certain Relationships and Related Transactions................. 30
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K....................................................... 31
Signatures............................................................... 36
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PART I
IMPORTANT INFORMATION
GOING CONCERN RISK
If the Company is unable to consummate the merger discussed herein, then, in
the absence of another business transaction or debt restructuring, the Company
cannot maintain 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 has been traded on the London Stock Exchange Limited
(the "London Stock Exchange") since 1982. Depositary shares ("Depositary
Shares"), each representing the beneficial ownership of five shares of Common
Stock, have traded on the Primary List of the American Stock Exchange since May
31, 1995, and prior to that on the Emerging Company Marketplace of the American
Stock Exchange since November 14, 1994. The Company's principal executive
offices are located in Dallas, Texas, and the Company maintains a 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 new $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 has an
interest in the same properties.
Current Operations
Colombia. The Company is the owner of interests in, and is engaged in
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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 thirteen
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 totaled approximately 14.1 million barrels during the
period from April 1992, when production commenced, through December 1998.
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.
The contracts for the La Fragua concession, which adjoined Santana to the
north, and the Yuruyaco concession, which adjoined Santana and La Fragua to the
east, were approved by Ecopetrol in June 1992 and September 1995, respectively.
The acquisition of all seismic data required under these contracts was
completed. The Company determined, however, that further exploration on these
concessions was not technically justified and the concessions were formally
relinquished in December 1998.
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Each concession is governed by a separate contract with Ecopetrol. Generally,
the contracts cover a 28-year period and require certain exploration
expenditures in the early years of the contract and, in the later years of the
contract, permit exploitation of reserves that have been found. All of the
contracts provide that Ecopetrol shall receive, on behalf of the Colombian
Ministry of Mines, royalty payments in the amount of 20% of the gross proceeds
of the oil produced pursuant to the respective contract, less certain costs of
transporting the oil to the point of sale. Under each of the contracts,
application must be made to Ecopetrol for a declaration of commerciality for
each discovery. If Ecopetrol declares the discovery commercial, it has the right
to a 50% reversionary interest in the field and is required to pay 50% of all
future costs. If, alternatively, Ecopetrol declines to declare the discovery
commercial, 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 concession agreements) 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
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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
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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
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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
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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 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."
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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 substantially recovered through insurance, there can be no
assurance that such coverage will remain available or affordable. The Colombian
army guards the Company's operations, however, there can be no assurance that
the Company's operations will not be the target of significant guerrilla attacks
in the future.
United States. The Company's activities in the United States are subject to a
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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 13 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
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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, 1998, the Company received
the majority of its revenue from Ecopetrol. Sales to Ecopetrol accounted for
$2,632,000, or 79.0% of oil and gas revenue for 1998, $7,405,000, or 76.1% of
oil and gas revenue for 1997 and $9,437,000, or 68.6% of oil and gas revenue for
1996, representing the Company's entire Colombian oil revenue. If Ecopetrol
were to elect not to purchase the Company's Colombian oil production, the
Company believes that other purchasers could be found for such production.
United States. The Company does not refine or otherwise process domestic
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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, 1997 and 1996, 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, $1,516,000, or 15.6% of oil and gas revenue for
1997 and $1,609,000, or 11.7% of oil and gas revenue for 1996. If this
purchaser were to elect not to purchase the Company's oil and gas production,
the Company believes that other purchasers could be found for such production.
General. Oil and gas are the Company's only products. There is substantial
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uncertainty as to the prices that the Company may receive for production from
its existing oil and gas reserves or from oil and gas reserves, if any, which
the Company may discover or purchase. It is possible that under market
conditions prevailing in the future, the production and sale of oil or gas, if
any, from the Company's properties in Papua New Guinea may not be commercially
feasible. The availability of a ready market and the prices received for oil and
gas produced depend upon numerous factors beyond the control of the Company
including, without limitation, adequate transportation facilities (such as
pipelines), marketing of competitive fuels, fluctuating market demand,
governmental regulation and world political and economic developments. World oil
and gas markets are highly volatile and shortage or surplus conditions
substantially affect prices. As a result, there have been dramatic swings in
both oil and gas prices in
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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,
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federal, state, and local laws and regulations governing the discharge of
materials into the environment or otherwise relating to environmental
protection. These laws and regulations may require the acquisition of a permit
by operators before drilling commences; restrict the types, quantities, and
concentration of various substances that can be released into the environment in
connection with drilling and production activities; limit or prohibit drilling
activities on certain lands lying within wilderness areas, wetlands, and other
protected areas; require remedial measures to mitigate pollution from former
operations, such as plugging and abandoning wells; and impose substantial
liabilities for pollution resulting from the Company's operations. The
regulatory burden on the oil and gas industry increases the cost of doing
business and consequently affects its profitability. Changes in environmental
laws and regulations occur frequently, and any changes that result in more
stringent and costly waste handling, disposal, remedial, drilling, or
operational requirements could have a material adverse impact on the operating
costs of the Company, as well as significantly impair the Company's ability to
compete with larger, more highly capitalized companies. Management believes
that the Company is in substantial compliance with current applicable
environmental laws and regulations and that continued compliance with existing
requirements will not have a material adverse impact on the Company's
operations, capital expenditures, and earnings. Management further believes,
however, that risks of substantial costs and liabilities are inherent in oil and
gas operations, and there can be no assurance that significant costs and
liabilities, including 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
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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 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
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currently in substantial compliance with U.S. federal, state, and local
environmental laws and regulations. Over the past year, 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, 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 ("OPA '90") and regulations thereunder impose a
variety of requirements on "responsible parties" related to the prevention of
oil spills and liability for damages resulting from such spills in waters of the
United States. A "responsible party" includes the owner or operator of an
onshore facility, vessel or pipeline, or the lessee or permittee of the area in
which an offshore facility is located. OPA '90 assigns liability to each
responsible party for oil spill removal costs and a variety of public and
private damages from oil spills. While liability 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
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currently unaware of any oil spills for which the Company has been designated as
a responsible party under OPA '90 and that will have a material adverse impact
on the Company or its operations. OPA '90 also imposes ongoing requirements on
facility operators, such as the preparation of an oil spill contingency plan.
The Company has such plans in place.
With amendments to OPA '90 signed into law by President Clinton on October 19,
1996, OPA '90 now requires owners and operators of offshore facilities that have
a worst case oil spill of more than 1,000 barrels to demonstrate financial
responsibility in amounts ranging from $10 million in specified state waters to
$35 million in federal outer continental shelf waters, with higher amounts of up
to $150 million in certain limited circumstances where the U.S. Minerals
Management Service ("MMS") believes such a level is justified by the risks posed
by the quantity or quality of oil that is handled by the facility. The
Company's two U.S. properties, Main Pass Block 41 field, a federal lease on the
outer continental shelf ("OCS") offshore Louisiana, and Breton Sound Block 31
field, on state leases offshore Louisiana, are subject to OPA '90 as amended.
On August 11, 1998, the MMS promulgated a final rule implementing these OPA '90
financial responsibility requirements. The Company believes that it currently
has established adequate proof of financial responsibility for its offshore
facilities. However, the Company cannot predict whether these financial
responsibility requirements under the OPA '90 amendments or the 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. In connection with these regulations,
however, the EPA also issued an administrative order that effectively delayed
compliance with the no discharge requirement for produced water until January 1,
1997. Effective August 27, 1996, the Louisiana Department of Environmental
Quality ("LDEQ") officially assumed responsibility for compliance and
enforcement issues for produced water as they relate to the Company's Breton
Sound Block 31 facilities with the EPA operating in an oversight capacity. 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, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
that are considered responsible for the release of a "hazardous substance" into
the environment. These persons include the owner or operator of the disposal
site or sites where the release occurred and companies that disposed or arranged
for the disposal of hazardous substances found at the site. Persons who are or
were responsible for releases of hazardous substances under CERCLA may be
subject to joint and several liability for the costs of cleaning up the
hazardous substances that have been released into the environment and for
damages to natural resources, and it is not uncommon for neighboring landowners
and other third parties to file claims for personal injury, property damage and
recovery of response costs allegedly caused by the hazardous substances released
into the environment. The Company has not received any notification nor is it
otherwise aware of circumstances indicating that it may be potentially
responsible for cleanup costs under CERCLA.
The federal Resource Conservation and Recovery Act ("RCRA") and comparable
state statutes regulate the storage, treatment and disposal of wastes, including
hazardous wastes. The EPA and various state agencies have limited the approved
methods of disposal for certain hazardous and nonhazardous wastes, thereby
making such disposal more costly. Furthermore, certain wastes generated by the
Company's oil and natural gas operations that are currently exempt from
treatment as hazardous wastes may in the future be designated as hazardous
wastes and therefore be subject to more rigorous and costly operating and
disposal requirements.
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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.
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 recently proposed to amend such regulations to prohibit
the flaring of liquid hydrocarbons and oil without prior authorization.
Similarly, the MMS has promulgated other regulations governing the plugging and
abandonment of wells located offshore and the removal of all production
facilities. To cover the various obligations of lessees on the OCS, the MMS
generally requires that lessees post substantial bonds or other acceptable
assurances that such obligations will be met. The cost of such bonds or other
surety can be substantial and there is no assurance that bonds or other surety
6
<PAGE>
can be obtained in all cases. Under certain circumstances, the MMS may require
Company operations on federal leases to be suspended or terminated. Any such
suspension or termination could materially and adversely affect the Company's
financial condition and operations.
The MMS has issued a notice of proposed rulemaking in which it proposes to
amend its regulations governing the calculation of royalties and the valuation
of crude oil produced from federal leases. This proposed rule would modify the
valuation procedures for both arm's length and non-arm's length crude oil
transactions to decrease reliance on oil posted prices and assign a value to
crude oil that better reflects its market value, establish a new MMS form for
collecting differential data, and amend the valuation procedure for the sale of
federal royalty oil. The Company cannot predict what action the MMS will take
on this matter, nor can it predict how the Company will be affected by any
change to this regulation. The MMS has recently approved its intention to issue
a proposed rule that would require all but the smallest producers to be capable
of reporting production information electronically.
The MMS recently implemented a final rule that describes the types of
transportation components that are deductible for calculating and reporting
royalties, as well as various cost components associated with marketing
functions that are not deductible. In particular, under the rule, the MMS will
not allow deduction of costs associated with marketer fees, cash out and other
gas pipeline imbalance penalties, or long-term storage fees. The Company cannot
predict at this time how it might be affected by implementation of the new rule.
Finally, the MMS is conducting an inquiry (not specifically directed at the
Company) into certain contractual agreements from which producers on MMS leases
have received settlement proceeds that are royalty bearing and the extent to
which producers have paid the appropriate royalties on those proceeds. The
Company believes that this inquiry will not have a material adverse impact on
its financial condition, liquidity or results of operations.
Sales of crude oil, condensate and gas liquids by the Company are not
currently regulated and are made at market prices. Effective as of January 1,
1995, the FERC implemented regulations establishing an indexing system for
transportation rates for oil that could increase the cost of transporting oil to
the purchaser. The Company is not able to predict what effect, if any, this
order will have on it, but other factors being equal, it may tend to increase
transportation costs or reduce wellhead prices for crude oil.
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 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 Mining and Petroleum, 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
7
<PAGE>
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, 1998, Aviva had 65 full-time employees including 7 in the
United States and 58 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, 1998. "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
----------- ---- ---------- ---
1998 United States - - - -
Colombia - - - -
----------- ---- ---------- ---
Total - - - -
=========== ==== ========== ===
1997 United States - - - -
Colombia 0.5 - - -
----------- ---- ---------- ---
Total 0.5 - - -
=========== ==== ========== ===
1996 United States 0.4 - - -
Colombia 0.3 - - 0.3
----------- ---- ---------- ---
Total 0.7 - - 0.3
=========== ==== ========== ===
In the above table, a productive well is an exploratory or development well
that is not a dry well. A dry well is an exploratory or a development well
found to be incapable of producing either oil or gas in commercial quantities.
A development well is a well drilled within the proved area of an oil and gas
reservoir to the depth of a stratigraphic horizon known to be productive. An
exploratory well is any well that is not a development well.
Undeveloped Acreage
The Company's undeveloped acreage in Colombia is held pursuant to 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, 1998. 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
9
<PAGE>
interests generally created in connection with their acquisition, liens incident
to operating agreements, liens for current taxes and other burdens and minor
liens, encumbrances, easements and restrictions. The Company believes that none
of such burdens materially detracts from the value of such properties or its
interest therein or will materially interfere with the use of the properties in
the operation of the Company's business.
Federal Leases
The Company conducts a portion of its operations on federal oil and gas leases
and therefore must comply with numerous additional regulatory restrictions,
including certain nondiscrimination statutes. Certain of the Company's
operations on federal leases must be conducted pursuant to appropriate permits
or approvals issued by various federal agencies. Pursuant to certain federal
leases, approval of certain operations must be obtained from one or more
government agencies prior to the commencement of such operation. Federal leases
are subject to extensive regulation. See "Item 1. Business -- Regulation."
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, 1998, that is not the same as that included in the estimate of
proved oil and gas reserves as of December 31, 1998, 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,
-----------------------
1998 1997 1996
------ ------ -------
Oil (1) United States 44 76 94
Colombia 255 426 476
Gas United States 68 316 1,146
Colombia - - -
(1) Includes crude oil and condensate.
10
<PAGE>
The average sales price per barrel of oil and per thousand cubic feet ("MCF")
of gas produced by the Company and the average production (lifting) cost per
dollar of oil and gas revenue and per barrel of oil equivalent (6 MCF: 1 barrel)
were as follows for the years indicated:
<TABLE>
<CAPTION>
Year ended December 31, (1)
---------------------------
1998 1997 1996
------ ------ ------
<S> <C> <C> <C> <C>
Average sales price per barrel of oil (2) United States $12.03 $19.17 $20.68
Colombia $10.31 $17.39 $19.82
Average sales price per MCF of gas United States $ 2.42 $ 2.73 $ 2.07
Colombia $ - $ - $ -
Average production cost per dollar of
oil and gas revenue United States $ 1.80 $ 0.54 $ 0.45
Colombia $ 0.86 $ 0.40 $ 0.31
Average production cost per barrel of
oil equivalent United States $22.54 $ 9.81 $ 6.76
Colombia $ 8.88 $ 6.98 $ 6.11
</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
producing 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 1999.
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 9 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
11
<PAGE>
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 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.
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 commercialization 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 commercialization fee
of $0.165 per barrel. In 1998, Ecopetrol exported the crude each month and the
sales price averaged $10.31 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 and Neo 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.
12
<PAGE>
Main Pass Block 41 is a federal lease located approximately 25 miles east of
Venice, Louisiana, in 50 feet of water. There are currently five productive
wells in the field. The field's 1998 production averaged 30 barrels of oil per
day and 119 MCF per day, net to the Company's interest, from six completions in
four sands between 6,000 and 7,500 feet. The Company owns a 35% interest in
this field.
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 1998, six wells averaged 92 barrels of oil per day and 49 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 merger with Sharpe
Resources Corporation. 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 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.
According to the terms of the agreement governing PPL-206, the parties agreed
to perform surface geological work and complete a seismic program during late
1997 and early 1998. These activities have been completed and a decision
regarding the drilling of an exploratory well in late 1999 will be made
following the final evaluations of the geological work and 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.
13
<PAGE>
ITEM 3. LEGAL PROCEEDINGS
There are no legal proceedings to which the Company is a party or to which its
properties are subject which are, in the opinion of management, likely to have a
material adverse effect on the Company's results of operations or financial
condition.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Special Meeting in lieu of the 1998 Annual Meeting of Shareholders of
Aviva Petroleum Inc. was held on October 20, 1998, pursuant to notice, at which
the following persons were elected directors of the Company to serve until the
next annual meeting of the shareholders or until their successors are elected
and qualify:
For Against Abstain
---------- ------- -------
Ronald Suttill 24,333,447 26,323 14,334
Eugene C. Fiedorek 24,339,712 19,738 14,654
In addition the following proposals were approved by the shareholders:
The issuance of common stock of the Company pursuant to the Agreement and Plan
of Merger dated as of June 24, 1998, providing for the merger of an indirect,
wholly owned subsidiary of the Company with and into Garnet Resources
Corporation was passed with 20,633,550 votes in favor, 14,675 votes against,
23,545 votes abstaining and 3,702,334 broker non-votes.
The re-appointment of KPMG LLP as independent auditors of the Company for
fiscal year 1998 was passed with 24,346,043 votes in favor, 13,656 votes
against and 14,405 votes abstaining.
The text of the above proposals is incorporated by reference to Aviva's Proxy
Statement for the Special Meeting in lieu of the 1998 Annual Meeting of
Shareholders dated October 20, 1998, filed with the Securities and Exchange
Commission ("SEC") on Form S-4.
14
<PAGE>
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
Price Range of Depositary Shares and Common Stock
The Company's Depositary Shares, each representing the beneficial ownership of
five shares of Common Stock, have traded on the Primary List of the American
Stock Exchange since May 31, 1995 and prior to that on the Emerging Company
Marketplace of the American Stock Exchange since November 14, 1994 (collectively
the "ASE"). In addition, the Company's Common Stock has been traded on the
London Stock Exchange since 1982 and has been quoted in the National Quotation
Bureau's Daily Quotation Sheets (known as the "pink sheets") since December
1993.
