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<SEC-DOCUMENT>0000890566-98-000578.txt : 19980406

<SEC-HEADER>0000890566-98-000578.hdr.sgml : 19980406

ACCESSION NUMBER:

0000890566-98-000578

CONFORMED SUBMISSION TYPE:

10-K/A

PUBLIC DOCUMENT COUNT:

5

CONFORMED PERIOD OF REPORT:

19971231

FILED AS OF DATE:

19980403

SROS:

NONE

FILER:

COMPANY DATA:

COMPANY CONFORMED NAME:

CENTRAL INDEX KEY:

STANDARD INDUSTRIAL CLASSIFICATION:

IRS NUMBER:

FISCAL YEAR END:



SEVEN SEAS PETROLEUM INC

0000947156

OIL AND GAS FIELD EXPLORATION SERVICES [1382]

731468669

1231



FILING VALUES:

FORM TYPE:

SEC ACT:

SEC FILE NUMBER:

FILM NUMBER:



001-13771

98587671



BUSINESS ADDRESS:

STREET 1:

STREET 2:

CITY:

STATE:

ZIP:

BUSINESS PHONE:



1990 POST OAK BLVD SUITE 960

THIRD POST OAK CENTRAL

HOUSTON

TX

77056

7136228218



10-K/A



MAIL ADDRESS:

STREET 1:

STREET 2:

CITY:

STATE:

ZIP:

</SEC-HEADER>

<DOCUMENT>

<TYPE>10-K/A

<SEQUENCE>1

<TEXT>



1990 POST OAK BLVD SUITE 960

THIRD POST OAK CENTRAL

HOUSTON

TX

77056



SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K/A

Amendment No. 1

[X]



ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE

ACT OF 1934

FOR FISCAL YEAR ENDED DECEMBER 31, 1997

or



[ ]



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

OF 1934

Commission File No. 0-22483

SEVEN SEAS PETROLEUM INC.

(Exact name of registrant as specified in its charter)



YUKON TERRITORY

(State or other jurisdiction of

incorporation or organization)

SUITE 960, THREE POST OAK CENTRAL

1990 POST OAK BOULEVARD

HOUSTON, TEXAS

(Address of principal executive offices)



73-1468669

(I.R.S. Employer

Identification No.)



77056

(Zip Code)



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

The aggregate market value of the common stock 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 $ 638,089,326 on March 26, 1998 based upon the

closing sale price of the Common Stock on such date of $27.00 per share on the

American Stock Exchange as reported by The Wall Street Journal.

AS OF MARCH 27, 1998 THERE WERE 35,216,606 SHARES OF THE REGISTRANT'S COMMON

SHARES, NO PAR VALUE PER SHARE, OUTSTANDING.



Indicate by check mark whether the registrant (1) has filed all reports required

to be filed by Section 13 of 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, 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.[ ]

<PAGE>

TABLE OF CONTENTS TO FORM 10-K

<TABLE>

<CAPTION>

PAGE

PART I

<S>

Item 1.

Item 2.

Item 3.

Item 4.



<C>

Business .....................................................

Risk Factors..................................................

Properties ...................................................

Legal Proceedings ............................................

Submission of Matters to a Vote of Security Holders...........



<C>

2

6

12

20

20



PART II

Item

Item

Item

Item

Item



5.

6.

7.

8.

9.



Market for Registrant's Common Equity and Related ............

Selected Financial Data ......................................

Management's Discussion and Analysis of Financial.............

Financial Statements and Supplementary Data...................

Changes in and Disagreements with Accountants on Accounting...

and Financial Disclosure



21

21

22

26

27



Item 10.

Item 11.

Item 12.



Directors and Executive Officers of the Registrant ..........

Executive Compensation.......................................

Security Ownership of Certain Beneficial Owners and .........

Management



28

32

40



Item 13.



Certain Relationships and Related Transactions ..............



41



Item 14.



Exhibits, Financial Statement Schedules and Reports on Form

8-K .........................................................



42



Signatures ...................................................



46



PART III



PART IV



</TABLE>

<PAGE>

PART I

ITEM 1.



BUSINESS



OVERVIEW

Seven Seas is an independent international energy company engaged in the

exploration, development and production of oil and natural gas in Colombia. The

Company is the operator of an oil discovery ("Emerald Mountain") held by two

adjoining association contracts covering a total of 109,000 acres in central

Colombia. The Company has focused its efforts on delineating the oil and gas

potential of Emerald Mountain. The five exploratory wells completed to date on

Emerald Mountain have achieved maximum tested actual production rates ranging

from 3,415 to 13,123 barrels per day. The Company's 57.7% working interest in

Emerald Mountain (before Colombian government participation) was acquired

through a series of transactions from 1995 through 1997. The Company has

interests in three additional association contracts in Colombia which, together

with the Emerald Mountain association contracts, cover over one million gross

acres. As of December 31, 1997, the Company's estimated net proved reserves

attributable to the delineation of 14,459 acres of Emerald Mountain were 32.2

million barrels of oil with an SEC PV-10 of $144.9 million.

Certain members of the Company's management have been involved in the

Emerald Mountain project since its inception in 1992. The Company's executive

officers average approximately 25 years of experience in the oil and gas

industry and predecessors of the Company have operated throughout the U.S. and

Canada since 1959. As of March 31, 1998, the Company's officers and directors

beneficially owned approximately 30% of the Company's outstanding shares on a

diluted basis.

The Company believes that it will be able to fund its operations and

investments through the first phase of its Emerald Mountain development program

("Phase I") with existing cash balances, the issuance of public or private debt

securities, as well as by obtaining a secured line of credit from one or more

commercial banking institutions. Phase I includes development and delineation

drilling and the construction of a 36-mile pipeline from the Emerald Mountain

project to a connection with an existing pipeline. Upon its scheduled completion

in mid-1999, the Phase I pipeline will transport 50,000 barrels of oil per day

of production from Emerald Mountain to an existing pipeline with approximately

50,000 barrels per day of available transportation capacity. To date, the

Company has financed its operations and its exploration and continued

delineation of Emerald Mountain primarily with private offerings of equity and

convertible debt, providing the Company with aggregate net proceeds of $47.0



million. In future periods, the Company may finance its operations and

investments through the issuance of public and private debt, equity, and

convertible securities, as well as through commercial banking credit facilities.

