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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

FOR FISCAL YEAR ENDED DECEMBER 31, 1998

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES ACT OF 1934

FOR THE TRANSITION PERIOD FROM TO

COMMISSION FILE NO. 0-22483

SEVEN SEAS PETROLEUM INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)

YUKON TERRITORY 73-1468669
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization Identification No.)
5555 SAN FELIPE, SUITE 1700
HOUSTON, TEXAS 77056
(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: (713) 622-8218

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

NAME OF EACH EXCHANGE
TITLE OF CLASS ON WHICH REGISTERED
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Common shares -- no par value per share American Stock Exchange

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

None

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 checkmark 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 [ ]

As of March 24, 1999 there were 37,778,420 shares of the registrant's
common shares, no par value per share, outstanding. The aggregate market value
of the common shares held by non-affiliates of the registrant (treating all
executive officers and directors of the registrant and their respective
affiliates for this purpose as if they may be affiliates of the registrant) was
approximately $144.4 million on March 24, 1999, based upon the closing sale
price of the common shares on such date of $5 1/8 per share on the American
Stock Exchange as reported by The Wall Street Journal.

Documents Incorporated by Reference: Proxy Statement to be filed pursuant
to Regulation 14A under the Securities Exchange Act of 1934 with respect to the
1999 Annual Meeting of Stockholders is incorporated by reference into Part III
of this Form 10-K.
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TABLE OF CONTENTS TO FORM 10-K

PAGE
----

PART I
Item 1. Business.................................................... 1
Item 2. Properties.................................................. 11
Item 3. Legal Proceedings........................................... 23
Item 4. Submission of Matters to a Vote of Security Holders......... 24
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters....................................... 25
Item 6. Selected Financial Data..................................... 26
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operation.................................. 26
Item 7a. Quantitative and Qualitative Disclosures about Market
Risk...................................................... 33
Item 8. Financial Statements and Supplementary Data................. 35
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................. 59
PART III
Item 10. Directors and Officers of the Registrant.................... 59
Item 11. Executive Compensation...................................... 59
Item 12. Security Ownership of Certain Beneficial Owners and
Management................................................ 59
Item 13. Certain Relationships and Related Transactions.............. 59
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K....................................................... 59

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PART I

ITEM 1. BUSINESS

OVERVIEW

Seven Seas Petroleum Inc. and its consolidated subsidiaries ("Seven Seas"
or the "Company") is an independent international energy company engaged in the
exploration, development and production of oil and natural gas, primarily in
Colombia, South America. The Company holds interests in the Dindal, Rio Seco,
Rosablanca, Montecristo and Tapir Association Contracts covering approximately 1
million acres in Colombia and a minority interest in a 1.8 million acre block
offshore Australia. The Company is the operator of an oil discovery (the
"Guaduas Field" formerly known as "Emerald Mountain") that is located within the
Dindal and Rio Seco Association Contracts, covering an area of approximately
109,000 contiguous acres in central Colombia. The Company owns a 57.7% working
interest in the Dindal and Rio Seco Association Contracts before participation
by Empresa Colombiana de Petroleos ("Ecopetrol"), the Colombian state oil
company. To date, the Company has focused its efforts on delineating the oil and
gas potential of the Guaduas Field. As of December 31, 1998, the Company had
drilled and completed twelve exploratory wells within the two Association
Contracts, of which six have been production tested and have achieved maximum
actual oil production rates ranging from 1,666 to 13,123 Bbls/d. Four of the
twelve wells did not produce commercial amounts of oil and gas during testing
and two remain to be tested. As of December 31, 1998, the Company had produced
approximately 300,000 barrels of oil during various testing procedures. Except
for additional production testing and further reservoir evaluation, continuous
production of the Guaduas Field will not commence prior to installation of the
infrastructure necessary to produce and transport continuous oil production. The
Company estimates that these facilities will be in place by year end 2000. As of
December 31, 1998, the Company's estimated net proved reserves attributable to
the delineation of 14,521 acres of the Guaduas Field were 38,719,235 barrels of
oil with an SEC PV-10 of $115.9 million, while total proved reserves
attributable to the Guaduas Field were 163,303,000 barrels of oil.

STRATEGY FOR GUADUAS FIELD DEVELOPMENT AND PIPELINE PRODUCTION

The Company has developed a plan to use existing cash and cash generated
from operations to further delineate and develop the Guaduas Field. Management
believes this strategy will enable the Company to take advantage of the expected
low equipment and construction costs associated with a currently depressed oil
industry and position it to be a globally competitive low-cost producer. The
Company anticipates developing the shallow Cimarrona reservoir of the Guaduas
Field in increments, coinciding with the timing of a commerciality (see "Item 2.
Properties -- Colombian Properties -- Guaduas Field -- Terms of Association
Contracts and Related Matters) agreement with Ecopetrol, environmental and right
of way permits for pipelines, wells and production facilities, the results of
drilling additional development and delineation wells and the installation of
production and transportation facilities. See "Item 2. Properties -- Colombian
Properties -- Guaduas Field -- Timing of Critical Events."

Increment I of the plan, the Portable Trucking Facility ("PTF"), includes a
portable, skid mounted oil production and truck loading facility. The Company
anticipates that production of between 4,000 Bbls/d and 6,000 Bbls/d will begin
in early-2000. Prior to installation of permanent facilities, the Company plans
to sell, at the field, production from Increment I of the development program to
be trucked to a privately owned refinery approximately 80 miles north of the
field. The PTF will eventually become a permanent production facility, but
during Early Pipeline Production, Increment II, it will be utilized in various
parts of the field so that the Company can truck oil to the permanent facilities
where the Guaduas pipeline connects as soon as new wells are completed.

Increment II, Early Pipeline Production, is expected to be completed by
year-end 2000 and to begin production at a rate of between 20,000 Bbls/d and
30,000 Bbls/d. Increment II includes further development and delineation
drilling, the horizontal/lateral re-drilling of wells that failed to produce oil
and gas in commercial quantities when tested, one gas injection well, the
construction of production facilities and a

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36-mile pipeline with an ultimate throughput capacity of 100,000 Bbls/d with the
installation of maximum additional pumping capacity. The Early Pipeline
Production increment will connect the Guaduas Field by pipeline to an existing
regional pipeline, known as the Oleoducto Alto Magdelena ("OAM"), that currently
has approximately 62,000 Bbls/d of available transportation capacity.

Increment III of the development plan, which is scheduled to be completed
in 2002, anticipates the drilling of additional wells and additional production
facilities and is designed to increase production to between 40,000 Bbls/d and
65,000 Bbls/d.

Increment IV of the development plan, which is scheduled to be completed in
2003, includes the drilling of additional wells, additional production
facilities and increased pumping capacity for the pipeline and is designed to
increase production to between 70,000 Bbls/d and 120,000 Bbls/d. Available
excess capacity, if any, in the OAM regional pipeline upon completion of
Increment III will determine the eventual net capital expenditure required
because additional pumping equipment and/or drag reducing agents may be required
in order for the OAM pipeline to handle the transportation of additional oil.

Increment V of the development plan, which would occur only if the reserves
of the Guaduas Field's shallow Cimarrona reservoir increase to levels that
warrant significant daily production above 100,000 Bbls/d or if additional
reserves were to be established at deeper levels, would be completed by
early-2005 and produce at rates between 170,000 Bbls/d to 290,000 Bbls/d.

Increments II through V production increases will each require additional
production facilities, a pipeline expansion and the expansion of proved oil
reserves through successful development and delineation drilling of the shallow
Cimarrona reservoir. The Company's schedule of construction as estimated above
is dependent upon the timely issuance of various environmental permits and the
Company's agreement with Ecopetrol on "commerciality." Although the Company has
reason to believe a commerciality agreement can be reached with Ecopetrol that
will allow the Company to proceed as planned, without the commerciality
agreement in place before December 1999, the Company will not be able to meet
the aforementioned schedule. In addition to implementing the strategy for the
development of the Guaduas Field, the Company has plans to drill a west flank
exploratory well and an exploratory well of the deep structure below the shallow
Cimarrona reservoir. The schedule for these plans is contingent upon the
availability of adequate funding.

The Company intends to use its available cash and cash flow generated from
production under its Increment I development plan to fund activities associated
with Increment II. To the extent the Company experiences delays or cost overruns
in the Increment II development plan, the Company would be required to seek
additional financing to complete Increment II. In addition, the Company will be
required to obtain additional sources of financing to undertake development
plans under Increments III through V. Such additional sources of financings may
occur from project financing of the pipeline, industry joint ventures or other
like arrangements with industry service companies, commercial bank lending and
debt and equity offerings of the Company's securities. There can be no assurance
that additional sources of financing will be available when needed by the
Company. The Company's expenditures for Increment II, may be substantially
reduced by way of the formation of a separate and independent company to
construct the Guaduas pipeline (connecting to the OAM regional pipeline) to be
financed and owned by others and in which the Company may have little or no
equity, thereby obligating the Company to pay only a per barrel tariff on its
oil as transported through the pipeline and none of the capital expenditures
that are currently budgeted by the Company for the construction of the pipeline.
If additional financing from any of the above sources becomes available, the
Company plans to accelerate its incremental expansion of the Guaduas Field
production, drill the Guaduas Field structure west flank delineation well, drill
the deep structure exploration well and drill exploration wells on its multiple
prospects within the Company-operated Rosablanca and Montecristo blocks. See
"Item 2. Properties -- Montecristo and Rosablanca Association Contracts."

HISTORY

Seven Seas was formed effective June 29, 1995 as a result of an
amalgamation (the "Amalgamation") under laws of the province of British Columbia
of Rusty Lake Resources Ltd. ("Rusty Lake") and Seven

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Seas Petroleum Inc. (the "Predecessor"), which was incorporated under the laws
of British Columbia on February 3, 1995. Rusty Lake was formed effective January
31, 1993 by an amalgamation of Lithium Corporation of Canada, Limited and
Stockgold Resources Inc. under the laws of Ontario. In August 1996, the Company
was continued as a Yukon Territory, Canada, Corporation.

Seven Seas was originally organized to take non-operator interests in oil
and gas exploration projects outside of North America. In August 1995, the
Company acquired a 15% interest in the Dindal and Rio Seco Association Contracts
from GHK Company Colombia ("GHKCC"), a subsidiary of the GHK Company, L.L.C.,
and participated in the drilling of the El Segundo Guaduas Field discovery well.
In 1996, the Company acquired an additional 36.7% interest in both Association
Contracts through its acquisition of 100% of GHKCC and Esmeralda LLC and a 63%
interest in Cimarrona LLC by exchanging the Company's securities valued at
$151.1 million in the aggregate at the time of the closing the transaction. In
1997, the Company acquired an additional 6% interest in the Association
Contracts from Petrolinson S.A. in exchange for the issuance of the Company's
securities valued at $25 million in the aggregate at the time of the closing of
the transaction. See "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources."

RISK FACTORS

In addition to the other information set forth elsewhere herein, the
following factors relating to the Company should be carefully considered when
evaluating the Company.

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

This document includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act and Section 21E of the Exchange Act. All
statements included herein other than statements of historical fact are
forward-looking statements. Such forward-looking statements include, without
limitation, the statements in "Business," "Management's Discussion and Analysis
of Financial Condition and Results of Operations," regarding the Company's
financial position, estimated quantities of reserves, business strategy and
plans and objectives for future operations. Forward-looking statements herein
generally are accompanied by words such as "anticipate," "believe," "estimate,"
"project," "potential" or "expect" or similar statements. Although the Company
believes that the expectations reflected in such forward-looking statements are
reasonable, no assurance can be given that such expectations will prove correct.
Factors that could cause the Company's results to differ materially from the
results discussed in such forward-looking statements are discussed in "Risk
Factors" and elsewhere herein. All forward-looking statements included herein
and therein are expressly qualified in their entirety by the cautionary
statements in this paragraph.

RISKS RELATED TO THE COMPANY

SUBSTANTIAL INDEBTEDNESS; LACK OF CASH FLOW

At December 31, 1998, the Company had $110 million of indebtedness
outstanding consisting of its 12 1/2% Senior Notes due 2005 (the "Senior
Notes"). The Company and its subsidiaries may incur additional indebtedness
under the terms of the indenture governing the Senior Notes under certain
circumstances. This level of indebtedness may pose substantial risks to the
Company, including the possibility that the Company may not generate sufficient
cash flow from operations to pay the principal and interest on such
indebtedness.

The Company's ability to generate revenues and cash flow to pay the
principal of and interest on its indebtedness will depend upon the drilling and
completion of additional wells. The Company has no significant income-producing
properties, and its principal assets, its interests in the Dindal and Rio Seco
Association Contracts, are in the early stage of exploration and development.
Since inception through December 31, 1998, the Company has incurred cumulative
losses of $102.4 million and, because of its continued exploration and
development activities, expects that it will continue to incur losses and that
its accumulated deficit will increase until commencement of production from the
Dindal and Rio Seco Association Contracts in quantities sufficient to cover
operating expenses. The Company had oil sales in 1996, 1997, 1998 of $0.2
million,

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$0.8 million, and $0.02 million, respectively, which pertained solely to
production testing of the Company's wells in Colombia. These sales represented
the Company's only sales of production since its inception. Although the Company
intends to continue to sell oil resulting from production tests, significant
production from the wells drilled to date is not expected to commence until
construction of production facilities and pipelines. The Company has received
basic and detailed engineering specifications for the construction of pipelines
and production facilities. The construction of the Company's planned pipelines
and production facilities is subject to a number of conditions, including
negotiating construction contracts and obtaining required environmental and
construction permits, easements and rights of way. The Company does not expect
these facilities to be completed before mid-2000, and no assurance can be given
as to when such facilities will be completed. Accordingly, no assurance can be
given as to when significant production from the wells will occur, if at all. If
the Company is unsuccessful in constructing production facilities and a pipeline
or in increasing its proved reserves or realizing future production from its
properties, the Company may be unable to pay all of the principal of and
interest on its indebtedness when due. The Company has initiated an incremental
development strategy that it believes will lead to production and early cash
flow in the Guaduas Field. A preliminary request for commerciality was submitted
to Ecopetrol in December 1998. The Company plans to submit a pre-commerciality
Memorandum of Understanding ("MOU") that will address the sharing of on-going
pre-commercial costs and other issues associated with commerciality. The MOU is
expected to be approved in the second quarter of 1999 and commerciality declared
in the fourth quarter of 1999. If the MOU and/or commerciality is not approved,
the Company may have capital expenditures higher than the amounts presented as
net to the Company. See "-- Risks Related to Construction of Pipeline and
Production Facilities" and "-- Risks Related to the Oil and Gas Industry."

The level of the Company's indebtedness will have certain important effects
on its future operations, including a substantial portion of the Company's cash
flow from operations likely will be dedicated to payments on indebtedness and
will not be available for other purposes. In addition, such level of
indebtedness may affect the Company's ability to finance its future operations
and capital needs and may limit its ability to pursue other business
opportunities. In addition, the Company's ability to meet its debt service
obligations and to limit its total indebtedness will depend upon the Company's
future performance, which will be subject to general economic conditions, the
economic and political environment in Colombia, prices received for the
Company's production and operating hazards inherent in the oil and gas business,
all of which are beyond the control of the Company.

RISKS RELATED TO CONSTRUCTION OF PIPELINE AND PRODUCTION FACILITIES

The Company has completed the basic and detailed engineering specifications
for the construction of pipelines and production facilities. The construction of
the pipelines and the related production facilities is subject to a number of
conditions, including negotiating construction contracts and obtaining required
environmental and construction permits, easements and rights of way. The Company
expects the Increment II pipeline of between 20,000 Bbls/d and 30,000 Bbls/d, to
be completed by year-end 2000, but no assurance can be given as to whether or
when such pipeline will be completed. The production facilities are scheduled to
be completed incrementally with production capacity of approximately 25,000
Bbls/d by year-end 2000; 50,000 Bbls/d in 2002; 100,000 Bbls/d in 2003; and
potentially 250,000 Bbls/d in early-2005 and beyond. The Company has not
finalized its negotiations with the operator of the OAM pipeline for the
transportation of oil produced under the Increment II development plan. If the
Company is unsuccessful in constructing its pipeline and production facilities
or in increasing its proved reserves or realizing future production from its
properties, the Company may be unable to pay all of the principal of and
interest on its indebtedness when due. See "-- Risks Related to the Oil and Gas
Industry."

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The ability of the Company to meet its objective to have online production
by year-end 2000 is dependent on certain key events, including the receipt of
environmental permits for the pipeline, a global operating license from the
Colombian Ministry of Environment and approval of commerciality by Ecopetrol. No
assurance can be given that the approvals or permits will be obtained or
obtained in a timely matter. Failure to obtain the requisite approvals or
permits will adversely affect the Company's ability to generate the necessary
cash flow from operations to continue its further development plans and may
hinder the Company's efforts to achieve alternative financing arrangements.

NEED FOR SIGNIFICANT CAPITAL

The exploration and development of the Company's current properties and any
properties acquired in the future is expected to require substantial amounts of
additional capital which the Company may be required to raise through external
sources of financing or entering into arrangements whereby certain costs of
exploration will be paid by others to earn an interest in the Company's
properties. There can be no assurance that the additional financings will be
available to the Company. Without some additional financing, the Company
believes its current cash resources may not be sufficient to finance its total
budgeted capital expenditure requirements for Increment II (see "-- Strategy for
Guaduas Field Development and Pipeline Production"). Increments III through V
will require substantial additional amounts of capital and no external sources
of capital have yet been identified. It is expected that additional monies for
capital expenditures will be externally financed, as the Company does not expect
any significant revenues from operations before year-end 2000 when the permanent
production facilities are expected to be in place. If sufficient funds cannot be
raised to meet the Company's obligations with respect to a property, the Company
may elect to forfeit its interest in such property. The Company does not
anticipate that it will lose any of its Colombian property to forfeiture. As of
February 28, 1999, the Company has non-discretionary commitments under existing
exploration and development contracts of $5.3 million through year-end 1999. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."

The Company's estimated capital expenditures assume in each case that each
of the associates in the Association Contracts approves and pays its
proportionate share of capital expenditures. Under the terms of the Association
Contracts, if a commercially feasible discovery is made, Ecopetrol may acquire a
50% interest in the property, and the interests of all other parties to the
contract, including the Company, will be reduced by 50%. Ecopetrol will bear 50%
of the associated development costs and will reimburse the other working
interest owners for 50% of certain exploration activities. The Company believes
that Ecopetrol may finance a significant portion of the costs associated with
its working interest from Ecopetrol's share of future production rather than
contributing its proportionate share of development costs in cash. As a result,
the Company and the other working interest owners could be required initially to
finance Ecopetrol's share of the development costs associated with the property.
While the Association Contracts do not require Ecopetrol's participation in the
pipeline and production facilities, the Company believes that Ecopetrol will
participate to the extent of 50% in Increments I and II of the Guaduas Field
infrastructure and pipeline. No assurance can be given, however, that an
agreement will be reached on these terms and the Company may be required to fund
amounts greater than the amounts presented as the Company's net share. See
"Business -- Properties -- Terms of Association Contracts and Related Matters."

RISKS IN COLOMBIA AND OTHER FOREIGN OPERATIONS

Foreign properties, operations or investments may be adversely affected by
local political and economic developments, exchange controls, currency
fluctuations, devaluation of local currency, royalty and tax increases,
retroactive tax claims, renegotiation of contracts with governmental entities,
expropriation, import and export regulations and other foreign laws or policies
governing operations of foreign-based companies, as well as by laws and policies
of the United States affecting foreign trade, taxation and investment. In
addition, as the Company's operations are governed by foreign laws, in the event
of a dispute, the Company may be subject to the exclusive jurisdiction of
foreign courts and the application of foreign laws or may not be successful in
subjecting foreign persons to the jurisdiction of courts in the United States.
The Company may

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also be hindered or prevented from enforcing its rights with respect to a
governmental instrumentality because of the doctrine of sovereign immunity.

The Company's business is subject to political risks inherent in all
foreign operations. While Colombia has no history of nationalizing its business
or expropriation of foreign assets, the Company's oil and gas operations are
subject to certain risks, including: (i) loss of revenue, property, and
equipment as a result of unforeseen events such as expropriation,
nationalization, war and insurrection, (ii) risks of increases in taxes and
governmental royalties, (iii) renegotiation of contracts with governmental
entities, and (iv) changes in laws and policies governing operations of
foreign-based companies in Colombia. Guerrilla activity in Colombia has
disrupted the operation of oil and gas projects in many areas in Colombia but to
date has not affected the Dindal and Rio Seco Association Contracts areas. No
assurance can be given as to the future level or impact of future guerilla
activities, including after the construction of pipeline and production
facilities in the Dindal and Rio Seco Association Contracts areas, or the steps,
if any, that may be taken by the government in response to such activities. The
Company's other three association contracts are located in more remote areas
that have been subject to guerrilla activity. The government continues its
efforts through negotiation and legislation to reduce the problems and effects
of insurgent groups. These efforts include regulations containing sanctions such
as impairment or loss of contract rights on companies and contractors found to
be giving aid to such groups. To date, guerrilla activities have not materially
disrupted operations in the areas where the other three association contracts
are located.

Colombia is among several nations whose progress in stemming the production
and transit of illegal drugs is subject to annual certification by the President
of the United States. The consequences of the failure to receive certification
generally include the following: all bilateral aid, except anti-narcotics and
humanitarian aid, has been or will be suspended; the Export-Import Bank of the
United States and the Overseas Private Investment Corporation ("OPIC") will not
approve financing for new projects in Colombia; United States representatives at
multilateral lending institutions will be required to vote against all loan
requests from Colombia, although such votes will not constitute vetoes; and the
President of the United States and Congress retain the right to apply future
trade sanctions. In June 1998, Andres Pastrana, the Conservative Party
candidate, was elected president of Colombia, defeating the ruling Liberal party
candidate in a runoff election. Mr. Pastrana, who took office in early August
1998, has publicly announced his desire to bring peace to the country, and, the
peace negotiation process between government officials and representatives of
rebel groups is continuing. In February 1999, the President of the United States
granted Colombia a full certification, thereby avoiding any of the consequences
associated with decertification. If the United States were to decertify Colombia
in the future, such actions could result in adverse economic consequences in
Colombia and could further heighten the political and economic risks associated
with the Company's operations in Colombia.

SUBSTANTIAL CONCENTRATION OF OPERATIONS

The Company's oil and gas properties are concentrated in Colombia and
specifically in the state of Cundinamarca. As of December 31, 1998, all of the
Company's proved reserves were attributable to the Guaduas Field. There are
significant operating and economic risks associated with conducting business in
Colombia. Due to the Company's concentration in and reliance on such operations
for its future cash flow, if the operations in Colombia were adversely affected,
the Company would experience a material adverse effect. See "-- Risks in
Colombian and Other Foreign Operations" and "-- Risks Related to the Oil and Gas
Industry."

LIMITED OPERATING HISTORY AND HISTORICAL OPERATING LOSSES

The Company commenced its operations in 1995 and has only a limited
operating history. The Company also has had operating losses at an increasing
rate each year since inception. Accordingly, the Company has limited historical
financial and operating information upon which to base an evaluation of its
performance. For example, the only production to date has been approximately
300,000 barrels of test production. The Company is not expected to have
continuous pipeline production until year-end 2000. Therefore, estimates of
proved reserves and the level of future production attributable to such reserves
are difficult to determine, and there can be no assurance as to the volume of
recoverable reserves that will be realized. The Company's prospects
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must be considered in light of the risks, expenses, delays and difficulties
frequently encountered by companies in the early stages of their development.
The development of the Company's business will continue to require substantial
expenditures. The Company's future financial results will depend primarily on
its ability to economically locate and produce hydrocarbons in commercial
quantities and on the market prices for oil and natural gas. There can be no
assurance that the Company will achieve or sustain profitability or positive
cash flows from operating activities in the future. See "-- Need for Significant
Capital," "Selected Combined Financial Data," and "Management's Discussion and
Analysis of Financial Condition and Results of Operations."