In August 1998, the ASE notified the Company that it had initiated a review of
Aviva's listing eligibility in light of the Company's continued net losses and
financial difficulties. On October 27, 1998, the Company was informed by the
ASE of its intention to delist Aviva's Depositary Shares. The Company appealed
this decision, however on March 25, 1999, the ASE advised the Company that it
will delist the Company's Depositary Shares effective as of April 9, 1999. When
the Depositary Shares cease to be listed on the ASE, the Depositary Shares will
become subject to Rule 15g-9 under the Exchange Act. This Rule (the "Penny Stock
Rule") imposes additional sales practice requirements on broker-dealers that
sell such securities to persons other than established customers and "accredited
investors" (generally, individuals with a net worth in excess of $1,000,000 or
annual incomes exceeding $200,000, or $300,000 together with their spouses). For
transactions covered by Rule 15g-9, a broker-dealer must make a special
suitability determination for the purchaser and have received the purchaser's
written consent to the transaction prior to the sale. Consequently, such rule
may affect the ability of the broker-dealer to sell the Company's securities and
may affect the ability of purchasers to sell any of the Company's securities in
the secondary market. During 1998, an aggregate of 2,751,000 Depositary Shares
were traded on the ASE.
The following table sets forth, for the periods indicated and subject to the
following qualifications, the high and low prices for the Depositary Shares on
the ASE and the high and low prices for the Common Stock on the London Stock
Exchange.
In the United Kingdom, the average daily trading volume of the Common Stock on
the London Stock Exchange during 1998 was approximately 11,000 shares. The
London Stock Exchange prices indicated in the table are the middle market prices
for the Common Stock as published in the Daily Official List and do not
represent actual transactions. Prices on the London Stock Exchange are
expressed in British pounds sterling, and, accordingly, the prices for the
Common Stock traded on the London Stock Exchange included in the following table
are similarly expressed. For ease of reference, these prices are also expressed
in U.S. dollars, having been converted using the exchange rate in effect on the
first day on which the stock price attained the high or low price indicated.
15
<PAGE>
<TABLE>
<CAPTION>
1998 1997 1996
---------------------- ---------------------- -----------------------
High Low High Low High Low
---- --- ----- --- ---- ---
<S> <C> <C> <C> <C> <C> <C>
ASE
- ---
Depositary Shares (1)
- ---------------------
First Quarter $1.75 $1.00 $4.13 $2.88 $ 4.38 $3.88
Second Quarter $1.19 $0.69 $3.00 $1.63 $11.38 $3.50
Third Quarter $1.00 $0.13 $4.13 $1.63 $ 6.25 $3.00
Fourth Quarter $0.31 $0.06 $2.06 $0.98 $ 5.75 $3.00
London Stock Exchange
- ---------------------
Common Stock
- ------------
First Quarter
(Pounds) (Pounds)0.28 (Pounds)0.12 (Pounds)0.42 (Pounds)0.28 (Pounds)0.46 (Pounds)0.34
US$ $0.45 $0.20 $0.69 $0.45 $ 0.71 $0.52
Second Quarter
(Pounds) (Pounds)0.14 (Pounds)0.10 (Pounds)0.32 (Pounds)0.27 (Pounds)0.41 (Pounds)0.25
US$ $0.22 $0.16 $0.51 $0.44 $ 0.63 $0.38
Third Quarter
(Pounds) (Pounds)0.10 (Pounds)0.05 (Pounds)0.30 (Pounds)0.21 (Pounds)0.34 (Pounds)0.25
US$ $0.17 $0.08 $0.50 $0.34 $ 0.53 $0.38
Fourth Quarter
(Pounds) (Pounds)0.06 (Pounds)0.04 (Pounds)0.25 (Pounds)0.17 (Pounds)0.41 (Pounds)0.28
US$ $0.10 $0.07 $0.40 $0.28 $ 0.67 $0.43
</TABLE>
(1) Representing five shares of Common Stock.
As of February 26, 1999, the Company had approximately 5,800 shareholders of
record, including nominees for an undetermined number of beneficial holders.
Dividend History and Restrictions
No dividends have been paid since June 1983, nor is there any current
intention on the part of the directors of the Company to pay dividends in the
future.
Furthermore, in 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."
16
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
The following table summarizes certain selected financial data with respect to
the Company for, and as of the end of, each of the five years ended December 31,
1998, which should be read in conjunction with the Consolidated Financial
Statements included elsewhere herein.
<TABLE>
<CAPTION>
For the Years Ended
December 31,
-------------------------------------------------------
1998 1997 1996 1995 1994
------- -------- ------- ------- ---------
(in thousands, except per share, per barrel and per MCF data)
<S> <C> <C> <C> <C> <C>
For the period
Revenues $ 3,332 $ 9,726 $13,750 $10,928 $ 8,546
Loss before extraordinary
item $(16,881) $(22,482) $ (937) $(2,689) $(2,460)
Extraordinary item -
debt extinguishment $ (197) $ - $ - $ - $ -
Net loss $(17,078) $(22,482) $ (937) $(2,689) $(2,460)
Loss before extraordinary
item per common share $ (0.49) $ (0.71) $ (0.03) $ (0.09) $ (0.08)
Basic and diluted net loss
per common share $ (0.50) $ (0.71) $ (0.03) $ (0.09) $ (0.08)
Weighted average
shares outstanding 34,279 31,483 31,483 31,483 31,483
Cash dividends per
common share $ - $ - $ - $ - $ -
Total annual net oil
production (barrels)
Colombia 255 426 476 435 250
United States 44 76 94 106 99
-------- -------- ------- ------- -------
Total 299 502 570 541 349
-------- -------- ------- ------- -------
Total annual net gas
production (MCF)
United States 68 316 1,146 1,184 1,839
Average price per barrel
of oil
Colombia $ 10.31 $ 17.39 $ 19.82 $ 16.39 $ 13.60
United States $ 12.03 $ 19.17 $ 20.68 $ 16.78 $ 15.40
Average price per MCF of
Gas - United States $ 2.42 $ 2.73 $ 2.07 $ 1.70 $ 1.97
At period end
Total assets $ 11,422 $ 16,445 $42,944 $45,460 $42,383
Long term debt, including
current portion $ 14,805 $ 7,690 $ 7,990 $13,067 $ 6,640
Stockholders' equity
(deficit) $(11,083) $ 3,748 $26,230 $27,167 $29,856
</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).
17
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
The following discussion and analysis should be read in conjunction with the
Consolidated Financial Statements included elsewhere herein.
Results of Operations
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
barrel in 1997. In 1998 prices have been 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.
Depreciation, depletion and amortization ("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.
18
<PAGE>
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.
General and administrative ("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.
1997 versus 1996
- ----------------
United States Colombia
Oil Gas Oil Total
------ ------- ------- --------
(Thousands)
Revenue - 1996 $1,940 $ 2,373 $ 9,437 $13,750
Volume variance (366) (1,782) (995) (3,143)
Price variance (115) 223 (1,037) (929)
Other - 48 - 48
------ ------- ------- -------
Revenue - 1997 $1,459 $ 862 $ 7,405 $ 9,726
====== ======= ======= =======
Colombian oil volumes were 426,000 barrels in 1997, a decrease of 50,000
barrels from 1996. Such decrease resulted from a 68,000 barrel decrease due to
the Company's net revenue interest declining from 18% to 12.6% in June 1996 when
cumulative production from the Santana concession reached the 7 million barrel
threshold specified in the risk-sharing contract, and a 119,000 barrel decrease
resulting from normal production declines, partially offset by a 136,000 barrel
increase primarily due to the completion of two development wells in the latter
part of 1996 and one development well completed in June 1997.
U.S. oil volumes were 76,000 barrels in 1997, down 18,000 barrels from 1996.
This decrease resulted primarily from the sale of the Company's U.S. onshore
properties on December 23, 1996. U.S. gas volumes before gas balancing
adjustments were 274,000 MCF in 1997, down 862,000 MCF from 1996. Such decrease
is the result of an 896,000 MCF decrease resulting from the U.S. onshore
property sale, and normal production declines partially offset by new production
from a development well completed at Main Pass 41 during October 1996.
Colombian oil prices averaged $17.39 per barrel during 1997. The average
price for the same period in 1996 was $19.82 per barrel. The Company's average
U.S. oil price decreased to $19.17 per barrel in 1997, down from $20.68 in 1996.
U.S. gas prices averaged $2.73 per MCF in 1997 compared to $2.07 per MCF in
1996.
In addition to the above-mentioned variances, U.S. gas revenue increased
approximately $48,000 as a result of gas balancing adjustments.
Operating costs decreased by $599,000, or 12%. Of such decrease,
approximately $845,000 resulted from the sale of the U.S. onshore properties,
offset by a $181,000 increase for the U.S. offshore properties and a $65,000
increase for the Colombian properties.
DD&A decreased $1.3 million, or 17%, mainly due to lower production levels.
19
<PAGE>
The Company recorded write-downs to the carrying amounts of its U.S. and
Colombian oil and gas properties of $2,124,000 and $17,829,000, respectively,
during 1997. The U.S. write-down was primarily due to lower prices. The
Colombian write-down resulted primarily from lower prices and, to a somewhat
lesser extent, downward revisions of proved oil reserves.
G&A expense decreased $44,000 mainly due to reductions in the number of
employees, officers, directors and related fees and expenses which resulted in
cost savings of approximately $262,000 during 1997. These savings were
partially offset by increases in legal and consulting fees aggregating $201,000.
Interest and other income (expense) decreased mainly due to the absence in
1997 of a $641,000 gain recorded in 1996 relating to the sale of the U.S.
onshore oil and gas properties.
Interest expense was $156,000 lower, primarily as a result of lower average
balances outstanding.
Income taxes were lower in 1997 primarily due to Colombian deferred tax
benefits resulting from the write-down of the carrying amount of the Company's
Colombian oil and gas properties.
Year 2000
The Year 2000 problem is the inability of a meaningful proportion of the
world's computers, software applications and embedded semiconductor chips to
cope with the change of the year from 1999 to 2000. This issue can be traced to
the infancy of computing, when computer data and programs were designed to save
memory space by truncating the date field to just six digits (two for the day,
two for the month and two for the year). Such information applications
automatically assume that the two-digit year field represents a year within the
20th century. As a result of this, systems could fail to operate or fail to
produce correct results.
The Year 2000 problem affects computers, software applications, and related
equipment used, operated or maintained by the Company. Accordingly, the Company
is currently assessing the potential impact of, and the costs of remediating,
the Year 2000 problem for its internal systems and on facilities and equipment.
The Company's business is substantially dependent upon the operations of
computer systems, and as such, the Company has established a committee made up
of leaders from the operational areas of the Company. The committee has the
involvement of senior management and its objectives are high priority.
The Company is in the process of identifying the computers, software
applications, and related equipment used in connection with its operations that
must be modified, upgraded or replaced to minimize the possibility of a material
disruption of its business. The Company has commenced the process of modifying,
upgrading and replacing systems which have already been assessed as adversely
affected by the Year 2000 problem, and expects to complete this process by the
end of the third quarter of 1999.
In addition to computers and related systems, the operation of office
equipment, such as fax machines, copiers, telephone switches, security systems
and other common devices may be affected by the Year 2000 problem. The Company
is currently assessing the potential effect of, and costs of remediating, the
Year 2000 problem on its office systems and equipment. The Company has initiated
communications with third party suppliers of computers, software, and other
equipment used, operated or maintained by the Company to identify and, to the
extent possible, to resolve issues involving the Year 2000 problem. However,
the Company has limited or no control over the actions of these third party
suppliers. Thus, while the Company expects that it will be able to resolve any
significant Year 2000 problems with these systems, there can be no assurance
that these suppliers will resolve any or all Year 2000 problems with these
systems before the occurrence of a material disruption to the business of the
Company. Any failure of these third parties to timely resolve Year 2000
problems with their systems could have a material adverse effect on the
Company's business, financial condition, and results of operations.
Because the Company's assessment is not complete, it is unable to accurately
predict the total cost to the Company of completing any required modifications,
upgrades, or replacements of its systems or equipment. The Company does not,
however, believe that such total cost will exceed $200,000. The Company expects
to identify and resolve all Year 2000 problems that could materially adversely
affect its business operations. However, management believes that it is not
possible to determine with complete certainty that all Year 2000 problems
affecting the Company, its purchasers or its suppliers have been identified or
corrected. The number of devices that could be
20
<PAGE>
affected and the interactions among these devices are simply too numerous. In
addition, no one can accurately predict how many Year 2000 problem-related
failures will occur or the severity, duration, or financial consequences of
these perhaps inevitable failures. As a result, management expects that the
Company will likely suffer the following consequences: (i) a significant number
of operational inconveniences and inefficiencies for the Company, its purchasers
and its suppliers will divert management's time and attention and financial and
human resources from its ordinary business activities; (ii) a few serious system
failures that will require significant effort by the Company, its purchasers or
its suppliers to prevent or alleviate material business disruptions; (iii)
several routine business disputes and claims due to Year 2000 problems that will
be resolved in the ordinary course of business; and (iv) possible business
disputes alleging that the Company failed to comply with the terms of its
contracts or industry standards of performance, some of which could result in
litigation.
The Company will develop contingency plans to be implemented if its efforts to
identify and correct Year 2000 problems affecting its operational systems and
equipment are not effective. The Company plans to complete its contingency
plans by the end of the second quarter of 1999. Depending on the systems
affected, any contingency plans developed by the Company, if implemented, could
have a material adverse effect on the Company's financial condition and results
of operations.
The discussion of the Company's efforts, and management's expectations,
relating to Year 2000 compliance are forward-looking statements. The Company's
ability to achieve Year 2000 compliance and the level of incremental costs
associated therewith, could be adversely impacted by, among other things, the
availability and cost of programming and testing resources, vendors' ability to
modify proprietary software, and unanticipated problems identified in the
ongoing compliance review.
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, 1999. 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 2000.
Liquidity and Capital Resources
21
<PAGE>
During the last quarter of calendar year 1997 and throughout calendar year
1998, world oil prices have declined dramatically. This decline in oil prices
has been particularly severe in Colombia. Colombian oil prices have, during the
twenty-four month period ended December 31, 1998, fallen 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.
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, 1998, 1997 and 1996, the Company reported net losses of $17.1
million, $22.5 million and $0.9 million, respectively, and declining amounts of
net cash provided by (used in) operating activities of $(0.05) million, $1.7
million and $8.9 million, respectively. As of December 31, 1998, the Company's
stockholders' deficit was approximately $11.1 million.
The Company is highly leveraged with $14.8 million in current debt as of
December 31, 1998, pursuant to bank credit facilities with ING (U.S.) Capital
Corporation ("ING Capital") and Chase Bank of Texas, N.A. ("Chase"), as more
fully described in note 5 to the consolidated financial statements contained
elsewhere herein.
As of December 31, 1998, the Company is not in compliance with various
covenants under the bank credit facilities. Furthermore, assuming no change in
its capital structure, the Company does not have the financial resources to
maintain the minimum escrow balance required under the bank credit facilities
beginning March 31, 1999, nor to pay the minimum monthly principal payments of
$5.7 million on April 30, 1999, and $281,250 each month thereafter until
December 31, 2001. Management of the Company is in discussions with the
Company's lenders to restructure the above-referenced debt as set forth below.
On February 22, 1999, the Company signed a letter of intent to merge with
Sharpe Resources Corporation ("Sharpe"), a publicly traded oil and gas
exploration and production company incorporated in Ontario, Canada. Sharpe
currently has onshore oil and gas production in the United States from working
and overriding royalty interests in over 115 wells on 107 properties in 4 states
which include Texas, Oklahoma, New Mexico and Wyoming. Sharpe's offshore Gulf
of Mexico production is from its operated interests in Matagorda One and
Matagorda Two properties located offshore Matagorda Island, Texas in 48 feet of
water. Sharpe's principal office is located in Houston, Texas.
The proposed arrangements contemplate that Sharpe will be the parent company
following the merger, that each six shares of Company Common Stock will be
converted into one share of Sharpe Common Stock, and that the Company's lenders
will restructure the Company's indebtedness to them. Such debt restructuring may
include the conversion of a portion of the debt to a preferred stock position in
the merged entity.
The proposed arrangements are subject to numerous and substantial
contingencies, the most important of which are: (i) completion of negotiations
between the Company and Sharpe regarding the structure of the proposed
transaction; (ii) preparation, negotiation, execution and delivery of a
definitive merger agreement; (iii) approval of the definitive merger agreement
and consent to the proposed debt restructuring by the Company's lenders (i.e.,
ING Capital, Chase and the Overseas Private Investment Corporation); approval of
the debt restructuring arrangements by the board of directors of the Company;
and approval of the definitive merger agreement by the boards of directors and
stockholders of the Company and Sharpe. The proposed merger is subject to
preparation, negotiation, execution and delivery of definitive debt
restructuring agreements between the Company and its lenders.
Management believes that the consummation of this merger will provide the
combined companies with the ability to raise additional capital which is
necessary to continue operations and proceed with certain development and
exploration activities that management believes are essential to the survival of
the Company.