The Company issued 17.8 million common shares as consideration for a portion of

its interests in Emerald Mountain. Based on the closing sales price of its

common shares on the American Stock Exchange ("SEV") on March 26, 1998, the

Company had an equity market capitalization, on a diluted basis, of

approximately $1.1 billion.

BUSINESS STRATEGY

The Company's strategy is to maximize cash flow and profitability through:

(i) continuing to develop and delineate Emerald Mountain; (ii) maintaining a

balance between development activities that generate near-term cash flow and a

longer-term exploration program; (iii) capitalizing on the relative advantages

of Emerald Mountain compared to other areas in Colombia; and (iv) mitigating the

risk of foreign operations.

DEVELOPING THE EMERALD MOUNTAIN ASSET. As operator of Emerald Mountain, the

Company's goal is to rapidly and efficiently continue its field development and

delineation drilling program and to build the production facilities and pipeline

infrastructure to allow its production to reach existing transportation lines

for access to export markets.

o



DEVELOPMENT AND DELINEATION DRILLING ACTIVITIES. The Company's Phase I

drilling program for 1998 and 1999 includes capital expenditures of

$16.2 million for Emerald Mountain field development and delineation,

which is scheduled to be completed by mid-1999.



o



PIPELINE AND INFRASTRUCTURE ACTIVITIES. The Company is engaged in

negotiations with leading oil service, construction and engineering

firms to construct its processing, storage and related facilities, and a

36-mile pipeline from the Emerald Mountain project to a connection with

an existing pipeline. Upon its scheduled completion in mid-1999, the

Phase I pipeline will transport 50,000 barrels of oil per day of

production from Emerald Mountain

2



<PAGE>

to an existing pipeline with approximately 50,000 barrels per day of

available transportation capacity. The Company's 1998-1999 budgeted

expenditures for these activities are $34.2 million for Phase I. The

Company may utilize joint ventures and other arrangements to minimize

its capital outlays for pipeline infrastructure and production

facilities related to Emerald Mountain.

BALANCING DEVELOPMENT ACTIVITIES WITH EXPLORATION PROGRAM. The Company seeks

to balance its development drilling program with an exploration program focused

on delineating and extending the reservoir limits of Emerald Mountain. The

Company utilizes advanced technology, including 2-D and 3-D seismic techniques

as well as other proven exploratory tools.

CAPITALIZING ON FAVORABLE OPERATING ENVIRONMENT. The Company intends to

capitalize on the relative advantages of the location and characteristics of

Emerald Mountain, which it believes represent a more favorable operating

environment than most other discoveries and producing fields in Colombia. These

advantages include:

o



The productive Upper Cretaceous Cimarrona formation at Emerald Mountain

is at relatively shallow vertical depth of between 6,000 to 7,500 feet

and does not require the relatively more complicated and more expensive

drilling methods required to reach the deeper formations that are found

in many other areas of Colombia.



o



Emerald Mountain benefits from accessible terrain at an average of

approximately 3,000 feet above sea level in a generally unforested area,

which is served by a major highway and is located near the Oleoductos

Alto Magdalena ("OAM") pipeline.



o



Emerald Mountain is located 60 miles northwest of Bogota in the capital

state of Cundinamarca in central Colombia, which is characterized by

greater civil and political stability and by a higher general population

and military presence than more remote areas of Colombia.



o



Colombia is a relatively stable democracy with a long history of

consistent GDP growth and an announced goal of aggressively expanding

its oil exports. Colombia's sovereign U.S. dollar rating as of March

1998 was Baa3/BBB-.



MITIGATING RISKS OF FOREIGN OPERATIONS. The Company seeks to mitigate

operating and financial risks associated with operating in Colombia by: (i)

building on its relationship with the Colombian government, which, through the

Colombian national oil company ("Ecopetrol"), has the right to back-in to an

initial 50% working interest in Emerald Mountain; (ii) continuing the high level

of involvement of the Company's Colombian advisory board consisting of prominent

business and government leaders, all of whom are shareholders of the Company, to

provide advice and to facilitate operating in Colombia; (iii) building on

existing favorable relationships with the local community by, among other

initiatives, providing local employment as well as medical and educational

assistance; (iv) employing local personnel with in-country oil and gas industry

expertise; and (v) operating primarily in U.S. dollars with the right to

expatriate profits from Colombia.

EMERALD MOUNTAIN

OVERVIEW. The Company's Colombian operations are focused on Emerald

Mountain. The Emerald Mountain discovery is located on two adjoining concession



areas in central Colombia, approximately 60 miles northwest of Bogota. The

concession areas are defined by two association contracts, the Rio Seco

Association Contract and the Dindal Association Contract. The Company owns a

57.7% working interest in Emerald Mountain before Colombian government

participation. See "-The Association Contracts." As of December 31, 1997,

estimated net proved reserves of Emerald Mountain were 32.2 MMBO with an SEC

PV-10 of $144.9 million.

The Emerald Mountain geological structure is a large anticline. The primary

oil reservoir is the Upper Cretaceous Cimarrona formation, which comprises both

limestone and sandstone and is relatively under pressured. The Emerald Mountain

reserves are located at vertical depths of between 6,000 and 7,500 feet and are

characterized by low sulfur content (less than 1%), low paraffin content and a

medium gravity (18 degree to 20 degree API gravity).

DRILLING ACTIVITY. The Company has enhanced its knowledge of the Cimarrona

reservoir and of its potential productive capacity through the drilling of eight

wells on the formation. Production tests of the wells have indicated a uniform

and

3

<PAGE>

extensive degree of permeability within the area investigated. In 1994, a

predecessor to the Company drilled the Escuela 1, which was non-commercial. The

five exploratory wells completed to date on Emerald Mountain have encountered on

average 303 feet of net pay at vertical depths between 6,000 and 7,500 feet. For

the five wells where production testing has been completed, actual per well

production rates realized ranged from 3,415 to 13,123 barrels per day with an

average in excess of 7,079 barrels per day. The table below sets forth drilling

results to date on Emerald Mountain.