DEPENDENCE ON KEY PERSONNEL

The Company believes that its success will depend to a significant extent
upon the continued services of certain key executive officers and operating
personnel. The Company has entered into employment agreements with certain of
its key executive officers. The Company also depends on the services of
professionals such as engineers, geologists and geophysicists. The loss of the
services of certain key executive officers and operating personnel or the loss
of or shortage of significant number of professionals could have a material
adverse effect on the Company. The Company does not maintain key employee
insurance on any of its personnel. See "-- Employees."

POTENTIAL CONFLICTS

Certain of the directors of the Company also serve as officers, directors
or consultants of other companies involved in natural resource development which
activities may be in competition with the Company and may result in conflicts of
interest. In the event a director has an interest in an investment or proposed
investment of the Company or other conflict of interest, it is the Company's
policy that such director not participate in the Company's decision-making with
respect thereto and that any transactions with such officers or directors be on
terms consistent with industry standards and sound business practices.

RISKS RELATED TO THE OIL AND GAS INDUSTRY

UNCERTAINTY OF ESTIMATES OF OIL AND GAS RESERVES

This report on Form 10-K contains estimates of the Company's proved oil and
gas reserves and the estimated future net revenues therefrom based upon the
Company's own estimates or on those of Ryder Scott Company Petroleum Engineers
and Servipetrol Ltd. Such estimates rely upon various assumptions, including
assumptions required by the United State Securities and Exchange Commission (the
"Commission") as to oil and gas prices, drilling and operating expenses, capital
expenditures, taxes and availability of funds. The process of estimating oil and
gas reserves is complex, requiring significant decisions and assumptions in the
evaluation of available geological, geophysical, engineering and economic data
for each reservoir. As a result, such estimates are inherently imprecise. Actual
future production, oil and gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and gas
reserves may vary substantially from those estimated by the Company, Ryder Scott
Company Petroleum Engineers or Servipetrol Ltd. Any significant variance in
these assumptions could materially affect the estimated quantity and value of
reserves set forth here. The Company's properties may also be susceptible to
hydrocarbon drainage from production by other operators on adjacent properties.
In addition, the Company's estimated proved reserves may be subject to downward
or upward revision based upon production history, results of future exploration
and development, prevailing oil and gas prices, mechanical difficulties,
government regulation and other factors, many of which are beyond the Company's
control. Actual production, revenues, taxes, development expenditures and
operating expenses with respect to the Company's reserves will likely vary from
the estimates used, and such variances may be material.

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attributable to the Company's oil and gas reserves have been prepared in
accordance with industry standards, no assurance can be given that the estimated
costs are accurate, that development will occur as scheduled or that the results
will be as estimated.

The present value of future net revenues (SEC PV-10) referred to here
should not be construed as the current market value of the estimated oil and gas
reserves attributable to the Company's properties. In accordance with applicable
requirements of the Commission, the estimated discounted future net cash flows
from proved reserves are generally based on prices and costs as of the date of
the estimate, whereas actual future prices and costs may be materially higher or
lower. See "-- Volatility of Oil and Natural Gas." The timing of actual future
net cash flows from proved reserves, and thus their actual present value, will
be affected by the timing of both the production and the incurrence of expenses
in connection with development and production of oil and gas properties. In
addition, the 10% discount factor, which is required by the Commission to be
used in calculating discounted future net cash flows for reporting purposes, is
not necessarily the most appropriate discount factor based on interest rates in
effect from time to time and risks associated with the Company or the oil and
gas industry in general.

DRILLING, EXPLORATION AND DEVELOPMENT RISKS

Oil and gas exploration and development is a speculative business and
involves a high degree of risk. The Company has expended, and plans to continue
to expend, significant amounts of capital on the exploration and development of
its oil and gas interests. Even if the results of such activities are favorable,
subsequent drilling at significant costs must be conducted on a property to
determine if commercial development of the property is feasible. Oil and gas
drilling may involve unprofitable efforts, not only from dry holes but from
wells that are productive but do not produce sufficient net revenues to return a
profit after drilling, operating and other costs. It is difficult to project the
costs of implementing an exploratory drilling program due to the inherent
uncertainties of drilling and completing wells in unknown formations, the costs
associated with encountering various drilling conditions such as underpressured
and overpressured zones and tools lost in the hole, and changes in drilling
plans and locations as a result of prior exploratory wells or additional seismic
data and interpretations thereof. The marketability of oil and gas which may be
acquired or discovered by the Company will be affected by the quality and
viscosity of the production and by numerous factors beyond its control,
including market fluctuations, the proximity and available capacity of oil and
gas pipelines and production equipment, government regulations, including
regulations relating to prices, taxes, royalties, land tenure, importing and
exporting of oil and gas and environmental protection. The Company's future
drilling activities may not be successful, and, if unsuccessful, such failure
will have an adverse effect on the Company's future results of operations and
financial condition, including the Company's ability to pay all of the principal
and interest on its indebtedness, including the Senior Notes, when due. There
can be no assurance the Company will be able to discover, develop and produce
sufficient reserves in Colombia or elsewhere to recover the costs and expenses
incurred in connection with the acquisition, exploration and development thereof
and achieve profitability.

Acquiring, developing and exploring for oil and natural gas involve many
risks, which even a combination of experience, knowledge and careful evaluation
may not be able to overcome. These risks include encountering unexpected
formations or pressures, premature declines of reservoirs, blow-outs, equipment
failures and other accidents in completing wells and otherwise, cratering, sour
gas releases, uncontrollable flows of oil, natural gas or well fluids, adverse
weather conditions, pollution, other environmental risks, fires and spills.
Losses resulting from such events could have a material adverse effect on the
Company.

As protection against operating hazards, the Company maintains insurance
against some, but not all, potential losses. The Company's coverages include,
but are not limited to, operator's extra expense, physical damage on certain
assets, employer's liability, comprehensive general liability, automobile,
workers' compensation and limited coverage for sudden environmental damages, but
all such coverages are subject to certain exceptions, conditions and
limitations. The Company does not believe that insurance coverage for the full
potential liability that could be caused by sudden environmental damages and
certain other risks is available at a reasonable cost. Accordingly, the Company
may be subject to liability or may lose substantial portions of its

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properties in the event of environmental damages or certain other events. The
occurrence of an event that is not fully covered by insurance could have a
material adverse effect on the Company.

VOLATILITY OF OIL AND NATURAL GAS PRICES

The Company's revenues, future rate of growth, results of operations,
financial condition and ability to borrow funds or obtain additional capital, as
well as the carrying value of its properties, are substantially dependent upon
prevailing prices of oil and natural gas. Historically, the markets for oil and
natural gas have been volatile, and such markets are likely to continue to be
volatile in the future. Prices for oil and natural gas are subject to wide
fluctuation in response to relatively minor changes in the supply of and demand
for oil and natural gas, market uncertainty and a variety of additional factors
that are beyond the control of the Company. These factors include the level of
consumer product demand, weather conditions, domestic and foreign governmental
regulations, the price and availability of alternative fuels, political
conditions in the Middle East, actions of the Organization of Petroleum
Exporting Countries ("OPEC"), the foreign supply of oil and natural gas, the
price of foreign imports and overall economic conditions. It is impossible to
predict future oil and natural gas price movements with certainty. Declines in
oil and natural gas prices may materially adversely affect the Company's
financial condition, liquidity, ability to finance planned capital expenditures
and results of operations. Lower oil and natural gas prices also may reduce the
amount of oil and natural gas that the Company can produce economically. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."

The Company periodically reviews the carrying value of its oil and natural
gas properties under the full cost accounting rules of the Commission. Under
these rules, capitalized costs of proved oil and natural gas properties may not
exceed the present value of estimated future net revenues from proved reserves,
discounted at 10% (SEC PV-10) and adjusted for income tax effects. Application
of this "ceiling" test generally requires pricing future revenue at the
unescalated prices in effect as of the end of each fiscal quarter and requires a
write-down for accounting purposes if the ceiling is exceeded. The Company was
required to record a pre-tax $129.8 million or after tax $84.4 million write
down of the carrying value of its oil and natural gas properties for the year
1998. Once incurred, a write-down of oil and natural gas properties is not
reversible at a later date.

RESERVE REPLACEMENT RISK

In general, the volume of production from oil and natural gas properties
declines as reserves are depleted, with the rate of decline depending on
reservoir characteristics. Except to the extent the Company conducts successful
exploration and development activities or acquires properties containing proved
reserves, or both, the proved reserves of the Company will decline as reserves
are produced. The Company's future oil and natural gas production is, therefore,
highly dependent upon its level of success in finding or acquiring additional
reserves. The business of exploring for, developing or acquiring reserves is
capital intensive. To the extent cash flow from operations is reduced and
external sources of capital become limited or unavailable, the Company's ability
to make necessary capital investment to maintain or expand its asset base of oil
and natural gas reserves would be impaired. The failure of an operator of the
Company's wells to adequately perform operations, or such operator's breach of
the applicable agreements, could adversely impact the Company. In addition,
there can be no assurance that the Company's future exploration, development and
acquisition activities will result in additional proved reserves or that the
Company will be able to drill productive wells at acceptable costs. Furthermore,
although the Company's revenues could increase if prices for oil and natural gas
increase significantly, the Company's finding and development costs could also
increase. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations."

ENVIRONMENTAL RISKS

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obligations to remediate current and former facilities and off-site locations.
In addition, special provisions may be appropriate or required in
environmentally sensitive areas of operation, such as where the Company's
Colombian interests are located and where other producers of oil and gas have
faced significant liability resulting from environmental claims. There can be no
assurance that the Company will not incur substantial financial obligations in
connection with environmental compliance.

It is possible that the administration and enforcement of current
environmental laws and regulations 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 and expand the
Company's operations in such country. The Company has experienced and may
continue to experience delays in obtaining the necessary environmental permits
to expand its operations in Colombia.

Significant liability could be imposed on the Company for damages, clean-up
costs and/or penalties in the event of certain discharges into the environment,
environmental damage caused by previous owners of property purchased by the
Company or non-compliance with environmental laws or regulations. Such liability
could have a material adverse effect on the Company. Moreover, the Company
cannot predict what environmental legislation or regulations will be enacted in
the future or how existing or future laws or regulations will be administered or
enforced. Compliance with more stringent laws or regulations, or more vigorous
enforcement policies of any regulatory agency, could in the future require
material expenditures by the Company for the installation and operation of
systems and equipment for remedial measures, any or all of which could have a
material adverse effect on the Company.

The Company has experienced environmental problems on certain of its
Colombian properties on which it may have liabilities. See "-- Regulation."

MARKETS

The marketability of the Company's production depends upon the availability
and capacity of gathering systems, pipelines, compression and production
facilities, including storage, separation and re-injection facilities. The
unavailability or lack of capacity thereof could result in the shut-in of
producing wells or the delay or discontinuance of development plans for
properties. In addition, there is substantial uncertainty as to the prices which
the Company may receive for production from its existing oil reserves or from
additional oil and gas reserves, if any, which the Company may discover. 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, but
not limited to, adequate transportation facilities (such as pipelines), the
marketing of competitive fuels, fluctuating market demand, governmental
regulation and world political and economic developments. Prices for crude oil
are subject to wide fluctuation in response to relatively minor changes in
supply and demand, market uncertainty and a variety of additional factors that
are beyond the control of the Company. It is possible that, under market
conditions prevailing in the future, the production and sale of oil, if any,
from certain of the Company's properties may not be commercially feasible and
the production of gas from the Company's oil and gas interests in Colombia is
not currently commercially feasible. The sale of oil from the production tests
on the Company's properties in Colombia has been sold to Ecopetrol and a private
refinery.

COMPETITION

The Company encounters competition from other oil and gas companies in all
areas of its operations, including the acquisition of producing properties. The
Company's competitors in Colombia include major multi-national integrated oil
and gas companies and both local and multi-national independent oil and gas
companies. Many of its competitors are large, well-established companies with
substantially larger operating staffs and greater capital resources than the
Company's and which, in many instances, have been engaged in the oil and gas
business for a longer time than the Company. Such companies may be able to offer
more attractive terms in obtaining contracts for exploratory prospects and
secondary operations and to pay more for productive properties and exploratory
prospects and to define, evaluate, bid for and purchase a greater number of
properties and prospects than the Company's financial or human resources permit.
The Company's ability

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to acquire additional properties and to discover reserves in the future will be
dependent upon its ability to evaluate and select suitable properties and to
consummate transactions in this highly competitive environment, as well as its
ability to obtain adequate capital.

EMPLOYEES

Certain members of the Company's management have been involved in the
Guaduas Field project since its inception in 1992. The Company's executive
officers average approximately 29 years of experience in the oil and gas
industry, and predecessors of the Company have operated oil and gas interests
throughout the U.S. and Canada since 1959. As of December 31, 1998, the
Company's officers and directors beneficially owned approximately 25% of the
Company's outstanding common shares. As of March 5, 1999 the Company had 67 full
time employees, including geologists, geophysicists, and engineers. The
following is a list of the Company's key employees and executive officers as of
March 5, 1999:

YEARS OF OIL &
GAS
EXECUTIVE OFFICER POSITION HELD WITH SEVEN SEAS EXPERIENCE LOCATION
----------------- ----------------------------- -------------- --------

Robert A. Hefner III................. Chief Executive Officer, 42 Houston
Chairman
Executive Vice President, Houston
Larry A. Ray......................... Chief 28
Operating Officer & Director
Executive Vice-President, Houston
Herbert C. Williamson III............ Chief 20
Financial Officer, & Director
William W. Daily*.................... Executive Vice President, 30 Bogota
President of GHKCC, &
Director

YEARS OF OIL &
GAS
EXECUTIVE OFFICER POSITION HELD WITH SEVEN SEAS EXPERIENCE LOCATION
----------------- ----------------------------- -------------- --------

Russ D. Cunningham................... Exploration Manager 21 Denver
Charles P. O'Brien................... Reservoir Engineering Manager 18 Houston
Raymond H. Parsons................... Geophysical Manager 19 Houston
Jeff McCloskey*...................... Facilities and Construction 23 Bogota
Manager
Todd Habliston*...................... Manager of Production and 15 Bogota
Operations
Gary Wallen*......................... Drilling Manager, GHKCC 25 Bogota
Wayne Lewis*......................... Project Manager, GHKCC 28 Bogota

- ---------------

* These are the oil professionals that have been designated the "Bogota Team"
and are in charge of planning, budgeting and execution of the Company's
Colombian operations. The Bogota team professionals have over 100 cumulative
years of international experience in the development of large oil fields,
production facilities, pipelines and oil and gas field infrastructure.

ITEM 2. PROPERTIES

COLOMBIAN PROPERTIES

GUADUAS FIELD

OVERVIEW. The Company's Colombian operations are focused on the Guaduas
Field. The Guaduas Field discovery is within two adjoining association contracts
located in the capital state of Cundinamarca in central Colombia, approximately
60 miles northwest of Bogota. The contract areas, covering approximately 109,000

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acres, are defined by the Rio Seco and Dindal Association Contracts. The village
of Guaduas lies within the Dindal and Rio Seco Association Contract blocks and
provides infrastructure for the local economy, which is primarily agrarian in
nature. The area is accessible via the main road between Bogota and Medellin and
the Colombian Carribean Coast. The OAM pipeline is a regional pipeline
transporting oil production from the Upper and Middle Magdalena river basins to
the oil refining and terminal city of Vasconia where it connects with the
Oleoducto de Colombia ("ODC") regional pipeline that transports oil to the
export terminal facilities at the port of Covenas, on the Caribbean coast. As a
result of current and forecast continuing excess capacity in the OAM and ODC
lines, the Company plans to build its pipeline from the Guaduas Field to La
Dorada, a town located 36 miles northwest of Guaduas, where it will connect with
the OAM pipeline so that Guaduas Field oil production can be transported via the
ODC pipeline to the port of Covenas. The Company owns a 57.7% working interest
in the Guaduas Field before participation by Ecopetrol. The remaining interests
are owned by MTV Investments Limited Partnership (9.4%) and Sociedad
Internacional Petrolera, S.A. ("Sipetrol") (32.9%). Sipetrol is the
international exploration and production subsidiary of the Chilean national oil
company. As of December 31, 1998, Ryder Scott Company Petroleum Engineers
estimated the Company's net proved reserves attributable to the delineation of
14,521 acres of the Guaduas Field to be 38,719,235 Bbls. of oil with a SEC PV-10
of $115.9 million, and the Guaduas Field total reserves to 163,303,000 Bbls.

DRILLING ACTIVITY. To date, twelve wells have been drilled on the Dindal
and Rio Seco Association Contract areas. The first well, the Escuela 1, which
was drilled in 1994 prior to the acquisition of an interest in the Association
Contracts by the Company, did not encounter the Cimarrona formation and was
plugged and abandoned as non-commercial.

The discovery well on the Guaduas Field was the second well drilled on the
Dindal block, El Segundo 1-E. The El Segundo 1-E discovery well commenced
drilling in December 1995 and reached total depth in mid-January 1996. The well
encountered the Cimarrona formation, the oil and gas reservoir of the Guaduas
Field, at a measured depth of 5,718 feet, but drilling was stopped after
penetrating only 88 feet of the Cimarrona due to circulation problems while
drilling. The well was then completed open hole in February 1996. The El Segundo
I-E tested oil at an actual maximum rate of 3,415 Bbls/d.

A third well, El Segundo 1-N, reached total measured depth of 6,820 feet in
November 1996. This well was intentionally deviated from the surface location of
El Segundo 1-E to a bottom hole location approximately 2,000 feet north. The
well encountered approximately 352 feet of oil saturated and highly fractured
Cimarrona reservoir rocks. During production testing, El Segundo 1-N produced
oil at an actual maximum rate of 8,948 Bbls/d.

A fourth well, El Segundo 1-S, was drilled and completed in September 1997
to a total measured depth of 6,920 feet. The bottom hole location of this well
is approximately 2,000 feet south of the surface location of the El Segundo 1-E
well. In October 1997, the El Segundo 1-S was production tested at an actual
maximum rate of 4,528 Bbls/d.

In October 1997, a fifth well, the Tres Pasos 1-E was drilled at a location
approximately 1.6 miles northwest of the El Segundo 1-E as the first well on the
Rio Seco contract. The Tres Pasos 1-E well was completed at a measured depth of
6,150 feet. Production testing of the Tres Pasos 1-E well was conducted in
late-1997 and oil was produced at an actual maximum rate of 13,123 Bbls/d.
Analysis of reservoir pressure data during production testing indicated pressure
communication with all three El Segundo 1 wells. The Company believes that such
pressure communication over a 1.6-mile distance supports core studies showing an
intensive degree of inter-connected fractures and the large calculated
permeability within the area of the Cimarrona formation investigated during
production testing.

In November 1997, the sixth well, El Segundo 2-E was drilled to a measured
depth of 6,292 feet on the Dindal Association Contract, approximately 3.7 miles
north of the surface location of the El Segundo 1-E discovery well. Production
testing of El Segundo 2-E was completed in January 1998 and resulted in a
maximum actual production rate of 5,381 Bbls/d. Analysis of pressure data during
production testing evidenced communication with the El Segundo 1-S well with a
bottom hole location approximately 3.8 miles to the south. This data further
confirmed the presence of a pervasive fracture system supporting the evidence
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for extensive permeability within the Cimarrona formation over the area
investigated during the production testing.

In December 1997, the seventh well, Tres Pasos 2-E, was drilled to a
measured depth of 6,054 feet on the Rio Seco block approximately 5.6 miles
northwest of the surface location of El Segundo 1-E. The well encountered 290
feet of Cimarrona reservoir. Due to an operational problem that resulted from a
failure to properly cement liner casing through the Cimarrona formation, the
Company drilled a new side-tracked well bore. The Tres Pasos 2-E side-track
reached a total measured depth of 5,880 feet with a bottom hole location
approximately 900 feet southeast of the surface location. The Company plans to
complete and test the side-track bore hole in 1999.

In November 1997, drilling commenced on the eighth well, El Segundo 3-E,
located approximately 2.8 miles south of the surface location of the El Segundo
1-E well on the Dindal block. The drilling of El Segundo 3-E was completed at a
measured depth of 8,021 feet in February 1998. The well encountered 292 feet of
Cimarrona formation. Customary log analysis indicated similar characteristics of
lithology and fracturing as that observed in previous wells; however, unlike the
other wells, there were no oil shows, only natural gas shows. This well was not
cored. After the completion of drilling operations on El Segundo 3-E, the
Company experienced significant mechanical problems while attempting to complete
the well for production testing. The Company has temporarily abandoned the El
Segundo 3-E well.

The ninth well, El Segundo 6-E, is located on the Dindal block
approximately 5.3 miles south of the surface location of the El Segundo 1-E
well. In June 1998, the El Segundo 6-E well reached a total measured depth from
the surface of 8,669 feet. Preliminary analyses while drilling included the
observation of highly fractured core samples and over 300 feet of Cimarrona
reservoir rocks with no apparent indication of oil-water contact and shows of
oil and gas. During production only small show of oil and gas along with large
quantities of water. Attempts to eliminate water migrating from behind the pipe
were unsuccessful. Analysis of the water and its origin are ongoing. Due to the
magnitude of oil and gas shows encountered during drilling operations,
management believes this well may be a candidate for a horizontal re-drill. In
February 1999, the Company shut-in the well to begin pressure recording in order
to determine if there would be communication over the approximate six miles
between it and the Tres Pasos No. 1-W horizontal well during its production
testing.

In July 1998, the Company completed drilling operations on the tenth, Tres
Pasos No. 4-E, located on the Rio Seco Association Contract area, approximately
3.1 miles northwest from the surface location of the El Segundo No. 1-E
discovery well. The well reached a total measured depth of approximately 6,300
feet. Although the Tres Pasos 4-E well encountered 303 feet of Cimarrona
formation with oil and gas shows, the well bore did not appear to intersect the
larger fracture system due to a rotation in reservoir fracture system
orientation at the well's bottom hole location. Consequently, the well may not
be commercially productive. The Company is continuing evaluation and analysis
using bottom hole pressure recording to determine whether a side-track
lateral/horizontal well bore is warranted.

In September 1998, the Company drilled the eleventh well, Tres Pasos 3-E,
located on the Rio Seco block approximately 1.9 miles south of the Tres Pasos
1-E well. The Tres Pasos 3-E well encountered 282 feet of Cimarrona with oil and
gas shows. Drilling was then extended to a total measured depth of 10,187 feet
in the deeper Villeta formation where shows of oil and gas were encountered. In
February 1999, the Company perforated the deeper Villeta formation, the
secondary zone of interest, which resulted in natural gas but not in commercial
quantities of oil and gas. The possibility of hydraulically fracturing the
Villeta formation is currently being evaluated. The shallower Cimarrona
formation objective has not yet been tested. Perforating and testing of the
Cimarrona formation is scheduled for later in 1999.

In December 1998, the Company completed drilling its twelfth well and its
first horizontal/lateral well, Tres Pasos No. 1-W, which was drilled to a
measured depth of 7,180 feet on the Rio Seco block. The horizontal bore hole
penetrated 1,160 feet of the Cimarrona reservoir. Significant rates of oil flow
were encountered while drilling the reservoir and no indications of water were
encountered. In late January 1999, the Company began production testing without
stimulation at a controlled rate of approximately 1,100 to 1,666 barrels of oil
per day using a small submersible pump. To date, approximately 39,000 barrels of
oil have been produced without water. Test oil is being sold at the field and
trucked 80 miles from the well to a private local
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refinery, the Refinerie de Nare. The rate of continuous production has been
limited by storage, trucking and pump capacities. On March 1, 1999, the well was
shut-in for two-weeks for pressure build-up analysis. The Company plans further
testing, reservoir stimulation, and testing at multiple higher rates during the
second quarter of 1999. This lengthy testing process is designed to achieve data
needed to determine optimal production capacity for this well, the provision of
additional reservoir engineering and data and further evaluation of the Guaduas
Field oil reserves.

TABLE OF GUADUAS FIELD WELLS

The table below sets out maximum production testing rates for the Guaduas
Field wells, however, maximum testing rates of oil production are not indicative
of production rates that may be realized during sustained commercial production.
Production tests are conducted to obtain an indication of the production
capacity of individual wells and to give an indication of reservoir quality and
extent. Actual producing rates from individual wells will depend on the results
of an integrated reservoir management strategy and an engineering production
plan, which will incorporate data from all wells in the field in a development
plan to maximize the economic recovery of oil from the reservoir.