While management of the Company is pursuing the reorganization of the Company
assiduously, its ability to effect such a reorganization is dependent upon the
acquiesence of the Company's lenders and Sharpe, matters that are beyond the
control of the Company. In particular, the Company's lenders must: (i) consent
to waive the defaults of the Company under its bank credit facilities pending
preparation, negotiation, execution and delivery of a definitive merger
agreement and a definitive debt restructuring agreement and pending receipt of
stockholder approvals of the definitive merger agreement; (ii) agree to debt
restructuring arrangements that are acceptable to Sharpe; and (iii) negotiate,
execute and deliver a definitive debt restructuring agreement. The Company's
lenders have not yet and may not ever agree to a restructuring of the Company's
debt. If the Company is unable to consummate the merger, then, in the absence of
another business transaction or debt restructuring, the Company cannot maintain
compliance with nor make principal payments required by the bank credit
facilities and, accordingly, the lenders could declare a default,
22
<PAGE>
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 1996 through 1998, costs incurred in oil and gas property
acquisition, exploration and development activities by the Company totaled
approximately $21.1 million. Of this figure, approximately $2.0 million was for
exploration predominantly in Colombia, $10.8 million pertained to development
costs in the United States (41%) and Colombia (59%), 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 - 1998 - $(0.05)
million; 1997 - $1.7 million; and 1996 - $8.9 million; (ii) net cash provided
by investing activities (before property and equipment expenditures) - 1998 -
$1.4 million; 1997 - $0.02 million; and 1996 - $2.7 million; and (iii) net cash
provided by (used in) financing activities - 1998 - $1.1 million; 1997 - $(0.3)
million; and 1996 - $(5.1) million.
The Company may recomplete certain existing wells and engage in various other
projects in Colombia. The Company's share of the estimated future costs of
these development activities is approximately $0.6 million at December 31, 1998.
Failure to fund certain expenditures could result in the forfeiture of all or
part of the Company's interest in the concessions.
The Company will most likely fund the recompletion of certain wells through
arrangements with service companies whereby the services are paid for with
proceeds from the sale of incremental oil production. Any miscellaneous projects
will be funded through cash provided from operations. Any substantial decreases
in the borrowing base as hereinafter defined or increases in the amounts of
these required expenditures could adversely affect the Company's ability to fund
these 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, 1998 would be immaterial.
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.
23
<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.
<TABLE>
<CAPTION>
NAME AGE POSITIONS DIRECTOR SINCE
- ---- --- --------- --------------
<S> <C> <C> <C>
Ronald Suttill 67 President, Chief Executive Officer 1985
and Director
Eugene C. Fiedorek 67 Director 1997
Robert J. Cresci 55 Director 1998
</TABLE>
The following sets forth the periods during which directors have served as
such and a brief account of the business experience of such persons during at
least the past five years.
RONALD SUTTILL has been a director of the Company since August 1985 and has
been President and Chief Executive Officer of the Company since January 1992.
In December 1991, Mr. Suttill was appointed President and Chief Operating
Officer and prior to that served as Executive Vice President of the Company.
EUGENE C. FIEDOREK has been a director of the Company since July 1997. Mr.
Fiedorek is a Managing Director of EnCap Investments, L.C., a company he co-
founded in 1988. He was previously associated with RepublicBank Dallas for more
than 20 years, most recently as the Managing Director in the Energy Department
in charge of all energy-related commercial lending and corporate finance
activities. Prior to joining RepublicBank, Mr. Fiedorek was with Shell Oil
Company as an Exploitation Engineer. Mr. Fiedorek currently serves on the
boards of Energy Capital Investment Company PLC, Apache Corporation and
privately held Matador Petroleum Corporation.
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 Bridgeport Machines, Inc., EIS International, Inc., Sepracor,
Inc., Arcadia Financial, Ltd., Hitox, Inc., Meris Laboratories, Inc., Film
Roman, Inc., Educational Medical, Inc., Source Media, Inc., Castle Dental
Centers, Inc., Candlewood Hotel Co., Inc., SeraCare, Inc. 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, 67 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.
24
<PAGE>
James L. Busby, 38 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 six meetings during 1998. 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 two meetings
during 1998.
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 1998.
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,
1998, all of the Reporting Persons complied with their Section 16(a) filing
requirements.
25
<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 Bonus sation Award(s) Options/ Payouts Compensa-
Position Year ($) ($) ($) ($) SARs (#) ($) tion ($)
- --------- ---- ------- -------- ------- ---------- ------------ ------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Ronald Suttill(1)
President and CEO 1998 157,500 - - - - - 4,750
President and CEO 1997 185,000 - - - - - 4,750
President and CEO 1996 200,000 - - - - - 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
Mr. Fiedorek received $5,000 for his services as a director in 1998.
Beginning April 1, 1998, directors are no longer paid a cash fee. Directors
are, however, reimbursed for travel and lodging expenses. Mr. Suttill receives
no compensation as a director but is reimbursed for travel and lodging expenses
incurred to attend meetings.
On July 1 each year, non-employee directors who have served in such capacity
for at least the entire proceeding calendar year each receives an option to
purchase 5,000 shares of the Company's Common Stock pursuant to the Aviva
Petroleum Inc. 1995 Stock Option Plan, as amended.
Option Grants During 1998
There were no options granted to the Named Executive Officer during 1998. No
stock appreciation rights have been issued by the Company.
Option Exercises During 1998 and Year End Option Values
The following table provides information related to options exercised by the
Named Executive Officer during 1998 and the number and value of options held at
year-end. No stock appreciation rights have been issued by the Company.
<TABLE>
<CAPTION>
Number of Securities Value of Unexercised
Underlying Unexercised In-the-Money Options
Options at FY-End (#) at FY-End ($) (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>
(1) No values are ascribed to unexercised options of the Named Executive Officer
at December 31, 1998 because the fair market value of a share of the
Company's Common Stock at December 31, 1998 ($0.02) did not exceed the
exercise price of any such options.
26
<PAGE>
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. Until this committee was originally
appointed in 1993, the compensation of the executive officers was established by
the Board of Directors as a whole, including Mr. Suttill.
Employment Contracts
Each executive officer serves at the discretion of the Board of Directors,
except that, effective in January 1995, the Company entered into an employment
contract with Mr. Suttill. Mr. Suttill's contract provides for annual
compensation of not less than $200,000 if his employment is terminated for any
reason other than death, disability or cause, as defined in the contract. Mr.
Suttill's contract was automatically renewed for one-year periods on January 1,
1996, 1997, 1998 and 1999.
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 1998 was comprised of
salary, stock options and matching employer contributions made pursuant to the
Company's 401(k) Plan. The Company's 401(k) Plan is generally available to all
employees after one year of service. The Company makes matching contributions
of 50% of the amount deferred by the employee, up to 3% of an employee's annual
salary. There were no bonuses paid to the executive officers during or for
1998.
Compensation Committee
E. C. Fiedorek
R. J. Cresci
27
<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 1993 1994 1995 1996 1997 1998
AVIVA PETROLEUM INC. 100.0 122.62 104.76 92.86 39.29 2.38
INDUSTRY INDEX 100.0 104.80 115.26 153.26 155.34 124.43
BROAD MARKET 100.0 88.33 113.86 120.15 144.57 142.61
28
<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 26, 1999.
<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 11.28%
411 West Putnam Avenue
Greenwich, Connecticut 06830
Pecks Management Partners Ltd. (4) 5,155,108 10.70%
One Rockefeller Plaza
New York, New York 10020
Lehman Brothers Inc.(5) 2,966,876 6.16%
3 World Financial Center
11th Floor
New York, NY 10285
ING (U.S.) Capital Corporation(6) 2,700,000 5.60%
135 East 57th Street
New York, New York 10022
Yale University(7) 2,551,886 5.29%
230 Prospect Street
New Haven, CT 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 46,700,132 shares of the Common Stock issued and outstanding on
February 26, 1999, 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.
29
<PAGE>
Security Ownership of Management
The following table sets forth certain information as of February 26, 1999,
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) 4.36%
8235 Douglas Avenue, Suite 400
Dallas, TX 75225
Eugene C. Fiedorek 916,542 1.88%
3811 Turtle Creek Blvd., Suite 1080
Dallas, TX 75219
Robert J. Cresci 0(5) *
Pecks Management Partners Ltd.
One Rockefeller Plaza
New York, NY 10020
All directors and executive officers
as a group (4 persons) 3,640,566(6) 7.45%
</TABLE>
(1) Except as noted below, each beneficial owner has sole voting power and sole
investment power.
(2) Based on 46,700,132 shares of Common Stock issued and outstanding on
February 26, 1999. 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 26, 1999.
(4) Includes the entire ownership of AMG Limited, a limited liability company of
which Mr. Suttill is a member, as of February 26, 1999, 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 341,333 shares exercisable on or within 60 days of February 26,
1999.
* Less than 1% of the outstanding Aviva Common Stock.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
30
<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 Agreement of Withdrawal from Argosy dated September 16, 1987 by
and among Argosy, Neo, and Argosy Energy Incorporated, as
general partners; and Parkside Investments, Richard Shane
McKnight, Douglas W. Fry, P-5 Ltd., GO-DEO, Inc., Dale E.
Armstrong, Richard Shane McKnight, The Yvonne McKnight Trust,
and William Gaskin, as limited partners (filed as exhibit 10.5
to the Company's Registration Statement on Form10, File No. 0-
22258, and incorporated herein by reference).
*10.6 Option Agreement dated September 16, 1987 between the general
and limited partners of Argosy and Neo (filed as exhibit 10.6 to
the Company's Registration Statement on Form10, File No. 0-
22258, and incorporated herein by reference).
*10.7 Escrow Agreement between Argosy, Neo, Overseas Private
Investment Corporation and The Chase Manhattan Bank dated March
15, 1988 and amended on May 31, 1990 (filed as exhibit 10.7 to
the Company's Registration Statement on Form10, File No. 0-
22258, and incorporated herein by reference).
31
<PAGE>
*10.8 Santana Block A Relinquishment dated March 6, 1990 between
Ecopetrol, Argosy and Neo (filed as exhibit 10.8 to the
Company's Registration Statement on Form10, File No. 0-22258,
and incorporated herein by reference).
*10.9 Purchase Sale - Transportation and Commercialization of the
Santana Crude between Ecopetrol, Argosy and Neo (filed as
exhibit 10.9 to the Company's Registration Statement on Form10,
File No. 0-22258, and incorporated herein by reference).
*10.10 La Fragua Association Contract dated June 1, 1992 between
Ecopetrol, Argosy and Neo (filed as exhibit 10.10 to the
Company's Registration Statement on Form10, File No. 0-22258,
and incorporated herein by reference).
*10.11 Operating Agreement for the La Fragua Area between Argosy
and Neo dated April 15, 1992 (filed as exhibit 10.11 to the
Company's Registration Statement on Form10, File No. 0-22258,
and incorporated herein by reference).
*10.12 Employment Agreement between the Company and Ronald Suttill
dated November 29, 1991 (filed as exhibit 10.12 to the Company's
Registration Statement on Form10, File No. 0-22258, and
incorporated herein by reference).
*10.13 Employee Stock Option Plan of the Company (filed as exhibit
10.13 to the Company's Registration Statement on Form10, File
No. 0-22258, and incorporated herein by reference).
*10.14 Letter agreement dated January 6, 1993 between NationsBank
Investment Banking and the Company (filed as exhibit 10.14 to
the Company's Registration Statement on Form10, File No. 0-
22258, and incorporated herein by reference).
*10.15 Letter agreement dated March 3, 1993 between EnCap Investments
L.C. and the Company (filed as exhibit 10.15 to the Company's
Registration Statement on Form10, File No. 0-22258, and
incorporated herein by reference).
*10.16 Credit Agreement dated August 6, 1993 between the Company, Aviva
America, Inc. ("Aviva America"), Neo and Internationale
Nederlanden Bank N.V., New York Branch ("ING Capital") (filed as
exhibit 10.16 to the Company's Registration Statement on Form10,
File No. 0-22258, and incorporated herein by reference).
*10.17 Subordination Agreement dated August 6, 1993 between the
Company, Aviva America, Aviva Operating Company ("Aviva
Operating"), Neo and ING Capital (filed as exhibit 10.17 to the
Company's Registration Statement on Form10, File No. 0-22258,
and incorporated herein by reference).
*10.18 Stock Pledge Agreement dated August 6, 1993 between the Company
and ING Capital (filed as exhibit 10.18 to the Company's
Registration Statement on Form10, File No. 0-22258, and
incorporated herein by reference).
*10.19 Stock Pledge Agreement dated August 6, 1993 between Aviva
America and ING Capital (filed as exhibit 10.19 to the Company's
Registration Statement on Form10, File No. 0-22258, and
incorporated herein by reference).
*10.20 Guaranty dated August 6, 1993 made by the Company in favor of
ING Capital (filed as exhibit 10.20 to the Company's
Registration Statement on Form10, File No. 0-22258, and
incorporated herein by reference).
*10.21 Guaranty dated August 6, 1993 made by Aviva America in favor of
ING Capital (filed as exhibit 10.21 to the Company's
Registration Statement on Form10, File No. 0-22258, and
incorporated herein by reference).
*10.22 Guaranty dated August 6, 1993 made by Aviva Operating in favor
of ING Capital (filed as exhibit 10.22 to the Company's
Registration Statement on Form10, File No. 0-22258, and
incorporated herein by reference).
*10.23 Form of Subscription Agreement dated June 18, 1993 between the
Company and purchasers of 12,884,207 shares of common stock
("Purchasers") (filed as exhibit 10.23 to the Company's
Registration Statement on Form10, File No. 0-22258, and
incorporated herein by reference).
*10.24 Option Agreement between RBS and Aviva Energy Inc. ("Aviva
Energy") dated July 1, 1993 (filed as exhibit 10.24 to the
Company's Registration Statement on Form10, File No. 0-22258,
and incorporated herein by reference).
*10.25 Option Agreement between Aviva Energy and Purchasers dated
July 1, 1993 (filed as exhibit 10.25 to the Company's
Registration Statement on Form10, File No. 0-22258, and
incorporated herein by reference).
*10.26 Santana Block B 50% relinquishment dated September 13, 1993
between Ecopetrol, Argosy and Neo (filed as exhibit 10.26 to the
Company's annual report on Form 10-K for the year ended December
31, 1993, File No. 0-22258, and incorporated herein by
reference).
32
<PAGE>
*10.27 Amendment to La Fragua Association contract dated December 2,
1993 between Ecopetrol, Argosy and Neo (filed as exhibit 10.27
to the Company's annual report on Form 10-K for the year ended
December 31, 1993, File No. 0-22258, and incorporated herein by
reference).
*10.28 Letter from Ecopetrol dated February 24, 1994 and Resolution
dated February 18, 1994 revising pipeline tariff (filed as
exhibit 10.28 to the Company's annual report on Form 10-K for
the year ended December 31, 1993, File No. 0-22258, and
incorporated herein by reference).
*10.29 Aviva Petroleum Inc. 401(k) Retirement Plan effective March 1,
1992 (filed as exhibit 10.29 to the Company's annual report on
Form 10-K for the year ended December 31, 1993, File No. 0-
22258, and incorporated herein by reference).
*10.30 Relinquishment of Putumayo dated December 1, 1993 (filed as
exhibit 10.30 to the Company's annual report on Form 10-K for
the year ended December 31, 1993, File No. 0-22258, and
incorporated herein by reference).
*10.31 Amendment to ING Capital agreement dated March 28, 1994 (filed
as exhibit 10.31 to the Company's annual report on Form 10-K for
the year ended December 31, 1993, File No. 0-22258, and
incorporated herein by reference).
*10.32 Deposit Agreement dated September 15, 1994 between the Company
and Chemical Shareholder Services Group, Inc. (filed as exhibit
10.29 to the Company's Registration Statement on Form S-1, File
No. 33-82072, and incorporated herein by reference).
*10.33 Form of Registration Agreement dated as of September 15, 1994
between the Company and Shearson Lehman Brothers Inc. (filed as
exhibit 10.30 to the Company's Registration Statement on Form S-
1, File No. 33-82072, and incorporated herein by reference).
*10.34 Form of Registration Agreement and Limited Power of Attorney
dated as of September 15, 1994 between the Company and all other
Selling Shareholders (filed as exhibit 10.31 to the Company's
Registration Statement on Form S-1, File No. 33-82072, and
incorporated herein by reference).
*10.35 Form of Broker-Dealer Agreement dated as of October 19, 1994
between the Company and Petrie Parkman & Co. (filed as exhibit
10.32 to the Company's Registration Statement on Form S-1, File
No. 33-82072, and incorporated herein by reference).
*10.36 Purchase and Sale Agreement dated July 22, 1994 by and between
Newfield Exploration Company and Aviva America (filed as exhibit
10.33 to the Company's Registration Statement on Form S-1, File
No. 33-82072, and incorporated herein by reference).
*10.37 Letter from ING Capital dated October 27, 1994, amending Section
5.2 (n) of the Credit Agreement (filed as exhibit 10.37 to the
Company's annual report on Form 10-K for the year ended December
31, 1994, File No. 0-22258, and incorporated herein by
reference).
*10.38 Letter from Ecopetrol dated December 28, 1994, accepting
relinquishment of Putumayo (filed as exhibit 10.38 to the
Company's annual report on Form 10-K for the year ended December
31, 1994, File No. 0-22258, and incorporated herein by
reference).
*10.39 Letter from Ecopetrol dated February 28, 1995, accepting
modifications to the La Fragua Association Contract (filed as
exhibit 10.39 to the Company's annual report on Form 10-K for
the year ended December 31, 1994, File No. 0-22258, and
incorporated herein by reference).
*10.40 Amendment to ING Capital Credit Agreement dated March 7, 1995
(filed as exhibit 10.40 to the Company's annual report on Form
10-K for the year ended December 31, 1994, File No. 0-22258, and
incorporated herein by reference).
*10.41 Santana Crude Oil Sale Contract dated March 19, 1995 (filed as
exhibit 10.41 to the Company's annual report on Form 10-K for
the year ended December 31, 1994, File No. 0-22258, and
incorporated herein by reference).
*10.42 Employment Agreement between the Company and Ronald Suttill
effective January 1, 1995 (filed as exhibit 10.1 to the
Company's quarterly report on Form 10-Q for the quarter ended
March 31, 1995, File No. 0-22258, and incorporated herein by
reference).