<TABLE>

<CAPTION>

MAXIMUM

ACTUAL

MAXIMUM ACTUAL

GAS TEST

DATE

VERTICAL DEPTH OIL TEST RATE

RATE

WELL NAME

COMPLETED

(FEET)

(BBS/D) (1)

(MCF/D)

DESCRIPTION

-----------------------------------------------<S>

<C>

<C>

<C>

<C>

Escuela 1

(2)

(2)

(2)

(2)

Non-commercial

El Segundo 1-E



2/96



5,718



3,415



1,350



Discovery well



El Segundo 1-N



11/96



6,820



8,948



3,500



Drilled



from



initial pad



El Segundo 1-S



9/97



6,920



4,528



451



Drilled



from



initial pad



El Segundo 2-E



11/97



6,292



5,381



826



Drilled 3 miles

below ES 1-N



El Segundo 3-E



(3)



8,021



(3)



Tres Pasos 1-E



10/97



6,200



13,123



(3)

6,000



ES



1-E;



1,168'



Drilled 2.8 miles south of ES 1-E;

temporarily abandoned

Drilled



Tres Pasos 2-E

2/98

6,054

(4)

(4)

Drilled

- --------------</TABLE>

(1) References are from production testing only and are not necessarily

indicative of flow rates that may be utilized during production. Production

tests are conducted to obtain an indication of the flow 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 study 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.

(2) The Escuela 1 well, drilled in 1994, encountered Tertiary and Cretaceous

shales and siltstones from surface to total depth. This predominately shale

section, emplaced by thrust faulting adjacent to the Cimarrona reservoir

section, is believed to form the eastern critical element of the trap for

Emerald Mountain.

(3) While the anticipated formation was encountered, the Company experienced

major mechanical problems while attempting to complete the well for

production testing and has temporarily abandoned the well pending a

scheduled return to this location in the third quarter of 1998.

(4) Due to an operational problem that resulted from a failure to properly

cement liner casing through the Cimarrona formation, the Company has decided

to sidetrack and drill a new well bore. This operation is scheduled to be

completed during the second quarter of 1998. Log and core analysis

performed subsequent to the completion of drilling operations resulted in

indications of a highly fractured and oil bearing formation.

CAPITAL SPENDING PROGRAM. Phase I of the Company's two-stage development

plan, scheduled to be completed in mid-1999, includes the completion of

production facilities and a 36-mile pipeline link to the OAM pipeline in La

Dorado, which will enable 50,000 barrels of daily production to be transported

from Emerald Mountain. The OAM pipeline will transport oil from La Dorado to

Vasconia, where it will join the Oleoducto Central S.A. ("OCENSA") and the

Oleoducto de Columbia ("ODC") pipelines for transport to Covenas, the major

export terminal in Colombia on the Caribbean. The 50,000 barrels per day

production level represents the maximum available capacity on the OAM pipeline.

The Company plans to drill seven development and delineation wells in 1998 and

the first half of 1999 to develop production capacity for Phase I. The gross

capital expenditures estimated for Phase I include $97.9 million ($34.2 million



north of



600'

5.6



downdip to Northwest of ES 1-E

miles to Northwest of ES 1-E



net) for pipeline and production facilities and $31.2 million ($16.2 million

net) for development and delineation drilling.

The Company believes that Phase II of the development plan, scheduled to be

completed in the first quarter of 2000, will result in an increase in Emerald

Mountain production capacity to 250,000 barrels per day. To meet these volume

requirements, the Company's plans call for a 250,000 barrel per day pipeline

that would extend the Phase I pipeline 45 miles

4

<PAGE>

from La Dorado to Vasconia and would be constructed alongside the existing OAM

pipeline. At Vasconia, a major oil terminal, the Company's oil would be

transported 300 miles on the two existing pipelines to Covenas. The 250,000

barrels per day production level represents the maximum capacity currently

available on the OCENSA and ODC pipelines. The Company plans to drill 49

development wells from 1998 through 2000 in Phase II to increase production. The

gross capital expenditures estimated for Phase II include $85.8 million ($24.8

million net) for pipeline and production facilities and $209.4 million ($63.4

million net) for development and delineation drilling. The construction of the

Phase I and Phase II pipeline and the production facilities is subject to a

number of conditions, including obtaining required environmental and

construction permits and necessary easements and rights of way.

THE ASSOCIATION CONTRACTS. The Company and its partners have secured the

right to produce oil and gas from the Dindal and Rio Seco contract areas through

the years 2021 and 2023, respectively. Under the terms of the association

contracts, Ecopetrol receives a royalty on behalf of the Colombian government

equal to 20% of production after transportation costs are deducted and, in the

event of commerciality, Ecopetrol has the right to acquire an initial 50%

working interest in the project. Until the partners have been repaid for 50% of

all costs associated with successful drilling, Ecopetrol's share of production

will be applied to the repayment of such costs. Until commercial production is

initiated, the Company expects that the current working interest owners will

fund all costs associated with the initiation of commercial production.

Ecopetrol's share of production and costs in the Dindal contract area will

increase once a commercial field produces in excess of 60 MMBls, up to a maximum

interest of 70% if the field produces in excess of 150 MMBbls. In addition,

Ecopetrol's share of production and costs in the Rio Seco contract area is also

subject to increase up to a maximum interest of 75% depending upon revenues and

associated costs. The Company's weighted average net interest in barrels of

estimated production over the life of the Association Contracts before Colombian

government royalty is 24.36%.

ADDITIONAL EXPLORATION POTENTIAL. The Company believes that its existing

properties hold additional exploration potential in deeper horizons at Emerald

Mountain beneath the Cimarrona formation including Tertiary formations and

repeated upper Cretaceous zones including the Cimarrona and Villeta formations.

In addition to capital expenditures for seismic and other technical evaluation,

the Company has budgeted approximately $9.0 million to participate in drilling a

deep, up to approximately 18,000 feet, exploratory well on Emerald Mountain.

OTHER COLOMBIAN PROPERTIES

The Company owns a 75% working interest in the contiguous Montecristo and

Rosablanca Association Contract areas, which cover approximately 692,000 gross

acres in the northern Middle Magdalena Basin. In the Central Llanos Basin, 40

miles east of the Cusiana field, the Company owns an 11.875% initial working

interest in the 233,000 acre Tapir contract area operated by Heritage Minerals

Colombia ("Heritage Minerals"). During 1998, the Company expects to reprocess

and evaluate 2-D seismic on the Montecristo and Rosablanca areas and to

participate in the drilling of the Mateguafa #1 well on the Tapir contract.

COMPANY BACKGROUND

Seven Seas was formed February 3, 1995 to participate in exploration and

development activities outside of North America. In August 1995, the Company

purchased a 15.0% interest in Emerald Mountain from GHK Company Colombia, Inc.