MAXIMUM MAXIMUM
ACTUAL ACTUAL
MEASURED OIL TEST GAS TEST
DEPTH DAYS RATE RATE
WELL NAME BLOCK (FEET) TESTED (BBLS/D) (MCF/D) STATUS
- --------- -------- -------- ------ -------- -------- ------

Escuela 1.............. Dindal 7,802 -- -- -- Plugged and abandoned
El Segundo 1-E......... Dindal 5,718 28 3,415 1,350 Discovery well
El Segundo 1-N......... Dindal 6,820 63 8,948 3,500 Oil and gas well
El Segundo 1-S......... Dindal 6,920 7 4,528 451 Oil and gas well
Tres Pasos 1-E......... Rio Seco 6,150 19 13,123 6,000 Oil and gas well
El Segundo 2-E......... Dindal 6,292 14 5,381 826 Oil and gas well
El Segundo 3-E......... Dindal 8,021 21 -- Non-commercial test
Tres Pasos 2-E......... Rio Seco 5,880 -- -- -- Side-tracked and waiting on completion
El Segundo 6-E......... Dindal 8,669 76 -- -- Non-commercial test; may side-track
Tres Pasos 3E.......... Rio Seco 10,187 -- -- -- Waiting on Cimarrona completion
Tres Pasos 4E.......... Rio Seco 6,300 20 -- -- Non-commercial test; may side-track
Tres Pasos 1-WH........ Rio Seco 7,180 33 1,666 263 Oil and Gas Well

GEOLOGY AND RESERVOIR CHARACTERISTICS. The Guaduas Field geological
structure is a large anticlinal structure. The primary oil reservoir is the
Upper Cretacous Cimarrona formation, which is located on the west flank of the
Villeta anticline with an average dip of 14 degrees at a depth of between
approximately 6,000 and 8,000 vertical feet. The reservoir comprises both
limestone and sandstone and is under pressured. The oil is characterized by low
sulfur content of approximately 0.5%, low paraffin content, a medium gravity of
between 18 degrees to 20 degrees API and a pour point of minus 34 degrees
Fahrenheit.

The reservoir is generally intensely fractured and has indicated high
permeability in the wells that successfully produced oil and gas. Pressure test
analysis indicates the reservoir to be connected in most directions by large
fractures that allow hydrocarbons to flow readily through the reservoir. These
highly permeable fractures, in conjunction with the angle of the formation dip,
will allow the oil to be produced by a combination of efficient oil recovery
mechanisms including gravity drainage, gravity segregation and pressure
maintenance.

STRATEGY FOR THE DEVELOPMENT OF OIL PRODUCTION BY INCREMENTS AND FURTHER
EXPLORATION. The Company's strategy to develop the Guaduas Field is as follows:
(i) focus its resources on the development of the shallow Cimarrona reservoir of
the Guaduas Field in order to achieve commercial production as soon as
practicable, (ii) generate near-term cash flow to help finance continuing
expansion of Guaduas Field oil production, (iii) continue development and
delineation of the Guaduas Field, and (iv) use internally generated cash as well
as external financing such as the issuance of equity or debt securities, project
financing of pipeline and production facilities, commercial bank lending,
industry joint ventures or other like arrangements with

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industry service companies to accelerate incremental increases in Guaduas Field
production, delineation drilling of the west flank of the Guaduas structure, the
exploratory drilling of the deep structure below the shallow Cimarrona formation
and the multiple prospects on the Montecristo and Rosablanca Association
Contracts in the northern Middle Magdelena Basin.

As operator of the Guaduas Field, the Company's goal is to continue its
field development and delineation drilling program and to install the production
facilities and pipeline infrastructure to allow its production to reach the
existing transportation pipelines for access to markets. The Company plans to
achieve increasing production rates incrementally as described in "Item 1.
Business -- Strategy for Guaduas Field Development and Pipeline Production."

TIMING OF CRITICAL EVENTS. In addition to contingencies discussed herein,
there are several key events that must occur on schedule in order for the
Company to reach Increment II, the Early Pipeline Production, by year end 2000,
including the following:

- Global operating license -- The Company must receive a global operating
license from the Colombian Ministry of Environment allowing for all
development activity within the Association Contract areas. The Company
filed its application for this permit on March 4, 1999.

- Environmental Permit for Pipeline -- The Company must procure an
environmental permit for the pipeline prior to the commencement of
pipeline construction. The Company expects to file its application for
this permit before mid-1999.

- Approval of commerciality -- The Company must obtain approval of
commerciality by Ecopetrol, as fifty percent of all costs for development
and production subsequent to the date of commerciality will be borne by
Ecopetrol (see "-- Terms of Association Contracts and Related Matters")
and no commitments for the production development and pipeline
construction can be made by the Company until Ecopetrol and the Company
have a written commerciality agreement. The Company has entered into
formal pre-commerciality discussions with Ecopetrol and anticipates
receiving the commerciality agreement in December 1999.

All approvals must be obtained by January 2000 for the Company to meet the
goal of completing Increment II, the Early Pipeline Production of 20,000 Bbls/d
to 30,000 Bbls/d, before year-end 2000. Although the Company has begun the
process for each of these approvals, no assurance can be given that they will be
received or received on timely basis.

PRODUCTION FACILITIES, GATHERING AND PIPELINE SYSTEMS.

The Company has completed the basic and detailed engineering specifications
for the construction of pipelines and production facilities. The construction of
the pipeline and the production facilities is subject to a number of conditions,
including negotiating construction contracts and obtaining required
environmental and construction permits, easements and rights of way. The Company
does not expect the pipeline to be completed before year-end 2000, and no
assurance can be given as to whether or when such pipeline will be completed. In
addition, the Company has not finalized its negotiations with the operator of
the OAM pipeline for the transportation of oil produced under the Increment II
development plan. If the Company is unsuccessful in constructing its pipeline
and production facilities or in increasing its proved reserves or realizing
future production from its properties, the Company may be unable to pay all of
the principal of and interest on its indebtedness when due. See "-- Risks
Related to the Oil and Gas Industry."

There are certain economic incentives to build the pipeline as a separate
project outside the Association Contracts. Discussions have been initiated with
the other associates and several outside parties which have expressed an
interest in forming a separate company to execute the pipeline project. Should a
separate and independent company be formed, the Company may or may not take an
equity interest in that pipeline company.

TERMS OF ASSOCIATION CONTRACTS & RELATED MATTERS. Association contracts
acquired from Ecopetrol, after receipt of the necessary approval by Colombian
governmental authorities as well as the approval of the board
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18

of Ecopetrol, are executed by the parties and subsequently recorded as a public
deed in Colombia. Therefore, ownership of an association contract is protected
by Colombian law.

The Association Contracts were issued by Ecopetrol for the Dindal contract
in March 1993 and for the Rio Seco contract in August 1995. The Association
Contracts generally provide for a maximum six-year exploration period followed
by a maximum 22-year production period, with partial relinquishments of acreage,
excluding commercial fields, required commencing at the end of the sixth year of
each contract. Under the terms of the Association Contracts, the associates pay
100% of all exploratory costs. Ecopetrol will receive a royalty equal to 20% of
production on behalf of the Colombian government and, after the field is
declared commercial by Ecopetrol, it will acquire a 50% interest in the
remaining production, bear 50% of the development costs, and reimburse the
associates, from Ecopetrol's share of future production, for 50% of the
associates' costs of certain direct exploration activities. Upon its acceptance
of a field as commercial, Ecopetrol will acquire a 50% interest therein and the
interests of the other parties to the contract, including the Company, will be
reduced by 50%; all decisions regarding the development of a commercial field
will be made by an Executive Committee consisting of a representative of the
associated parties to the contract and Ecopetrol who will vote in proportion to
their respective interests in such contract. Decisions of the Executive
Committee will be made by the affirmative vote of the holders of over 50% of the
interests in the contract.

Under the terms of the Dindal Association Contract, Ecopetrol's interest in
production and costs would increase on a sliding scale after a commercial
contract area produces in excess of 60 MMBbls. Such increases occur in 5%
increments from 50% to 70% as accumulated production from all fields producing
from the Dindal contract area increase in 30 million barrel increments from 60
MMBbls to 150 MMBbls. Recovery of Ecopetrol's 50% share of direct exploration
costs is limited to production from successfully producible exploration wells.
Unless extended by Ecopetrol, the exploration period under the Dindal
Association Contract will expire in September 1999, at which time the Company
must relinquish 50% of the contract area or all lands that fall outside a five
kilometer buffer zone around the area designated to be the commercial field. The
Company has requested an extension of the exploration period.

Under the terms of the Rio Seco Association Contract, after a commercial
contract area produces in excess of 60 MMBbls and the associates have recovered
100% of their investment, Ecopetrol's interest in production and costs would
increase from 50% to 75% as the ratio of the accumulated income attributable to
the associated parties to the contract other than Ecopetrol to the accumulated
development, exploration and operating costs of such parties (less any expenses
reimbursed by Ecopetrol) increases from a one-to-one ratio to a two-to-one
ratio. Ecopetrol will be required upon declaration of commerciality to reimburse
the Company for its 50% share of all seismic and exploratory wells costs from
all production under the Rio Seco contract.

Under the terms of the Association Contracts, in the event a discovery is
made and is not deemed to be commercially feasible by Ecopetrol, the associates
may expend up to $2 million per contract over a one-year period to further
delineate the field, 50% of which will be reimbursed if Ecopetrol subsequently
accepts the commercial feasibility of the property. The associates have the
right to develop fields they believe are commercial on a sole risk basis. In
such event, Ecopetrol will have the right to acquire a 50% interest therein upon
payment of a penalty of 200% of the amounts expended by the associates. Once the
associates have recovered 200% penalty and Ecopetrol backs in to the project,
Ecopetrol must pay its proportionate share of all future costs on a pay as you
go basis.

The Company and the other associates have paid all costs of the exploration
program under the Association Contracts to date. Under the terms of the Dindal
and Rio Seco Association Contracts, the Company and its partners are required to
drill one well on each contract per year through 1999 and 2001, respectively,
and will continue to bear all costs relating to a field until such field is
declared commercial. The Company presented a preliminary request for
commerciality to Ecopetrol in December 1998 and anticipates obtaining a
pre-commerciality agreement during mid-1999. If an acceptable agreement is
reached, the Company plans to submit a commerciality application to Ecopetrol in
the third quarter of 1999 with respect to its discovery. Such application is
subject to approval by Ecopetrol, which has the right to reject or delay
acceptance of commerciality or to accept commerciality and acquire a 50% working
interest in the Association Contracts. The Company is prepared to proceed with
development and production of the Guaduas Field on a

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sole risk basis in the event that Ecopetrol does not approve commerciality,
subject to the availability of necessary financing.

GHKCC serves as the operator of the Guaduas Field, pursuant to the terms of
operating agreements between the Company, its respective subsidiaries and the
other associates. GHKCC has exclusive charge of carrying out the program of
operations within the budgets and work programs approved by the Executive
Committee and may demand payment in advance from each party of its respective
shares of estimated subsequent monthly expenditures.

Under the terms of a letter agreement dated September 11, 1992, as amended,
between GHKCC and Dr. Jay Namson, the holders of interests in the Association
Contracts, except for Petrolinson, will be required to assign a 2% working
interest in the Dindal Association Contract and the Rio Seco Association
Contracts to Dr. Namson after recovery from production of 100% of all costs
incurred in connection with the exploration and development of the Dindal and
Rio Seco Association Contract areas since the completion of the first year work
obligations under the Dindal Association Contract. Accordingly, when such costs
have been recovered, the Company will be required to assign to Dr. Namson 2% of
its interests prior to the acquisition of the 6% Petrolinson interest (or a
0.517% interest in the Association Contracts after adjusting for the acquisition
of a 50% interest by Ecopetrol which is expected to occur prior to the
assignment to Dr. Namson).

The Company currently holds a 57.7% interest in the Association Contracts,
including a 6% interest acquired indirectly through the Company's acquisition of
100% of the securities of Petrolinson, the holder of such 6% interest. As the
holders of the remaining 94% interest, the Company and the other associates had
previously agreed to pay 100% of the exploration costs attributable to such 6%
interest through the exploration period. The 6% previously owned by Petrolinson
was a carried interest through the exploration phase. The exploration period
will terminate upon Ecopetrol's declaration of the commerciality of a field,
which the Company expects to occur during the fourth quarter of 1999.

OTHER COLOMBIAN ASSOCIATION CONTRACTS

MONTECRISTO AND ROSABLANCA ASSOCIATION CONTRACTS. Effective February 28,
1998, the Company acquired a 75% interest in the contiguous Montecristo and
Rosablanca Association Contract areas, which cover a total of approximately
692,000 gross acres in the northern Middle Magdalena Basin. The terms of the
Montecristo and Rosablanca Association Contracts are substantially similar to
those of the Rio Seco Association Contract with two major beneficial changes. In
the Montecristo and Rosablanca Association Contracts, Ecopetrol's interest in
production and costs after a declaration of commerciality is on an individual
field basis rather than being applicable to the entire contract and they provide
for an additional contract term of four years in the event of the discovery of a
gas field.

The Company has completed the reprocessing of 950 miles of 2-D seismic data
on the Montecristo and Rosablanca Association Contract areas and is currently
evaluating the reprocessed data. The Company is considering acquisition of
outside funding via farm-out or forming an alliance with a seismic contractor to
complete the 1999 work obligation of acquiring 60 miles (100 kilometers) of new
seismic on each block, either of which events will result in a reduction of the
Company's interest in the Association Contracts. The initial interpretation of
the 2-D seismic data has revealed several potential drilling prospects.

TAPIR ASSOCIATION CONTRACT. Overview. The Company acquired an 11.875%
interest in the Tapir Association Contract in April 1996. The Tapir Association
Contract area consists of 233,000 gross acres located in the Llanos Basin of
east central Colombia and is crossed by two oil pipelines carrying production
from nearby oil fields. Other interests in the Tapir Association Contract are
held by Mohave Colombia Corporation (37.5%), which serves as the operator,
Doreal Energy Corporation (12.5%) and Solana Petroleum Exploration (Colombia)
Ltd. (38.125%).

Drilling Activity. In 1993, the Macarenas #1 discovery well was drilled on
the Tapir Association Contract area and produced 320 Bbls/d during a short-term
test, but was not completed for production. Since the well was drilled and
tested, additional oil pipeline infrastructure has been built in the area. The
operator plans to place the well on long-term production test after the
completion of the exploratory well to determine

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sustainable production rates and the extent of the reservoir. The Company
participated in the Mateguafa well, which was completed and tested in April
1998. The Mateguafa well has been tested at rates of 777 Bbls/d. The operator
has recommended releasing 50% of the contract area rather than drill two wells
in 1999. An additional exploration well necessary to maintain 50% of the
contract area, the Caporal 1 well, was spud in March 1999 and is expected to
reach its target depth in April 1999.

Terms of Tapir Association Contract. The Tapir Association Contract was
effective on February 6, 1995 on terms substantially similar to the Rio Seco
Association Contract.

OTHER PROPERTIES

AUSTRALIA. During 1998, the Company sold its interest in two Perth Basin
exploration permits to a third party for total proceeds of $1.2 million. The
following is a description of the Company's remaining interest in Australia,
which the Company plans to divest or farm out.

Bass Basin, Block T27P. In March 1996, the Company acquired a six-month
option to purchase its interest in the block for $0.3 million and, in September
1996, exercised that option. The Company holds a 20% working interest in Block
T27P, a 1,800,000 acre block in approximately 70 meters of water in the Bass
Strait Basin in offshore southeastern Australia. The Bass Strait Basin has been
the site of a series of gas and oil discoveries, including the Yolla Field,
which is adjacent to Block T27P. The Yolla Field was discovered by Amoco in the
mid-1980s and has not yet been fully appraised or developed.

Globex Exploration, the operator of the permit with an 80% working
interest, was granted the Offshore Petroleum Exploration Permit effective August
10, 1994 (the "Bass Basin Permit"). Globex completed a 620-mile 2-D seismic
program on the block. The remaining work commitment on the block consists of a
3-D seismic survey and two exploration wells. Globex has selected a drillable
prospect approximately 6.2 miles north of the Yolla Field and is seeking
additional participants in the block to share the cost of an exploratory well
which is estimated to cost approximately $9.2 million. As suitable drilling rigs
were not available, Globex obtained a permit extension in the block until such
rig could be contracted. Globex now plans to spud an exploratory test well in
mid-1999, depending on rig availability. If the well is drilled and the Company
is unsuccessful in farming-out its interest, its share of the well costs are
estimated to be $1.84 million.

PAPUA NEW GUINEA. The Company acquired 100% of exploration permit PPL-182
in southern Papua New Guinea effective June 11, 1996. The permit covers an area
of 1,200,000 acres located both onshore and offshore in the Fly River Delta and
the Gulf of Papua. The Company entered into an Agreement with ARCO Papua New
Guinea Inc. ("ARCO") for a farm out of its interest whereby ARCO funded the
Company's obligation for the twelve-month period ended July 1998 in return for
an 80% interest in the exploration permit. Subsequently, the Company
relinquished further rights in the property to ARCO and retained a small
production payment.

OIL AND GAS RESERVES

The following table sets forth estimated net proved oil and gas reserves of
the Company, the estimated future net revenues before income taxes, the present
value of estimated future net revenues before income taxes related to proved
reserves and the standardized measure of discounted future net cash flows
related to proved reserves, in each case as of December 31, 1998. All
information relating to estimated net proved oil and gas reserves and the
estimated future net revenues and cash flows attributable thereto is based upon
a report from Ryder Scott Company Petroleum Engineers ("Ryder Scott"). All
calculations of estimated net proved

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reserves have been made in accordance with the rules and regulations of the
United States Securities and Commission (the "Commission").

AS OF AS OF
DECEMBER 31, DECEMBER 31,
1998 1997
------------ ------------

Total net proved reserves:
Oil (MBbls)............................................... 38,719 32,160
Gas (MMcf)................................................ -- --
Total (MBOE).............................................. 38,719 32,160
Net proved developed reserves:
Oil (MBbls)............................................... 20,238 11,494
Gas (MMcf)................................................ -- --
Total (MBOE).............................................. 20,238 11,494
Estimated future net revenues before income taxes
(in thousands)(1)......................................... $226,175 $241,700
Present value of estimated future net revenues before income
taxes
(in thousands)(1)......................................... $115,878 $144,866
Standardized measure of discounted future net cash flows
(in thousands)(1)(2)...................................... $ 89,850 $100,617

- ---------------

(1) The present value of estimated future net revenues attributable to the
Company's proved reserves was prepared using constant prices as of December
31, 1998, discounted at 10% per annum on a pre-tax basis (SEC PV-10). The
net price in 1998 was calculated using the December 31, 1998 price of $12.05
per barrel, less $4.50 per barrel for gravity adjustment and transportation
and marketing costs, yielding a net price of $7.55 per barrel. The net price
for 1997 was calculated using the December 31, 1997 price of $17.00 per
barrel, less $6.85 per barrel for gravity adjustment and transportation and
marketing costs, yielding a net price of $10.15 per barrel. The year-end
1997 costs for gravity adjustments were $1.32 per barrel higher than
year-end 1998. The 1997 transportation and marketing costs included a $1.03
per barrel tariff and fee for amortization of the Guaduas to La Dorada
portion of the pipeline. The pipeline costs were included in capital costs
in the 1998 year-end report.

(2) The standardized measure of discounted future net cash flows represents the
present value of estimated future net revenues from proved reserves after
income tax, discounted at 10% per annum.

There are numerous uncertainties inherent in estimating quantities of
proved reserves, future rates of production and the timing of development
expenditures, including many factors beyond the control of the Company. The
reserve data set forth herein represent only estimates. Reserve engineering is a
subjective process of estimating underground accumulations of oil and gas that
cannot be measured in an exact manner, and the accuracy of any reserve estimate
is a function of the quality of available data, engineering and geological
interpretation and judgment and the existence of commercial development plans.
As a result, estimates of reserves made by different engineers for the same
property will often vary. Results of drilling, testing and production subsequent
to the date of an estimate may justify a revision of such estimates.
Accordingly, reserve estimates generally differ from the quantities of oil and
gas ultimately produced. Further, the estimated future net revenues from proved
reserves and the present value thereof are based upon certain assumptions,
including geological success, prices, future production levels and costs that
may not prove to be correct. Predictions about prices and future production
levels are subject to great uncertainty, and the meaningfulness of such
estimates depends on the accuracy of the assumptions upon which they are based.

This document contains estimates of the Company's proved oil and gas
reserves and the estimated future net revenues therefrom based upon the
Company's own estimates and on those of Ryder Scott and Servipetrol Ltd. Such
estimates rely upon various assumptions, including assumptions required by the
Commission as to oil and gas prices, drilling and operating expenses, capital
expenditures, taxes and availability of funds. The process of estimating oil and
gas reserves is complex and by its very nature uncertain, requiring significant
decisions and assumptions in the evaluation of available geological,
geophysical, engineering and economic

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data for each reservoir. As a result, such estimates are inherently imprecise.
Actual future production, oil and gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and gas
reserves may vary substantially from those estimated by the Company or Ryder
Scott and Servipetrol Ltd. Any significant variance in these assumptions could
materially affect the estimated quantity and value of reserves set forth
herewith. The Company's properties may also be susceptible to hydrocarbon
drainage from production by other operators on adjacent properties. In addition,
the Company's estimated proved reserves may be subject to downward or upward
revision based upon production history, results of future exploration and
development, prevailing oil and gas prices, mechanical difficulties, government
regulation and other factors, many of which are beyond the Company's control.
Actual production, revenues, taxes, development expenditures and operating
expenses with respect to the Company's reserves will likely vary from the
estimates used, and such variances may be material.

Approximately 48% of the Company's total estimated proved reserves at
December 31, 1998 were undeveloped, which are by their nature less certain.
Recovery of such reserves will require significant capital expenditures and
successful drilling and completion operations. The Company's reserve data assume
that ongoing capital expenditures by the Company will be required to develop
such reserves. Although cost and reserve estimates attributable to the Company's
oil and gas reserves have been prepared in accordance with industry standards,
no assurance can be given that the estimated costs are accurate, that
development will occur as scheduled or that the results will be as estimated.

The present value of future net revenues (SEC PV-10) referred to herewith
should not be construed as the current market value of the estimated oil and gas
reserves attributable to the Company's properties. In accordance with applicable
requirements of the Commission, the estimated discounted future net cash flows
from proved reserves are generally based on prices and costs as of the date of
the estimate, whereas actual future prices and costs may be materially higher or
lower. Actual future net cash flows also will be affected by increases in field
consumption of gas and oil and changes in governmental regulations or taxation.
The timing of actual future net cash flows from proved reserves, and thus their
actual present value, will be affected by the timing of both the production and
the incurrence of expenses in connection with development and production of oil
and gas properties. In addition, the 10% discount factor, which is required by
the Commission to be used in calculating discounted future net cash flows for
reporting purposes, is not necessarily the most appropriate discount factor
based on interest rates in effect from time to time and risks associated with
the Company or the oil and gas industry in general.

PRODUCTIVE WELLS

The following table sets forth the productive oil and gas wells owned by
the Company as of December 31, 1998:

WELLS(1)
--------------------------
OIL GAS
----------- -----------
GROSS NET GROSS NET
----- --- ----- ---

Colombia.................................. 6 3.5(2) 0 0.0
--- ---
Total................................ 6 3.5 0 0.0

- ---------------

(1) One or more completions in the same well bore are counted as one well.

(2) Before Ecopetrol's 50% acquisition rights have been exercised.

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ACREAGE

The following table sets forth estimates of the developed and undeveloped
acreage for which oil and gas leases or concessions were held by the Company as
of December 31, 1998.