*10.43 Employment Agreement between the Company and Robert C. Boyd
effective January 1, 1995 (filed as exhibit 10.2 to the
Company's quarterly report on Form 10-Q for the quarter ended
March 31, 1995, File No. 0-22258, and incorporated herein by
reference).
*10.44 Amendment to ING Capital Credit Agreement dated June 9, 1995
(filed as exhibit 10.3 to the Company's quarterly report on Form
10-Q for the quarter ended June 30, 1995, File No. 0-22258, and
incorporated herein by reference).
33
<PAGE>
*10.45 Amendment to the Incentive and Nonstatutory Stock Option Plan of
the Company (filed as exhibit 10.4 to the Company's quarterly
report on Form 10-Q for the quarter ended September 30, 1995,
File No. 0-22258, and incorporated herein by reference).
*10.46 Aviva Petroleum Inc. 1995 Stock Option Plan (filed as exhibit
10.5 to the Company's quarterly report on Form 10-Q for the
quarter ended September 30, 1995, File No. 0-22258, and
incorporated herein by reference).
*10.47 Yuruyaco Association Contract dated September 20, 1995 between
Ecopetrol, Argosy and Neo (filed as exhibit 10.6 to the
Company's quarterly report on Form 10-Q for the quarter ended
September 30, 1995, File No. 0-22258, and incorporated herein by
reference).
*10.48 Letter from ING Capital dated November 3, 1995, amending Section
5.2 (n) of the Credit Agreement (filed as exhibit 10.7 to the
Company's quarterly report on Form 10-Q for the quarter ended
September 30, 1995, File No. 0-22258, and incorporated herein by
reference).
*10.49 Amendment to the Santana Crude Oil Sale Contract (filed as
exhibit 10.49 to the Company's annual report on Form 10-K for
the year ended December 31, 1995, File No. 0-22258, and
incorporated herein by reference).
*10.50 Amendment to the La Fragua Association Contract dated April 27,
1995 (filed as exhibit 10.50 to the Company's annual report on
Form 10-K for the year ended December 31, 1995, File No. 0-
22258, and incorporated herein by reference).
*10.51 Santana Block B 25% relinquishment dated October 2, 1995 (filed
as exhibit 10.51 to the Company's annual report on Form 10-K for
the year ended December 31, 1995, File No. 0-22258, and
incorporated herein by reference).
*10.52 Amendment to the La Fragua Association Contract dated August 1,
1995 (filed as exhibit 10.52 to the Company's annual report on
Form 10-K for the year ended December 31, 1995, File No. 0-
22258, and incorporated herein by reference).
*10.53 Operating Agreement for the Yuruyaco Area between Argosy and
Neo dated November 7, 1995 (filed as exhibit 10.53 to the
Company's annual report on Form 10-K for the year ended December
31, 1995, File No. 0-22258, and incorporated herein by
reference).
*10.54 Letter from ING Capital dated March 19, 1996, amending the
borrowing base, schedule of principal repayments and Section 5.2
(m) of the Credit Agreement (filed as exhibit 10.54 to the
Company's annual report on Form 10-K for the year ended December
31, 1995, File No. 0-22258, and incorporated herein by
reference).
*10.55 Amendment to the ING Capital Credit Agreement dated March 29,
1996 (filed as exhibit 10.1 to the Company's quarterly report on
Form 10-Q for the quarter ended March 31, 1996, File No. 0-
22258, and incorporated herein by reference).
*10.56 Aviva Petroleum Inc. Severance Benefit Plan (filed as exhibit
10.2 to the Company's quarterly report on Form 10-Q for the
quarter ended March 31, 1996, File No. 0-22258, and incorporated
herein by reference).
*10.57 Amendment to the ING Capital Credit Agreement dated November 22,
1996 (filed as exhibit 10.57 to the Company's annual report on
Form 10-K for the year ended December 31, 1996, File No. 0-
22258, and incorporated herein by reference).
*10.58 Purchase and Sale Agreement dated November 22, 1996 between BWAB
Incorporated and Aviva America (filed as exhibit 10.58 to the
Company's annual report on Form 10-K for the year ended December
31, 1996, File No. 0-22258, and incorporated herein by
reference).
*10.59 Purchase and Sale Agreement dated December 6, 1996 between Lomak
Petroleum Inc. and Aviva America (filed as exhibit 10.59 to the
Company's annual report on Form 10-K for the year ended December
31, 1996, File No. 0-22258, and incorporated herein by
reference).
*10.60 Santana Crude Sale and Purchase Agreement dated February 10,
1997 (filed as exhibit 10.60 to the Company's annual report on
Form 10-K for the year ended December 31, 1996, File No. 0-
22258, and incorporated herein by reference).
*10.61 Aviva Petroleum Inc. 1995 Stock Option Plan, as amended
(filed as Appendix A to the Company's definitive Proxy Statement
for the Annual Meeting of Shareholders dated June 10, 1997, and
incorporated herein by reference).
*10.62 Amendment to the ING Capital Credit Agreement dated August
12, 1997 (filed as exhibit 10.2 to the Company's quarterly
report on Form 10-Q for the quarter ended June 30, 1997, File
No. 0-22258, and incorporated herein by reference).
*10.63 Amended and Restated Aviva Petroleum Inc. Severance Benefit Plan
dated September 30, 1997 (filed as exhibit 10.3 to the Company's
quarterly report on Form 10-Q for the quarter ended September
30, 1997, File No. 0-22258, and incorporated herein by
reference).
34
<PAGE>
*10.64 Amendment to the ING Capital Credit Agreement dated December 29,
1997 (filed as exhibit 10.64 to the Company's annual report on
Form 10-K for the year ended December 31, 1997, File No. 0-
22258, and incorporated herein by reference).
*10.65 Amendment to the Santana Crude Sale and Purchase Agreement dated
January 5, 1998 (filed as exhibit 10.65 to the Company's annual
report on Form 10-K for the year ended December 31, 1997, File
No. 0-22258, and incorporated herein by reference).
*10.66 Amendment to the ING Capital Credit Agreement dated February 13,
1998 (filed as exhibit 10.66 to the Company's annual report on
Form 10-K for the year ended December 31, 1997, File No. 0-
22258, and incorporated herein by reference).
*10.67 Amendment to the ING Capital Credit Agreement dated August 6,
1998 (filed as exhibit 10.1 to the Company's quarterly report on
Form 10-Q for the quarter ended June 30, 1998, File No. 0-22258,
and incorporated herein by reference).
*10.68 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).
*10.69 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).
**10.70 Amendment to the Santana Crude Sale and Purchase Agreement dated
February 16, 1999.
**21.1 List of subsidiaries of Aviva Petroleum Inc.
**27.1 Financial Data Schedule.
____________________
* Previously Filed
** Filed Herewith
b. Reports on Form 8-K
-------------------
The Company filed the following Current Reports on Form 8-K during and
subsequent to the end of the fourth quarter:
Date of 8-K Description of 8-K
----------- ------------------
October 2, 1998 Submitted a description of the resignation of
James E. Tracey, a director of the Company, along
with his resignation letter (including its
antecedents).
October 28, 1998 Submitted a description of the merger with Garnet
Resources Corporation that was completed on
October 28, 1998. Also submitted a summary of the
new bank credit facilities signed on October 28,
1998.
March 4, 1999 Submitted a copy of the Company's Press Release
dated March 4, 1999, announcing the merger plans
between Aviva America, Inc., a wholly owned
subsidiary of Aviva Petroleum Inc., and Sharpe
Resources Corporation.
35
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
AVIVA PETROLEUM INC.
By: /s/ RONALD SUTTILL
-------------------
Ronald Suttill
Chief Executive Officer and Director
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
/s/ RONALD SUTTILL President, Chief Executive Officer March 26, 1999
- ------------------ and Director (principal executive --------------
Ronald Suttill officer)
/s/ JAMES L. BUSBY Treasurer and Secretary March 26, 1999
- ------------------ (principal financial and accounting --------------
James L. Busby officer)
/s/ EUGENE C. FIEDOREK Director March 26, 1999
- ---------------------- --------------
Eugene C. Fiedorek
/s/ ROBERT J. CRESCI Director March 26, 1999
- -------------------- --------------
Robert J. Cresci
36
<PAGE>
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
Page
----
Independent Auditors' Report................................... 38
Consolidated Balance Sheet as of December 31, 1998 and 1997.... 39
Consolidated Statement of Operations for the years
ended December 31, 1998, 1997 and 1996.................... 40
Consolidated Statement of Cash Flows for the years
ended December 31, 1998, 1997 and 1996.................... 41
Consolidated Statement of Stockholders' Equity for the years
ended December 31, 1998, 1997 and 1996.................... 42
Notes to Consolidated Financial Statements..................... 43
Supplementary Information Related to Oil and Gas Producing
Activities (Unaudited).................................... 57
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.
37
<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, 1998 and 1997, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 1998, 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 5, 1999
38
<PAGE>
AVIVA PETROLEUM INC. AND SUBSIDIARIES
Consolidated Balance Sheet
DECEMBER 31, 1998 AND 1997
(in thousands, except number of shares)
<TABLE>
<CAPTION>
1998 1997
--------- ---------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents $ 1,712 $ 690
Restricted cash (note 5) 417 -
Accounts receivable (note 10):
Oil and gas revenue 363 1,108
Trade 554 518
Other 586 177
Inventories 836 602
Prepaid expenses and other 627 203
-------- --------
Total current assets 5,095 3,298
-------- --------
Property and equipment, at cost (note 5):
Oil and gas properties and equipment (full cost method) 68,636 61,036
Other 612 606
-------- --------
69,248 61,642
Less accumulated depreciation, depletion
and amortization (64,440) (49,873)
-------- --------
4,808 11,769
Other assets (note 4) 1,519 1,378
-------- --------
$ 11,422 $ 16,445
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Current liabilities:
Current portion of long term debt (note 5) $ 14,805 $ 480
Accounts payable 5,526 3,091
Accrued liabilities 308 356
-------- --------
Total current liabilities 20,639 3,927
-------- --------
Long term debt, excluding current portion (note 5) - 7,210
Gas balancing obligations and other (note 12) 1,866 1,560
Stockholders' equity (deficit) (notes 5 and 7):
Common stock, no par value, authorized 348,500,000 shares;
issued 46,700,132 in 1998 and 31,482,716 shares in 1997 2,335 1,574
Additional paid-in capital 34,862 33,376
Accumulated deficit* (48,280) (31,202)
-------- --------
Total stockholders' equity (deficit) (11,083) 3,748
Commitments and contingencies (note 11)
-------- --------
$ 11,422 $ 16,445
======== ========
</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.
39
<PAGE>
AVIVA PETROLEUM INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(in thousands, except per share data)
<TABLE>
<CAPTION>
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Oil and gas sales (note 10) $ 3,332 $ 9,726 $ 13,750
-------- -------- --------
Expense:
Production 3,525 4,235 4,834
Depreciation, depletion and amortization 3,152 6,067 7,339
Write-down of oil and gas properties (note 1) 12,343 19,953 -
General and administrative 1,074 1,510 1,554
Provision for losses on accounts receivable 420 - -
Severance (note 8) - - 196
-------- -------- --------
Total expense 20,514 31,765 13,923
-------- -------- --------
Other income (expense):
Interest and other income (expense), net (note 6) 1,045 122 1,061
Interest expense (748) (658) (814)
Debt refinancing expense (note 5) - - (100)
-------- -------- --------
Total other income (expense) 297 (536) 147
-------- -------- --------
Loss before income taxes and extraordinary item (16,885) (22,575) (26)
Income (taxes) benefits (note 9) 4 93 (911)
-------- -------- --------
Loss before extraordinary item (16,881) (22,482) (937)
Extraordinary item - debt extinguishment (197) - -
-------- -------- --------
Net loss $(17,078) $(22,482) $ (937)
======== ======== ========
Weighted average common shares outstanding 34,279 31,483 31,483
======== ======== ========
Basic and diluted net loss per common share $ (0.50) $ (0.71) $ (0.03)
======== ======== ========
</TABLE>
See accompanying notes to consolidated financial statements.
40
<PAGE>
AVIVA PETROLEUM INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(in thousands)
<TABLE>
<CAPTION>
1998 1997 1996
--------- --------- --------
<S> <C> <C> <C>
Net loss $(17,078) $(22,482) $ (937)
Adjustments to reconcile net loss to
net cash provided by operating activities:
Depreciation, depletion and amortization 3,152 6,067 7,339
Write-down of oil and gas properties 12,343 19,953 -
Provision for losses on accounts receivable 420 - -
Deferred foreign income taxes - (692) 195
Loss (gain) on sale of assets, net - 15 (651)
Foreign currency exchange loss (gain), net (1) 75 16
Other (275) (217) (253)
Changes in assets and liabilities:
Escrow account (417) - -
Accounts and notes receivable 825 1,934 (916)
Inventories 195 118 88
Prepaid expenses and other (196) 79 406
Accounts payable and accrued liabilities 983 (3,119) 3,656
-------- -------- -------
Net cash provided by (used in)
operating activities (49) 1,731 8,943
-------- -------- -------
Cash flows from investing activities:
Property and equipment expenditures (1,405) (2,757) (8,667)
Proceeds from sale of assets - 19 2,729
Other 1,421 - (46)
-------- -------- -------
Net cash provided by (used in)
investing activities 16 (2,738) (5,984)
-------- -------- -------
Cash flows from financing activities:
Proceeds from long term debt 1,560 - -
Principal payments on long term debt (400) (300) (5,077)
Other (97) - -
-------- -------- -------
Net cash provided by (used in)
financing activities 1,063 (300) (5,077)
-------- -------- -------
Effect of exchange rate changes on cash and
cash equivalents (8) (44) (41)
-------- -------- -------
Net increase (decrease) in cash and cash
equivalents 1,022 (1,351) (2,159)
Cash and cash equivalents at beginning of
year 690 2,041 4,200
-------- -------- -------
Cash and cash equivalents at end of year $ 1,712 $ 690 $ 2,041
======== ======== =======
</TABLE>
See accompanying notes to consolidated financial statements.
41
<PAGE>
AVIVA PETROLEUM INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (DEFICIT)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(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, 1995 31,482,716 $1,574 $33,376 $ (7,783) $ 27,167
Net loss - - - (937) (937)
---------- ------ ---------- ----------- --------
Balances at
December 31, 1996 31,482,716 1,574 33,376 (8,720) 26,230
Net loss - - - (22,482) (22,482)
---------- ------ ---------- ----------- --------
Balances at
December 31, 1997 31,482,716 1,574 33,376 (31,202) 3,748
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)
========== ====== ========== =========== ========
</TABLE>
See accompanying notes to consolidated financial statements.
42
<PAGE>
AVIVA PETROLEUM INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Summary of Significant Accounting Policies
General
Aviva Petroleum Inc. and its subsidiaries (the "Company") are engaged in
the business of exploring for, developing and producing oil and gas in
Colombia and in the United States. The Company's Colombian oil production
is sold to Empresa Colombiana de Petroleos, the Colombian national oil
company ("Ecopetrol"), while the Company's U.S. oil and gas production is
sold to numerous U.S. purchasers (See notes 10 and 13).
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
$60,000 in 1998, $127,000 in 1997 and $129,000 in 1996.
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:
1998 1997 1996
------ ------ ------
United States $27.00 $ 7.32 $ 5.93
Colombia $ 5.98 $11.59 $11.49
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 following table
summarizes the write-downs of the
43
<PAGE>
AVIVA PETROLEUM INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
carrying amounts of the Company's oil and gas properties as a result of
ceiling limitations on capitalized costs (in thousands):
1998 1997
------- -------
Colombia $10,556 $17,829
United States 1,787 2,124
------- -------
$12,343 $19,953
======= =======
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 either the U.S. or
Colombian cost centers, result in a ceiling test write-down that is
significant to the Company's operating results.
Gains and losses on sales of oil and gas properties are not recognized in
income unless the sale involves a significant portion of the reserves
associated with a particular cost center. Capitalized costs associated
with unevaluated properties are excluded from amortization until it is
determined whether proved reserves can be assigned to such properties or
until the value of the properties is impaired. Unevaluated costs of
$532,000 and $251,000 were excluded from amortization at December 31, 1998
and 1997, respectively. Unevaluated properties are assessed quarterly to
determine whether any impairment has occurred. The unevaluated costs at
December 31, 1998 represent exploration costs and were incurred primarily
during the three-year period ended December 31, 1998. Such costs are
expected to be evaluated and included in the amortization computation
within the next three years.
In December 1996, the Company sold its remaining U.S. onshore oil and gas
properties for $2,702,000 in cash, net of closing adjustments. The sale
involved a significant portion of the reserves associated with the U.S.
cost center and, accordingly, the resultant gain on the sale was recognized
in the accompanying Consolidated Statement of Operations for 1996 (See note
6).
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 1998, 1997 and 1996, the Company
capitalized $29,000, $91,000 and $189,000 of interest, respectively.
Loss Per Common Share
The Company adopted Statement of Financial Accounting Standards No. 128
("SFAS 128") during the fourth quarter of 1997. Under SFAS 128, basic
earnings per share ("EPS") is computed by dividing income available to
common shareholders by the weighted-average number of common shares
outstanding for the period. Diluted EPS reflects the potential dilution
that could occur if securities or other contracts to issue common stock
were exercised or converted into common stock or resulted in the issuance
of common stock that then shared in the earnings of the entity. For the
years presented herein, basic and diluted EPS are the same since the
effects of potential common shares (notes 5 and 7) are antidilutive.