("GHK Colombia"), a subsidiary of GHK Company L.L.C. In July 1996, the Company

acquired an additional 36.7% working interest in Emerald Mountain through its

acquisition of 100% of GHK Colombia and Esmeralda Limited Liability Company and

63% of Cimarrona Limited Liability Company. In March 1997, the Company acquired

an additional 6.0% working interest in Emerald Mountain through its acquisition

of Petrolinson, S.A., resulting in the Company's current ownership of a 57.7%

working interest in Emerald Mountain (before Colombian government

participation). In connection with these acquisitions, the Company issued 17.8

million common shares.

RECENT DEVELOPMENTS

DRILLING ACTIVITY. On February 13, 1998, Seven Seas announced the Tres Pasos

2-E well had reached a total depth of 6,054 feet. The well is located 5.6 miles

north-northwest of the El Segundo 1-E discovery well on the Rio Seco block. The

well encountered 290 feet of Cimarrona formation with no indication of oil-water

contact. Due to an operational problem that resulted from a failure to properly

cement casing through the Cimarrona formation, the Company has decided to

sidetrack and drill a new well bore. This sidetracking operation is scheduled to

be completed during the second quarter of

5

<PAGE>

1998. Log and core analysis performed subsequent to the completion of drilling

operations resulted in an indication of highly fractured and oil bearing

formation.

On January 30, 1998, Seven Seas announced that the completion and results

from 33 days of reservoir testing for the El Segundo 2-E well located on the



Dindal block. The well encountered 314 feet of net pay and had a maximum

production rate of 5,381 barrels of oil per day and 826,000 cubic feet of gas

per day and there was no evidence of oil-water contact. The production rate and

interference data confirm a significant extension of the reservoir approximately

3.7 miles to the north.

In November 1997, drilling commenced for the El Segundo 3-E well, the eighth

and most southern well to be drilled on Emerald Mountain and the sixth to be

drilled on the Dindal block. The drilling of the El Segundo 3-E was completed in

February 1998, and the well encountered 292 feet of Cimarrona formation. After

the completion of drilling operations on the El Segundo 3-E, the Company

encountered major mechanical problems while attempting to complete the well for

production testing. Due to a failure to effectively install the lower portion of

the well's casing, it was not possible to achieve sufficient communication with

the Cimarrona formation to initiate production testing. The Company plans to

temporarily abandon the El Segundo 3-E well pending a scheduled return to this

location in the third quarter of 1998.

OTHER INTERNATIONAL INTERESTS. The Company is in the process of eliminating

any mandatory capital commitments outside of Colombia. In Papua New Guinea, the

Company signed a farm-out agreement with ARCO Papua New Guinea Inc. whereby the

Company will retain a 20% carried interest with no required capital

expenditures. In the Western Perth Basin in Australia, the Company has signed a

purchase and sale agreement in August 1997 with Forcenergy International Inc. in

which the Company will exchange its 11.77% working interest for $850,000. The

Company will retain a small overriding interest and will also be reimbursed

$263,000 for certain capital expenditures. The agreement is pending its final

approval by an aboriginal council in West Australia. In the Bass Strait Basin in

Australia, the Company is seeking to farm-out its interests. The Company has no

required capital commitments for this prospect.

RISK FACTORS

DISCLOSURE FORWARD LOOKING STATEMENTS

All statements other than statements of historical fact contained herein,

including, "Management's Discussion and Analysis of Financial Condition and

Results of Operations," "Business" and "Properties," regarding the Company's

financial position, estimated quantities of reserves, business strategy and

plans and objectives for future operations are forward looking statements.

Forward-looking statements in this annual report are generally 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 in this annual report. All forward-looking statements included herein

are expressly qualified in their entirety by the cautionary statements in this

paragraph.

RISKS RELATED TO THE COMPANY

LACK OF CASH FLOW

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, 1997, the Company incurred cumulative losses of $12,242,557and 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 related thereto. The Company

had oil and gas sales in 1996 and 1997 of $233,682 and $779,767, 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 further work is done to evaluate the field through

the drilling of additional wells, and producing facilities and pipelines have

been constructed. The Company has

6

<PAGE>

received preliminary plans and engineering specifications for the construction

of pipelines and production facilities. The construction of the Phase I and

Phase II pipelines and the production facilities is subject to a number of

conditions, including obtaining required environmental and construction permits

and necessary easements and rights of way. The Company does not expect these

facilities to be completed before July 1999, and no assurances can be given as

to when such facilities will be completed. If the Company is unsuccessful in

constructing a production facility and a pipeline or in increasing its proved

reserves or realizing future production from its properties, the Company may be

unable to pay existing or future debt. See "-Risks Related to Oil and Gas

Industry" and "-Risks Related to Construction of Pipeline and Production

Facilities."

RISKS RELATED TO CONSTRUCTION OF PIPELINE AND PRODUCTION FACILITIES

The marketability of the Company's production depends upon the availability

and capacity of oil gathering systems, pipelines and processing facilities, and

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, regulation of oil and natural gas production and

transportation, general economic conditions and changes in supply and demand

could adversely affect the Company's ability to produce and market its oil and

natural gas on a profitable basis.



The Company has received preliminary plans and 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 obtaining required environmental and construction permits and

necessary easements and rights of way. The Company does not expect these

facilities to be completed before July 1999, and no assurances can be given as

to when such facilities will be completed. If the Company is unsuccessful in

constructing a production facility and a pipeline or in increasing its proved

reserves or realizing future production from its properties, the Company may be

unable to pay principle and interest on existing debt or debt incurred in the

future. See "-Risks Related to Oil and Gas Industry" and "- Risks Related to

Construction of Pipeline and Production Facilities."

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 debt or

equity financings, encumbering properties or entering into arrangements whereby

certain costs of exploration will be paid by others to earn an interest in the

property. The Company has budgeted capital expenditures of $67.6 million for

1998 and $145.2 million for 1999. The Company believes it is capable of

obtaining sufficient funds to finance its initial capital expenditure

requirements for Phase I, although no assurance can be given as to the actual

amount that will need to be spent. Substantial amounts of capital will be needed

to finance Phase II, and no external sources of capital have yet been

identified. It is expected that additional monies for capital expenditures will

be financed through either debt or equity financings in the future, as the

Company does not expect any significant revenues from operations until the

production facilities are constructed in the third quarter of 1999. There can be

no assurance that the additional debt or equity financing will be available to

the Company on economically acceptable terms. As of December 31, 1997, the

Company has commitments under existing exploration and development contracts of

$3,310,000 through 2001. 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. See "Management's

Discussion and Analysis of Financial Condition and Results of Operations."