DEVELOPED UNDEVELOPED
-------------------------- --------------------------
GROSS ACRES NET ACRES(1) GROSS ACRES NET ACRES(1)
----------- ------------ ----------- ------------

Colombia...................... 14,521 8,379 1,019,309 601,293
Australia..................... -- -- 1,800,000 360,000
------ ----- --------- -------
Total.................... 14,521 8,379 2,819,309 961,293

- ---------------

(1) Net acres are based on the Company's respective working interests and, in
Colombia, are before Colombian government participation.

DRILLING ACTIVITY

The following table sets forth the number of wells drilled by the Company
from inception through December 31, 1998:

EXPLORATORY DEVELOPMENT
----------- -----------
PRODUCTIVE DRY PRODUCTIVE DRY
----------- ------------- ----------- -----------
GROSS NET GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- --- ----- ---

Year ended December 31, 1998:
Colombia............................................ 1 0.6 5(1) 2.8(2) 0 0.0 0 0.0
== === === ===== == === == ===
Year ended December 31, 1997:
Colombia............................................ 3 1.7 0 0.0 0 0.0 0 0.0
== === === ===== == === == ===
Year ended December 31, 1996:
Colombia............................................ 2 1.2 0 0.0 0 0.0 0 0.0
Argentina........................................... 0 0.0 1 0.3 0 0.0 0 0.0
-- --- --- ----- -- --- -- ---
2 1.2 1 0.3 0 0.0 0 0.0
== === === ===== == === == ===
Year ended December 31, 1995:
Australia........................................... 0 0.0 1 0.1 0 0.0 0 0.0
== === === ===== == === == ===

- ---------------

(1) Two of the exploratory wells listed as dry during 1998 are being evaluated
as horizontal/lateral side-track candidates and two have not been tested.

(2) Before Ecopetrol's 50% acquisition rights have been exercised.

Since December 31, 1998, the Company has drilled no wells. The Company is
currently continuing to test one gross exploratory well (0.6 net to the
Company).

MARKETING

Oil produced from the Dindal and Rio Seco Association Contract areas during
long-term production tests has been sold to Ecopetrol and the Refinerie del
Nare. Upon Ecopetrol's declaration of the commerciality of the Company's
discovery, oil produced from the Dindal and Rio Seco Association Contract areas
may be sold to Ecopetrol or to third parties. In the event the production is
required to satisfy internal demand for oil in Colombia, the Company may be
required to sell some or all of its production to Ecopetrol at prevailing market
prices.

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REGULATION

GENERAL

The Company's operations are affected by political developments and laws
and regulations in the areas in which it operates. In particular, oil and gas
production operations and economics are affected by price controls, tax and
other laws relating to the petroleum industry, by changes in such laws and by
changing administrative regulations and the interpretations and application of
such rules and regulations. Oil and gas industry legislation and agency
regulation is periodically changed for a variety of political, economic,
environmental and other reasons. Numerous governmental departments and agencies
issue rules and regulations binding on the oil and gas industry, some of which
carry substantial penalties for the failure to comply. The regulatory burden on
the oil and gas industry increases the Company's cost of doing business.

Extensive national, provincial and/or local environmental laws and
regulations in Colombia and the other countries in which the Company operates
affect nearly all of the operations of the Company. These laws and regulations
set various standards regulating certain aspects of health and environmental
quality, provide for penalties and other liabilities for the violation of such
standards and establish in certain circumstances obligations to remediate
current and former facilities and off-site locations. In addition, special
provisions may be appropriate or required in environmentally sensitive areas of
operation, such as where the Company's Colombian interests are located and where
other independent producers of oil and gas have faced significant liability
resulting from environmental claims.

The Company's operations are subject to regulations imposed by the local
regulatory authorities including, without limitation, currency regulation,
import and export regulation, taxation and environmental controls. The
regulations also generally specify, among other things, the extent to which
properties may be acquired or relinquished, permits necessary for drilling of
wells, spacing of wells, permits for development and operations of the field and
of pipeline transportation systems, measures required for preventing waste of
oil and gas resources and, in some cases, rates of production and sales prices
to be charged to purchasers. Specifically, Colombian operations are governed by
a number of ministries and agencies including Ecopetrol, the Ministry of Mines
and Energy, the Ministry of Public Works and the Ministry of the Environment.

ENVIRONMENTAL MATTERS

The Company's operations in Colombia are subject to a variety of national,
provincial, and local environmental laws and regulations governing the discharge
of materials into the environment, the disposal of oil and gas wastes, and the
protection of human health and environmental quality. On the federal level, the
Ministry of Environment regulates all activities that could have an adverse
impact on the environment and natural resources of Colombia. The Ministry
requires specific environmental licenses for a variety of oil and gas
exploration and production activities, and individual licenses are issued only
upon completion of a detailed environmental impact study. The Company has
experienced and may continue to experience delays in obtaining the federal
environmental licenses and other, local environmental permits required for
expansion of its operations in Colombia. Nevertheless, the Company has obtained
timely environmental licenses for its global operating permit for exploration
activities in the Dindal and Rio Seco Association Contract areas. The Company
has applied for the necessary licenses for production and development drilling
activities and is in the process of completing the environmental impact studies
that must be performed in order to obtain an environmental license for the
transportation plan. See "-- Colombian Properties -- Guaduas Field -- Timing of
Critical Events." In addition, the Company is currently planning to commence
preparation of environmental impact studies required for the issuance of
environmental licenses for exploration and production activities for the Rosa
Blanca and Montecristo contract areas.

It is possible that the administration and enforcement of current
environmental laws and regulations 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 and expand the
Company's operations in such country. Significant liability could be imposed on
the Company for damages, clean-up costs and/or penalties in the event of certain
discharges into the environment, environmental damage caused by

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previous owners of property purchased by the Company or non-compliance with
environmental laws or regulations. Such liability could have a material adverse
effect on the Company. Moreover, the Company cannot predict what environmental
legislation or regulations will be enacted in the future or how existing or
future laws or regulations will be administered or enforced. Compliance with
more stringent laws or regulations, or more vigorous enforcement policies of any
regulatory agency, could in the future require material expenditures by the
Company for the installation and operation of systems and equipment for remedial
measures, any or all of which could have a material adverse effect on the
Company.

On March 18, 1998, the Ministry of the Environment provided notice of its
intention to investigate alleged violations of environmental requirements with
respect to location work on the Company's El Segundo 6-E exploratory well. The
Company responded promptly to the notice from the Ministry of the Environment by
reporting that all of the alleged violations had been corrected. In a subsequent
site visit, Ministry officials confirmed that the alleged violations had been
properly remedied. Although no assurances can be given, the Company does not
expect any fines or penalties to be imposed in connection with the alleged
environmental violations at the Company's El Segundo 6-E well.

The Ministry of Environment by resolution has decided to open a list of
charges against GHK Company Colombia based on alleged environmental damages,
originating from the location that has been constructed for the proposed El
Segundo 7-E well. The Company has experienced difficulty trying to stabilize the
slopes of this location, and as a result, sediments from the location were
entering a creek. At this time, remediation efforts are underway and should be
completed soon. The Company has been notified that it will likely be assessed a
fine for the alleged environmental damages at the El Segundo 7-E location. The
Company believes that the amount accrued will be sufficient to cover remediation
costs and potential fines assessed as a result of El Segundo 7-E operations.

Furthermore, no assurance can be given that new environmental requirements
will not be imposed on the Company's operations and activities, and the Company
cannot predict how environmental laws and regulations will be administered or
enforced in the future in Colombia and the other countries in which the Company
operates. Significant changes in environmental requirements or in the
administration and enforcement of environmental laws and regulations in areas
where the Company operates could have a material adverse effect on the Company.

ITEM 3. LEGAL PROCEEDINGS

On September 24, 1997, Timothy T. Stephens, formerly the President of Seven
Seas Petroleum Inc., filed a lawsuit in the 164th Judicial District Court,
Harris County, Texas under Cause No. 97-48443 against Seven Seas Petroleum Inc.
and Mr. Robert A. Hefner III. Mr. Stephens was the President of the Company from
March 1995 until May 1997. Mr. Stephens is alleging damages relating to the
Company's alleged failure to timely extend stock options and is seeking a
further extension of his stock option period and unspecified actual,
consequential, and exemplary damages. The Company has filed an Original Answer
generally denying the material allegations in Stephens' petition. The Court has
set this case for trial for the two-week period beginning July 19, 1999.

Commercial relations between the Company and International Technical
Solutions Inc. (ITS), a consulting engineering firm, were terminated by the
Company's operating subsidiary, GHKCC as of January 1999. ITS states that there
were unfair causes for termination and has demanded that the Company pay $3.2
million to ITS. The Company and ITS are currently negotiating this claim. In the
event that an agreement is not reached, however, ITS has declared that it
intends to initiate an Ordinary Lawsuit before a Judge in Colombia against the
Company to prove that it has the right to receive the amounts claimed. The
Company has no written contract with ITS and believes the claims are
substantially without merit. The Company's Colombian legal counsel is of the
opinion that the likelihood of any substantial payments other than valid,
existing accounts payable to ITS as a result of an Ordinary Lawsuit are remote.

Petrolinson, S.A. and GHK Colombia (two of the Company's subsidiaries),
along with Norman Rowlinson (the former owner of Petrolinson, S.A.) and the
heirs of Howard Thomas Corrigan, are defendants in a lawsuit filed in the civil
circuit court of Santa Fe de Bogota, Colombia in 1998 by the heirs of Nicolas
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Beltran Franco alleging that (i) a de facto company existed between Nicolas
Beltran Franco and the defendants with regards to the exploration and production
of the Dindal and Rio Seco Association Contract areas and that (ii) prior to the
execution of the Dindal and Rio Seco Association Contracts the de facto company
conducted exploration works in the Dindal and Rio Seco Association Contract
areas, resulting in the plaintiffs having the right to participate in income
derived from the Dindal and Rio Seco Association Contract areas. Despite the
fact that none of the plaintiffs is a party to the Association Contracts, the
plaintiffs are seeking 50% of the income generated by the alleged de facto
company. It is unclear from the statements made in the lawsuit, however, what
percentage of the Dindal and Rio Seco Association Contract areas might be
covered by the plaintiffs' claims made through the alleged de facto company.

The Company believes that this lawsuit is without merit and intends to
defend the lawsuit vigorously. The Company believes that the outcome of this
lawsuit will not have a material adverse effect on the Company. In May 1998, the
Company's Colombian legal counsel investigated these claims and based on their
review of the matter to date, are of the opinion that if the above-described
claim is litigated to its conclusion the chance that the plaintiffs in such
lawsuit would succeed are remote.

Other than the foregoing, there are no material proceedings to which the
Company is a party or to which any of its properties is subject.

ITEM 4. SUBMISSION OF MATTERS TO VOTE

None

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PART II

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

The Company's common shares have been listed on the American Stock Exchange
("AMEX") under the symbol "SEV" since January 9, 1998 and The Toronto Stock
Exchange ("TSE") in Toronto, Ontario, Canada under the symbol "SVS.U" since
February 10, 1997. From June 30, 1995 through February 7, 1997, the Company's
common shares traded on the Canadian Dealing Network under the symbol "SVSE.U".
The following table summarizes the high and low closing prices as reported on
the Canadian Dealing Network for each quarterly period since the commencement of
trading on June 30, 1995 through February 7, 1997 and the high and low sales
prices as reported on the TSE since February 10, 1997. The prices listed below
are stated in U.S. dollars, which is the currency in which they were quoted:

HIGH LOW
------------ ------------

1996
First Quarter.................................. Cdn $ 6.75 Cdn $ 0.55
Second Quarter(1).............................. US $10.50 $ 5.25
Third Quarter.................................. 20.00 7.00
Fourth Quarter................................. 25.75 14.75
1997
First Quarter (through February 7, 1997)....... $19.00 $15.00
First Quarter (since February 10, 1997)........ 17.40 9.00
Second Quarter................................. 13.10 8.25
Third Quarter.................................. 14.10 9.60
Fourth Quarter................................. 20.05 11.80
1998
First Quarter.................................. $31.40 $15.75
Second Quarter................................. 26.75 17.75
Third Quarter.................................. 21.10 8.60
Fourth Quarter................................. 9.75 4.75

- ---------------

(1) During the first quarter and the first twelve days of the second quarter of
1996, the common shares were quoted in Canadian dollars, with the high and
low closing prices during such period of the second quarter being Cdn $7.25
and Cdn $5.25, respectively.

The following table summarizes the high and low sales prices as reported on
the AMEX for the periods presented below.

HIGH LOW
------ ------

1998
First Quarter............................................... $31.25 $16.44
Second Quarter.............................................. 26.63 17.13
Third Quarter............................................... 21.63 8.50
Fourth Quarter.............................................. 10.00 4.63

On March 24, 1999, the closing sale price of the common shares, as reported
on the AMEX and the TSE were $5 1/8 per share and $5.10 per share, respectively.
The number of record holders on December 31, 1998, was approximately 9,700. The
Company has never declared or paid cash dividends on its common shares, and
management anticipates that all earnings in the foreseeable future will be
retained for development of the Company's business.

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ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth certain historical consolidated financial
data for the Company as of and for each of the periods indicated. The following
data should be read in conjunction with "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the Company's consolidated
financial statements and notes thereto included elsewhere herewith.

PERIOD FROM
INCEPTION
(FEBRUARY 3,
YEAR ENDED DECEMBER 31, 1995) TO
--------------------------------- DECEMBER 31,
1998 1997 1996 1995
--------- --------- --------- ------------
(IN THOUSANDS, EXCEPT PER SHARE
AMOUNTS)

INCOME STATEMENT DATA:
Revenue................................ $ 3,797 $ 1,567 $ 575 $ 152
Net loss............................... (90,199) (7,928) (2,195) (2,120)
Net loss per common share.............. (2.49) (0.24) (0.17) (0.23)
Weighted average shares outstanding.... 36,204 32,505 12,972 9,247
BALANCE SHEET DATA (END OF PERIOD):
Cash and cash equivalents.............. $ 38,147 $ 18,067 $ 10,620 $ 3,366
Total assets................... 279,900 291,914 235,501 4,170
Current liabilities.................... 12,357 8,205 2,806 120
Minority interest...................... 9,713 4,087 1,060 --
Stockholders' equity................... 123,098 184,163 167,667 4,050

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

INTRODUCTION

The following discussion is intended to assist in understanding Seven Seas'
financial position and results of operations for each year in the three-year
period ended December 31, 1998 and for the period from inception (February 3,
1995) to December 31, 1998.

From time to time, Seven Seas may make certain statements that provide
stockholders and the investing public with "forward-looking" information (as
defined in the Private Securities Litigation Reform Act of 1995). Words such as
"anticipate," "assume," "believe," "estimate," "project," and similar
expressions are intended to identify such forward-looking statements.
Forward-looking statements may be made by management orally or in writing,
including, but not limited to, in press releases, as part of this "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
section and as part of other sections of the Company's filings with the SEC
under the Securities Act and the Securities Exchange Act. Such forward-looking
statements may include, but not be limited to, statements concerning estimates
of current and future results of operations, financial position, reserves, the
timing and commencement of wells and development plans, drilling results as
indicated by log analysis, core samples, examination of cuttings, hydrocarbons
shows while drilling and production estimates from wells drilled based upon
drill stem tests and other test data, future capacity under credit arrangements,
future capital expenditures, liquidity requirements, liquidity sufficiency and
year 2000 compliance.

Such forward-looking statements are subject to certain risks, uncertainties
and assumptions, including without limitation, those defined below. Should one
or more of these risks or uncertainties materialize, or should any of the
underlying assumptions prove incorrect, actual results of current and future
operations may vary materially from those anticipated, estimated or projected.

Among the factors that have a direct bearing on Seven Seas' results of
operations and the oil and gas industry in which it operates are uncertainties
inherent in estimating oil and gas reserves and future hydrocarbon production
and cash flows, particularly with respect to wells that have not been fully
tested and with wells having limited production testing histories; access to
additional capital; changes in the price of oil

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and natural gas, services and equipment; the limited exploration of the
concessions; the status of existing and future contractual relationships with
Ecopetrol; foreign currency fluctuation risks; Seven Seas' substantial
indebtedness, the presence of competitors with greater financial resources and
capacity; and difficulties and risks associated with operating in Colombia.

OVERVIEW

Seven Seas' principal asset is a 57.7% interest (before participation by
Ecopetrol, the Colombian state oil company) in the Dindal and Rio Seco
Association Contracts. See "Item 2. Properties -- Colombian
Properties -- Guaduas Field." As of December 31, 1998, Ryder Scott Company
Petroleum Engineers ("Ryder Scott") estimated total proved recoverable reserves
for the Guaduas Field of 163,303,000 Bbls, of which 38,719,235 Bbls were
attributable to the Company's interest.

The Company currently plans to focus its resources on placing the Guaduas
Field on production by increments in order to achieve cash flow as soon as
possible and to take advantage of the expected low equipment, service and
construction cost resulting from the oil and gas industry's current depressed
state. See "Item 1. Business -- Strategy for Guaduas Field Development and
Pipeline Production." First production from the Guaduas Field, Increment I,
should be achieved through the construction of a Portable Trucking Facility
("PTF" -- subsequently to become part of the permanent facilities) for the
trucking of between 4,000 Bbls/d and 6,000 Bbls/d to a local refinery located
approximately 80 miles from the Guaduas Field. The estimated net capital cost to
the Company for these facilities is approximately $9.4 million. The Company
estimates that it can commence PTF production in early 2000. Increment II, Early
Pipeline Production, includes the construction of facilities for the production
of 20,000 Bbls/d to 30,000 Bbls/d and is scheduled to go on line by
year-end-2000. Increment II facilities will include the construction of a
36-mile pipeline that will connect with the existing regional OAM pipeline.
Contemporaneously, the Company will drill additional development wells and one
gas injection well. The Company estimates that the net capital cost of the
pipeline, the production facilities and drilling the necessary wells will be
approximately $14 million. The net cost of the pipeline is approximately $6.1
million.

The Company's unrestricted cash reserves as of December 31, 1998 were $44.5
million and the Company has obligatory capital expenditure commitments of $5.3
million through year end 1999 (see "-- Liquidity and Capital Resources").
Whether the Company can achieve the Increment I and II objectives on schedule
and with the Company's existing capital resources is dependant upon a number of
factors, many of which are not within its control, such as timely environmental
permitting, securing pipeline rights of way, obtaining Ecopetrol's agreement to
commerciality under the Association Contracts and timely payments by the co-
participants of their share of these costs as well as the market price of oil
field equipment and services. If the Company experiences delays or cost
overruns, which must be considered possible, the Company will seek other sources
of financing, including project financing, industry joint ventures or like
arrangements with industry service companies, commercial bank borrowings and
traditional debt and equity financing. The Company's expenditures for Increment
II, Early Pipeline Production, may be substantially reduced by the formation of
a separate company to construct the Guaduas pipeline (connecting to the OAM
regional pipeline) to be owned and financed by third parties and in which the
Company may have little or no equity, thereby obligating the Company to pay only
a per barrel tariff on its oil transported through the pipeline and none of the
capital expenditures that are currently budgeted by the Company for the
construction of the pipeline.

Furthermore, the Company will be required to obtain additional sources of
financing to meet its other, multiple objectives of accelerating incremental
production from the Guaduas Field beyond Increment II and delineation and
exploratory drilling (see "Item 2. Properties -- Colombian Properties -- Guaduas
Field -- Strategy for the Development of Oil Production by Increments and
Further Exploration"). Each additional increment of field production (Increments
III through V) will require additional production facilities, a pipeline
expansion, the expansion of proved oil reserves through successful development
and delineation drilling of the shallow Cimarrona reservoir. If external
financing is obtained, the Company would anticipate drilling a delineation well
on the west flank of the Guaduas structure and an exploration well to test the
deep

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Guaduas Field structure, depending on certain actions by Ecopetrol (see
"-- Review of 1998 Activities" concerning the effects of unanticipated events on
prior Company plans).

The Company also plans to participate in the drilling of an exploratory
well on the Tapir block and to conduct seismic operations on the Rosablanca and
Montecristo blocks during 1999 at an aggregate cost of $3.1 million.

REVIEW OF 1998 ACTIVITIES

The Company's 1997 plan to develop the Guaduas Field, as outlined in its
Form 10-K for the year ended December 31, 1997, called for the drilling of seven
wells in 1998 and the first half of 1999, at a then-estimated net cost of $16.2
million, and the building of a pipeline and production facilities to produce
initially 50,000 Bbls/d at an estimated net cost of $34.2 million. In 1997,
management estimated that the Company could have the Guaduas Field on production
during 1999. Due to a number of circumstances, however, first pipeline
production is now estimated to commence year-end 2000 at a rate of 20,000 Bbls/d
to 30,000 Bbls/d. The principal circumstances contributing to delays were: 1)
delays caused by mechanical difficulties of both drilling and completion
operations; 2) longer than anticipated production testing of wells; 3)
commerciality negotiations with Ecopetrol; 4) the need to replace the entire
senior management of the Company's Colombian subsidiary, GHKCC and terminate the
Company's Bogota-based engineering consultants; and 5) a decision by the
Colombian Supreme Court that declared the established environmental "global
permitting" laws to be unconstitutional, resulting in the promulgation of new
environmental laws and standards.

As a result of the aforementioned circumstances and resulting delays, the
Company actually drilled six wells and completed and extensively tested three
wells during 1998 with a net cost of approximately $19.4 million for drilling
and approximately $5.5 million for completion and testing. None of the three
wells tested in 1998 were successful. Management believes that oil and gas shows
encountered in the drilling of two of the delineation wells that did not produce
during testing coupled with log and core data taken from these wells, which was
generally similar to the data from the other productive wells, suggests that
test production failure may have been a result of engineering and completion
problems. For this reason, El Segundo 6-E and Tres Pasos 4-W are potential
candidates for horizontal or lateral drilling in 1999. Management believes that
in spite of the setbacks in 1998, that the substantial amount of 1997-98
production testing and engineering studies and pressure and reservoir analysis
performed during the year significantly improved the Company's understanding of
the Guaduas Field and its Cimarrona reservoir. Additionally the Company
completed its first 3-D seismic survey covering the north half of the Guaduas
structure. Use of the data recorded should lead to better locations for future
development and delineation wells. Further, the Company drilled and completed
the first Guaduas Field horizontal well in late-1998. Production testing began
in early-1999 and unstimulated production rates of 1,100 Bbls/d to 1,666 Bbls/d
indicate a commercial well with potential to produce at higher rates; however,
the final results will not be known until the completion of reservoir
stimulation and testing at multiple, higher rates, which are expected to take
place during the second quarter of 1999. The Company also moved operational
control of the Guaduas Field from Houston to Bogota and hired a team of oil
professionals (see Item 1. Business -- Employees) with extensive international
experience in the development of large oil fields, production facilities and
pipelines to take the place of independent engineering consultants.

As a result of the Company's extensive production testing and reservoir
analysis performed by the Company's professionals, as well as Servipetrol Ltd.
and Ryder Scott, the estimation of the Guaduas Field's total proved reserves
increased by 31,303,000 Bbls, or by 23.7%, from 132,000,000 Bbls to 163,303,000
Bbls. The net increase for the Company was 20%, or 6,558,990 Bbls, bringing the
Company's total proved reserves to 38,719,235 from 32,160,245 Bbls. The pre-tax
net present value of the Company's proved oil reserves, discounted at 10%,
decreased by $28,988,312 to $115,878,106 from $144,866,418 over the same period.
The decrease is the result of an oil price decrease over the period from $17.00
to $12.05, a change to the year 2000 in the expected commencement of pipeline
production, and the increase in the Company's net proved reserves of 6,558,990
Bbls. The $4.95 reduction in oil price was a factor in the write-down of the
Company's oil and gas

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properties in the pre-tax amount of $129.8 million (after tax $84.4 million)
(see "-- Results of Development Stage Operations").

In summary, management believes that, without unforeseen cost overruns or
further delays and with additional delineation drilling, completion and
reservoir knowledge, and the use of 3-D seismic and horizontal drilling employed
by the Company's new professional team, that the Company will be able to carry
the strategies described herein in a timely manner.