44
<PAGE>
AVIVA PETROLEUM INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
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 $860,000 in 1998, $641,000 in
1997 and $834,000 in 1996 and paid income taxes of $117,000 in 1998,
$212,000 in 1997 and $111,000 in 1996.
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 have declined dramatically. This decline in oil
prices has been particularly severe in Colombia. Colombian oil prices
have, during the twenty-four month period ended December 31, 1998, fallen
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.
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, 1998, 1997 and 1996, the Company reported net losses of
$17.1 million, $22.5 million and $0.9 million, respectively, and declining
amounts of net cash provided by (used in) operating activities of $(0.05)
million, $1.7 million and $8.9 million, respectively. As of December 31,
1998, the Company's stockholders' deficit was approximately $11.1 million.
45
<PAGE>
AVIVA PETROLEUM INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The Company is highly leveraged with $14.8 million in current debt as of
December 31, 1998, pursuant to bank credit facilities with ING (U.S.)
Capital Corporation ("ING Capital") and Chase Bank of Texas, N.A.
("Chase"), as more fully described in note 5.
As of December 31, 1998, the Company is not in compliance with various
covenants under the bank credit facilities. Furthermore, assuming no
change in its capital structure, the Company does not have the financial
resources to maintain the minimum escrow balance required under the bank
credit facilities beginning March 31, 1999, nor to pay the minimum monthly
principal payments of $5.7 million on April 30, 1999, and $281,250 each
month thereafter until December 31, 2001. Management of the Company is in
discussions with the Company's lenders to restructure the above-referenced
debt as set forth below.
On February 22, 1999, the Company signed a letter of intent to merge with
Sharpe Resources Corporation ("Sharpe"), a publicly traded oil and gas
exploration and production company incorporated in Ontario, Canada. Sharpe
currently has onshore oil and gas production in the United States from
working and overriding royalty interests in over 115 wells on 107
properties in 4 states which include Texas, Oklahoma, New Mexico and
Wyoming. Sharpe's offshore Gulf of Mexico production is from its operated
interests in Matagorda One and Matagorda Two properties located offshore
Matagorda Island, Texas in 48 feet of water. Sharpe's principal office is
located in Houston, Texas.
The proposed arrangements contemplate that Sharpe will be the parent
company following the merger, that each six shares of Company Common Stock
will be converted into one share of Sharpe Common Stock, and that the
Company's lenders will restructure the Company's indebtedness to them. Such
debt restructuring may include the conversion of a portion of the debt to a
preferred stock position in the merged entity.
The proposed arrangements are subject to numerous and substantial
contingencies, the most important of which are: (i) completion of
negotiations between the Company and Sharpe regarding the structure of the
proposed transaction; (ii) preparation, negotiation, execution and delivery
of a definitive merger agreement; (iii) approval of the definitive merger
agreement and consent to the proposed debt restructuring by the Company's
lenders (i.e., ING Capital, Chase and the Overseas Private Investment
Corporation); approval of the debt restructuring arrangements by the board
of directors of the Company; and approval of the definitive merger
agreement by the boards of directors and stockholders of the Company and
Sharpe. The proposed merger is subject to preparation, negotiation,
execution and delivery of definitive debt restructuring agreements between
the Company and its lenders.
Management believes that the consummation of this merger will provide the
combined companies with the ability to raise additional capital which is
necessary to continue operations and proceed with certain development and
exploration activities that management believes are essential to the
survival of the Company.
While management of the Company is pursuing the reorganization of the
Company assiduously, its ability to effect such a reorganization is
dependent upon the acquiescence of the Company's lenders and Sharpe,
matters that are beyond the control of the Company. In particular, the
Company's lenders must: (i) consent to waive the defaults of the Company
under its bank credit facilities pending preparation, negotiation,
execution and delivery of a definitive merger agreement and a definitive
debt restructuring agreement and pending receipt of stockholder approvals
of the definitive merger agreement; (ii) agree to debt restructuring
arrangements that are acceptable to Sharpe; and (iii) negotiate, execute
and deliver a definitive debt restructuring agreement. The Company's
lenders have not yet and may not ever agree to a restructuring of the
Company's debt. If the Company is unable to consummate the merger, then, in
the absence of another business transaction or debt restructuring, the
Company cannot maintain compliance with nor make principal payments
required by the 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. As a result of this
uncertainty, management believes there is substantial doubt about the
Company's ability to continue as a going concern.
46
<PAGE>
AVIVA PETROLEUM INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(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
=======
The following sets forth selected consolidated financial information for
the Company on a pro forma basis for the years ended December 31, 1998 and
1997 assuming the Garnet merger had occurred on January 1, 1997. The
following selected pro forma combined financial information is based on the
historical consolidated statements of operations of Aviva and Garnet as
adjusted to give effect to the merger using the purchase method of
accounting for business combinations. In addition, the following selected
pro forma combined financial information gives effect to the purchase of
Garnet debentures by Aviva pursuant to the Debenture Purchase Agreement,
the borrowing by Aviva of $15 million pursuant to the Bank loans (as
discussed in note 5) and the application of such funds to refinance Aviva's
outstanding debt and the debt to Chase of a Garnet subsidiary (as discussed
in note 3.) The following selected pro forma combined financial
information may not necessarily reflect the financial condition or results
of operations of Aviva that would actually have resulted had the merger
occurred as of the date and for the periods indicated or reflect the future
results of operations of Aviva (in thousands, except per share amounts).
1998 1997
-------- --------
Revenues $ 5,933 $ 18,708
======== ========
Net loss $(24,466) $(48,262)
======== ========
Basic and diluted net loss per common share $ (0.52) $ (1.03)
======== ========
The above pro forma net losses for the years ended December 31, 1998 and
1997, include combined historical charges for ceiling write-downs of oil
and gas producing properties of $17,470,000 and $45,714,000, respectively.
47
<PAGE>
AVIVA PETROLEUM INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(4) OTHER ASSETS
A summary of other assets follows:
December 31
---------------
(thousands)
1998 1997
------ ------
Abandonment funds for U.S. offshore properties $1,402 $1,272
Deferred financing charges 113 102
Other 4 4
------ ------
$1,519 $1,378
====== ======
(5) LONG TERM DEBT
On August 6, 1993, the Company entered into a credit agreement with ING
Capital, secured by a mortgage on substantially all U.S. oil and gas
assets, a pledge of Colombian assets and the stock of three subsidiaries,
pursuant to which ING Capital agreed to loan to the Company up to $25
million, subject to an annually redetermined borrowing base which was
predicated on the Company's U.S. and Colombian reserves. As of December
31, 1997, the borrowing base permitted, and the outstanding loan balance
was, $7,690,000. The outstanding loan balance has been subject to interest
at the prime rate, as defined (7.75% at December 31, 1998) plus 1% or, at
the option of the Company, a fixed rate, based on the London Interbank
Offered Rate ("LIBOR") plus 2.75%, for a portion or portions of the
outstanding debt from time to time.
In February 1998, the Company entered into an agreement with ING Capital
pursuant to which the outstanding loan balance was paid down to $7,440,000
from $7,690,000, the interest rate was increased to the prime rate, as
defined, plus 1.5%, or at the option of the Company, a fixed rate based on
LIBOR plus 3%, and the repayment schedule was amended to require monthly
payments of 80% of defined monthly cash flows until October 1, 1999, at
which time the remaining balance would be due and payable. Additionally,
ING Capital reduced to $2 million the minimum amount of consolidated
tangible net worth that the Company is required to maintain.
As of June 30, 1998, the Company was not in compliance with the above-
referenced tangible net worth covenant. Accordingly, on August 6, 1998,
the Company entered into an agreement with ING Capital to further amend the
credit facility in order to: (i) waive the Company's non-compliance with
the tangible net worth covenant through July 1, 1999; (ii) require the
Company to consummate the merger with Garnet on or before October 31, 1998;
and (iii) provide to the Company a cash advance of $760,000 in order to
supplement the Company's existing working capital. As compensation for
making the new advance and entering into the new agreement, the Company
issued to ING Capital 400,000 new shares of the Company's common stock.
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. ING Capital and Chase now share on a 60/40
basis, respectively, all collateral.
The ING Capital loan and the Chase 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. The Chase loan
is unconditionally guaranteed by OPIC.
48
<PAGE>
AVIVA PETROLEUM INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Borrowings under the ING Capital loan bear interest at LIBOR plus 3.0% per
annum. Borrowings under the Chase loan bear interest at the LIBOR rate
plus 0.6% per annum. In addition, a guarantee fee of 2.4% per annum on the
borrowings under the Chase loan guaranteed by OPIC will be payable to OPIC.
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 valued
using the Black-Scholes option-pricing model. Both amounts are included in
debt extinguishment costs in the 1998 consolidated statement of operations.
Borrowings under the Bank Credit Facilities are payable as follows: $50,000
per month through March 1999, $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, 1998, the Company is not in compliance with
various covenants under the Bank Credit Facilities. The Company has,
therefore, classified all long-term debt as current in the December 31,
1998 consolidated balance sheet.
The Company is also required to maintain an escrow account of $250,000
until March 31, 1999. 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.
In consideration of certain modifications to the above referenced credit
agreement in March 1996 the Company paid a fee of $100,000 to ING Capital.
(6) INTEREST AND OTHER INCOME (EXPENSE)
A summary of interest and other income (expense) follows:
<TABLE>
<CAPTION>
(thousands)
1998 1997 1996
------ ------ ------
<S> <C> <C> <C>
Gain on settlement of litigation $ 720 $ - $ -
Interest income 70 138 231
Foreign currency exchange gain (loss) 1 (75) (16)
Gain (loss) on sale of assets, net - (15) 651
Other, net 254 74 195
------ ----- ------
$1,045 $ 122 $1,061
====== ===== ======
</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.
49
<PAGE>
AVIVA PETROLEUM INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Stock Option Plans
At December 31, 1998, 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>
1998 1997 1996
-------- -------- ------
<S> <C> <C> <C> <C>
Net loss As reported $(17,078) $(22,482) $ (937)
Pro forma $(17,095) $(22,506) $ (947)
Loss per share As reported $ (0.50) $ (0.71) $(0.03)
Pro forma $ (0.50) $ (0.71) $(0.03)
</TABLE>
At the Annual Meeting of Shareholders held on June 6, 1995, the Company's
shareholders approved the adoption of the Aviva Petroleum Inc. 1995 Stock
Option Plan (the "Current Plan"). The Current Plan is administered by a
committee (the "Committee") composed of two or more outside directors of
the Company, who are disinterested within the meaning of Rule 16b-3(c)
under the Securities Exchange Act of 1934, as amended (the "Exchange Act").
Except as indicated below and except for non-discretionary grants to non-
employee directors, the Committee has authority to determine all terms and
provisions under which options are granted pursuant to the Current Plan,
including (i) the determination of which employees shall be eligible to
receive options, (ii) the number of shares for which an option shall be
granted and (iii) the terms and conditions upon which options may be
granted. Options will vest at such times and under such conditions as
determined by the Committee, as permitted under the Current Plan. An
aggregate of up to 1,000,000 shares of the Company's common stock may be
issued upon exercise of stock options or in connection with restricted
stock awards that may be granted under the Current Plan.
The aggregate fair market value (determined at the time of grant) of shares
issuable pursuant to incentive stock options which first become exercisable
in any calendar year by a participant in the Current Plan may not exceed
$100,000. The maximum number of shares of common stock which may be
subject to an option or restricted stock grant awarded to a participant in
a calendar year cannot exceed 100,000. Incentive stock options granted
under the Current Plan may not be granted at a price less than 100% of the
fair market value of the common stock on the date of grant (or 110% of the
fair market value in the case of incentive stock options granted to
participants in the Current Plan holding 10% or more of the voting stock of
the Company). Non-qualified stock options may not be granted at a price
less than 50% of the fair market value of the common stock on the date of
grant.
At the Annual Meeting of Shareholders held on June 10, 1997, the Company's
shareholders approved the amendment of the Current Plan. The amendment
increased the 200,000 shares reserved for options to be awarded to non-
employee directors to 400,000 shares. In addition, the amendment provides
for the grant, on July 1, 1997, and on each subsequent July 1, to each non-
employee director who has served in such capacity for at least the entire
preceding calendar year of an option to purchase 5,000 shares of the
Company's common stock (the "Annual Option Awards"), exercisable as to
2,500 shares on the first anniversary of the date of grant and as to the
remaining shares on the second anniversary thereof. Except for the vesting
provisions relating to the Annual Options Awards, the provisions of the
Plan relating to vesting of such options, the determination of the exercise
prices thereof and other terms of such options remain unchanged.
As a result of the adoption of the Current Plan, during 1995 the Company's
former Incentive and Non-Statutory Stock Option Plan was terminated as to
the grant of new options, but options then outstanding for 258,000 shares
of the Company's common stock remain in effect as of December 31, 1998.
50
<PAGE>
AVIVA PETROLEUM INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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>
1998 1997 1996
------ ----- -----
<S> <C> <C> <C>
Expected life (years) 10.0 10.0 5.0
Risk-free interest rate 4.8% 6.6% 7.0%
Volatility 77.0% 71.0% 77.0%
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, 1998, 1997 and 1996, and changes during the years ended on
those dates is presented below:
<TABLE>
<CAPTION>
1998 1997 1996
------ ----- -----
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 550 $1.53 530 $1.80 716 $1.60
Granted 675 .06 45 .52 20 .74
Forfeited (77) 3.60 (25) 4.95 (206) 1.25
------ ------ ------
Outstanding at
end of year 1,148 .53 550 1.53 530 1.80
====== ===== ======
Options exercisable
at year-end 655 445 401
Weighted-average fair
value of options
granted during
the year $ .05 $ .42 $ .50
</TABLE>
The following table summarizes information about fixed stock options
outstanding at December 31, 1998:
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
----------------------------------------------- ----------------------------
Range Number Weighted-Avg. Number
of Outstanding Remaining Weighted-Avg. Exercisable Weighted-Avg.
Exercise Prices at 12/31/98 Contractual Life Exercise Price at 12/31/98 Exercise Price
------------------ ----------- ---------------- ---------------- ----------- --------------
<S> <C> <C> <C> <C> <C>
$ .06 to .17 675,000 9.84 years $ 0.06 209,333 $ 0.06
.51 to .98 223,000 4.59 0.86 195,500 0.91
1.08 to 2.79 250,000 4.24 1.49 250,000 1.49
--------------- --------- -------
$ .06 to 2.79 1,148,000 7.60 0.53 654,833 0.86
=============== ========= =======
</TABLE>
(8) SEVERANCE EXPENSE
The Board of Directors had charged a committee of the Board with the task
of reviewing the Company's general and administrative expenses and making
recommendations as to the reduction of such expenses. On March 18, 1996,
the Board, acting on one of such committee's recommendations, determined to
terminate the employment of the Executive Vice President and Chief
Operating Officer of the Company (the "Officer") effective on June 1, 1996.
In connection with the severance arrangements between the Company and the
Officer, the Company incurred costs of $172,000.
51
<PAGE>
AVIVA PETROLEUM INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
On July 25, 1996, the above mentioned committee was dissolved and its
function was assumed by the entire Board of Directors. In the third
quarter of 1996, the Company incurred an additional $24,000 of severance
expense relating to the termination of certain employees affected by the
program.
(9) INCOME TAXES
Income tax expense includes current Colombian income taxes (benefit) of
$(4,000) in 1998, $587,000 in 1997 and $709,000 in 1996 and deferred
Colombian income taxes (benefit) of $-0- in 1998, $(692,000) in 1997 and
$195,000 in 1996. Income tax expense also includes $-0-, $12,000 and $7,000
of state income taxes in 1998, 1997 and 1996, respectively.
The Company's effective tax rate differs from the U.S. statutory rate each
year principally due to losses without tax benefit.
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities at
December 31, 1998 and 1997 follow:
<TABLE>
<CAPTION>
(thousands)
1998 1997
-------- --------
<S> <C> <C>
Deferred tax assets - principally net operating loss carryforwards $ 46,028 $ 42,053
Less valuation allowance 46,028 42,053
-------- --------
Net deferred tax assets - -
Deferred tax liabilities - -
-------- --------
Net deferred tax liability $ - $ -
======== ========
</TABLE>
The valuation allowance for deferred tax assets at January 1, 1996 was
$39,124,000. The net change in the valuation allowance was a $3,975,000
increase in 1998, a $5,927,000 increase in 1997 and a $2,998,000 decrease
in 1996. 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, 1998, the Company and its subsidiaries have aggregate net
operating loss carryforwards for U.S. federal income tax purposes of
approximately $113,000,000, expiring from 1999 through 2013, 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.
(10) 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, 1998, 1997 and 1996, Ecopetrol
exercised that option and sales to Ecopetrol accounted for $2,632,000
(79.0%), $7,405,000 (76.1%) and $9,437,000 (68.6%), respectively, of the
Company's aggregate oil and gas sales.
52
<PAGE>
AVIVA PETROLEUM INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
For the years ended December 31, 1998, 1997 and 1996, sales to one U.S.
purchaser accounted for $479,000 (14.4%), $1,516,000 (15.6%) and $1,609,000
(11.7%), respectively, of oil and gas sales.
(11) 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 may
recomplete certain existing wells and engage in various other projects.
The Company's share of the estimated future costs of these activities is
approximately $0.6 million at December 31, 1998. Failure to fund certain
expenditures could result in the forfeiture of all or part of the Company's
interest in this contract. Any substantial increases in the amounts of the
above referenced expenditures could adversely affect the Company's ability
to meet these obligations.