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, 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 or may not be

successful in subjecting foreign persons to the jurisdiction of courts in the

United States. The Company may also be hindered or prevented from enforcing its

rights with respect to a governmental instrumentality because of the doctrine of

sovereign immunity.

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The Company's business is subject to political risks inherent in all foreign

operations. While Colombia has no history of nationalizing its business nor

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 certain areas in Colombia but

to date has not affected the Dindal and Rio Seco Association Contracts. 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 if found

to be giving aid to such groups. The Company and its partners will continue to

cooperate with the government, and do not expect that future guerrilla activity

will have a material impact on the exploration and development of the

Association Contracts. However, there can be no assurance that such activity

will not occur or have such an impact and no opinion can be given on what steps

the government may take in response to any such activity. 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.

In March 1996, the President of the United States announced that Colombia would

neither be certified nor granted a national interest waiver. 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 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. Each of these consequences of

the failure to receive such certification 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. See "BusinessProperties-Colombia."



SUBSTANTIAL CONCENTRATION OF OPERATIONS

The Company's producing properties are substantially concentrated in

Colombia and specifically in the state of Cundinamarca. As of December 31, 1997,

all of the Company's proved reserves were attributable to Emerald Mountain.

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 Inherent in Foreign Operations" and "-Risk Related to the Oil and Gas

Industry."

RISKS OF JOINT VENTURES

The Company has and expects to continue to acquire only partial interests in

oil and gas properties through joint venture agreements with other oil and gas

corporations that may, by the terms of such joint venture agreements, be the

operators of such programs. Although the Company can take certain steps to

determine if the risk of the program to be conducted by the operator is

appropriately spread over a number of prospects, there can be no assurance that

the risk will be so allocated, that the program will be carried out by the

operator in a manner deemed appropriate by the Company or that the prospects

will be successful. In addition, the Company's ability to continue its

exploration and development programs may be dependent upon the decision of its

joint venture partners to continue exploration and development programs and to

finance their portion of the costs and expenses of the joint venture. If the

Company's partners do not elect to continue and to finance their obligations to

the joint ventures, the Company may be required to accept an assignment of the

partners' interests therein and assume their financing obligations or relinquish

its interest in the joint venture.

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 each year since

inception. Potential investors, therefore, have limited historical financial and

operating information upon which to base an evaluation of the Company's

performance. For example, the only production to date has been test production.

The Company is not expected to have regular production until 1999. 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

must be considered in

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light of the risks, expenses 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 " - Significant Capital Requirements,"

"Selected Combined Financial Data," "Management's Discussion and Analysis of

Financial Condition and Results of Operations" and "Business - Oil and Gas

Reserves."

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. See "Management - Employment Agreements." 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.

POTENTIAL CONFLICTS

Certain of the directors of Seven Seas 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.

SERVICE AND ENFORCEMENT OF LEGAL PROCESS

The Company is continued under the laws of the Yukon Territory in Canada.

Three of the directors of the Company, and certain experts utilized by the

Company, are not residents of the United States and all or substantially all of

such persons' assets are located outside of the United States. The Company has

been advised by its counsel that there is no assurance that judgments of U.S.

courts for liabilities predicated solely upon U.S. federal securities laws will

be enforceable against the Company or against any of its directors or experts

who are not residents of the United States.

RISKS RELATED TO THE OIL & GAS INDUSTRY

UNCERTAINTY OF ESTIMATES OF OIL AND GAS RESERVES



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 or on a Reserve Report that relies 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, 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 or contained in the Reserve

Report. Any significant variance in these assumptions could materially affect

the estimated quantity and value of reserves set forth in this document. The

Company's properties may also be susceptible to hydrocarbon drainage from

production by other operators on adjacent properties. In addition, the Company's

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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Approximately 64% of the Company's total proved reserves at December 31,

1997 were undeveloped, which are by their nature less certain of recovery.

Recovery of such reserves will require significant capital expenditures and

successful drilling operations. The Company's reserve data assume that

substantial 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. See "Business

- - Oil and Gas Reserves."

The present value of future net revenues (SEC PV-10) referred to herein

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

consumption by gas and oil purchasers 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.

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 in unknown formations, the costs associated with

encountering various drilling conditions such as 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 capacity of oil and gas pipelines and processing equipment,

government regulations, including regulations relating to prices, taxes,

royalties, land tenure, importing and exporting of oil and gas and environmental

protection. 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.

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, 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" and "Business-Marketing."

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

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the present value of estimated future net revenues from proved reserves,

discounted at 10% (SEC PV-10). 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, even if prices were depressed for only a short period

of time. The Company may be required to write down the carrying value of its oil

and natural gas properties when oil and natural gas prices are depressed or

unusually volatile. If a write-down is required, it would result in a charge to

earnings, but would not impact cash flow from operating activities. 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 prevailing 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

Extensive national, provincial and/or local environmental laws and

regulations in each of the 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. There can be no assurance that the Company will not incur

substantial financial obligations in connection with environmental compliance.

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.

OPERATING RISKS OF OIL AND OTHER UNCERTAINTIES

Acquiring, developing and exploring for oil and natural gas involves many

risks, which even a combination of experience, knowledge and careful evaluation

may not be able to overcome. These risks including encountering unexpected

formations or pressures, premature declines of reservoirs, blow-outs, equipment

failures and other accidents, 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.

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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, loss of production income insurance 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 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.

MARKETS

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.

COMPETITION

Oil and gas exploration is extremely competitive in all of its phases and

particularly in exploration for and development of new sources of crude oil and

natural gas. The Company must compete with other companies that are larger and

financially stronger in acquiring properties suitable for exploration, in

contracting for drilling equipment and in securing trained personnel. The

Company's future operations will be dependent upon its ability to compete in

this highly competitive environment.

REGULATION

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, 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,

and the Ministry of the Environment. 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.

ITEM 2.



PROPERTIES



COLOMBIA

DINDAL AND RIO SECO ASSOCIATION CONTRACTS; EMERALD MOUNTAIN

OVERVIEW. Association Contracts acquired from Ecopetrol, after being

approved by all proper Colombian governmental authorities as well as the board

of Ecopetrol, are mutually executed by the parties and subsequently recorded as

a public deed in Colombia. Therefore, ownership of an Association Contract is of

public record and protected by Colombian law.