LIQUIDITY AND CAPITAL RESOURCES

The Company had working capital of $40.8 million, net of restricted
investments, and unrestricted cash resources of $44.5 million as of December 31,
1998. The Company's unrestricted cash resources as of February 28, 1999 are
$36.5 million. The Company's non-discretionary capital commitments for the
remainder of 1999 as of February 28, 1999 are approximately $5.3.

The Company's activities from its inception through December 31, 1998 were
funded primarily by the proceeds from private placements of the Company's
securities, including the Company's common shares, warrants and notes, resulting
in aggregate cash proceeds of $157.0 million. Recent transactions are as
follows:

(i) Exchangeable Notes. In August 1997, the Company issued $25 million of
6% Exchangeable Notes (the "Exchangeable Notes") in a private transaction with
institutional and accredited investors. The Exchangeable Notes accrued interest
at a rate of per annum and were payable on December 31 and June 30 in each year,
commencing December 31, 1997. The Exchangeable Notes were scheduled to mature on
August 7, 2003.

The Exchangeable Notes were exchanged for a like principal amount of 6%
Convertible Debentures on August 5, 1998. The 6% Convertible Debentures were
converted on August 6, 1998 into Units consisting of 2,173,901 common shares and
warrants exercisable for 1,086,957 common shares. The warrants expired on
February 5, 1999. The Company received proceeds of $0.3 million from the
exercise of 18,913 warrants.

(ii) Senior Notes. In May 1998, the Company completed the offering of $110
million of 12 1/2% Senior Notes due May 15, 2005 (the "Senior Notes") and
received net proceeds of approximately $106 million, of which approximately
$37.8 million has been held in a separate account or in escrow to provide for
the first three years of interest payable under the Senior Notes. Interest on
the Senior Notes is payable semi-annually on May 15 and November 15 of each
year, commencing November 15, 1998. The Senior Notes mature on May 15, 2005. The
Senior Notes are redeemable at the option of the Company, in whole or in part,
at any time on or after May 15, 2002, at the prescribed redemption price, plus
accrued and unpaid interest, liquidated damages and additional amounts, if any,
to the date of redemption. Notwithstanding the foregoing, at any time prior to
May 15, 2001, the Company may redeem up to 33 1/3% of the original aggregate
principal amount of the Senior Notes with a portion of the net proceeds of an
equity or strategic investor offering, provided that at least 66 2/3% of the
original aggregate principal amount of the Senior Notes remains outstanding
immediately after the occurrence of such redemption. The Senior Notes may also
be redeemed at the option of the Company, in whole but not in part, at any time
at a redemption price equal to 100% of the principal amount thereof plus accrued
and unpaid interest, liquidated damages and additional amounts, if any, to the
redemption date in the event of certain changes affecting withholding taxes
applicable to certain payments on the Senior Notes. Upon the occurrence of a
change of control, (i) unless the Company redeems the Senior Notes as provided
in clause (ii) below, the Company will be required to offer to purchase the
Senior Notes at a purchase price equal to 101% of the aggregate principal amount
thereof, plus accrued and unpaid interest, liquidated damages and additional
amounts, if any, to the date of purchase, and (ii) the Company will have the
option, at any time prior to May 15, 2002, to redeem the Senior Notes, in whole
but not in part at a redemption price equal to 100% of the principal amount
thereof plus the applicable premium and accrued and unpaid interest, liquidated
damages and additional amounts, if any, to the date of redemption.

The Senior Notes are senior obligations of the Company and rank pari passu
in right and priority of payment with all existing and future senior
indebtedness of the Company.

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Proposed Credit Facility. During 1998, the Company executed a commitment
letter with Banque Paribas for a $25 million senior secured revolving credit
facility; however, due to delays in resolving issues regarding Canadian
withholding taxes on interest payments, a satisfactory loan agreement was not
concluded and the commitment letter provided by Banque Paribas expired.

Colombia. In 1995, the Company acquired a 15% interest in the Dindal and
Rio Seco Association Contracts through its participation in El Segundo 1-E, the
Guaduas Field discovery well. In 1996, the Company acquired an additional 36.7%
in the Dindal and Rio Seco Association Contracts in Colombia in exchange for the
issuance of the Company's common shares valued at $153.1 million in the
aggregate at that time. In 1997, the Company acquired an additional 6% in the
Dindal and Rio Seco Association Contracts in Colombia in exchange for the
issuance of the Company's common shares valued at $25.0 million in the aggregate
at that time. From inception through December 31, 1998, the Company had capital
expenditures of $68.7 million for the acquisition, exploration, and development
of its oil and gas properties including $65.5 million with respect to its
interests in Colombia.

The Company's estimated capital expenditures assume in each case that each
of the associates in the Association Contracts approves and pays its
proportionate share of capital expenditures. Under the terms of the Association
Contracts, if a commercially feasible discovery is made, the Colombian national
oil company ("Ecopetrol") may acquire a 50% interest in the property, and the
interests of all other parties to the contract, including the Company, will be
reduced by 50%. Ecopetrol will bear 50% of the associated development costs and
will reimburse the other associates for 50% of certain exploration activities.
The Association Contracts require Ecopetrol's participation in the production
facilities. The Company expects that Ecopetrol will participate to the extent of
50% of the pipeline and infrastructure costs. No assurances can be given,
however, that an agreement will be reached on these terms and the Company may be
required to fund amounts greater than the amounts presented as the Company's net
share. Ecopetrol retains the right not to participate initially in the
development. In this case, the associates can develop the Guaduas Field under a
sole risk provision, and will be required to invest 100% of the development
costs. After the associates have recovered 200% of the costs invested for
development plus 50% of certain exploration costs, Ecopetrol will become a
participant in the project at a 50% interest (see
"Business -- Properties -- Terms of Association Contracts and Related Matters").

Total 1999 capital expenditures on the Company's non-operated Tapir
Association Contract area are estimated to be $0.6 million. Such expenditures
will be made to complete the Mateguafa 1 well, which was drilled in 1998, and to
drill one more exploratory wells on the block.

To date, all oil revenues have been due to the Company's share of crude oil
produced during production testing of the Company's wells on the Guaduas Field.
Although the Company intends to continue to sell oil resulting from production
tests, significant commercial production is not expected until further
development of the field through the drilling and re-drilling and completion of
additional wells and construction of production and pipeline transportation
facilities. The Company has completed plans for the construction of pipeline and
production facilities at the Guaduas Field. Permitting and the purchasing of
equipment and supplies for pipeline and production facilities are now
proceeding. Anticipated completion of Increment II at 20,000 Bbls/d to 30,000
Bbls/d is year-end 2000 (see Item 2. Properties -- Colombian
Properties -- Guaduas Field -- Strategy for the Development of Oil Production by
Increments and Further Exploration).

The Company plans to conduct seismic operations on the Montecristo and
Rosablanca Association Contract areas in 1999 for an estimated cost of $2.5
million. The Company is considering acquisition of outside funding via farm-out
or forming an alliance with a seismic contractor to complete this work. Either
of these events will result in a reduction of the Company's interest.

Australia. The Company is in the process of eliminating any mandatory
capital commitments outside of Colombia. In the Bass Strait Basin offshore
southeast Australia, the Company is seeking to farm out its interests. If the
Company does not farm-out its interests in this prospect and an exploratory well
is drilled during 1999, the Company will have an estimated $2.2 million capital
commitment for this prospect during 1999.

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In 1998, the Company completed the sale of its 11.77% working interest in
the Perth Basin in Western Australia for approximately $0.9 million in cash and
the reimbursement of approximately $0.3 million for certain capital
expenditures.

Papua New Guinea. The Company entered into an Agreement with ARCO Papua New
Guinea Inc. ("ARCO") for a farm out of its interest whereby ARCO funded the
Company's obligation for the twelve-month period ended July 1998 for an 80%
interest in the subject exploration permit. Subsequently, the Company
relinquished its rights in the property to ARCO, retaining a small production
payment. The Company has no remaining required capital expenditures.

ACCOUNTING POLICIES AND DEVELOPMENT STAGE ACCOUNTING

The Consolidated Financial Statements and Notes thereto included herein
have been prepared in accordance with generally accepted accounting principles
in the United States of America.

The Company's exploration and development activities have not generated a
substantial amount of revenue, thus requiring the financial statements to be
presented as a development stage enterprise. Accumulated losses are presented on
the balance sheet as "Deficit accumulated during the development stage." The
income statement presents revenues and expenses for each period presented and
also a cumulative total of both amounts from the Company's inception. The
statement of cash flows shows inflows and outflows for each period presented and
from the Company's inception. The statement of stockholders' equity presents the
date and number of shares of each class of security issued for cash or other
consideration and the dollar amount assigned. In addition, the Notes to
Consolidated Financial Statements are required to identify the enterprise as
development stage.

The Company follows the full-cost method of accounting for oil and natural
gas properties. Under this method, all costs incurred in the acquisition,
exploration and development of oil and gas properties, including unproductive
wells, are capitalized in separate cost centers for each country. Such
capitalized costs include contract and concession acquisition, geological,
geophysical and other exploration work, drilling, completing and equipping oil
and gas wells, constructing production facilities and pipelines, and other
related costs. As of December 31, 1996, unevaluated oil and gas interests
included capitalized general and administrative costs of $0.1 million. No
additional general and administrative costs were capitalized during 1997 and
1998. The Company capitalized interest of $9.8 million and $0.6 million in 1998
and 1997, respectively.

The capitalized costs of oil and gas properties in each cost center are
amortized on the composite units of production method based on future gross
revenues from proved reserves. Sales or other dispositions of oil and gas
properties are normally accounted for as adjustments of capitalized costs. Gain
or loss is not recognized in income unless a significant portion of a cost
center's reserves are involved. Capitalized costs associated with the
acquisition and evaluation of unproved 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. If the net
capitalized costs of oil and gas properties in a cost center exceed an amount
equal to the sum of the present value of estimated future net revenues from
proved oil and gas reserves in the cost center and the lower of cost or fair
value of properties not being amortized, both adjusted for income tax effects,
such excess is charged to expense.

As of December 31, 1998, the Company's exploration and development
activities have not generated significant revenues. As a result, the Company's
historical results of operations have been presented as a development stage
company; thus, period-to-period comparisons of such results and certain
financial data may not be meaningful or indicative of future results. In this
regard, future results of the Company will be highly dependent upon the success
of the Company's Guaduas Field operations.

RESULTS OF DEVELOPMENT STAGE OPERATIONS

To date, oil revenues and lease operating expenses pertained solely to the
Company's share of crude oil produced during production testing of the Company's
wells in the Guaduas Field. Revenues from oil sales

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34

were $.02 million, $0.8 million, and $0.2 million in 1998, 1997, and 1996,
respectively. Lease operating expenses were $0.9 million, $0.9 million, and $0.3
million in 1998, 1997, and 1996, respectively. The Company tested four wells in
1997 and two wells in 1996. The 1998 oil and gas operating expenses represent
such costs as tank rentals and other miscellaneous fixed costs.

Oil production in Colombia (net to the Company, including minority
interest) of 1,997 barrels, 56,546 barrels and 14,188 barrels in 1998, 1997, and
1996, respectively, pertaining solely to the Company's share of oil produced
from production testing, was sold to Ecopetrol at an average price of $8.14 per
barrel in 1998, $13.79 per barrel in 1997, and $16.47 per barrel in 1996.
Production in 1998 was substantially lower than in 1997 because the Company's
testing program required that the wells be shut-in for pressure build up tests
during much of the year 1998. In January 1999, production testing began again
from the Tres Pasos 1-W Horizontal and will be conducted throughout much of the
first quarter of the year. Later in 1999 the Company plans additional production
testing.

Interest income was $3.8 million, $0.8 million and $0.3 million in 1998,
1997 and 1996, respectively. The increase from 1997 to 1998 was the consequence
of higher cash and investment balances resulting from the issuance of the Senior
Notes in May 1998. The increase from 1996 to 1997 was the consequence of higher
cash balances resulting from the issuance of $25 million of Exchangeable Notes
in August 1997.

General and administrative costs were $9.8 million, $8.7 million, and $2.5
million in 1998, 1997, and 1996, respectively. The costs incurred during 1997
included approximately $1.5 million of severance and $2.1 million of related
compensation costs associated with the resignation of former officers. The costs
incurred during 1998 included $2.1 million relating to costs incurred conducting
feasibility studies for the proposed construction of pipeline and production
facilities and other development activities in Colombia. The remaining $2.6
million increase in general and administrative expenses from 1997 to 1998 was
primarily attributable to a $1.1 million increase in personnel costs, including
salaries, benefits, travels, rents, and insurance due to increased personnel in
both the U.S. and Colombia as well as the expansion of operations in Colombia.
In addition, the Company incurred $0.8 million in professional services and
consulting fees and accrued $0.7 million for certain commitments and
contingencies. The increase from 1996 to 1997 was primarily attributable to
severance costs paid to former executive officers and recognition of
compensation expense related to a change in the exercise period of stock options
held by such executives. In addition, the Company expanded its operating
activities and significantly added to its professional staff in the U.S. and
Colombia.

Depreciation and amortization was $0.7 million, $0.1 million, and $0.1
million in 1998, 1997, and 1996, respectively. The increase from 1997 to 1998
was primarily attributable to the amortization of costs incurred on the issue of
the Senior Notes in May 1998 and the Exchangeable Notes in August 1997 (see
"Liquidity and Capital Resources"). The remaining increase resulted from higher
depreciation costs relating to the increase in fixed assets. As of December 31,
1998, the Company has not recorded depletion of its proved oil and gas property
as only insignificant quantities of oil have been produced during its production
testing plan.

As required under the full cost method of accounting, capitalized costs are
limited to the sum of the present value of future net revenues using current
unescalated pricing discounted at 10% related to estimated production of proved
reserves and the lower of cost or estimated fair value of unevaluated
properties, all net of expected income tax effects. At December 31, 1998, the
Company recognized a non-cash write-down of oil and gas properties in the amount
of $129.8 million pre-tax or $84.4 million after tax pursuant to this ceiling
limitation required by the full cost method of accounting for oil and gas
properties. The write-down was primarily the result of the decline in crude oil
prices and the impairment of unevaluated properties due primarily to the failure
of five non-commercial exploratory wells.

The Company incurred net losses of $90.2 million, $7.9 million, and $2.2
million for the years ended December 31, 1998, 1997, and 1996, respectively. The
1998 loss includes a non-cash write-down of $129.8 million pre-tax or $84.4
million after tax.

32
35

COLOMBIAN TAXES

The Company's net income, as defined under Colombian law, from Colombian
sources is subject to Colombian corporate income tax at a rate of 35%. An
additional remittance tax is imposed upon remittance of profits abroad at a rate
of 7%.

YEAR 2000 DISCLOSURE

The "Year 2000 Issue" is a general term used to refer to certain business
implications of the arrival of the new millennium. In simple terms, on January
1, 2000, all hardware and software systems which use the two-digit year
convention could fail completely or create erroneous data as a result of the
system failing to recognize the two digit internal date "00" as representing the
Year 2000.

The Company does not believe that its internal systems and operations have
any material issues with respect to Year 2000 compliance and does not anticipate
incurring significant remediation costs, if any. The Company has a limited
operating history and is engaged solely in the exploration, development and
production of oil and natural gas in Colombia. As such, the Company engages in
few transactions and has minimum reliance on the hardware and software systems
of third parties. Further, the Company's hardware and software systems are
relatively new, widely utilized and the Company has been advised that all of
these systems are Year 2000 compliant. The Company's internal dependence on
information systems and other operating equipment that could potentially require
remedial action to become Year 2000 compliant is low. Accordingly, the risk of
operation disruptions and the corresponding risk of liability for disruptions
caused by non-Year 2000 compliant systems are not of major concern to the
Company.

One of the next phases in the development of the Guaduas Field is the
transportation and marketing of crude oil to be produced from the Company's
properties. The Company is engaged in negotiations with oil pipeline,
construction and engineering firms to construct its processing, storage and
related facilities and a 36-mile pipeline from the Guaduas Field to the existing
Oleoducto Alto Magdalena ("OAM") pipeline, which terminates at Vasconia. Beyond
Vasconia, the Company's oil production may be transported to the export terminal
at Covenas via the two existing pipeline systems, Oleducto de Colombia ("ODC").
The Company has retained Brown & Root Energy Services and Technivance Brown &
Root S.A. to conduct planning and engineering studies for its planned pipeline
and associated compression facilities from the Guaduas Field and intends that
the technology employed in its own delivery systems will be Year 2000 compliant.
The Company has also asked these consultants to review any Year 2000 risks
associated with the planned interconnection of its delivery systems with the
OAM, ODC and OCENSA pipelines, and is reviewing the OAM delivery systems in
conjunction with its current negotiations with the operator of that pipeline.
The Company or the consultants will review and, where necessary, rectify the
Year 2000 risks associated with interconnections to the OAM and ODC pipelines.
The Company is not currently aware of Year 2000 limitations affecting the
computer systems that control these third party pipeline systems that would
compromise the operation of such systems. Moreover, the Company would not be
responsible for remediation costs associated with such computer systems should
any technical problems arise. However, in the event a pipeline was rendered
inoperable as a result of Year 2000 issues affecting its operating systems, the
Company may be required to rely on less efficient alternate delivery systems,
such as tanker trucks, to transport any oil production to market.

As the Company develops its infrastructure at the Guaduas Field, it will
continue to monitor Year 2000 compliance issues as they relate to equipment
supplied by its vendors and contractors. Since the Company does not currently
supply significant oil production to its customers, and no supply contracts have
been entered into in respect of the Guaduas Field production, the Company is
unable to assess the significance of Year 2000 issues affecting potential
customers at this stage in its operations.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Seven Seas is exposed to market risk, including adverse changes in
commodity prices, interest rates and foreign currency exchange rates as
discussed below.

33
36

Commodity Risk. The Company's exposure in the commodity pricing applicable
to its oil and natural gas production is currently minimal due to the small
amounts of oil and gas produced to date. Realized commodity prices received for
such production are primarily driven by the prevailing worldwide price for crude
oil and spot prices applicable to natural gas. The effects of such pricing are
expected to be minor until such time as the Company produces commercial
quantities of oil and gas.

Interest Rate Risk. The Company considers its interest rate risk exposure
to be minimal as a result of a fixed interest rate on the $110 million 12 1/2%
Senior Notes. The Company currently has no open interest rate swaps agreements.

Foreign Currency Exchange Rate Risk. The Company conducts business in
several foreign currencies and is subject to foreign currency exchange rate risk
on cash flows related to sales, expenses and capital expenditures. However,
because predominately all transactions in Seven Seas' existing foreign
operations are denominated in U.S. dollars, the U.S. dollar is the functional
currency for all operations. Exposure from transactions in currencies other than
the U.S. dollars is not material.

34
37

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

PAGE
----

Seven Seas Petroleum Inc. and Subsidiaries
Report of Independent Public Accountants.................... 36
Consolidated Balance Sheets as of December 31, 1998 and
1997...................................................... 37
Statements of Consolidated Operations and Accumulated
Deficit for the years ended December 31, 1998, 1997 and
1996 and from Inception (February 3, 1995) to December 31,
1998...................................................... 38
Statements of Consolidated Stockholders' Equity for the
years ended December 31, 1998, 1997 and 1996 and from
Inception (February 3, 1995) to December 31, 1998......... 39
Statements of Cash Flows for the years ended December 31,
1998, 1997 and 1996 and from Inception (February 3, 1995)
to December 31, 1998...................................... 40
Notes to Financial Statements............................... 42

35
38

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To Seven Seas Petroleum Inc.:

We have audited the accompanying consolidated balance sheets of Seven Seas
Petroleum Inc. (a Yukon Territory, Canada corporation in the development stage,
see Note 1) and subsidiaries as of December 31, 1998 and 1997, and the related
consolidated statements of operations and accumulated deficit, stockholders'
equity and cash flows for the years ended December 31, 1998, 1997 and 1996 and
for the period from inception (February 3, 1995) to December 31, 1998. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these 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 Seven Seas
Petroleum Inc. and subsidiaries as of December 31, 1998 and 1997, and the
results of their operations and their cash flows for the years ended December
31, 1998, 1997 and 1996 and for the period from inception to December 31, 1998
in conformity with generally accepted accounting principles.

ARTHUR ANDERSEN LLP

Houston, Texas
March 25, 1999

36
39

SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)

ASSETS

DECEMBER 31,
1998 1997
--------- --------

CURRENT ASSETS
Cash and cash equivalents................................. $ 38,147 $ 18,067
Short-term investments.................................... 6,399 44
Restricted short-term investments......................... 13,244 --
Accounts receivable....................................... 6,562 3,865
Interest receivable....................................... 532 --
Inventory................................................. 1,316 --
Prepaids and other........................................ 225 118
--------- --------
66,425 22,094
Note receivable from related party.......................... 200 200
Restricted long-term investments............................ 18,658 --
Land........................................................ 1,257 --
Evaluated oil and gas properties, full-cost method.......... 74,993 46,117
Unevaluated oil and gas properties, full-cost method........ 113,116 221,713
Fixed assets, net of accumulated depreciation of $232 at
December 31, 1998 and $43 at December 31, 1997............ 1,357 304
Other assets, net of accumulated amortization of $461 at
December 31, 1998 and $194 at December 31, 1997........... 3,894 1,486
--------- --------
TOTAL ASSETS...................................... $ 279,900 $291,914
========= ========

LIABILITIES AND STOCKHOLDERS' EQUITY

CURRENT LIABILITIES
Accounts payable.......................................... $ 10,058 $ 6,885
Interest payable.......................................... 1,719 --
Accrued compensation...................................... -- 1,228
Other accrued liabilities................................. 580 92
--------- --------
12,357 8,205
Long-term debt.............................................. 110,000 25,000
Deferred income taxes....................................... 24,732 70,459
Minority interest........................................... 9,713 4,087
COMMITMENTS AND CONTINGENCIES (Note 10)
STOCKHOLDERS' EQUITY
Share capital --
Authorized unlimited common shares without par value;
37,778,420 and 35,071,606 issued and outstanding at
December 31, 1998 and 1997, respectively............... 222,447 196,406
Authorized unlimited Class A preferred shares without par
value; none outstanding................................ -- --
Warrants for common share -- 1,068,044 and none
outstanding at December 31, 1998 and December 31, 1997,
respectively........................................... 3,093 --
Deficit accumulated during development stage.............. (102,442) (12,243)
Treasury stock; 29 shares held at December 31, 1998 and
December 31, 1997...................................... -- --
--------- --------
Total Stockholders' Equity........................ 123,098 184,163
--------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY........ $ 279,900 $291,914
========= ========

The accompanying notes are an integral part of these financial statements.

37
40

SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

STATEMENTS OF CONSOLIDATED OPERATIONS AND ACCUMULATED DEFICIT
(IN THOUSANDS, EXCEPT SHARE DATA)

CUMULATIVE
TOTAL FROM
INCEPTION
(FEBRUARY 3,
YEAR ENDED DECEMBER 31, 1995) TO
--------------------------------------- DECEMBER 31,
1998 1997 1996 1998
----------- ----------- ----------- ------------

REVENUE
Crude oil sales........................ $ 16 $ 780 $ 234 $ 1,029
Interest income........................ 3,781 787 341 5,062
----------- ----------- ----------- -----------
3,797 1,567 575 6,091
EXPENSES
General and administrative............. 9,761 8,714 2,455 22,001
Oil and gas operating expenses......... 942 907 253 2,102
Depreciation and amortization.......... 674 148 111 971
Writedown of proved oil & gas
properties.......................... 129,789 -- -- 129,789
Gain on sale of exploration
properties.......................... (577) -- -- (546)
Dry hole and abandonment costs......... 17 5 1,145
Geological and geophysical............. -- 27 10 47
Other (income) expense................. (97) (24) -- (122)
----------- ----------- ----------- -----------
140,492 9,789 2,834 155,387
NET LOSS BEFORE INCOME TAXES AND MINORITY
INTEREST............................... (136,695) (8,222) (2,259) (149,296)
INCOME TAX BENEFIT....................... (45,718) -- -- (45,718)
----------- ----------- ----------- -----------
NET LOSS BEFORE MINORITY INTEREST........ (90,977) (8,222) (2,259) (103,578)
MINORITY INTEREST........................ 778 294 64 1,136
----------- ----------- ----------- -----------
NET LOSS................................. (90,199) (7,928) (2,195) (102,442)
----------- ----------- ----------- -----------
DEFICIT ACCUMULATED DURING THE
DEVELOPMENT STAGE, beginning of
period................................. (12,243) (4,315) (2,120) --
DEFICIT ACCUMULATED DURING THE
DEVELOPMENT STAGE, end of period....... $ (102,442) $ (12,243) $ (4,315) $ (102,442)
=========== =========== =========== ===========
BASIC AND DILUTED NET LOSS PER COMMON
SHARE.................................. $ (2.49) $ (0.24) $ (0.17) $ (4.45)
=========== =========== =========== ===========
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING............................ 36,203,713 32,504,872 12,971,871 23,036,678
=========== =========== =========== ===========

The accompanying notes are an integral part of these financial statements.