The Company will most likely fund the recompletion of certain wells through
arrangements with service companies whereby the services are paid for with
proceeds from the sale of incremental oil production. Any miscellaneous
projects will be funded using cash provided from operations. Risks that
could adversely affect funding of such activities include, among others, a
decrease in the Company's borrowing base, delays in obtaining the required
environmental approvals and permits, cost overruns, failure to produce the
reserves as projected or a further decline in the sales price of oil.
Depending on the results of future exploration and development activities,
substantial expenditures which have not been included in the Company's cash
flow projections may be required.
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. The Colombian army
guards the Company's operations; however, there can be no assurance that
the Company's operations will not be the target of guerrilla attacks in the
future. The damage resulting from the above referenced attack was covered
by insurance. There can be no assurance that such coverage will remain
available or affordable.
Under the terms of the contracts with Ecopetrol, 25% of all revenues from
oil sold to Ecopetrol is paid in Colombian pesos which may only be utilized
in Colombia. To date, the Company has experienced no difficulty in
repatriating the remaining 75% of such payments, which are payable in U.S.
dollars.
Activities of the Company with respect to the exploration, development and
production of oil and natural gas are subject to stringent foreign,
federal, state and local environmental laws and regulations, including but
not limited to the Oil Pollution Act of 1990, the Outer Continental Shelf
Lands Act, the Federal Water Pollution Control Act, the Resource
Conservation and Recovery Act and the Comprehensive Environmental Response,
Compensation, and Liability Act. Such laws and regulations have increased
the cost of planning, designing, drilling, operating and abandoning wells.
In most instances, the statutory and regulatory requirements relate to air
and water pollution control procedures and the handling and disposal of
drilling and production wastes. 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.
53
<PAGE>
AVIVA PETROLEUM INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The Company has one lease for office space in Dallas, Texas, which expires
in January 2002. Rent expense relating to the lease was $90,000, $83,000
and $84,000 for 1998, 1997 and 1996, respectively. Future minimum payments
under the lease are: 1999 - $96,000; 2000 - $102,000; 2001 - $102,000; and
2002 - $9,000.
(12) GAS BALANCING
As of December 31, 1998 and 1997, 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, 1998 and 1997, the Company had sold net gas with a volume
equivalent of approximately 444,000 MCF and 458,000 MCF (with an estimated
value of $725,000 and $748,000 included in gas balancing obligations and
other), respectively, for which the other joint owners are entitled
generally to be repaid in volumes ("overproduced"). In certain instances
the parties have the option of requesting payment in cash.
In connection with the sale of the Company's U.S. onshore properties in
December 1996, approximately 384,000 MCF for which the Company was
underproduced and approximately 337,000 MCF for which the Company was
overproduced were assumed by the buyer of such properties.
In 1997, the Company reacquired from the aforementioned buyer for $98,000
in cash approximately 196,000 MCF for which the Company was overproduced.
54
<PAGE>
AVIVA PETROLEUM INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(13) 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, 1998, 1997 and 1996 follows:
<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)
======= ======== ========
Identifiable assets $ 1,906 $ 7,387 $ 9,293
======= ========
Corporate assets-cash, cash equivalents and
restricted cash balances 2,129
--------
Total assets $ 11,422
========
</TABLE>
55
<PAGE>
AVIVA PETROLEUM INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
<TABLE>
<CAPTION>
(Thousands)
United
States Colombia Total
------- -------- --------
<S> <C> <C> <C>
1997
----
Oil and gas sales $ 2,321 $ 7,405 $ 9,726
------- -------- --------
Expense:
Production 1,262 2,973 4,235
Depreciation, depletion and amortization 1,009 5,058 6,067
Write-down of oil and gas properties 2,124 17,829 19,953
General and administrative 1,499 11 1,510
------- -------- --------
5,894 25,871 31,765
------- -------- --------
Interest and other income (expense), net 92 30 122
Interest expense (399) (259) (658)
------- -------- --------
Loss before income taxes (3,880) (18,695) (22,575)
Income (taxes) benefit (12) 105 93
------- -------- --------
Net loss $(3,892) $(18,590) $(22,482)
======= ======= ========
Identifiable assets $ 3,789 $ 11,966 $ 15,755
======== ========
Corporate assets-cash and cash equivalents 690
--------
Total assets $ 16,445
========
1996
----
Oil and gas sales $ 4,313 $ 9,437 $ 13,750
------- -------- --------
Expense:
Production 1,926 2,908 4,834
Depreciation, depletion and amortization 1,750 5,589 7,339
General and administrative 1,539 15 1,554
Severance 196 - 196
------- -------- --------
5,411 8,512 13,923
------- -------- --------
Interest and other income (expense), net 894 167 1,061
Interest expense (355) (459) (814)
Debt refinancing expense - (100) (100)
------- -------- --------
Income (loss) before income taxes (559) 533 (26)
Income taxes (7) (904) (911)
------- -------- --------
Net loss $ (566) $ (371) $ (937)
======= ======== ========
Identifiable assets $ 6,838 $ 34,065 $ 40,903
======= ========
Corporate assets-cash and cash equivalents 2,041
--------
Total assets $ 42,944
========
</TABLE>
56
<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, 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
======= ======= =======
December 31, 1997
- -----------------
Unevaluated oil and gas properties $ 142 $ 109 $ 251
Proved oil and gas properties 12,075 48,710 60,785
------- ------- -------
Total capitalized costs 12,217 48,819 61,036
Less accumulated depreciation
depletion and amortization 10,622 38,725 49,347
------- ------- -------
Capitalized costs, net $ 1,595 $10,094 $11,689
======= ======= =======
</TABLE>
57
<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>
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
====== ====== ======
1996
- ----
Exploration $ - $1,382 $1,382
Development 3,239 4,030 7,269
------ ------ ------
Total costs incurred $3,239 $5,412 $8,651
====== ====== ======
</TABLE>
58
<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, 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 (1,054) - (1,054)
Production (61) - (61)
----- ----- -----
End of period 4 - 4
===== ===== =====
Proved developed reserves, end of period 4 - 4
===== ===== =====
</TABLE>
59
<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>
60
<PAGE>
AVIVA PETROLEUM INC. AND SUBSIDIARIES
Supplementary Information Related to Oil and Gas Producing Activities
(UNAUDITED) (CONTINUED)
<TABLE>
<CAPTION>
Changes in the Estimated Quantities of Reserves
-----------------------------------------------
United
States Colombia Total
------ -------- -----
<S> <C> <C> <C>
Year ended December 31, 1996
- ----------------------------
Oil (Thousands of barrels)
Proved reserves:
Beginning of period 564 3,255 3,819
Revisions of previous estimates (74) 38 (36)
Discoveries and extensions 6 - 6
Sales of reserves (97) - (97)
Production (94) (476) (570)
----- ----- -----
End of period 305 2,817 3,122
===== ===== =====
Proved developed reserves, end of period 305 2,008 2,313
===== ===== =====
Gas (Millions of cubic feet)
Proved reserves:
Beginning of period 7,037 - 7,037
Revisions of previous estimates (770) - (770)
Discoveries and extensions 23 - 23
Sales of reserves (3,462) - (3,462)
Production (1,146) - (1,146)
----- ----- -----
End of period 1,682 - 1,682
===== ===== =====
Proved developed reserves, end of period 1,682 - 1,682
===== ===== =====
</TABLE>
61
<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, 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>
62
<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
======= ======== ========
At December 31, 1996:
- ---------------------
Future gross revenues $14,070 $ 63,666 $ 77,736
Future production costs (6,128) (11,362) (17,490)
Future development costs, including
abandonment of U.S. offshore platforms (970) (3,067) (4,037)
------- -------- --------
Future net cash flows before
income taxes 6,972 49,237 56,209
Future income taxes (51) (1,052) (1,103)
------- -------- --------
Future net cash flows after
income taxes 6,921 48,185 55,106
Discount at 10% per annum (993) (9,513) (10,506)
------- -------- --------
Standardized measure of discounted
future net cash flows $ 5,928 $ 38,672 $ 44,600
======= ======== ========
</TABLE>
63
<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)
1998 1997 1996
------ ------ ------
<S> <C> <C> <C>
Sales of oil and gas, net of production costs $ 192 $ (5,491) $(8,916)
Sales of reserves in place - - (3,924)
Development costs incurred that reduced
future development costs - 801 3,043
Accretion of discount 1,142 4,547 3,577
Discoveries and extensions - - 87
Purchase of reserves in place 2,998 - -
Revisions of previous estimates:
Changes in price (9,585) (24,154) 13,468
Changes in quantities (539) (7,054) 153
Changes in future development costs (448) 1,175 (86)
Changes in timing and other changes (561) (3,878) 2,303
Changes in estimated income taxes - 874 (540)
------- -------- -------
Net increase (decrease) (6,801) (33,180) 9,165
Balances at beginning of year 11,420 44,600 35,435
------- -------- -------
Balances at end of year $ 4,619 $ 11,420 $44,600
======= ======== =======
</TABLE>
64
<PAGE>
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
Sequentially
Numbered
Number Description of Exhibit Page
- ------ ---------------------- ------------
<S> <C> <C>
*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 Agreement of Withdrawal from Argosy dated September 16, 1987 by and
among Argosy, Neo, and Argosy Energy Incorporated, as general partners;
and Parkside Investments, Richard Shane McKnight, Douglas W. Fry, P-5
Ltd., GO-DEO, Inc., Dale E. Armstrong, Richard Shane McKnight, The
Yvonne McKnight Trust, and William Gaskin, as limited partners (filed
as exhibit 10.5 to the Company's Registration Statement on Form10, File
No. 0-22258, and incorporated herein by reference).
*10.6 Option Agreement dated September 16, 1987 between the general and
limited partners of Argosy and Neo (filed as exhibit 10.6 to the
Company's Registration Statement on Form10, File No. 0-22258, and
incorporated herein by reference).
*10.7 Escrow Agreement between Argosy, Neo, Overseas Private Investment
Corporation and The Chase Manhattan Bank dated March 15, 1988 and
amended on May 31, 1990 (filed as exhibit 10.7 to the Company's
Registration Statement on Form10, File No. 0-22258, and incorporated
herein by reference).
*10.8 Santana Block A Relinquishment dated March 6, 1990 between
Ecopetrol, Argosy and Neo (filed as exhibit 10.8 to the Company's
Registration Statement on Form10, File No. 0-22258, and incorporated
herein by reference).
*10.9 Purchase Sale - Transportation and Commercialization of the Santana
Crude between Ecopetrol, Argosy and Neo (filed as exhibit 10.9 to the
Company's Registration Statement on Form10, File No. 0-22258, and
incorporated herein by reference).
*10.10 La Fragua Association Contract dated June 1, 1992 between Ecopetrol,
Argosy and Neo (filed as exhibit 10.10 to the Company's Registration
Statement on Form10, File No. 0-22258, and incorporated herein by
reference).
</TABLE>
1
<PAGE>
<TABLE>
<CAPTION>
Sequentially
Numbered
Number Description of Exhibit Page
- ------ ---------------------- ------------
<S> <C> <C>
*10.11 Operating Agreement for the La Fragua Area between Argosy and Neo
dated April 15, 1992 (filed as exhibit 10.11 to the Company's
Registration Statement on Form10, File No. 0-22258, and incorporated
herein by reference).
*10.12 Employment Agreement between the Company and Ronald Suttill dated
November 29, 1991 (filed as exhibit 10.12 to the Company's Registration
Statement on Form10, File No. 0-22258, and incorporated herein by
reference).
*10.13 Employee Stock Option Plan of the Company (filed as exhibit 10.13
to the Company's Registration Statement on Form10, File No. 0-22258,
and incorporated herein by reference).
*10.14 Letter agreement dated January 6, 1993 between NationsBank
Investment Banking and the Company (filed as exhibit 10.14 to the
Company's Registration Statement on Form10, File No. 0-22258, and
incorporated herein by reference).
*10.15 Letter agreement dated March 3, 1993 between EnCap Investments L.C.
and the Company (filed as exhibit 10.15 to the Company's Registration
Statement on Form10, File No. 0-22258, and incorporated herein by
reference).
*10.16 Credit Agreement dated August 6, 1993 between the Company, Aviva
America, Inc. ("Aviva America"), Neo and Internationale Nederlanden
Bank N.V., New York Branch ("ING Capital") (filed as exhibit 10.16 to
the Company's Registration Statement on Form10, File No. 0-22258, and
incorporated herein by reference).
*10.17 Subordination Agreement dated August 6, 1993 between the Company,
Aviva America, Aviva Operating Company ("Aviva Operating"), Neo and ING
Capital (filed as exhibit 10.17 to the Company's Registration Statement
on Form10, File No. 0-22258, and incorporated herein by reference).
*10.18 Stock Pledge Agreement dated August 6, 1993 between the Company and
ING Capital (filed as exhibit 10.18 to the Company's Registration
Statement on Form10, File No. 0-22258, and incorporated herein by
reference).
*10.19 Stock Pledge Agreement dated August 6, 1993 between Aviva America
and ING Capital (filed as exhibit 10.19 to the Company's Registration
Statement on Form10, File No. 0-22258, and incorporated herein by
reference).
*10.20 Guaranty dated August 6, 1993 made by the Company in favor of ING
Capital (filed as exhibit 10.20 to the Company's Registration Statement
on Form10, File No. 0-22258, and incorporated herein by reference).
*10.21 Guaranty dated August 6, 1993 made by Aviva America in favor of ING
Capital (filed as exhibit 10.21 to the Company's Registration Statement
on Form10, File No. 0-22258, and incorporated herein by reference).
*10.22 Guaranty dated August 6, 1993 made by Aviva Operating in favor of
ING Capital (filed as exhibit 10.22 to the Company's Registration
Statement on Form10, File No. 0-22258, and incorporated herein by
reference).
*10.23 Form of Subscription Agreement dated June 18, 1993 between the
Company and purchasers of 12,884,207 shares of common stock
("Purchasers") (filed as exhibit 10.23 to the Company's Registration
Statement on Form10, File No. 0-22258, and incorporated herein by
reference).
*10.24 Option Agreement between RBS and Aviva Energy Inc. ("Aviva Energy")
dated July 1, 1993 (filed as exhibit 10.24 to the Company's
Registration Statement on Form10, File No. 0-22258, and incorporated
herein by reference).
*10.25 Option Agreement between Aviva Energy and Purchasers dated July 1,
1993 (filed as exhibit 10.25 to the Company's Registration Statement on
Form10, File No. 0-22258, and incorporated herein by reference).
*10.26 Santana Block B 50% relinquishment dated September 13, 1993 between
Ecopetrol, Argosy and Neo (filed as exhibit 10.26 to the Company's
annual report on Form 10-K for the year ended December 31, 1993, File
No. 0-22258, and incorporated herein by reference).
</TABLE>
2
<PAGE>
<TABLE>
<CAPTION>
Sequentially
Numbered
Number Description of Exhibit Page
- ------ ---------------------- ------------
<S> <C> <C>
*10.27 Amendment to La Fragua Association contract dated December 2, 1993
between Ecopetrol, Argosy and Neo (filed as exhibit 10.27 to the
Company's annual report on Form 10-K for the year ended December 31,
1993, File No. 0-22258, and incorporated herein by reference).
*10.28 Letter from Ecopetrol dated February 24, 1994 and Resolution dated
February 18, 1994 revising pipeline tariff (filed as exhibit 10.28 to
the Company's annual report on Form 10-K for the year ended December
31, 1993, File No. 0-22258, and incorporated herein by reference).
*10.29 Aviva Petroleum Inc. 401(k) Retirement Plan effective March 1, 1992
(filed as exhibit 10.29 to the Company's annual report on Form 10-K for
the year ended December 31, 1993, File No. 0-22258, and incorporated
herein by reference).
*10.30 Relinquishment of Putumayo dated December 1, 1993 (filed as exhibit
10.30 to the Company's annual report on Form 10-K for the year ended
December 31, 1993, File No. 0-22258, and incorporated herein by
reference).
*10.31 Amendment to ING Capital agreement dated March 28, 1994 (filed as
exhibit 10.31 to the Company's annual report on Form 10-K for the year
ended December 31, 1993, File No. 0-22258, and incorporated herein by
reference).
*10.32 Deposit Agreement dated September 15, 1994 between the Company and
Chemical Shareholder Services Group, Inc. (filed as exhibit 10.29 to
the Company's Registration Statement on Form S-1, File No. 33-82072,
and incorporated herein by reference).
*10.33 Form of Registration Agreement dated as of September 15, 1994
between the Company and Shearson Lehman Brothers Inc. (filed as exhibit
10.30 to the Company's Registration Statement on Form S-1,
File No. 33-82072, and incorporated herein by reference).
*10.34 Form of Registration Agreement and Limited Power of Attorney dated
as of September 15, 1994 between the Company and all other Selling
Shareholders (filed as exhibit 10.31 to the Company's Registration
Statement on Form S-1, File No. 33-82072, and incorporated herein by
reference).
*10.35 Form of Broker-Dealer Agreement dated as of October 19, 1994
between the Company and Petrie Parkman & Co. (filed as exhibit 10.32 to
the Company's Registration Statement on Form S-1, File No. 33-82072,
and incorporated herein by reference).
*10.36 Purchase and Sale Agreement dated July 22, 1994 by and between
Newfield Exploration Company and Aviva America (filed as exhibit 10.33
to the Company's Registration Statement on Form S-1, File No. 33-82072,
and incorporated herein by reference).