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The Company's principal asset is a 57.7% working interest in the Association

Contracts with Ecopetrol, which entitle the Company to engage in exploration,

development and production activities in approximately 109,000 acres located in

the oil producing Magdalena Basin, about 56 miles northwest of Bogota. The area

is accessible via the main road between Bogota and Honda. The village of Guaduas

lies within the block and provides infrastructure for the local economy which is

primarily agrarian in nature. 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.

Recent discoveries in the Magdalena Basin include Amoco's Opon Field,

located approximately 106 miles north of the prospect area, and Lasmo's

Venganza/Revancha complex, located approximately 93 miles to the south. The main

OAM pipeline is approximately 12-miles west of the prospect area and provides an

opportunity for oil transportation from Emerald Mountain.

EMERALD MOUNTAIN

To date, eight wells have been drilled on the Dindal and Rio Seco blocks

under the Association Contracts. The first well, the Escuela, which was drilled

in 1994 prior to the acquisition of an interest in the blocks by the Company,

was plugged and abandoned as non-commercial. The discovery well for the Emerald

Mountain Project was the second well drilled on the Dindal block, the 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 reached the objective

Cimarrona formation at a depth of 5,630 feet, but stopped drilling after



penetrating only 88 feet of the Cimarrona due to circulation problems

encountered while drilling. The well was then completed for testing in February

1996. In July 1996, the third well to be drilled, the El Segundo 1-N commenced

drilling in early September 1996 and reached total drilling depth of 6,820 feet

in late October. The well was intentionally deviated from the surface location

of the El Segundo 1-E well to a bottom hole location approximately 2,000 feet

north of the surface location. The well encountered approximately 450 feet of

oil saturated and highly fractured Upper Cretaceous Cimarrona formation. During

the production testing, the El Segundo 1-N produced oil at an actual maximum

rate of 8,948 barrels per day. A fourth well, El Segundo 1-S, was drilled and

completed in September 1997 to a total depth of 6,920 feet. The bottom hole

location of this well is approximately 2,000 feet south of the surface location

of El Segundo 1-E well. In October 1997, the Company conducted production

testing which resulted in oil production at an actual maximum rate of 4,528

barrels per day.

In October 1997, the Tres Pasos 1-E well was drilled and completed at a

vertical depth of 6,150 feet without evidence of any oil-water contact. This

well was the first to be drilled on the Rio Seco block and was located

approximately 1.6 miles northwest of the surface location of the El Segundo 1-E

well. Production testing of the Tres Pasos 1-E well was completed in December

1997 and resulted in oil being produced at an actual maximum rate of 13,123

barrels per day. Analysis of reservoir pressure data during production testing

indicated pressure communication with the El Segundo 1 wells located to the

southeast. Such pressure communication over a 1.6 mile distance supported

drilling results that indicated a consistently high and intensive degree of a

well-connected fracture system indicating an extensive storage capacity and

permeability within the area of the Cimarrona formation investigated during the

production test.

The sixth well to be drilled on Emerald Mountain, the El Segundo 2-E,

completed drilling at a vertical depth of 6,262 feet in November 1997 on the

Dindal block approximately 3.1 miles north of the surface location of the El

Segundo 1-E discovery well. Production testing of the El Segundo 2-E was

completed in January 1998 and resulted in a maximum actual production rate of

6,262 barrels per day. Analysis of pressure data during production testing

evidenced communication with the El Segundo 1-S well approximately 3.7 miles to

the south. This data further confirmed the presence of a uniform and pervasive

fracture system supporting the evidence for extensive storage capacity and

permeability within the Cimarrona formation over the area investigated by the

production testing.

Drilling of the seventh well on Emerald Mountain and the second on the Rio

Seco Block, the Tres Paso 2-E, commenced in December 1997 and was completed in

February 1998 at a location approximately 5.6 miles north-northwest of the

surface location of the El Segundo 1-E. This well was drilled to a vertical

depth of 6,054 feet and encountered 290 feet of the Cimarrona formation with no

evidence of any oil-water contact. Due to an operational problem that resulted

from a failure to properly cement casing through the Cimarrona formation, the

Company has decided to sidetrack and drill a new well bore. This sidetracking

operation is scheduled to be completed during the second quarter of 1998. Log

and core

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analysis performed subsequent to the completion of drilling operations resulted

in an indication of highly fractured and oil bearing formation similar to that

found in the preceding five successful wells.

In November 1997 drilling commenced for the El Segundo 3-E well located

approximately 2.8 miles south of the surface location of the El Segundo 1-E

well. This well was the eighth and most southern well to be drilled on Emerald

Mountain and the sixth to be drilled on the Dindal Block. The drilling of the El

Segundo 3-E was completed at a vertical depth of 8,021 feet in February 1998.

The well encountered 292 feet of Cimarrona formation that exhibited similar

characteristics in terms of lithology and fracturing as that exhibited in the

previous seven wells. After the completion of drilling operations on the El

Segundo 3-E, the Company encountered major mechanical problems while attempting

to complete the well for production testing. Due to a failure to effectively

install the lower portion of the well's casing, it was not possible to achieve

sufficient communication with the Cimarrona formation to initiate production

testing. The Company plans to temporarily abandon the El Segundo 3-E well and to

move the drilling rig to the surface location for the drilling of the El Segundo

6-E well located approximately 5.3 miles south of the surface location of the El

Segundo 1-E well.

PROSPECT GEOLOGY. The Emerald Mountain structure is formed by a faulted

anticlinal closure in the foot wall of the Bituima thrust fault system on the

eastern side of the Magdalena river valley. The primary oil reservoir tested to

date is the Upper Cretaceous Cimarrona formation which is comprised of both

limestones and sandstones. These reservoir sequences are charged with oil

generated from the immediately underlying Villeta (also called LaLuna) shale,

which is considered the principal source rock for the oil accumulations

throughout Colombia and Venezuela.

The Cimarrona formation is seen in surface outcrop to the north and west of

the structure, as well as in the Lasmo Madrigal #1 well, the AIPC Quina #1 well

and the Company's five successful delineation wells completed as of March 1998.