38
41

SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

STATEMENT OF CONSOLIDATED STOCKHOLDERS' EQUITY
FOR THE PERIOD FROM INCEPTION (FEBRUARY 3, 1995) THROUGH DECEMBER 31, 1998
(IN THOUSANDS, EXCEPT SHARE DATA)

COMMON STOCK PREFERRED STOCK SPECIAL WARRANT
---------------------- ---------------------- ------------------------
DATE NUMBER AMOUNT NUMBER AMOUNT NUMBER AMOUNT
----------------- ----------- -------- ----------- -------- ------------ ---------

Issuance of common share to
founder........................... February 3, 1995 1 $ -- -- $ -- -- $ --
Issuance of common shares to
founder for cash.................. February 27, 1995 999,999 -- -- -- -- --
Issuance of common shares in a
private placement for cash ($0.25
per share)........................ March 22, 1995 4,000,000 1,000 -- -- -- --
Issuance of common shares in
private placements for cash (0.75
per share)........................ May 31, 1995 5,687,666 4,266 -- -- -- --
June 9, 1995 979,000 734 -- -- -- --
Issuance of common shares in
settlement of agents' fees ($0.75
per share)........................ May 31, 1995 284,383 213 -- -- -- --
June 9, 1995 48,950 37 -- -- -- --
May 31-June 9,
Less: Common share issuance cost... 1995 -- (250) -- -- -- --
Issuance of common shares in
connection with the May 5, 1995
amalgamation agreement with Rusty
Lake Resources ($0.25 per
share)............................ June 29-30, 1995 680,464 170 -- -- -- --
Net loss........................... -- -- -- -- -- --
----------- -------- ----------- -------- ------------ ---------
BALANCE AT DECEMBER 31, 1995....... 12,680,463 6,170 -- -- -- --
Issuance of special warrants in a
brokered private placement for
cash ($2.75 per warrant).......... March 15, 1996 -- -- -- -- 2,000,000 5,096
Issuance of common shares to the
Company's 401(k) plan ($7.875 per
share)............................ April 29, 1996 10,000 79 -- -- -- --
Purchase Treasury Stock ($8.00 per
share)............................ June 26, 1996 -- -- -- -- -- --
Exercise of stock options for cash
($.75 per share).................. Jan.-- June 1996 305,000 229 -- -- -- --
Exercise of stock options for cash
($7.125 per share)................ April 29, 1996 10,000 71 -- -- -- --
Issuance of exchangeable preferred
stock in connection with business
combination ($9.125 per share).... July 26, 1996 -- -- 5,002,972 45,652 -- --
Issuance of special warrants in
connection with business
combination ($9.125 per
warrant).......................... July 26, 1996 -- -- -- -- 11,774,171 107,439
Issuance of convertible special
warrants in a brokered private
placement for cash ($15.00 per
warrant).......................... October 16, 1996 -- -- -- -- 500,000 7,013
Exercise of stock options for cash
($.75 per share).................. July-Dec 1996 310,333 233 -- -- -- --
Net loss........................... -- -- -- -- -- --
----------- -------- ----------- -------- ------------ ---------
BALANCE AT DECEMBER 31, 1996....... 13,315,796 6,782 5,002,972 45,652 14,274,171 119,548
Conversion of special warrants
issued in connection with the
business combination dated July
26, 1996 ($9.125 per share)....... February 7, 1997 11,774,171 107,439 -- -- (11,774,171) (107,439)
Conversion of the preferred shares
in connection with the business
combination dated July 26, 1996
($9.125 per share)................ February 7, 1997 5,002,972 45,652 (5,002,972) (45,652) -- --
Conversion of privately placed
special warrants ($15.00 per
warrant).......................... February 7, 1997 500,000 7,013 -- -- (500,000) (7,013)
Conversion of privately placed
special warrants ($2.75 per
warrant).......................... February 7, 1997 2,000,000 5,096 -- -- (2,000,000) (5,096)
Issuance of common shares in
connection with the business
combination ($18.55 per share).... March 5, 1997 1,000,000 18,550 -- -- -- --
Conversion of privately placed
special warrants for cash ($3.50
per warrant)...................... March 14, 1997 1,000,000 3,500 -- -- -- --
Exercise of stock options
($.75-- $10.90 per share)......... Jan. -- Dec, 1997 478,667 2,374 -- -- -- --
Net loss........................... -- -- -- -- -- --
----------- -------- ----------- -------- ------------ ---------
BALANCE AT DECEMBER 31, 1997....... 35,071,606 196,406 -- -- -- --
Exercise of stock options
($.75 -- $10.90 per share)........ Jan. -- Dec, 1998 514,000 5,351
Conversion of debentures ($11.50
per share, $2.90 per warrant)..... August 6, 1998 2,173,901 20,351 1,086,957 3,148
Exercise of warrants ($15.00 per
share)............................ August 12, 1998 18,913 339 (18,913) (55)
Net loss........................... -- -- -- -- -- --
----------- -------- ----------- -------- ------------ ---------
BALANCE AT DECEMBER 31, 1998....... 37,778,420 $222,447 -- $ -- 1,068,044 $ 3,093
=========== ======== =========== ======== ============ =========

DEFICIT
ACCUMULATED
TREASURY STOCK DURING
--------------- DEVELOPMENT
NUMBER AMOUNT PHASE TOTAL
------ ------ ------------ --------

Issuance of common share to
founder........................... -- $ -- $ -- $ --
Issuance of common shares to
founder for cash.................. -- -- -- --
Issuance of common shares in a
private placement for cash ($0.25
per share)........................ -- -- -- 1,000
Issuance of common shares in
private placements for cash (0.75
per share)........................ -- -- -- 4,266
-- -- -- 734
Issuance of common shares in
settlement of agents' fees ($0.75
per share)........................ -- -- -- 213
-- -- -- 37
Less: Common share issuance cost... -- -- -- (250)
Issuance of common shares in
connection with the May 5, 1995
amalgamation agreement with Rusty
Lake Resources ($0.25 per
share)............................ -- -- -- 170
Net loss........................... -- -- (2,120) (2,120)
--- ----- --------- --------
BALANCE AT DECEMBER 31, 1995....... -- -- (2,120) 4,050
Issuance of special warrants in a
brokered private placement for
cash ($2.75 per warrant).......... -- -- -- 5,096
Issuance of common shares to the
Company's 401(k) plan ($7.875 per
share)............................ -- -- -- 79
Purchase Treasury Stock ($8.00 per
share)............................ 29 -- -- --
Exercise of stock options for cash
($.75 per share).................. -- -- -- 229
Exercise of stock options for cash
($7.125 per share)................ -- -- -- 71
Issuance of exchangeable preferred
stock in connection with business
combination ($9.125 per share).... -- -- -- 45,652
Issuance of special warrants in
connection with business
combination ($9.125 per
warrant).......................... -- -- -- 107,439
Issuance of convertible special
warrants in a brokered private
placement for cash ($15.00 per
warrant).......................... -- -- -- 7,013
Exercise of stock options for cash
($.75 per share).................. -- -- -- 233
Net loss........................... -- -- (2,195) (2,195)
--- ----- --------- --------
BALANCE AT DECEMBER 31, 1996....... 29 -- (4,315) 167,667
Conversion of special warrants
issued in connection with the
business combination dated July
26, 1996 ($9.125 per share)....... -- -- -- --
Conversion of the preferred shares
in connection with the business
combination dated July 26, 1996
($9.125 per share)................ -- -- -- --
Conversion of privately placed
special warrants ($15.00 per
warrant).......................... -- -- -- --
Conversion of privately placed
special warrants ($2.75 per
warrant).......................... -- -- -- --
Issuance of common shares in
connection with the business
combination ($18.55 per share).... -- -- -- 18,550
Conversion of privately placed
special warrants for cash ($3.50
per warrant)...................... -- -- -- 3,500
Exercise of stock options
($.75-- $10.90 per share)......... -- -- -- 2,374
Net loss........................... -- -- (7,928) (7,928)
--- ----- --------- --------
BALANCE AT DECEMBER 31, 1997....... 29 -- (12,243) 184,163
Exercise of stock options
($.75 -- $10.90 per share)........ 5,351
Conversion of debentures ($11.50
per share, $2.90 per warrant)..... 23,499
Exercise of warrants ($15.00 per
share)............................ 284
Net loss........................... (90,199) (90,199)
--- ----- --------- --------
BALANCE AT DECEMBER 31, 1998....... 29 $ -- $(102,442) $123,098
=== ===== ========= ========

The accompanying notes are an integral part of these financial statements.

39
42

SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

STATEMENTS OF CONSOLIDATED CASH FLOWS
(IN THOUSANDS)

CUMULATIVE
TOTAL FROM
INCEPTION
(FEBRUARY 3,
YEAR ENDED DECEMBER 31, 1995) TO
---------------------------- DECEMBER 31,
1998 1997 1996 1998
-------- ------- ------- ------------

OPERATING ACTIVITIES
Net loss.................................................. $(90,199) $(7,928) $(2,195) $(102,442)
Add (subtract) items not requiring (providing) cash:
Compensation expense...................................... -- 2,140 -- 2,140
Minority interest......................................... (778) (294) (64) (1,136)
Common stock contribution to 401(k) retirement plan....... -- -- 79 79
Depreciation and amortization............................. 679 148 111 976
Writedown of proved oil & gas properties.................. 129,789 -- -- 129,789
Gain on sale of exploration properties.................... (577) -- -- (546)
Dry hole and abandonment costs............................ -- 17 -- 1,140
Gain on sale of marketable securities..................... (6) -- -- (6)
Deferred income tax benefit............................... (45,727) -- -- (45,727)
Changes in working capital excluding changes to cash and
cash equivalents:
Accounts receivable..................................... (3,238) (2,082) (316) (5,680)
Interest receivable..................................... (532) -- -- (532)
Inventory............................................... (1,316) -- -- (1,316)
Prepaids and other, net................................. (107) (118) -- (225)
Accounts payable........................................ 4,218 1,389 (17) 5,710
Other accrued liabilities............................... 487 (153) 243 579
-------- ------- ------- ---------
Cash Flow Used in Operating Activities.................... (7,307) (6,881) (2,159) (17,197)
-------- ------- ------- ---------
INVESTING ACTIVITIES
Exploration of oil and gas properties..................... (49,979) (16,360) (4,309) (72,345)
Purchase of land.......................................... (1,257) -- -- (1,257)
Purchase of investments................................... (38,301) -- -- (38,301)
Proceeds from acquisition................................. -- -- 630 630
Proceeds from sale of property............................ 1,163 -- -- 1,247
Proceeds from sale of marketable securities............... 50 -- -- 50
Note receivable from related party........................ -- (200) -- (200)
Other asset additions..................................... (1,242) (280) (64) (1,756)
-------- ------- ------- ---------
Cash Flow Used in Investing Activities.................... (89,566) (16,840) (3,743) (111,932)
-------- ------- ------- ---------
FINANCING ACTIVITIES
Proceeds from special warrants issued..................... 284 -- 12,109 12,393
Proceeds from share capital issued........................ 3,972 4,962 533 15,466
Proceeds from additional paid-in capital contributed...... -- -- 1 1
Proceeds from issuance of long-term debt.................. 110,000 25,000 -- 135,000
Costs of issuing long-term debt........................... (4,248) (1,573) -- (5,821)
Contributions by minority interest........................ 6,945 2,779 513 10,237
-------- ------- ------- ---------
Cash Flow Provided by Financing Activities................ 116,953 31,168 13,156 167,276
-------- ------- ------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS...... 20,080 7,447 7,254 38,147
Cash and cash equivalents, beginning of period............ 18,067 10,620 3,366 --
-------- ------- ------- ---------
CASH AND CASH EQUIVALENTS, END OF PERIOD.................. $ 38,147 $18,067 $10,620 $ 38,147
======== ======= ======= =========

The accompanying notes are an integral part of these financial statements.
40
43

Supplemental disclosures of cash flow information:

The Company incurred interest costs of $9.8 million and $0.6 million for
the years ended December 31, 1998 and 1997, respectively. Such amounts were
capitalized during the respective periods.

Cash paid for interest for the year ended December 31, 1998 and 1997 was
$8.1 million and $.6 million, respectively.

The Company paid $30,000 for estimated income taxes during the year ended
December 31, 1998.

41
44

SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. DEVELOPMENT STAGE OPERATIONS:

Seven Seas Petroleum Inc. (a Yukon Territory, Canada corporation) was
formed on February 3, 1995. Seven Seas Petroleum Inc. and its subsidiaries
(collectively referred to as "Seven Seas" or the "Company") are collectively a
development stage enterprise engaged in the exploration, development and
production of oil and natural gas, primarily in Colombia. The Company is the
operator of an oil discovery, known as the "Guaduas Field" (formerly known as
"Emerald Mountain"), which is on the Emerald Mountain structure and located in
an area defined by the Rio Seco and Dindal Association Contracts (the
"Association Contracts"), which cover a total of approximately 109,000
contiguous acres in central Colombia. The Company owns a 57.7% working interest
in the two Association Contracts before participation by Empresa Colombiana de
Petroleos ("Ecopetrol"), the Colombian state oil company. The Company has no
significant income producing properties and its principal assets, its interests
in the Association Contracts, are in the early stage of exploration and
development. Since inception through December 31, 1998, the Company incurred
cumulative losses of $102.4 million and, because of its continued exploration
and development activities, expects that it will continue to incur losses and
that its accumulated deficit will increase until commencement of production from
the Association Contracts occurs in quantities sufficient to cover operating
expenses.

To date, the Company has spent $242.8 million to acquire and $75.6 million
to delineate the reserve potential of the Guaduas Field. The Company has drilled
twelve exploratory wells within the Association Contracts, of which six have
been production tested and have achieved maximum actual oil production rates
ranging from 1,666 to 13,123 Bbls per day. Four of the twelve did not produce
commercial amounts of oil and gas during testing and two remain to be tested. As
of December 31, 1998, the Guaduas Field had produced approximately 300,000
barrels of oil during various testing procedures. Except for additional
production testing and further reservoir evaluation, continuous production of
the Guaduas Field will not commence prior to installation of the infrastructure
necessary to produce and transport continuous oil production.

The Company anticipates exploring and developing the Guaduas Field in
increments designed to optimize cash flows that can be reinvested into further
delineation and development of the field. These planned increments, starting
with an approximate 5,000 Bbl per day portable trucking facility (expected to be
in operation in early-2000) followed by an approximate 25,000 Bbls/d pipeline
facility (expected to be operational by year-end 2000) and culminating with an
approximate 250,000 Bbl per day pipeline facility (expected to be in operation
in early-2005) would be phased in as capital is available to fund the necessary
delineation and development drilling, production facility and transportation
facility expenditures.

These plans are further dependent upon the timing of a global operating
license allowing development in the Association Contract areas; environmental
and rights-of-way permits for production and transportation facilities; cost and
timeliness of construction activities; availability of transportation on third
party pipeline systems; and the timing of a commerciality agreement with
Ecopetrol. Approval of commerciality by Ecopetrol is a critical part of the
Company's strategy as Ecopetrol will bear fifty percent of all costs for
development and production subsequent to the date commerciality is declared.
Although the Company has reason to believe that a commerciality agreement can be
reached with Ecopetrol, if the commerciality agreement is not in place before
December 1999 the Company will not be able to proceed as planned.

As of December 31, 1998, the Company had cash and cash equivalents of $38.1
million and commitments under existing oil and gas agreements of $5.3 million in
1999. Based on available capital resources, the Company believes that it will be
able to make its commitments and fund its exploration and development plan
through 1999. To the extent the Company experiences delays or cost overruns in
the development plan, the Company will be required to seek additional financing
to meet its commitments and to carry out its exploration and development plan
through 2000. The continued exploration and development of the Company's current
properties is expected to require substantial amounts of additional capital
which the Company may be required to raise through debt or equity financing,
encumbering properties or entering into arrangements whereby certain costs will
be paid by others to earn an interest in the property. If the Company

42
45
SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

is unsuccessful in constructing production and transportation facilities,
increasing its proved reserves or realizing future production from its
properties, the Company may be unable to pay existing or future debt.

Seven Seas is subject to several categories of risk associated with its
development stage activities. Oil and gas exploration and development is a
speculative business and involves a high degree of risk. Among the factors that
have a direct bearing on Seven Seas' prospects are uncertainties inherent in
estimating oil and gas reserves and future hydrocarbon production and cash
flows, particularly with respect to wells that have not been fully tested and
with wells having limited production testing histories; access to additional
capital; changes in the price of oil and natural gas, services and equipment;
the limited exploration of the concessions; the status of existing and future
contractual relationships with Ecopetrol; foreign currency fluctuation risks;
Seven Seas' substantial indebtedness, the presence of competitors with greater
financial resources and capacity; difficulties and risks associated with
operating in Colombia.

2. BUSINESS COMBINATION:

On June 29, 1995 the Supreme Court of British Columbia approved the May 5,
1995 amalgamation of Seven Seas and Rusty Lake Resources Ltd. Stockholders of
Rusty Lake Resources Ltd. Were issued one common share in Seven Seas, the new
company after the amalgamation, for each 35 common shares held in Rusty Lake
Resources Ltd. Additional shares of Seven Seas were issued in settlement of
certain indebtedness of Rusty Lake Resources Ltd. This transaction has been
reflected as an acquisition by Seven Seas using the purchase method of
accounting, whereby the assets acquired and liabilities assumed were recorded at
the fair value and Rusty Lake Resources Ltd. Has been prospectively reflected in
the Company's financial statements since June 29, 1995.

On July 26, 1996 the Company acquired 100 percent of the outstanding stock
which represented 100 percent of the voting shares held in GHK Company Colombia
and Esmeralda LLC. Additionally, on the same date, the Company acquired 62.963
percent of the outstanding shares and voting stock in Cimarrona LLC. This
transaction has been reflected as an acquisition by Seven Seas using the
purchase method of accounting, whereby the assets acquired and liabilities
assumed were fair valued and the operations of the acquired entities have been
reflected in the Company's financial statements since July 26, 1996. As
consideration for the increased interest from these acquisitions, Seven Seas
issued to the stockholders in GHK Company Colombia, Esmeralda LLC and Cimarrona
LLC a combination of preferred shares and special warrants which were
exchangeable into a total of 16,777,143 common shares upon the earlier of the
approval of a prospectus qualifying the exchange, or one year from the closing
of the transaction. Of the 16,777,143 preferred shares and special warrants,
5,002,972 preferred shares were issued for all of the common shares in GHK
Company Colombia, 4,469,028 special warrants were issued for all of the common
shares in Esmeralda LLC, and 7,305,143 special warrants were issued for 62.963
percent of the common shares in Cimarrona LLC. The remaining 37.037 percent
interest in Cimarrona LLC represents a minority interest which is reflected as
such on the balance sheet. The 16,777,143 preferred shares and special warrants
were recorded based on the closing stock price of Seven Seas on July 26, 1996 at
$9.125 per share totaling $153.1 million. Collectively, the acquisition of these
three companies resulted in the purchase of an additional 36.7 percent
participating interest in the Association Contracts in which the Company
previously held a 15 percent participating interest. All three entities were oil
and gas exploration companies whose only material asset was the participating
interest they held in the Association Contracts in Colombia. Net assets acquired
include $217.1 million assigned to oil and gas properties and other nominal net
working capital, less amounts attributable to the minority interest in Cimarrona
LLC. Because of the differences in tax basis and the financial statement
valuation of such acquired oil and gas properties, $64.0 million of deferred
Colombian and U.S. income taxes was also recorded in this acquisition (see Note
5) and is included in the amount assigned to oil and gas properties. Income and
expenditures incurred by these three entities after July 26, 1996 are included
in the statements of operations and accumulated deficit for the years ended
December 31, 1998 1997 and 1996.
43
46
SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Of the 16,777,143 preferred shares and special warrants issued, 11,744,000
are held subject to an escrow agreement, whereby one third of the securities are
released each year for three years. The securities may be released earlier based
upon a valuation of the Seven Seas interests in the Association Contracts. As of
July 26, 1998, two-thirds of the 11,744,000 common shares or 7,829,334 common
shares was released from escrow pursuant to the escrow agreement.

On February 7, 1997 approvals were granted by the Ontario Securities
Commission, British Columbia Securities Commission and the Alberta Securities
Commission for the prospectus filed to qualify 11,774,171 special warrants and
5,002,972 preferred shares which were automatically converted to common shares.
These shares were issued in connection with the acquisition of a 36.7 percent
participating interest in the Association Contracts in Colombia by the Company
on July 26, 1996, as described above.

On March 5, 1997 the Company acquired 100 percent of the outstanding voting
stock held in Petrolinson, S.A. The terms of the transaction were agreed to in a
letter of intent dated November 22, 1996. The principal asset owned by
Petrolinson, S.A. is a six percent participating interest in the Association
Contracts. As consideration for the six percent participating interest in the
Association Contracts, Seven Seas issued to the sole shareholder in Petrolinson,
S.A. 1,000,000 common shares of Seven Seas Petroleum Inc. The common shares
issued to the sole shareholder of Petrolinson, S.A. were subject to an escrow
agreement, the terms of which provided for a 120 day escrow of shares commencing
from March 5, 1997 with an option by the Company to extend the escrow period for
an additional 30 days. The 1,000,000 common shares issued to the sole
shareholder of Petrolinson, S.A. were released from escrow on July 3, 1997, in
accordance with the escrow agreement as described above. This six percent
interest will be carried through exploration by the other 94 percent
participating interest parties. This transaction was reflected in 1997 as an
acquisition by Seven Seas using the purchase method of accounting, whereby the
assets acquired and liabilities assumed were fair valued and the acquired
operations have been reflected in the Company's financial statements since March
5, 1997. The 1,000,000 common shares were recorded at a price of $18.55, based
on the weighted average closing stock price of Seven Seas for the period
beginning 30 days prior to and ending 30 days subsequent to the date the letter
of intent was signed, November 22, 1996, which represented a transaction cost of
$18.6 million. Net assets acquired include $25.0 million assigned to oil and gas
properties (most of which is subject to future evaluation based on further
appraisal drilling) and other nominal net working capital. Because of the
differences in tax basis and the financial statement valuation of such acquired
oil and gas properties, $6.5 million of deferred Colombian income tax was also
recorded in this acquisition (see Notes 3 and 5) and is included in the amount
assigned to oil and gas properties.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

The Company follows U.S. generally accepted accounting principles. A
summary of the Company's significant policies is set out below:

USE OF ESTIMATES

The preparation of financial statements in conformity with generally
accepted accounting principles requires the Company to make estimates and
assumptions that affect the reported amounts of assets and liabilities, revenues
and expenses. Actual results could differ from the estimates and assumptions
used. Significant estimates include depreciation, depletion and amortization of
proved oil and gas reserves. Oil and natural gas reserve estimates, which are
the basis for depletion and the ceiling test, are inherently imprecise and
expected to change as future information becomes available.

44
47
SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONSOLIDATION

The consolidated financial statements include the accounts of the Company
and its wholly owned and majority owned subsidiaries, after eliminating all
material intercompany accounts and transactions. Certain reclassifications have
been made to prior period amounts to conform with current period financial
statement classification.

FAIR VALUE OF FINANCIAL INSTRUMENTS

The recorded amounts of cash and cash equivalents, accounts receivable and
accounts payable approximate fair value because of the short-term maturity of
those investments. The fair value of the Company's 12 1/2% $110 million Senior
Notes was $77.0 million at December 31, 1998.