*10.37 Letter from ING Capital dated October 27, 1994, amending Section
5.2 (n) of the Credit Agreement (filed as exhibit 10.37 to the
Company's annual report on Form 10-K for the year ended December 31,
1994, File No. 0-22258, and incorporated herein by reference).
*10.38 Letter from Ecopetrol dated December 28, 1994, accepting
relinquishment of Putumayo (filed as exhibit 10.38 to the Company's
annual report on Form 10-K for the year ended December 31, 1994, File
No. 0-22258, and incorporated herein by reference).
*10.39 Letter from Ecopetrol dated February 28, 1995, accepting
modifications to the La Fragua Association Contract (filed as exhibit
10.39 to the Company's annual report on Form 10-K for the year ended
December 31, 1994, File No. 0-22258, and incorporated herein by
reference).
*10.40 Amendment to ING Capital Credit Agreement dated March 7, 1995
(filed as exhibit 10.40 to the Company's annual report on Form 10-K for
the year ended December 31, 1994, File No. 0-22258, and incorporated
herein by reference).
*10.41 Santana Crude Oil Sale Contract dated March 19, 1995 (filed as
exhibit 10.41 to the Company's annual report on Form 10-K for the year
ended December 31, 1994, File No. 0-22258, and incorporated herein by
reference).
*10.42 Employment Agreement between the Company and Ronald Suttill
effective January 1, 1995 (filed as exhibit 10.1 to the Company's
quarterly report on Form 10-Q for the quarter ended March 31, 1995,
File No. 0-22258, and incorporated herein by reference).
</TABLE>
3
<PAGE>
<TABLE>
<CAPTION>
Sequentially
Numbered
Number Description of Exhibit Page
- ------ ---------------------- ------------
<S> <C> <C>
*10.43 Employment Agreement between the Company and Robert C. Boyd
effective January 1, 1995 (filed as exhibit 10.2 to the Company's
quarterly report on Form 10-Q for the quarter ended March 31, 1995,
File No. 0-22258, and incorporated herein by reference).
*10.44 Amendment to ING Capital Credit Agreement dated June 9, 1995 (filed
as exhibit 10.3 to the Company's quarterly report on Form 10-Q for the
quarter ended June 30, 1995, File No. 0-22258, and incorporated herein
by reference).
*10.45 Amendment to the Incentive and Nonstatutory Stock Option Plan of
the Company (filed as exhibit 10.4 to the Company's quarterly report on
Form 10-Q for the quarter ended September 30, 1995, File No. 0-22258,
and incorporated herein by reference).
*10.46 Aviva Petroleum Inc. 1995 Stock Option Plan (filed as exhibit 10.5
to the Company's quarterly report on Form 10-Q for the quarter ended
September 30, 1995, File No. 0-22258, and incorporated herein by
reference).
*10.47 Yuruyaco Association Contract dated September 20, 1995 between
Ecopetrol, Argosy and Neo (filed as exhibit 10.6 to the Company's
quarterly report on Form 10-Q for the quarter ended September 30, 1995,
File No. 0-22258, and incorporated herein by reference).
*10.48 Letter from ING Capital dated November 3, 1995, amending Section
5.2 (n) of the Credit Agreement (filed as exhibit 10.7 to the Company's
quarterly report on Form 10-Q for the quarter ended September 30, 1995,
File No. 0-22258, and incorporated herein by reference).
*10.49 Amendment to the Santana Crude Oil Sale Contract (filed as exhibit
10.49 to the Company's annual report on Form 10-K for the year ended
December 31, 1995, File No. 0-22258, and incorporated herein by
reference).
*10.50 Amendment to the La Fragua Association Contract dated April 27,
1995 (filed as exhibit 10.50 to the Company's annual report on
Form 10-K for the year ended December 31, 1995, File No. 0-22258,
and incorporated herein by reference).
*10.51 Santana Block B 25% relinquishment dated October 2, 1995 (file as
exhibit 10.51 to the Company's annual report on Form 10-K for the year
ended December 31, 1995, File No. 0-22258, and incorporated herein by
reference).
*10.52 Amendment to the La Fragua Association Contract dated August 1,
1995 (filed as exhibit 10.52 to the Company's annual report on
Form 10-K for the year ended December 31, 1995, File No. 0-22258,
and incorporated herein by reference).
*10.53 Operating Agreement for the Yuruyaco Area between Argosy and Neo
dated November 7, 1995 (filed as exhibit 10.53 to the Company's annual
report on Form 10-K for the year ended December 31, 1995, File
No. 0-22258, and incorporated herein by reference).
*10.54 Letter from ING Capital dated March 19, 1996, revising the
borrowing base and schedule of principal repayments and Section 5.2 (m)
of the Credit Agreement (filed as exhibit 10.54 to the Company's annual
report on Form 10-K for the year ended December 31, 1995,
File No. 0-22258, and incorporated herein by reference).
*10.55 Amendment to the ING Capital Credit Agreement dated March 29, 1996
(filed as exhibit 10.1 to the Company's quarterly report on Form 10-Q
for the quarter ended March 31, 1996, File No. 0-22258, and
incorporated herein by reference).
*10.56 Aviva Petroleum Inc. Severance Benefit Plan (filed as exhibit 10.2
to the Company's quarterly report on Form 10-Q for the quarter ended
March 31, 1996, File No. 0-22258, and incorporated herein by
reference).
*10.57 Amendment to the ING Capital Credit Agreement dated November 22,
1996 (filed as exhibit 10.57 to the Company's annual report on
Form 10-K for the year ended December 31, 1996, File No. 0-22258,
and incorporated herein by reference).
*10.58 Purchase and Sale Agreement dated November 22, 1996 between BWAB
Incorporated and Aviva America (filed as exhibit 10.58 to the Company's
annual report on Form 10-K for the year ended December 31, 1996, File
No. 0-22258, and incorporated herein by reference).
</TABLE>
4
<PAGE>
<TABLE>
<CAPTION>
Sequentially
Numbered
Number Description of Exhibit Page
- ------ ---------------------- ------------
<S> <C> <C>
*10.59 Purchase and Sale Agreement dated December 6, 1996 between Lomak
Petroleum Inc. and Aviva America (filed as exhibit 10.59 to the
Company's annual report on Form 10-K for the year ended December 31,
1996, File No. 0-22258, and incorporated herein by reference).
*10.60 Santana Crude Sale and Purchase Agreement dated February 10, 1997
(filed as exhibit 10.60 to the Company's annual report on Form 10-K for
the year ended December 31, 1996, File No. 0-22258, and incorporated
herein by reference).
*10.61 Aviva Petroleum Inc. 1995 Stock Option Plan, as amended (filed as
Appendix A to the Company's definitive Proxy Statement for the Annual
Meeting of Shareholders dated June 10, 1997, and incorporated herein by
reference).
*10.62 Amendment to the ING Capital Credit Agreement dated August 12, 1997
(filed as exhibit 10.2 to the Company's quarterly report on Form 10-Q
for the quarter ended June 30, 1997, File No. 0-22258, and incorporated
herein by reference).
*10.63 Amended and Restated Aviva Petroleum Inc. Severance Benefit Plan
dated September 30, 1997 (filed as exhibit 10.3 to the Company's
quarterly report on Form 10-Q for the quarter ended September 30, 1997,
File No. 0-22258, and incorporated herein by reference).
*10.64 Amendment to the ING Capital Credit Agreement dated December 29,
1997 (filed as exhibit 10.64 to the Company's annual report on
Form 10-K for the year ended December 31, 1997, File No. 0-22258,
and incorporated herein by reference).
*10.65 Amendment to the Santana Crude Sale and Purchase Agreement dated
January 5, 1998 (filed as exhibit 10.65 to the Company's annual report
on Form 10-K for the year ended December 31, 1997, File No. 0-22258,
and incorporated herein by reference).
*10.66 Amendment to the ING Capital Credit Agreement dated February 13,
1998 (filed as exhibit 10.66 to the Company's annual report on
Form 10-K for the year ended December 31, 1997, File No. 0-22258,
and incorporated herein by reference).
*10.67 Amendment to the ING Capital Credit Agreement dated August 6, 1998
(filed as exhibit 10.1 to the Company's quarterly report on Form 10-Q
for the quarter ended June 30, 1998, File No. 0-22258, and incorporated
herein by reference).
*10.68 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).
*10.69 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).
**10.70 Amendment to the Santana Crude Sale and Purchase Agreement dated
February 16, 1999.
**21.1 List of subsidiaries of Aviva Petroleum Inc.
**27.1 Financial Data Schedule.
- ---------------
* Previously Filed
** Filed Herewith
</TABLE>
5
<PAGE>
Exhibit 10.70
CONTRACT No.: GCI-003-99
SELLER: ARGOSY ENERGY INTERNATIONAL AND
OBJECT: SANTANA CRUDE SALE/PURCHASE
PERIOD: FEBRUARY 1, 1999 TO DECEMBER 31, 1999
AMOUNT: UNDETERMINED QUANTITY
The contracting parties, on one hand, the EMPRESA COLOMBIANA DE PETROLEOS
"ECOPETROL", which hereinafter will be called "ECOPETROL", an Industrial and
Commercial State owned Company, authorized by Law 165 of 1948 and regulated by
its approved statutes by Decree 1209 of 1994, with main headquarters located in
the City of Santafe de Bogota, D.C., represented by LUIS AUGUSTO YEPES G., of
legal age, identified by Colombian Identity Card No. 19.125.070 issued in
Bogota, residing in Bogota, who declares: a. That he acts in his capacity of
Vice President and in exercise of legal and internal norms of Ecopetrol.-b. As
party of the second part, ARGOSY ENERGY INTERNATIONAL, an existent and
organized company in accordance with the laws of the State of Utah, of The
United States of America, domiciled in Salt Lake City, State of Utah, with a
subidiary established in Colombia, duly constituted by Public Deed number 5323
conceded in the Seventh Notary of Bogota on October 25, 1983, and registered in
the Chamber of Commerce of Bogota, under registry No. 200848, on November 23,
1983, represented by SANTIAGO GONZALEZ ANGULO, of legal age, identified by
Colombian Identity Card No. 5.584.373, issued in Barrancabermeja, company which
henceforth will be designated as THE SELLER, who enter into this purchase and
sale contract of Santana Crude, contained in the following clauses: CLAUSE ONE:
- - OBJECT AND QUANTITIES. THE SELLER is obliged to sell and to deliver to
ECOPETROL, under the conditions here set forth, the crude oil produced under the
contract of "Santana" Risk Participation, that corresponds to THE SELLER, in
the quantity and quality that is stipulated and in agreement with that provided
in Clause Two of this document and that in consequence, ECOPETROL is obliged to
receive and pay. PARAGRAPH 1: The "Santana"Risk Participation contract was
entered into on May 27, 1987, with effective date that of July 27, 1987, between
ECOPETROL AND ARGOSY ENERGY INTERNATIONAL AND NEO ENERGY, INC, which was
modified by means of Public Deed No. 00064 dated January 19, 1999, conceded by
Notary 50 in Bogota. PARAGRAPH 2: All purchases will be made by ECOPETROL in
accordance with the preliminary crude purchasing program agreed upon by the
parties for six (6) month periods, that ECOPETROL could modify, giving previous
notice to THE SELLER with at least 30 days anticipation. CLAUSE TWO:
<PAGE>
QUALITY. The quality of the crude, subject matter of this contract, will have
the following specifications: a) the gravity of the crude oil will be that with
which said crude oil is obtained, through the operations that are carried out
for its production. b) The content of water and sediment in the crude oil,
cannot be greater than 0.5% in volume and its determination will be made
respectively by means of the ASTM-D4377 methods, "water in crude oil by
distillation" (Karl Fisher), last revision, ASTM-D473, "sediments in crude and
fuel oil by extraction", last revision. The parties agree that the Karl Fisher
method will be implemented within a 90 day period as of the subscription of this
contract. Meanwhile, the parties will continue using method ASTM D-95. c)The
content of sulphur in the crude oil with which said crude oil is obtained,
through the operations carried out for its production; its determination will be
made by the ASTM - D2622 method, last revision, "sulphur analysis by X-ray". d)
The salt content cannot be greater than 20 pounds for each 1,000 barrels of
crude oil and its determination will be made by the ASTM - D3230 method, " crude
salts (electrometric method), last revision. When any of the previously
mentioned parameters are not fulfilled or the previously mentioned
specifications are not within the permitted margin, ECOPETROL reserves the right
to reject the crude oil. But should ECOPETROL choose to accept with salinity
over the specifications, the price of the crude oil will be penalized in
accordance with the following chart:
<TABLE>
<CAPTION>
Salinity Content Penalty in U.S. Charged to
Pounds per 1,000 Dollars/Barrel
Barrels (US$/Barrel)
<S> <C> <C> <C>
20.01 30.0 0.160 THE SELLER
30.1 40.0 0.180 THE SELLER
40.1 60.0 0.200 THE SELLER
60.1 80.0 0.220 THE SELLER
80.1 100.0 0.240 THE SELLER
</TABLE>
It is understood that THE SELLER will make every effort possible to deliver the
contracted crude oil, with a salt content of less than twenty (20) pounds for
each one thousand (1,000) barrels of crude oil. e) Whatever variation
referring to the quality specifications mentioned previously, that be accepted
by both parties, will be consigned in a document subscribed
<PAGE>
between ECOPETROL Representatives and THE SELLER. CLAUSE THREE: PLACE OF
DELIVERY AND OWNERSHIP. The crude oil, subject of this contract, will be turned
over by THE SELLER to ECOPETROL in the Santana terminal where the crude will be
later measured and analyzed. Then, from the referred point, it will be
transported by ECOPETROL to the terminal in Tumaco. The property and risk title
will pass from THE SELLER to ECOPETROL at the moment in which the crude oil
passes the exit check point of the measuring system located in the Santana
Terminal. PARAGRAPH 1: If the Santana Association constructs the Santana-Orito
pipeline, the measurement and transfer of the ownership of the crude oil will be
made effective in Orito. Also, as of that date, the sales-purchase value of the
crude will be modified, as now the tariff for transport from Santana-Orito will
not be taken into account, in accordance with Resolution 6031 of February 8,
1994, from the Ministry of Mines and Energy. PARAGRAPH 2: The capacity for
receipt of Santana crude will be limited to the capacity of the pipeline,
Santana-Orito that exists at that moment. CLAUSE FOUR: DURATION. This agreement
will have an initial duration of eleven (11) months counted from the first of
February of 1999 until December 31, 1999, and could be extended for additional
periods of one (1) year by written agreement between the parties, before the
expiration of this contract. CLAUSE FIVE: TRANSPORTATION. For invoicing
purposes, the tariff approved by the Ministry of Mines and Energy will be
applied based on the total number of barrels transported. It is understood that
the Pipeline Transportation Regulation will be incorporated to this contract
once the parties approve it and once it has been submitted to the required
official approvals. CLAUSE SIX. PRICE. The price that ECOPETROL will pay THE
SELLER for the crude is defined in the following manner: Price = Base price plus
or minus quality adjustment less transport less handling and marketing.
PARAGRAPH 1: The basic price will be the average weighted of the export
shipments invoiced by Ecopetrol during that month. PARAGRAPH 2: The quality
adjustment that will be applied in this contract, will be for API Gravity and
Sulphur content that will be calculated monthly in accordance with the procedure
described in Annex 1. PARAGRAPH 3: The transportation cost, Santana-Tumaco, as
well as the respective transport tax will be adjusted to that designated by the
statutory clauses in force and remain subject to whatever modification
introduced by said provisions during the duration of the contract. In accordance
with that established in Resolution number 6031 of May 8, 1998, from the
Ministry of Mines and Energy, the Santana-Tumaco transport tariff to January 31,
1999, amounts to 1.6809 US$/BL. The amount of the transport tax corresponds to
2% (two percent) of the rate in accordance with that established in Article 17
of Decree 2140 of 1955, adopted as the
<PAGE>
permanent norm by Law 10 of 1961. Said tax will be paid according to the
Law 141 of 1994, which until January 31, 1999, is of 0.0336 US$/Bl. These
rates will be readjusted annually according to that established in the
previously mentioned Resolution No. 6031. PARAGRAPH 4: The handling and
marketing cost will be of 0.165 US$/BL. PARAGRAPH 5: If during one month or
consecutive months, there is no exportation of crude, the price would be that of
the preceding month (M-1). This will be adjusted in the following month (M + 1)
according to the new price calculated for the exports of said month M + 1. The
volume of Santana crude received in the corresponding month will be taken and
the adjustment for quality will be calculated with the average of price
quotations corresponding to the three months preceding the adjusted month (Month
M). PARAGRAPH 6. In the event that there are cabotages from the crude Tumaco
blend (South Blend), to the Cartagena refinery, the conditions for sale and
pricing that Ecopetrol will recognize to the Seller, will be the same obtained
by the International Trade Management for the crude blend (FOB Tumaco) received
by the Cartagena refinery plus or minus the quality adjustment, less the cost
for Santana-Tumaco transport and the respective tax, less marketing (USD 0.165
per barrel). In the event that the Cartagena Refinery purchases the South
Blend, without this resulting from a bidding process, the parties will agree on
a method to calculate this crude's price. PARAGRAPH 7. Not withstanding that
expressed in Paragraph 2, regarding the quality adjustment procedure, the
parties can agree to a revision of the crude supply and of the current method
used, and they could resort to a mutual agreement on the crude which should be
eliminated or added to the current supply. If an agreement is reached, it will
be applied to the entire contract. Additionally, the parties could also hire an
external consultant who could determine whether to continue with the current
method, or whether a new method should be implemented. In the event that the
parties do not reach an agreement, the current method will prevail. CLAUSE
SEVEN. BILLING AND FORM OF PAYMENT. THE SELLER will bill ECOPETROL in its
Bogota offices, within the ten (10) first days of each month, for the crude oil
of its ownership, delivered to ECOPETROL during the preceding month, after
having deducted the volume corresponding to royalties, contributions and shares.