From this geologic control and completed well information, the Cimarrona is

shown to be depositionally complex, with a high degree of fracturing consistent

in directional orientation. Cimarrona formation is on average approximately 290

feet in thickness and contains limestones, calcareous sandstones, and

siltstones.

Evidence for the structural trap is found in both seismic data over the

prospect and in surface geologic mapping. The trapping mechanism is believed to

be formed by structural closure in three directions (north, south and west), and



an imbricate fault within the Bituima Fault system to the east, which is

evidenced in the Escuela 1 well which was drilled in 1994, prior to the

acquisition of an interest in the block by the Company, and was determined to be

a non-commercial well. The Escuela 1 well is located 2.5 miles southeast of the

El Segundo 1-E discovery well location and encountered Tertiary and Cretaceous

shales and siltstones from surface to total depth. This predominantly shale

section, emplaced by thrust faulting adjacent to the Cimarrona reservoir

section, is believed to form the eastern critical element of the trap for the

prospect.

TERMS OF ASSOCIATION CONTRACTS AND RELATED MATTERS

The Association Contracts were issued by Ecopetrol in March 1993 and August

1995, respectively, and provide generally for a six-year exploration phase

followed by a 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,

Ecopetrol will receive a royalty equal to 20% of production (after

transportation costs are deducted) on behalf of the Colombian government and, in

the event a commercially feasible discovery is made, Ecopetrol will acquire a

50% interest in the remaining production, bear 50% of the development costs, and

reimburse the joint venture, from Ecopetrol's share of future production, for

50% of the joint venture's costs of certain exploration activities. Upon

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

representatives of the parties to the contract 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.

If any commercial field in the respective contract areas produces in excess

of 60 million barrels, Ecopetrol's interest in production and costs for such

contract area increases as follows: (i) under the terms of the Dindal

Association Contract, such increases occur in 5% increments from 50% to 70% as

accumulated production from any field increases in 30 million barrel increments

from 60 million barrels to 150 million barrels; and (ii) under the terms of the

Rio Seco Association Contract, Ecopetrol's interest increases from 50% to 75% as

the ratio of the accumulated income attributable to the parties

14

<PAGE>

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 one to one to two to one.

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 joint

venture may expend up to $2 million over a one-year period to further develop

the field, 50% of which will be reimbursed if Ecopetrol subsequently accepts the

commercial feasibility thereof. If Ecopetrol does not declare the field

commercial, the joint venture may continue to develop the field at its own

expense. In such event, Ecopetrol will have the right to acquire a 50% interest

therein upon payment of 200% of the amounts expended by the joint venture, which

payment may be made out of Ecopetrol's share of future production.

The Company and its partners 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 exploration costs relating to a field until such field is

declared commercial. The Company plans to submit a commerciality application to

Ecopetrol in the second quarter of 1998 with respect to its discovery.

GHK Company Colombia, a wholly-owned subsidiary of the Company, serves as

the operator of the joint venture to develop the Dindal and Rio Seco blocks,

pursuant to the terms of operating agreements between the Company, its

respective subsidiaries and its joint venture partners. GHK Company Colombia has

exclusive charge of carrying out the program of operations within the budgets

approved by the Operating Committee and may demand payment in advance from each

party of its respective shares of estimated monthly expenditures.

Under the terms of a letter agreement dated September 11, 1992, as amended,

between GHK Company Colombia and Dr. Jay Namson, the holders of interests in the

Association Contracts, as a group, will be required to assign a 2% working

interest in the Dindal Association Contract and the Rio Seco Association

Contract 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 blocks 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 each Association Contract, 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's weighted average net interest in barrels of estimated

production over the life of the Association Contracts before Colombian

government royalty is 24.36%.

LLANOS BASIN

INTRODUCTION. The Company acquired an 11.875% interest in the Tapir

Association Contract (the "Tapir Association Contract") in April 1996. The Tapir

block consists of 233,000 acres located in the Llanos Basin of east central

Colombia and is crossed by two oil pipelines carrying production from nearby oil



fields. Other Tapir Association Contract interests are held by Ampolex (56.25%),

Mohave Oil & Gas Corp. (10.205%), Doreal Energy (11.67%) and Heritage Minerals

(10%), which serves as the operator.

EXPLORATION PROSPECTS. There are three exploration prospect types on the

Tapir block: several conventional Llanos Basin small structural closures, a deep

Paleozoic anomaly and two basal Cretaceous stratigraphic prospects. The small

structural closures are relatively low risk, but are expected to have low

reserves potential (10-30 MMBO each). The Paleozoic prospect is of geologic

interest, but relies on unproven source and reservoir rocks, and is therefore

high risk until further geologic work can be completed. The geologic risk for

the two Cretaceous stratigraphic prospects depends on the effectiveness of the

lateral seal between the Ubaque sandstone and the adjacent Paleozoic section.

The Mateguafa prospect, one of the small structural closures in the central

portion of the Tapir block, has been selected as the first exploration drill

site. The Mateguafa #1 well on this prospect commenced drilling in March 1998.

EXISTING WELL. In 1993, the Macarenas #1 well, a discovery well, was drilled

on the Tapir block and produced 320 barrels per day in a short-term test, but

was not completed for production. Since the well was drilled and tested,

additional oil

15

<PAGE>

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 sustainable production rates and the extent of the reservoir.

TERMS OF TAPIR CONTRACT. The Tapir Association Contract was effective on

February 6, 1995 on terms substantially similar to the Rio Seco Association

Contract. Heritage Minerals, the Tapir Association Contract operator, has

completed a 51.5 mile seismic program in the field, which satisfied the work

program for the first year of the Tapir Association Contract and part of the

second year. The commitment for the second year well has been satisfied by the

drilling of the Mateguafa well required in the second year work program.

The Company acquired its interest in the Tapir Association Contract in April

1996 in consideration of the payment for $104,000 which represents reimbursement

for past seismic costs and permit administration, and its agreement to pay its

proportionate share of the costs of a seismic program, the first exploratory

well, the production test on the Macarenas #1 well (assuming the parties elect

to proceed therewith) and certain additional costs to earn its interest in the

Tapir Contract. The Company estimates that its proportionate share of these

costs, which are required to be paid to retain its interest in the Tapir

Association Contract, are approximately $400,000.

AUSTRALIA

The following is a description of the Company's interests in Australia,

which the Company plans to divest or farmout.