INVESTMENTS

The Company has adopted Statement of Financial Accounting Standards No. 115
("SFAS 115"), "Accounting for Certain Investments in Debt and Equity
Securities." SFAS 115 requires that all investments in debt securities and
certain investments in equity securities be reported at fair value except for
those investments which management has the intent and the ability to hold to
maturity (see Note 12). Investments which are held-for-sale are classified based
on the stated maturity and management's intent to sell the securities. Changes
in fair value are reported as a separate component of stockholders' equity, but
were immaterial for all periods presented herein.

ACCOUNTS RECEIVABLE

Accounts receivable included the following at December 31, 1998 and 1997
(In thousands):

DECEMBER 31,
---------------
1997 1998
------ ------

Crude oil sales............................................. $ -- $ 291
Joint interest billing...................................... 6,456 3,013
Advances.................................................... -- 541
Other....................................................... 106 20
------ ------
Total Accounts Receivable......................... $6,562 $3,865
====== ======

INVENTORY

Inventories consist primarily of goods used in the Company's operations and
are stated at the lower of average cost or market value.

OIL AND GAS INTERESTS

The Company follows the full-cost method of accounting for oil and natural
gas properties. Under this method, all costs incurred in the acquisition,
exploration and development, including unproductive wells, are capitalized in
separate cost centers for each country. Such capitalized costs include contract
and concession acquisition, geological, geophysical and other exploration work,
drilling, completing and equipping oil and gas wells, constructing production
facilities and pipelines, and other related costs. As of December 31, 1996
unevaluated oil and gas interests include capitalized employee costs related to
exploration and property evaluation of $0.1 million. No additional general and
administrative costs were capitalized during 1998 nor 1997. The Company
capitalized interest of $9.8 million and $0.6 million in 1998 and 1997,
respectively.

45
48
SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The capitalized costs of oil and gas properties in each cost center are
amortized on composite units of production method based on future gross revenues
from proved reserves. Sales or other dispositions of oil and gas properties are
normally accounted for as adjustments of capitalized costs. Gain or loss is not
recognized in income unless a significant portion of a cost center's reserves is
involved. Capitalized costs associated with the acquisition and evaluation of
unproved 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. If the net capitalized costs of oil and gas
properties in a cost center exceed an amount equal to the sum of the present
value of estimated future net revenues from proved oil and gas reserves in the
cost center and the lower of cost or fair value of properties not being
amortized, both adjusted for income tax effects, such excess is charged to
expense. At December 31, 1998, the Company recognized a non-cash write-down of
oil and gas properties in the amount of $129.8 million pre-tax or $84.4 million
after tax pursuant to this ceiling limitation required by the full cost method
of accounting for oil and gas properties. The write-down was primarily the
result of the decline in crude oil prices and the impairment of unevaluated
properties due primarily to the failure of four non-commercial exploratory
wells.

Since the Company has only produced test quantities of oil, a provision for
depletion has not been made.

Substantially all the Company's exploration and production activities are
conducted jointly with others and the accounts reflect only the Company's
proportionate interest in such activities.

FOREIGN CURRENCY TRANSLATION

The Company's foreign operations are a direct and integral extension of the
parent company's operations and the majority of all costs associated with
foreign operations are paid in U.S. dollars as opposed to the local currency of
the operations; therefore, the reporting and functional currency is the U.S.
dollar. Gains and losses from foreign currency transactions are recognized in
current net income. Monetary items are translated using the exchange rate in
effect at the balance sheet date; non-monetary items are translated at
historical exchange rates. Revenues and expenses are translated at the average
rates in effect on the dates they occur. No material translation gains or losses
were incurred during the periods presented.

INCOME TAXES

The Company follows the asset/liability method of accounting for income
taxes. Under this method, deferred tax assets and liabilities are recognized for
the future tax consequences of (i) temporary differences between the tax bases
of assets and liabilities and their reported amounts in the financial statements
and (ii) operating loss and tax credit carryforwards for tax purposes. Deferred
tax assets are reduced by a valuation allowance when, based upon management's
estimates, it is more likely than not that a portion of the deferred tax assets
will not be realized in a future period.

FIXED ASSETS

Fixed assets are recorded at cost. Depreciation is provided on a
straight-line basis over three to five years.

ORGANIZATION COSTS

Organization costs represent the cost of incorporating the Company. In
association with the amalgamation agreement with Rusty Lake Resources Ltd.,
organization costs of $87,000 were recorded to reflect the excess purchase price
of Seven Seas common shares provided to Rusty Lake Resources Ltd. Stockholders
over and above the net asset value of Rusty Lake Resources Ltd. As of June 29,
1995. Organization costs were amortized on a straight-line basis over two years.

46
49
SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

EARNINGS PER SHARE

The Company has implemented Financial Accounting Standards Board Statement
of Financial Accounting Standards No. 128 ("SFAS 128"), "Earnings per Share."
SFAS 128 establishes standards for computing and presenting earnings per share
("EPS"). This statement simplifies the standards for computing and presenting
EPS previously found in Accounting Principles Board Opinion No. 15, "Earnings
Per Share," and makes them comparable to international EPS standards. SFAS 128
was adopted for the year ended December 31, 1997; however, the Company's
adoption of this statement and the restatement of EPS data did not have a
significant effect since the exercise or conversion of any potential shares
would be antidilutive and result in a lower loss per share. Options to purchase
3,481,167 common shares at a weighted average option exercise price of $13.69
per common share were outstanding at December 31, 1998.

All shares issued in connection with the conversion of preferred shares and
special warrants issued during 1996 were not considered outstanding until
registration with the Canadian Securities Commissions occurred on February 7,
1997, including the shares held in escrow for the former shareholders of GHK
Company Colombia, Esmeralda LLC and Cimarrona LLC. The common shares held in
escrow were considered in the weighted average shares outstanding since they are
considered outstanding by the transfer agent and have voting rights.

NEW ACCOUNTING PRONOUNCEMENTS

In June 1997, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 130, "Reporting
Comprehensive Income." This statement requires the reporting of comprehensive
income which includes net income plus all other changes in equity during the
period not reflected in net income, such as the impact of foreign currency
translation. This statement is effective for the fiscal year ended December 31,
1998. There were no material items of other comprehensive income for all periods
presented.

The FASB has also issued SFAS 131 "Disclosures about Segments of an
Enterprise and Related Information." This statement requires the reporting of
expanded information of a company's operating segments and expands the
definition of what constitutes an entity's operating segments. This statement is
effective for the year ended December 31, 1998. This statement did not have an
impact on the Company's disclosure as Seven Seas has only one operating segment.

4. CASH AND CASH EQUIVALENTS (IN THOUSANDS):

The following table sets forth the Company's cash and cash equivalents. The
Company considers highly liquid investments with a maturity of three months or
less as cash equivalents.

DECEMBER 31,
-----------------
1998 1997
------- -------

Cash........................................................ $ 234 $ 2,157
Cash equivalents............................................ 37,913 15,910
------- -------
Total cash and cash equivalents............................. $38,147 $18,067
======= =======

47
50
SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

5. INCOME TAXES:

The geographical sources of loss before income taxes and minority interest
were as follows (In thousands):

YEAR ENDED DECEMBER 31,
-----------------------------
1998 1997 1996
--------- ------- -------

United States......................................... $ (3,246) $(4,515) $ (277)
Foreign............................................... (133,449) (3,707) (1,982)
--------- ------- -------
Loss before income taxes and minority interest........ $(136,695) $(8,222) $(2,259)
========= ======= =======

Deferred U.S. and Colombian income taxes have been provided for the
book-tax basis differences related to the Colombian acquisitions discussed in
Note 2. These foreign subsidiaries' cumulative undistributed earnings are
considered to be indefinitely reinvested outside of Canada and, accordingly, no
Canadian deferred income taxes have been provided thereon.

The Company's net deferred income tax liabilities consist of the following
(In thousands):

DECEMBER 31,
-------------------
1998 1997
-------- --------

Deferred Tax Liabilities.................................... $(25,033) $(70,459)
Deferred Tax Asset.......................................... 3,364 3,128
Valuation Allowance......................................... (3,063) (3,128)
-------- --------
Total Deferred Tax................................ $(24,732) $(70,459)
======== ========

The Company did not record any current or deferred income tax provision or
benefit for 1997 and 1996. The Company's provision for income taxes differs from
the amount computed by applying statutory rates, which are 45% in Canada and 35%
in the United States and Colombia, due principally to the valuation allowance
recorded against its deferred tax asset account relating primarily to net
operating tax loss carryforwards. In 1998, the Company released the valuation
allowance attributable to US net operating loss carryforwards, resulting in a
deferred tax benefit of $0.3 million, net of current US tax expense of $8,700
and a reduction in deferred tax liabilities of $45.4 million was recognized
relating to the Company's write-down of oil and gas properties.

Temporary differences included in the deferred tax liabilities relate
primarily to excess of book over tax basis on acquired oil and gas properties.
During 1997, deferred Colombian income tax in the amount of $6.5 million was
recorded in the acquisition of Petrolinson, S.A., as described in Note 2.
Deferred tax assets principally consist of net operating loss carryforwards.

As of December 31, 1998, 1997 and 1996, the Company's subsidiaries had net
operating loss carryforwards in various foreign jurisdictions (primarily Canada)
of approximately $3.9 million, $3.7 million and $2.2 million, respectively.
These loss carryforwards will expire beginning in 2002 if not utilized to reduce
Canadian income taxes. In addition, the Company had at December 31, 1998, 1997
and 1996 approximately $2.0 million, $1.5 million and $37,000, respectively, of
U.S. tax net operating loss carryforwards expiring in varying amounts beginning
in 2011. A valuation allowance has been provided for the Canadian deferred tax
assets resulting primarily from these loss carryforwards because their future
realization is not currently deemed probable by management. Management currently
believes that it is more likely than not that the US operating loss carryforward
will be realized in future periods.

48
51
SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

6. LONG-TERM DEBT:

Exchangeable Notes. In August 1997, the Company issued $25 million of
Exchangeable Notes in a private transaction with institutional and accredited
investors. The Exchangeable Notes accrued interest at a rate of 6% per annum and
were payable on December 31 and June 30 in each year, commencing December 31,
1997. The Exchangeable Notes were scheduled to mature on August 7, 2003.

The Exchangeable Notes were exchanged for a like principal amount of
Convertible Debentures on August 5, 1998. The Convertible Debentures were
converted on August 6, 1998 into Units consisting of a total of 2,173,901 common
shares and warrants exercisable for 1,086,957 common shares. Each warrant is
exercisable for one common share at an exercise price of $15 and will expire on
the earlier of (I) the date that is 30 calendar days following a 20-day period
during which the weighted average trading price for the common shares of the
Company on the Toronto Stock Exchange exceeds US$17.64 or (ii) February 5, 1999.

Senior Notes. The Company issued $110 million aggregate principal amount of
12 1/2% Senior Notes due 2005 (the "Senior Notes") in a private transaction on
May 7, 1998 that was not subject to registration requirements of the Securities
Act of 1933. The Senior Notes mature on May 15, 2005. Interest on the Senior
Notes will be payable semi-annually in arrears on May 15 and November 15,
commencing November 15, 1998 to holders of record on the immediately preceding
May 1 and November 1. The Senior Notes place restrictions on, among other
things, net working capital balances, dividend distributions, changes in
control, and asset sales.

The Senior Notes represent senior obligations of the Company, ranking pari
passu in right and priority of payment with all existing and future senior
indebtedness and senior in right and priority of payment to all indebtedness
that is expressly subordinated to the Senior Notes.

In accordance with the terms of the Senior Notes, the Company purchased
$13.5 million in U.S. Government Securities from the proceeds of the Senior
Notes and deposited such securities in a segregated account in an amount that
will be sufficient to provide for payment of the first two scheduled interest
payments (see Note 12). Additionally, the Company purchased and pledged to the
Bank of Nova Scotia Trust Company New York, the Trustee, as security for the
benefit of the holders of the Senior Notes, U.S. Government Securities of $25
million that will be sufficient to provide payment of the four scheduled
interest payments on the Notes from November 15, 1999 through May 15, 2001. Such
securities are classified as restricted short-term investments and restricted
long-term investments (see Note 12).

7. EQUITY:

On March 15, 1996, a brokered private placement was carried out in Canada
in which the Company issued to a third party financial brokerage institution
2,000,000 special warrants at $2.75 per warrant for net offering proceeds after
commissions and expenses of $5.1 million. Each special warrant was convertible
into one unit. Each unit consisted of one share of common stock and a one-half
common share purchase warrant at $3.50 per full share. The warrants were
convertible at the earlier of (a) one year from date of issuance or (b) the date
an approval is issued for a prospectus qualifying the conversion in the
appropriate jurisdictions. On March 14, 1997, the 1,000,000 common share
purchase warrants were exercised and converted to common shares for net proceeds
of $3.5 million.

On October 16, 1996, another brokered private placement was carried out in
Canada. Seven Seas issued to a third party financial brokerage institution
500,000 special warrants at $15.00 per warrant for a net offering after
commissions and expenses of $7.0 million. Each special warrant was convertible
into one Unit (see Note 6). Each Unit consisted of one share of common stock and
a one-half common share purchase warrant at $18.50 per full share. The warrants
were convertible at the earlier of (a) one year from date of issuance or

49
52
SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(b) the date an approval is issued for a prospectus qualifying the conversion in
the appropriate jurisdictions. The 250,000 common share purchase warrants were
not exercised and expired October 16, 1997.

An approval for qualification of the conversion of the 2,000,000 and
500,000 special warrants issued in the brokered private placements on March 15
and October 16, 1996, respectively, was received on February 7, 1997 by the
Ontario, Alberta, and British Columbia Securities Commissions. All special
warrants were exercised and have been converted to common shares.

The proceeds of the brokered private placements on March 15 and October 16,
1996 were used for drilling, seismic and production facilities related to the
Company's participation in the Association Contracts and for further exploration
activities.

8. STOCK BASED COMPENSATION PLANS:

Officers, directors and employees have been granted stock options under the
Company's Amended 1996 Stock Option Plan and the 1997 Stock Option Plan
(collectively referred to as "the Plans"). Pursuant to the Plans, 6,000,000
shares were authorized for issuance, of which 3,481,167 were outstanding as of
December 31, 1998. Options granted under the 1997 Stock Option Plan have been
granted with either no vesting requirement or vesting cumulatively on the
anniversary of the grant date over a period of two to five years and expire ten
years from the date of grant. Option agreements between the Company and
optionees under the 1997 Stock Option Plan may include stock appreciation
rights; however, no such rights are currently outstanding. Under each plan, the
option price equals the stock's market price on the date of grant.

The Compensation Committee of the Board of Directors is responsible for
administering the plans, determining the terms upon which options may be
granted, prescribing, amending and rescinding such interpretations and
determinations and granting options to employees, directors, and officers.

The following table presents a summary of stock option transactions for the
three years ended December 31, 1998:

WEIGHTED AVERAGE
COMMON OPTION PRICE
SHARES PER SHARE
--------- ----------------

December 31, 1995......................................... 985,000 .75
Granted................................................... 805,000 12.86
Exercised................................................. (625,333) .85
--------- ------
December 31, 1996......................................... 1,164,667 9.07
Granted................................................... 3,197,500 13.56
Exercised................................................. (478,667) 3.05
Revoked................................................... (5,000) 12.25
--------- ------
December 31, 1997......................................... 3,878,500 13.51
Granted................................................... 820,500 13.97
Exercised................................................. (514,000) 8.02
Revoked................................................... (703,833) 17.13
--------- ------
December 31, 1998......................................... 3,481,167 $13.69
========= ======

50
53
SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Exercisable stock options amounted to 1,718,829; 1,697,665; and 764,667 at
December 31, 1998, 1997, and 1996, respectively. The weighted average fair value
of options granted during 1998, 1997, and 1996 were $8.77; $7.68; and $4.65,
respectively. The following table summarizes stock options outstanding and
exercisable at December 31, 1998:

WEIGHTED WEIGHTED
EXERCISE PRICE AVERAGE AVERAGE AVERAGE
RANGE SHARES LIFE EXERCISE PRICE SHARES EXERCISE PRICE
- ----------------------------------------------- --------- ------- -------------- --------- --------------

$.75........................................... 3,000 1.4 $ .75 3,000 $ .75
7.13........................................... 5,000 2.6 7.13 5,000 7.13
8.06-8.63...................................... 185,000 9.8 8.47 -- --
9.00-9.56...................................... 342,500 9.7 9.01 26,667 9.04
10.70-10.90.................................... 1,004,000 8.5 10.70 695,666 10.70
12.25-14.09.................................... 758,000 8.7 13.20 329,500 13.17
18.23-18.75.................................... 1,138,667 7.4 18.59 590,662 18.62
22.94-23.88.................................... 45,000 9.3 23.67 68,334 23.88
--------- --- ------ --------- ------
3,481,167 1,718,829
--------- ---------

As part of the arrangements surrounding the resignations of four former
officers, the exercise period of the options granted during their employment was
extended from ninety days to eighteen months. This action gave rise to a new
measurement date and the Company was required to record compensation expense of
$2.1 million during 1997, representing the market value of the common shares on
the new measurement date less the exercise price of the options granted. Only
the exercisable options granted to the former Chairman, former President, former
Chief Financial Officer, and former Vice President of Exploration were
considered in the computation.

In accordance with the provisions of Statement of Financial Accounting
Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"), the
Company applies APB Opinion 25 in accounting for its stock option plan, and
accordingly does not recognize compensation cost at fair value as it relates to
SFAS 123.

If the Company had elected to recognize compensation cost based on the fair
value of the options granted at the grant date as prescribed by SFAS 123, net
loss and net loss per share would have increased to the proforma amounts shown
below:

DECEMBER 31,
-----------------------------
1998 1997 1996
-------- -------- -------

Pro Forma Net Loss (In thousands)........................... $(97,393) $(32,427) $(5,938)
Pro Forma Net Loss Per Share................................ $ (2.69) $ (1.00) $ (.46)

The effects of applying SFAS 123 in this proforma are not indicative of
future amounts.

The fair value of each option grant is estimated on the date of grant using
the Black-Scholes option pricing model with the following assumptions used for
grants during the year ended December 31, 1998: weighted average risk free
interest rate of 5.50 percent; no dividend yield; volatility of .4153; and
expected life of ten years. The Company granted options prior to public trading
on the Canadian Dealer Network on June 30, 1995. Consequently, the underlying
common shares had no historic volatility prior to June 30, 1995. The fair values
of the options granted prior to June 30, 1995 were based on the difference
between the present value of the exercise price of the option and the estimated
fair value price of the common shares.

51
54
SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

9. OPERATIONS BY GEOGRAPHIC AREA:

The Company has one operating and reporting segment. Information about the
Company's operations for 1998, 1997, and 1996 by geographic area is shown below
(In thousands):

OTHER
UNITED FOREIGN
CANADA STATES COLOMBIA AREAS TOTAL
------ ------- --------- ------- ---------

Year ended December 31, 1998
Revenues.......................... $3,626 $ 12 $ 159 $ -- $ 3,797
Operating Income (Loss)........... (2,714) 3,348 (137,761) 432 (136,695)
Capital Expenditures.............. -- 997 43,568 115 44,680
Identifiable Assets............... 91,067 1,430 186,902 501 279,900
Depreciation and Amortization..... 485 140 49 -- 674
Year ended December 31, 1997
Revenues.......................... $ 754 $ 2 $ 810 $ 1 $ 1,567
Operating Income (Loss)........... (1,781) (4,515) (1,838) (88) (8,222)
Capital Expenditures.............. -- 58 19,050 471 19,579
Identifiable Assets............... 17,462 488 272,982 982 291,914
Depreciation and Amortization..... 111 21 16 -- 148
Year ended December 31, 1996
Revenues.......................... $ 334 $ -- $ 239 $ 2 $ 575
Operating Income (Loss)........... (1,402) (278) (439) (140) (2,259)
Capital Expenditures.............. -- -- 4,335 272 4,607
Identifiable Assets............... 10,497 47 224,437 520 235,501
Depreciation and.................. -- 66 43 2 111
Amortization

10. COMMITMENTS AND CONTINGENCIES:

The Company leases property and equipment under various operating leases.
Aggregate minimum lease payments under existing contracts as of December 31,
1998, are as follows: $0.3 million for 1999; $0.3 million for 2000; $0.3 million
for 2001; $0.3 million for 2002; $0.1 million for 2003 and none thereafter.
Rental expense amounted to $0.2 million in 1998; $0.1 million in 1997; $0.1
million in 1996.

The Company has certain related commitments under existing oil and gas
exploration concession agreements. Management estimates future expenditures for
such commitments to be approximately $5.3 million in 1999; $30,000 in 2000; and
$30,000 in 2001, and none thereafter.

The Company is, from time to time, party to certain legal actions and
claims arising in the ordinary course of business. While the outcome of these
events cannot be predicted with certainty, management does not expect these
matters to have a material adverse effect on the financial position or results
of operations or cash flows of the Company.

The Ministry of Environment by resolution has decided to open a list of
charges against GHK Company Columbia based on alleged environmental damages,
originating from the location that has been constructed for the proposed El
Segundo 7-E well. The Company has experienced difficulty trying to stabilize the
slopes of this location, and as a result, sediments from the location were
entering a creek. At this time, remediation efforts are underway and should be
completed soon. The Company has been notified that it will likely be assessed a
fine for the alleged environmental damages at the El Segundo 7-E location. The
Company believes that the amount accrued will be sufficient to cover remediation
costs and potential fines assessed as a result of El Segundo 7-E operations.
52
55
SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The Dindal Association Contract was issued in March 1993 and provides for a
maximum six-year exploration period followed by a maximum 22-year production
period, with partial relinquishment of acreage, excluding commercial fields,
required commencing at the end of the sixth year of the Association Contract.
The exploration period had previously been extended and, unless further extended
by Ecopetrol, the exploration period under the Dindal Association Contract will
expire in September 1999, at which time the Company must relinquish 50% of the
contract area or all lands that fall outside a five kilometer buffer zone around
the area designated to be the commercial field. The Company has requested an
extension of the exploration period.

11. RELATED PARTY TRANSACTIONS:

On November 1, 1997, the Executive Vice President and Chief Operating
Officer obtained a $200,000 loan from the Company. This loan bears a 6.06%
interest rate and is due November 1, 2002. The Company recognized interest
income of $12,000 and $2,000 in 1998 and 1997, respectively.

The Company's Chairman and Chief Executive Officer, Mr. Robert A. Hefner
III, beneficially owns 100% of The GHK Company LLC ("GHK"). Effective July 1,
1997, the Company has entered into an administrative service agreement with GHK.
The Company recognized $28,000 and $10,500 of such expenses in 1998 and 1997,
respectively. In addition, GHK pays certain miscellaneous costs incurred on
behalf of the Company. The Company reimbursed GHK $0.1 million, $0.4 million and
$0.3 million in 1998, 1997 and 1996, respectively, for such costs. Mr. Hefner,
owns 100% of the shares of The GHK Corporation ("GHK Corp."). GHK Corp. owns an
executive aircraft, which Mr. Hefner and other Seven Seas executives and
employees use for certain business travel. The Company has entered into an
agreement with GHK Corp. whereby the Company pays GHK Corp. the lesser of the
cost of a first class airline ticket or the total actual expenses for each
specific flight. The Company had $31,000 in expenditures for such air travel
during 1998.

MTV Investments Limited Partnership ("MTV") owns 37.037 percent of
Cimarrona LLC ("Cimarrona"), an Oklahoma company; Cimarrona is a consolidated
subsidiary of the Company. Resulting from cash calls, MTV owed $0.5 million to
the Company at December 31, 1997.