Within seven (7) days of the before-mentioned deadline, ECOPETROL will supply
THE SELLER with the information that he requires to draw up the corresponding
invoice. The payment will be made on a monthly basis at thirty (30) days from
the date of receipt of the invoice by ECOPETROL, prior to that withheld
according to law, if there were occasion for it. Twenty-five percent ( 25% ) of
the amount will be paid in Colombian Pesos and seventy-five percent (75%) in
United States Dollars. The invoicing will be made on the basis of net volume,
free of water and
<PAGE>
sediment, adjusted to 60 degrees F. For the portion in Colombian Pesos, the
representative exchange rate for the market will be used according to the
Banking Superintendency, calculated as an arithmetical average, corresponding to
crude deliveries. PARAGRAPH 1: In the event of delay in payment of that
stipulated in the contract, for the payment in Dollars over invoices not
objected to opportunely by ECOPETROL, ECOPETROL will acknowledge to the SELLER
as interest paid in Dollars, the equivalent rate to the Prime Rate indicated by
the Chase Manhattan Bank of New York, during the days corresponding to the
effectual delay elapsed, plus 2.0%.: In the event of delay in payment of that
stipulated in the contract, liquidated in Pesos, over the respective quantity in
delay in Pesos, Ecopetrol will acknowledge the maximum monthly interest in
accordance to the certificate issued by the Banking Superindentency. The
invoices for interest charge in Pesos or in Dollars, will be cancelled within
ten (10) days following the receipt of the invoice by ECOPETROl. PARAGRAPH 2: If
ECOPETROL does not have in its possession and at its disposal, Dollars from the
United States of America, or could not obtain from the Colombian Government or
from its authorized agencies, Dollars to cover the purchases corresponding to
the contracted crude oil, Ecopetrol will quickly notify THE SELLER in writing
without detriment to the conditions stipulated in the preceding Paragraph 1, and
the parties will prepare for a maximum period of thirty (30) calendar days,
counting from the notification from ECOPETROL, as by mutual agreement, arrive at
an adequate solution. PARAGRAPH 3: ECOPETROL will dispose of fifteen (15)
working days to revise, correct or object to the invoices presented by THE
SELLER. Whatever invoice that has not been objected to within this period, will
be considered as final and correct. Whatever adjustment or correction that must
be made in the invoice, will occasion that the valid date of its presentation be
considered from the date in which said adjustment had been effectively made
before ECOPETROL. ECOPETROL will inform THE SELLER within the permitted term
over whatever invoice that is objected to so that it can be adjusted and
corrected, specifying clearly the items that must be adjusted or corrected and
the corresponding reason. CLAUSE EIGHT: INSPECTION AND MEASUREMENT. For the
purposes of Clause Two, the determination of quality will be made according to
the operative procedures that are established by mutual agreement between the
parties in accordance with the written record of proceedings. The cost of these
procedures will be shared by the parties in proportion to the crude ownership by
ECOPETROL and THE SELLER. In Addition to these operative procedures, whichever
of the parties could designate when they wish, an independent inspector to
certify quality and quantity, carry out examinations on the tanks or the
calibration of the volume measuring
<PAGE>
instruments. In the latter case, the cost will be covered by the party
requesting the measurement. CLAUSE NINE: TERMINATION. The Seller or ECOPETROL
can terminate the sale/purchase contract by written notice with an advance
notice of sixty (60) days. If THE SELLER decides to export his Santana crude
directly, he will advice ECOPETROL in writing with an advance notice of sixty
(60) days, a term within which Ecopetrol and the Seller can revoke this
contract. CLAUSE TEN: DESTINATION. ECOPETROL can give its acquired crude oil,
the destination that is considered appropriate for its interests, provided that
said destination be permitted by legal applicable arrangements that are in force
at that time. CLAUSE ELEVEN: TRANSFERS. Neither of the parties could cede, sell
or transfer the totality or any part of their rights and obligations here
contracted to a third party, without previous and written consent from the other
party. CLAUSE TWELVE: FORCE MAJEURE. Neither ECOPETROL nor THE SELLER will be
responsible for lack of compliance of all or any of their obligations according
to this agreement, if said failure is caused by events constituted as "force
majeure"or act of nature duly proven. Force Majeure is an unforseen event which
cannot be controlled, which cannot be blamed on the obliged party and that
places said party in a position where it cannot fulfil its obligations, such as:
natural phenomena (earthquakes, floods, landslides) or public order events
(strikes, Terrorism, mutiny, sabotage, pipeline ruptures). The "force majeure"
will not liberate ECOPETROL from its payment obligation to THE SELLER for those
invoices for the sale of crude oil that has been delivered by THE SELLER, in
conformity with the stipulated terms in Clause Eight of this contract. CLAUSE
THIRTEEN: APPLICATION OF COLOMBIAN LAWS. For all the purposes of this contract,
the parties confirm their domicile in the City of Santafe de Bogota, D.C.,
Republic of Colombia. This contract is in force in all of its parts by Colombian
law and the parties submit to the jurisdiction of Colombian courts and renounce
the intention of diplomatic claims in all that touches upon their rights and
obligations proceeding from this contract, except in the case of denial of
justice. For all effects of this contract, it is understood that the
dispositions incorporated in it from Article 25 of Law 40 of 1993, and that of
the Second Chapter of the Title Three of Law 104 of 1993, or from whatever other
norm that modifies or adds to them. CLAUSE FOURTEEN: NOTIFICATIONS. All
notifications made in accordance with this contract, should make reference to
this Clause and to the pertinent Clause. Said notifications should be sent by
certified mail, fax, or be delivered at the addresses that follow, are indicated
and will be considered as received in the respective address, on the date that
appears in the receipt of the letter or on the date in which the fax is sent.
<PAGE>
EMPRESA COLOMBIANA DE PETROLEOS - ECOPETROL, Calle 37 No. 7-43, Fax No. 3382585,
Attn.. International Trade and Gas Vice Presidency. THE SELLER, ARGOSY ENERGY
INTERNATIONAL, Avenue 13 (Autopista Norte), No. 122-56, floor 4, Fax No. 6-
195460 , Santafe de Bogota, D.C., Attn.: Santiago Gonzalez A., President. All
changes of address should be informed in writing, with anticipation, to the
other party. CLAUSE FIFTEEN: TAXES AND EXPENSES. All taxes and expenses that
are caused for entering into and performing this contract and its extentions or
modifications will be considered the exclusive duty of THE SELLER. CLAUSE
SIXTEEN: DISAGREEMENTS. A) In the event of disagreements between the parties
concerning legal issues related to the interpretation and performance of the
contract, that cannot be arranged in an amicable manner, shall be subjected to
the knowledge and decision of the jurisdiction branch of Colombian Sovereign
Power. B) Any difference in deed or of a technical character that arises
between the parties, with motive for the interruption or enforcement of the
contract, that cannot be settled in an amicable manner, will be subjected to the
decision of experts, named as follows: one for each party and a third
designated by mutual agreement by the principal experts named. If the two
experts did not agree on the nominated third party, this will be named by
petition of any of the parties, by the Board of Directors of the Colombian
Society of Engineers that has its headquarters in Santafe de Bogota, D.C. Any
difference of an accounting nature that arises between the parties caused by
interpretation and performance of the contract that cannot be arranged in an
amicable manner, will be subjected to the opinion of experts, who should be
certified accountants, designated as follows: one for each party and a third
named by the two principal experts. Lacking an agreement between these and on
the petition by either of the parties, said third expert will be named by the
Central Board of Accountants of Bogota, and lacking this, by the Colombian
Society of Engineers. D) Both parties declare that the decision by the experts
will have all the effects of a transaction between them and consequently, such a
decision will be definite. E) In the event of a disagreement between the
parties over technical quality, countable and/or legal, of the controversy, this
is considered as legal and the literal will be applied A) from this Clause,
that agreed to in the Clause is understood without damaging the special
procedures provided in this contract.
As written evidence, duly signed in Santafe de Bogota, D.C., on the Sixteenth
day of the month of February of Nineteen Ninety Nine (1999), on safety paper for
the original and the copy
<PAGE>
EMPRESA COLOMBIANA DE PETROLEOS ARGOSY ENERGY INTERNATIONAL
ECOPETROL
LUIS AUGUSTO YEPES G. SANTIAGO GONZALEZ ANGULO
VP International Trade and Gas Legal Representative
<PAGE>
ANNEX 1
CALCULATION OF THE ADJUSTMENT FOR QUALITY COMPENSATION
The procedure for quality adjustment will be applied for the deliveries of the
preceding month in accordance with the following procedure:
Information required:
+ Regression equation for the calculation of the referenced prices, according
to the information supplied at the end of this annex.
+ Volume and quality (API & %wtS) of the shipment (s) of crude from the Tumaco
terminal for export.
+ Volume and quality (API & %wtS) of Santana crude delivered to the Santana
terminal, as well as the deliveries in the Mary, Miraflor, Toroyaco and
Linda fields.
+ Price base of the South Blend crude delivered in Tumaco, that is exported.
Procedure:
1. Calculate the reference price for the South Blend withdrawn in Tumaco and
for the Santana crude delivered at the Santana terminal, by using a
regression equation according to its respective quality.
2. With the volume of the South Blend oil withdrawn in Tumaco and of the
Santana crude delivered at the Santana terminal and the reference prices
previously calculated, calculate the amount in US$ of each one.
3. Calculate the fraction of the amount of Santana crude in the South Blend,
dividing the US$ for the Santana crude by the US$ of the crude-Blend.
4. Calculate the volume of Santana crude compensated, multiplying the volume of
crude Blend withdrawn in Tumaco by the fraction of the cost of the Santana
crude.
5. Calculate the compensation factor of the Santana crude, dividing the
compensated volume of Santana crude by the Santana crude delivered in the
Santana terminal.
6. Calculate the amount of the compensation as follows:
Amount of the compensation = Base Price * (compensation factor minus 1)
The price is the amount of the export of the South Blend oil FOB Tumaco.
Example: All of the information presented as follows, is presented as an
example.
<PAGE>
Required information:
1. Regression Equation: Price=Bo+B1*SG+B2*%wtS.
B2 = - 0.7995 B1 =-3.8822 Bo = 20.1712
Where:
Bo = Independent Term
B1 = Regression coefficient associated with the specific gravity.
SGR = Specific gravity of the crude.
B2 = Regression coefficient associated with the percentage in weight of
sulphur.
%wtS = Percentage in crude sulphur weight.
2. South Blend crude withdrawn in the Tumaco terminal.
Volume: 400 Net Bls.
Quantity: 28.90 deg. API (0.882 SGR), 0.790 %S
Base Price of crude-Blend delivered in Tumaco: 16.0000 US$/Bl.
3. Santana crude delivered in Santana terminal.
Volume: 150,000 Bls.
Quality: 26.50 Deg. API (0.896 SGR).
The content of sulphur is obtained using the average of the sulphur content in
the crude from the Mary, Miraflor, Linda and Toroyaco fields, weighed by the
volume delivered per field, as follows:
<TABLE>
<CAPTION>
CRUDE % Weight of DELIVERED
(FIELDS) S FIELDS
BLS.
<S> <C> <C>
MARY 0.579 81.661
MIRAFLOR 0.644 13.454
LINDA 0.481 3.766
TOROYACO 0.527 60.164
TOTAL DELIVERIES 159.045
SULPHUR CONTENT 0.550
WEIGHED
Quality of sulphur: 0.550 %S
</TABLE>
<PAGE>
Note: The sulphur content from the different fields is that supplied by
Ecopetrol's Services Management of the Refining and Marketing Vicepresidency,
which for this end will be in charge of contracting an independent inspection
firm, whose expenses will be cancelled in accordance with Clause Eight of this
contract.
Procedure for Calculation:
1. Replacing the quality of each of the crudes in the regression equation .
CrudeBlend Price=20.1712+(-3.8822)*0.882+(0.7995)*0.790=16.1155 USD/BL.
Santana crude Price=20.1712+(-3.8822)*0.896+(-0.7995)*0.550=16.2530 USD/BL
2. Amount in US$ of each crude:
Crude Blend=Volume*Price=400.000 Bls*16.1155 USD/BL.=USD 6'446.200.00
Santana crude=Volume*Price=150.000 Bls*16.2530 USD/BL=USD 2'437.950
3. Fraction of Santana crude volume in crude Blend.
2'437.950.00/6'446.200.00=0.3782
4. Volume of the Santana compensated crude
400.000 Bls.*0.3782=151.280 Bls.
5. Compensation factor for Santana crude.
151.280.00 Bls./150.000.00 Bls.=1.0085
6. Amount of compensation = 16.00 USD/BL.*(1.0085-1)=0.1360 USD/BL.
INFORMATION REGARDING THE REGRESSION EQUATION
For the calculation of the regression equation, the following chart has been
drawn up of 14 international crudes. The prices of these crudes correspond to
an arithmetical average of their quotations in the three months previous to the
quality compensation evaluation. Said information, as much the price as the
quality, will be obtained from the monthly report published by Platt's and
titled as follows: " PLATT's OILGRAM PRICE REPORT".
The chart of the 14 international crudes is as follows:
<TABLE>
<CAPTION>
Price (USD/Bl.)
CRUDE API SGR %wtS Month X Year X
<S> <C> <C> <C> <C>
FATAH 30.70 0.8724 1.90 21.50
ARAB LIGHT 33.40 0.8581 1.77 22.53
ARAB MEDIUM 28.50 0.8844 2.85 21.55
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Price (USD/Bl.)
CRUDE API SGR %wtS Month X Year X
<S> <C> <C> <C> <C>
ARAB HEAVY 27.40 0.8905 2.80 20.79
BRENT BLEND 38.00 0.8348 0.30 24.04
BONNY LIGHT 35.70 0.8463 0.14 24.01
CANO LIMON 29.50 0.8789 0.45 24.45
FORCADOS 31.00 0.8708 0.20 24.06
FLOTTA BLEND 36.00 0.8448 1.20 23.49
ISTHMUS 33.00 0.8602 1.30 23.16
KUWAIT 31.40 0.8686 2.52 21.26
MANDJI 30.50 0.8735 1.10 22.08
MAYA 22.00 0.9218 3.40 19.83
ORIENT 29.50 0.8789 0.90 22.06
</TABLE>
The preceding international supply of crudes may be modified by mutual agreement
between the parties.
NOTE 1:
When the quality of the crude supplies varies during a month, an average will be
taken of the three quality prices corresponding to those same months in which
the quotations were taken.
NOTE 2:
When no quotation appears for one of the crude supplies in one month, an average
will be taken of the two previous months instead of the three quotations
established for the price calculation of that month and will be agreed upon by
the parties in writing if the supply is definitely reduced or it will be
replaced by whatever other crude in the price calculation for the following
month.
This is a fair and accurate English translation of the original document which
is in the Colombian language.
/s/ James L. Busby
------------------
James L. Busby
Secretary and Treasurer
of Aviva Petroleum Inc.
<PAGE>
Exhibit 21.1
Subsidiaries of Aviva Petroleum Inc.
Place of
Company Incorporation
- ---------------------------- -------------
Aviva Operating Company Nevada
Aviva (USA) Inc. Texas
London & Aberdeen Inc. Nevada
Aviva Energy Inc. Nevada
Aviva America, Inc. Delaware
Neo Energy, Inc. Texas
Garnet Resources Corporation Delaware
Garnet Oil Corporation Delaware
Garnet Pakistan Corporation Delaware
Garnet Spain Corporation Delaware
Garnet Turkey Corporation Delaware
Garnet PNG Corporation Delaware
Argosy Energy Incorporated Delaware
Garnet Energy Corporation Delaware
Garnet Acquisition II, Inc. Texas
Garnet Sulfur Company Nevada
Argosy Energy International Utah limited partnership
Argosy Petroleum Company, SA Colombia, South America
Garnet Resources Canada Ltd. British Columbia
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED BALANCE SHEET OF AVIVA PETROLEUM INC. AND SUBSIDIARIES AS OF
DECEMBER 31, 1998 AND THE RELATED CONSOLIDATED STATEMENT OF OPERATIONS FOR THE
YEAR ENDED DECEMBER 31, 1998 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO
SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<CASH> 2,129
<SECURITIES> 0
<RECEIVABLES> 1,923
<ALLOWANCES> 420
<INVENTORY> 836
<CURRENT-ASSETS> 5,095
<PP&E> 69,248
<DEPRECIATION> 64,440
<TOTAL-ASSETS> 11,422
<CURRENT-LIABILITIES> 20,639
<BONDS> 0
0
0
<COMMON> 2,335
<OTHER-SE> (13,418)
<TOTAL-LIABILITY-AND-EQUITY> 11,422
<SALES> 3,332
<TOTAL-REVENUES> 3,332
<CGS> 6,677
<TOTAL-COSTS> 6,677
<OTHER-EXPENSES> 12,343
<LOSS-PROVISION> 420
<INTEREST-EXPENSE> 748
<INCOME-PRETAX> (16,885)
<INCOME-TAX> (4)
<INCOME-CONTINUING> (16,881)
<DISCONTINUED> 0
<EXTRAORDINARY> (197)
<CHANGES> 0
<NET-INCOME> (17,078)
<EPS-PRIMARY> (0.50)
<EPS-DILUTED> (0.50)
</TABLE>