53
56
SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

12. INVESTMENTS AND RESTRICTED INVESTMENTS:

At December 31, 1998, all the Company's investments were classified as
held-to-maturity. These securities include both securities maturing within one
year and securities maturing beyond one year. The securities with a maturity
date within one year are classified as short-term investments as part of Current
Assets and are stated at amortized cost. The securities with maturity dates
beyond one year are included in Non-Current Assets classified as long-term
held-to-maturity investments and are stated at amortized cost. The calculation
of gross unrealized gain (loss) for the year ended December 31, 1998 was as
follows (In thousands):

GAIN
UNREALIZED
AMORTIZED GAIN
FAIR VALUE COST (LOSS)
---------- --------- ----------

SHORT-TERM INVESTMENTS
Goldman Sachs Group, face value of $3,500,000, due April 23,
1999...................................................... $ 3,423 $ 3,445 $(22)
National Rural Utilities, face value of 3,000,000, due April
23, 1999.................................................. 2,945 2,954 (9)
------- ------- ----
Total Short-term investments...................... $ 6,368 $ 6,399 $(31)
======= ======= ====
RESTRICTED SHORT-TERM INVESTMENTS
U.S. Treasury Note, face value of $6,663,000, interest at
6.375%, due April 30, 1999................................ $ 6,701 $ 6,681 $ 20
U.S. Treasury Strip, face value of $6,875,000, due
November 15, 1999...................................... 6,606 6,563 43
------- ------- ----
Total Restricted short-term investments........... $13,307 $13,244 $ 63
======= ======= ====
RESTRICTED LONG-TERM INVESTMENTS
U.S. Treasury Strip, face value of $6,875,000, due May 15,
2000...................................................... $ 6,457 $ 6,389 $ 68
U.S. Treasury Strip, face value of $6,875,000, due November
15, 2000.................................................. 6,312 6,219 93
U.S. Treasury Strip, face value of $6,875,000, due May 15,
2001...................................................... 6,166 6,050 116
------- ------- ----
Total Long-term held-to-maturity investments...... $18,935 $18,658 $277
======= ======= ====

Net unrealized gains (losses) on held-to-maturity securities have not been
recognized in the accompanying consolidated financial statements. The restricted
investments have been pledged or placed in escrow for the first three years of
interest payments on the $110 million 12 1/2% Senior Notes (see Note 6).

13. SUBSEQUENT EVENT:

On February 5, 1999, purchase warrants for 1.1 million common shares of
Seven Seas Petroleum Inc. expired without exercise. These purchase warrants had
been issued in association with the exchange and conversion of the Company's
previously outstanding $25 million issue of 6% Exchangeable Notes.

54
57
SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED):

Capitalized costs at December 31, 1998 and 1997, respectively, relating to
the Company's oil and gas activities are shown below (In thousands):

COLOMBIA OTHERS TOTAL
-------- ------ --------

As of December 31, 1998
Proved properties..................................... $ 74,993 $ -- $ 74,993
======== ==== ========
Unproved properties, net.............................. $112,655 $461 $113,116
======== ==== ========
As of December 31, 1997
Proved properties..................................... $ 46,117 $ -- $ 46,117
======== ==== ========
Unproved properties, net.............................. $220,771 $942 $221,713
======== ==== ========

Costs incurred during the years ended December 31, 1998, 1997, and 1996,
respectively, were as follows (In thousands):

COLOMBIA OTHERS TOTAL
-------- ------ --------

Year ended December 31, 1998
Development cost........................................ $ -- $ -- $ --
Property acquisition cost:
Proved................................................ -- -- --
Unproved.............................................. 160 -- 160
Exploration cost........................................ 50,387 115 50,502
-------- ---- --------
Total cost incurred........................... $ 50,547 $115 $ 50,662
======== ==== ========
Year ended December 31, 1997
Development cost........................................ $ 166 $ -- $ 166
Property acquisition cost:
Proved................................................ 4,331 -- 4,331
Unproved.............................................. 20,705 -- 20,705
Exploration cost........................................ 18,662 471 19,133
-------- ---- --------
Total cost incurred........................... $ 43,864 $471 $ 44,335
======== ==== ========
Year ended December 31, 1996
Property acquisition cost:
Proved................................................ $ 1,554 $ -- $ 1,554
Unproved.............................................. 215,536 250 215,786
Exploration cost........................................ 5,565 21 5,586
-------- ---- --------
Total cost incurred........................... $222,655 $271 $222,926
======== ==== ========

As of December 31, 1998, the Company has not made a provision for
depletion. The Company has produced only insignificant amounts of oil under its
production-testing plan. At such time that the Company completes its evaluation
of the Association Contracts and if a significant level of production of proved
reserves occurs, the currently excluded oil and gas properties will be included
in the amortization base. The Company anticipates completion of its evaluation
of the Association Contracts mid-year 1999 and will commence development
immediately if the evaluation proves successful and Ecopetrol approves the
Company's commerciality application.

55
58
SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The Company had oil and gas sales of $.02 million, $0.8 million and $0.3
million in 1998, 1997 and 1996, respectively, pertaining to production testing
of the exploratory wells on the Association Contracts in Colombia.

EXPLORATION COSTS

The Company has been involved in exploration activities in Colombia,
Australia, Argentina, Turkey and Papua New Guinea. Also, the Company purchased
an option for the right to participate in future exploration activities in North
Africa, but the option was never exercised. Additionally, the Company acquired
oil and gas properties in Colombia totaling $.1 million, $25.0 million and
$217.1 million in 1998, 1997 and 1996, respectively. Capitalized acquisition
costs incurred during 1998, 1997 and 1996 include zero, $6.5 million and $64.0
million, respectively, of deferred income tax as disclosed in Note 2, Business
Combination.

On May 16, 1995, the Company entered into an agreement whereby Seven Seas
purchased an option for $0.5 million to acquire a 5 percent participating
interest in three exploration blocks in North Africa upon completion of the
first exploration well drilled. The first exploration well was completed as a
dry hole in July 1995. After careful review, Seven Seas decided not to exercise
its option. The cost of the option, $0.5 million, plus additional costs incurred
toward purchasing this option was originally recorded as unproved oil and gas
interests and was subsequently expensed.

Ecopetrol has the right to back into Seven Seas' participating interest in
the Colombian Association Contracts upon its approval of the Company's
declaration of commerciality at an initial 50 percent participating interest.
Ecopetrol's interest can increase based upon accumulated production levels and
net income. Ecopetrol will, at the time of commerciality, bear 50 percent of the
future development costs in the field and reimburse the other parties in these
Dindal and Rio Seco blocks for 50 percent of certain previously incurred costs
associated with successful wells in both blocks and for other direct exploration
costs in the Rio Seco block only.

PROVED RESERVES (UNAUDITED)

Proved reserves represent estimated quantities of crude oil which
geological and engineering data demonstrate to be reasonably recoverable in the
future from known reservoirs under existing economic and operating conditions.
Estimates of proved developed oil reserves are subject to numerous uncertainties
inherent in the process of developing the estimates including the estimation of
the reserve quantities and estimated future rates of production and timing of
development expenditures. The accuracy of any reserve estimate is a function of
the quantity and quality of available data and of engineering and geological
interpretation and judgement.

Results of drilling, testing and production subsequent to the date of the
estimate may justify revision of such estimate. Additionally, the estimated
volumes to be commercially recoverable may fluctuate with changes in the price
of oil. Estimates of proved reserves have been determined using the most
economic development strategy; however, the Company is currently in the
development stage and has several critical steps to realize such commercial
economic production (see Note 1).

Estimates of future recoverable oil reserves and projected future net
revenues for all periods presented were provided by Ryder Scott Company
Petroleum Engineers. The Company's proved reserves were comprised entirely of
crude oil in Colombia.

56
59
SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Proved developed and undeveloped reserves (barrels):

1998 1997 1996
---------- ---------- -------

Beginning of year........................................... 32,160,245 818,000 --
Extensions and discoveries.................................. -- -- 818,000
Revision of estimate........................................ 6,558,990 31,342,245 --
---------- ---------- -------
End of year................................................. 38,719,235 32,160,245 818,000
========== ========== =======
Proved developed............................................ 20,238,430 11,494,236 408,000
========== ========== =======

The following table presents the standardized measure of discounted future
net cash flows relating to proved oil reserves. Future cash inflows and costs
were computed using prices and costs in effect at the end of the year without
escalation less a gravity and transportation adjustment of $4.50 to reference
prices. The reference price for the year ended December 31, 1998 was West Texas
Intermediate $12.05 per barrel. Future income taxes were computed by applying
the appropriate statutory income tax rate to the pretax future net cash flows
reduced by future tax deductions and net operating loss carryforwards.

Standardized Measure of Discounted Future Net Cash Flows (In thousands):

1998 1997 1996
-------- -------- -------

Future cash inflows......................................... $292,292 $326,427 $12,520
Future costs
Production................................................ 32,543 50,987 2,112
Development............................................... 33,574 33,740 1,939
-------- -------- -------
Future net cash flows before income taxes................... 226,175 241,700 8,469
Future income taxes......................................... 64,632 78,141 4,027
-------- -------- -------
Future net cash flows....................................... 161,543 163,559 4,442
10% discount factor......................................... 71,693 62,942 641
-------- -------- -------
Standardized measure of discounted future net cash flows.... $ 89,850 $100,617 $ 3,801
======== ======== =======

Principal sources of changes in the standardized measure of discounted
future net cash flows during 1998 and 1997 (In thousands):

1998 1997
-------- --------

Beginning of year........................................... $100,617 $ 3,801
Net change in price and production costs.................... (35,777) (1,741)
Extensions, discoveries, and additions, less related
costs..................................................... -- 141,402
Revision of quantity estimates.............................. 26,373 --
Net change in future development costs...................... 147 (1,612)
Net change in income taxes.................................. 18,221 (41,969)
Accretion of discount....................................... 14,486 736
Changes in production rates and other....................... (34,217) --
-------- --------
End of year................................................. $ 89,850 $100,617
======== ========

The standardized measure of discounted future net cash flows shown above
relates to the Company's discovery of oil on the Association Contracts in
Colombia.

57
60
SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The standardized measure of discounted future net cash flows does not
purport to present the fair market value of the Company's proved reserves. An
estimate of fair value would also take into account, among other things, the
recovery of reserves in excess of proved reserves, anticipated future changes in
prices and costs and a discount factor more representative of the time value of
money and the risks inherent in reserve estimates.

SUPPLEMENTARY FINANCIAL INFORMATION

Selected Quarterly Data. Results of development stage operations by quarter
for the years ended December 31, 1998, and 1997 were (in thousands, except per
share amounts):

1998 QUARTER ENDED
-----------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- ------- ------------ -----------

Operating revenues........................................ $ 184 $ 1,050 $ 1,431 $ 1,132
Less costs and expenses................................... 1,362 1,912 3,128 134,090
------- ------- ------- ---------
(1,178) (862) (1,697) (132,958)
Net loss.................................................. $(1,115) $ (752) $(1,602) $ (87,508)
======= ======= ======= =========
Net loss per share........................................ $ (0.03) $ (0.02) $ (0.04) $ (2.40)
======= ======= ======= =========

1997 QUARTER ENDED
-----------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- ------- ------------ -----------

Operating revenues........................................ $ 434 $ 237 $ 308 $ 588
Less costs and expense.................................... 1,194 2,408 1,340 4,847
------- ------- -------- ---------
(760) (2,171) (1,032) (4,259)
Net loss.................................................. $ (722) $(2,137) $ (972) $ (4,097)
======= ======= ======== =========
Net loss per share........................................ $ (.03) $ (.06) $ (.03) $ (.12)
======= ======= ======== =========

58
61

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

None

PART III

ITEM 10. DIRECTORS AND OFFICERS OF THE REGISTRANT

ITEM 11. EXECUTIVE COMPENSATION

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

For the information called for by Items 10 through 13 reference is made to
the Company's Proxy Statement for its 1999 annual meeting of shareholders, which
will be filed with the Securities and Exchange Commission within 120 days after
December 31, 1998 and which is incorporated herein by reference.

PART IV

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

(a) Financial Statements and Schedules:

(1) Financial Statements: The financial statements required to be filed are
included under Item 8 of this report.

(2) Schedules: All schedules for which provision is made in applicable
accounting regulations of the SEC have been omitted as the schedules are either
not required under the related instructions, are not applicable or the
information required thereby is set forth in the Company's Consolidated
Financial Statements or the Notes thereto.

(3) Exhibits:

The following instruments and documents are included as Exhibits to this
document. Exhibits incorporated by reference are so indicated by parenthetical
information.

EXHIBIT
NUMBER EXHIBIT DOCUMENT
------- ----------------

59
62

EXHIBIT
NUMBER EXHIBIT DOCUMENT
------- ----------------

*(B) -- The Association Contract by and between Ecopetrol, GHK
Company Colombia and Petrolinson, S.A. relating to the
Dindal block, as amended
*(C) -- The Association Contract by and between Ecopetrol and GHK
Company Colombia relating to the Rio Seco block
*(D) -- Joint Operating Agreement dated as of August 1, 1994 by
and between GHK Company Colombia and the holders of
interests in the Dindal block
*(E) -- The GHK Company Colombia Share Purchase Agreement dated
as of July 26, 1996 by and between Robert A. Hefner III,
Seven Seas Petroleum Colombia Inc. and the Company
*(F) -- The Cimarrona Purchase Agreement dated as of July 26,
1996 by and between the members of Cimarrona Limited
Liability Company, the Company, Seven Seas Petroleum
Colombia Inc., and Robert A. Hefner III
*(G) -- The Esmeralda Purchase Agreement dated as of July 26,
1996 by and between the members of Esmeralda Limited
Liability Company, Robert A. Hefner III, the Company,
Seven Seas Petroleum Holdings, Inc. and Seven Seas
Petroleum Colombia Inc.
*(H) -- The Registration Rights Agreement dated as of July 26,
1996 by and between the Company and certain individuals
*(I) -- Shareholders' Voting Support Agreement dated as of July
26, 1996 by and between Seven Seas Petroleum Inc. and
Messrs. Hefner, Kerr, Whitehead, Plewes and Stephens
*(J) -- Management Services Agreement by and among GHK Company
Colombia, the Company and The GHK Company LLC
*(K) -- The Escrow Agreement for a Natural Resources Company by
and among Montreal Trust Company as trustee, the Company
and certain individuals and entities
*(L) -- The Escrow Agreement for a Natural Resources Company by
and among Montreal Trust Company, as trustee, the Company
and Albert E. Whitehead
*(M) -- Amended 1996 Stock Option Plan
*(N) -- Form of Incentive Stock Option Agreement
*(O) -- Form of Directors' Stock Option Agreement
*(P) -- Form of Employment Agreement between the Company and each
of Messrs. Stephens, Dorrier and DeCort *(Q)
*(R) -- Form of Employment Agreement between the Company and
Larry A. Ray
*(S) -- Settlement Agreement between the Company and Mr.
Whitehead dated May 20, 1997
*(T) -- Petrolinson S.A. Share Purchase Agreement dated February
14, 1997, between Hazel Ventures LTD., Seven Seas
Petroleum Colombia Inc. and Seven Seas Petroleum Inc.
*(U) -- Pledge Agreement dated March 5, 1997 among Hazel Ventures
LTD., Seven Seas Petroleum Inc., Seven Seas Petroleum
Colombia Inc., and Integro Trust (BVI Limited)
*(V) -- Shareholder Voting Support Agreement made as of March 5,
1997 between Seven Seas Petroleum Inc. and Hazel Ventures
LTD.
*(W) -- Purchase Warrant Indenture made as of August 7, 1997
between Seven Seas Petroleum Inc. and Montreal Trust
Company of Canada

60
63

EXHIBIT
NUMBER EXHIBIT DOCUMENT
------- ----------------

*(X) -- Indenture made as of August 7, 1997 between Seven Seas
Petroleum Inc. and Montreal Trust Company of Canada
*(Y) -- Limited Recourse Guarantee, Security and Pledge Agreement
made as of August 7, 1997 between Seven Seas Petroleum
Holdings Inc. and Montreal Trust Company of Canada
*(Z) -- Limited Recourse Guarantee, Security and Pledge Agreement
made as of August 7, 1997 between Seven Seas Petroleum
Colombia Inc. and Montreal Trust Company of Canada
*(AA) -- Private Placement Subscription Agreement made as of
August 7, 1997 between Seven Seas Petroleum Inc. and
Jasopt Pty Limited
*(BB) -- 1997 Stock Option Plan
(CC) -- Form of Employment Agreement between the Company and
William W Daily
*(21) -- Subsidiaries of the Registrant
(23) -- Consent of experts and counsel
+(A) -- Consent of Ryder Scott Company Petroleum Engineers
+(B) -- Consent of Arthur Andersen LLP
(27) -- Financial Data Schedule

- ---------------

+ Filed herewith.

* Incorporated herein by reference to like exhibit in Registration on Form
10 (File No. 022483).

** Incorporated herein by reference to like exhibit in registration statement
on Form S-1 filed April 24, 1998.

(b) Consolidated Financial Statement Schedules

All schedules are omitted as the required information is inapplicable or
the information is presented in the financial statements or notes thereto.

(b) Reports on Form 8-K

None

61
64

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934,
this report has been signed as of the 30 day of March, 1999 by the following
persons in their capacity as officers of the Registrant.

SEVEN SEAS PETROLEUM INC.

By: /s/ ROBERT A. HEFNER III
----------------------------------
Robert A. Hefner III
Chief Executive Officer
(Principal Executive Officer)

By:
/s/ HERBERT C. WILLIAMSON, III
----------------------------------
Herbert C. Williamson, III
Chief Financial Officer
(Principal Financial Officer)

Pursuant to the requirements of the Securities and Exchange Act of 1934,
this report has been signed as of the 30 day of March, 1999 by the following
persons in their capacity as directors of the Registrant.

/s/ ROBERT A. HEFNER III Chairman, Chief Executive Officer and
- ----------------------------------------------------- Managing Director (Principal Executive
Robert A. Hefner III Officer)

/s/ BREENE M. KERR Director
- -----------------------------------------------------
Breene M. Kerr

/s/ SIR MARK THOMSON BT. Director
- -----------------------------------------------------
Sir Mark Thomson Bt

/s/ BRIAN EGOLF Director
- -----------------------------------------------------
Brian Egolf

/s/ ROBERT B. PANERO Director
- -----------------------------------------------------
Robert B. Panero

/s/ HERBERT C. WILLIAMSON, III Director, Executive Vice President and Chief
- ----------------------------------------------------- Financial Officer (Principal Financial
Herbert C. Williamson, III Officer)

/s/ JAMES D. SCARLETT Director
- -----------------------------------------------------
James D. Scarlett

/s/ LARRY A. RAY Director, Executive Vice President and Chief
- ----------------------------------------------------- Financial Officer
Larry A. Ray

/s/ GARY F. FULLER Director
- -----------------------------------------------------
Gary F. Fuller

/s/ WILLIAM W. DAILY Director, Executive Vice President and
- ----------------------------------------------------- President of GHKCC
William W. Daily

/s/ RAY A. HOUSLEY Treasurer and Controller
- -----------------------------------------------------
Ray A. Housley

62
65

INDEX TO EXHIBITS

EXHIBIT
NUMBER EXHIBIT DOCUMENT
------- ----------------

(3) -- Articles of Incorporation and By-laws
*(A) -- The Amalgamation Agreement effective June 29, 1995 by and
between Seven Seas Petroleum Inc., a British Columbia
corporation; and Rusty Lake Resources Ltd.
*(B) -- Certificate of Continuance and Articles of Continuance
into the Yukon Territory
*(C) -- By-Laws
(4) -- Instruments defining the rights of security holders,
including indentures
*(A) -- Excerpts from the Articles of Continuance
*(B) -- Excerpts from the By-laws
*(C) -- Specimen stock certificate
*(D) -- Form of Class B Warrant
*(E) -- Class B Warrant Indenture dated as of October 15, 1996 by
and between the Company of Canada and Montreal Trust
Company
(10) -- Material Contracts
*(A) -- Agreement dated August 14, 1995 by and between the
Company and GHK Company Colombia, as amended by letter
agreement dated November 30, 1995
*(B) -- The Association Contract by and between Ecopetrol, GHK
Company Colombia and Petrolinson, S.A. relating to the
Dindal block, as amended
*(C) -- The Association Contract by and between Ecopetrol and GHK
Company Colombia relating to the Rio Seco block
*(D) -- Joint Operating Agreement dated as of August 1, 1994 by
and between GHK Company Colombia and the holders of
interests in the Dindal block
*(E) -- The GHK Company Colombia Share Purchase Agreement dated
as of July 26, 1996 by and between Robert A. Hefner III,
Seven Seas Petroleum Colombia Inc. and the Company
*(F) -- The Cimarrona Purchase Agreement dated as of July 26,
1996 by and between the members of Cimarrona Limited
Liability Company, the Company, Seven Seas Petroleum
Colombia Inc., and Robert A. Hefner III
*(G) -- The Esmeralda Purchase Agreement dated as of July 26,
1996 by and between the members of Esmeralda Limited
Liability Company, Robert A. Hefner III, the Company,
Seven Seas Petroleum Holdings, Inc. and Seven Seas
Petroleum Colombia Inc.
*(H) -- The Registration Rights Agreement dated as of July 26,
1996 by and between the Company and certain individuals
*(I) -- Shareholders' Voting Support Agreement dated as of July
26, 1996 by and between Seven Seas Petroleum Inc. and
Messrs. Hefner, Kerr, Whitehead, Plewes and Stephens
*(J) -- Management Services Agreement by and among GHK Company
Colombia, the Company and The GHK Company LLC
*(K) -- The Escrow Agreement for a Natural Resources Company by
and among Montreal Trust Company as trustee, the Company
and certain individuals and entities
*(L) -- The Escrow Agreement for a Natural Resources Company by
and among Montreal Trust Company, as trustee, the Company
and Albert E. Whitehead
*(M) -- Amended 1996 Stock Option Plan

63
66

EXHIBIT
NUMBER EXHIBIT DOCUMENT
------- ----------------

*(N) -- Form of Incentive Stock Option Agreement
*(O) -- Form of Directors' Stock Option Agreement
*(P) -- Form of Employment Agreement between the Company and each
of Messrs. Stephens, Dorrier and DeCort *(Q)
*(R) -- Form of Employment Agreement between the Company and
Larry A. Ray
*(S) -- Settlement Agreement between the Company and Mr.
Whitehead dated May 20, 1997
*(T) -- Petrolinson S.A. Share Purchase Agreement dated February
14, 1997, between Hazel Ventures LTD., Seven Seas
Petroleum Colombia Inc. and Seven Seas Petroleum Inc.
*(U) -- Pledge Agreement dated March 5, 1997 among Hazel Ventures
LTD., Seven Seas Petroleum Inc., Seven Seas Petroleum
Colombia Inc., and Integro Trust (BVI Limited)
*(V) -- Shareholder Voting Support Agreement made as of March 5,
1997 between Seven Seas Petroleum Inc. and Hazel Ventures
LTD.
*(W) -- Purchase Warrant Indenture made as of August 7, 1997
between Seven Seas Petroleum Inc. and Montreal Trust
Company of Canada
*(X) -- Indenture made as of August 7, 1997 between Seven Seas
Petroleum Inc. and Montreal Trust Company of Canada
*(Y) -- Limited Recourse Guarantee, Security and Pledge Agreement
made as of August 7, 1997 between Seven Seas Petroleum
Holdings Inc. and Montreal Trust Company of Canada
*(Z) -- Limited Recourse Guarantee, Security and Pledge Agreement
made as of August 7, 1997 between Seven Seas Petroleum
Colombia Inc. and Montreal Trust Company of Canada
*(AA) -- Private Placement Subscription Agreement made as of
August 7, 1997 between Seven Seas Petroleum Inc. and
Jasopt Pty Limited
*(BB) -- 1997 Stock Option Plan
(CC) -- Form of Employment Agreement between the Company and
William W Daily
*(21) -- Subsidiaries of the Registrant
(23) -- Consent of experts and counsel
+(A) -- Consent of Ryder Scott Company Petroleum Engineers
+(B) -- Consent of Arthur Andersen LLP
(27) -- Financial Data Schedule

- ---------------

+ Filed herewith.

* Incorporated herein by reference to like exhibit in Registration on Form
10 (File No. 022483).

** Incorporated herein by reference to like exhibit in registration statement
on Form S-1 filed April 24, 1998.