SOUTHERN PERTH BASIN PERMITS. The Company holds an 11.77% working interest

in Exploration Permit 381 ("EP381") and Exploration Permit 408 ("EP408"), both

of which relate to properties that are located in the southern Perth Basin,

Western Australia. Other interests in these permit areas are held by: Pennzoil

(44.115%), Amity Oil (30.115%) and GeoPetro Company (14%).

The Company has entered into a sales contract with Forcenergy International

Inc. with respect to the sale of its interests in EP 381 and EP 408 for $850,000

and will be reimbursed $263,000 for certain capital expenditures. The required

consents of governmental authority and most third parties have been received.

Consummation of the transaction contemplated by the Letter of Intent is subject

to obtaining the approval of one remaining third party. No absolute assurance

can be given that the Company will complete this sale.

BASS BASIN, BLOCK T27P. The Company holds a 20% working interest in Block

T27P, a 1.8 million acre block in approximately 70 meters of water, in the Bass

Basin, the central of three basins offshore southern Australia. The easternmost

basin is the Gippsland Basin where BHP Petroleum and Esso have a series of large

oil and gas fields. The westernmost basin is the Otway Basin, the site of recent

gas discoveries by BHP Petroleum and others, which will likely serve the South

Australia and Victoria gas markets. The T27P block lies about halfway between

the Victoria coast to the north and the Tasmania coast to the south (about 56

miles each way). The Bass Basin has been the site of a series of gas and oil

shows and discoveries, including the Yolla Field, which is adjacent to Block

T27P. The Yolla Field was discovered by Amoco in the mid-1980's and has not yet

been 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 2D seismic program in the

block. The remaining work commitment in the block consists of a 3D seismic

survey and two exploratory wells. Globex has selected a drillable prospect some

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 be

approximately $5.0 million. As suitable drilling rigs are not available in the

near term, Globex has applied for a permit extension in the block until a

suitable rig can be contracted.

In March 1996, the Company acquired a six-month option to purchase its

interest in the block for $250,000 and exercised that option in September 1996.

Pursuant to the terms of the option agreement, the Company may elect to farmout

up to 50% of its interest in the Bass Basin Permit. In addition, if Globex

Exploration and the other interest holders seek to enter into a farmout, the

Company has agreed to participate proportionally with such parties in such

farmout provided that its interest may not be reduced below 10%.



16

<PAGE>

PAPUA NEW GUINEA

The Company holds 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.

Past exploration activity within PPL-182 has resulted in the acquisition of

seismic data and the drilling of several exploration wells. The Company's first

year work program consisted of a geological and geophysical review of existing

data. The Company has entered into an Agreement with ARCO Papua New Guinea Inc.

("ARCO") for a farmout of its interest whereby ARCO will fund the Company's

obligation for the twelve month period to July 1998 for an 80% interest in the

subject exploration permit. In future periods, the Company has no obligation to

expend funds but may be subject to a forfeiture of its interest should the

Company decide not to continue to fund its remaining 20% interest.

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 and the

present value of estimated future net revenues before income taxes related to

such reserves as of December 31, 1997. Estimated net proved oil and gas reserves

and the estimated future net cash flows attributable thereto is based upon a

report from Ryder Scott Company Petroleum Engineers. All calculations of

estimated net proved reserves have been made in accordance with the rules and

regulations of the Securities and Exchange Commission. The present value of

estimated future net revenues has been calculated using a discount factor of

10%.

AS OF

DECEMBER

31, 1997

------------Total net proved:

Oil (MBbls)...................................

Gas (MMcf)....................................

Total (MBOE) .................................



32,160

32,160



Net proved developed:

Oil (MBbls)...................................

Gas (MMcf)....................................

Total (MBOE) .................................



11,494

11,494



Estimated future net revenues before

income taxes (in thousands) (2)..............



$241,700



Present value of estimated future net revenues

before income taxes (in thousands) (1)(2).....



$144,866



Standardized measure of discounted future net

Cash flows (in thousands) (3).................

$100,617

--------------------------------------------------------------(1) The present value of estimated future net revenues attributable to the

Company's reserves was prepared using constant prices as of the calculation

date, discounted at 10% per annum on a pre-tax basis.

(2) Calculated using an average oil price of $10.15 per barrel.

(3) The standardized measure of discounted future net cash flows represents the

present value of estimated future net revenues after income tax discounted

at 10%.

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 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,

17

<PAGE>

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.

PRODUCTIVE WELLS

The following table sets forth the productive oil and gas wells owned by the

Company as of December 31, 1997:

WELLS(1)

----------------------------------OIL

GAS

---------------------------GROSS

NET

GROSS

NET

------------Colombia........

3

1.7

0

0



Total...........



3



1.7



0



0



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

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, 1997:

ACREAGE SUMMARY

AS OF DECEMBER 31,1997

---------------------------------------------------GROSS ACRES

NET ACRES(1)

----------------------------------------------DEVELOPED UNDEVELOPED

DEVELOPED UNDEVELOPED

Colombia:

Rio Seco/Dindal..........

Montecristo/Rosablanca...

Tapir....................

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

Australia..................

Total....................

(1)



14,459

14,459

========



94,579

692,179

232,613

1,200,000

2,394,546

--------4,613,917

=========



8,343

8,343

=====



54,572

519,134

27,623

1,200,000

429,978

------2,231,307

=========



Net acres based on the Company's respective working interest.

See "-- Properties".



DRILLING ACTIVITY

The following table sets forth the number of wells drilled by the Company

since its inception:

<TABLE>

<CAPTION>

EXPLORATORY

DEVELOPMENT

------------------------------------------------------------------PRODUCTIVE

DRY

PRODUCTIVE

DRY

----------------------------------------------------GROSS

NET

GROSS

NET

GROSS

NET

GROSS

NET

------------------------<S>

<C>

<C>

<C>

<C>

<C>

<C>

<C>

<C>

Year ended December 31, 1997:

Colombia ..................

3

1.731

0

0

0

0

0

0

Year ended December 31, 1996:

Colombia ..................

2

1.154

0

0

0

0

0

0

Argentina .................

0

0

1

.25

0

0

0

0

Year ended December 31, 1995:

Australia .................

0

0

1

.1

0

0

0

0

</TABLE>

Since December 31, 1997, the Company has drilled 0 gross productive

exploratory wells (0 net to the Company), 1 gross nonproductive exploratory well

(.577 net to the Company), 0 gross productive development wells (0 net to the

18

<PAGE>

Company and 0 gross nonproductive development wells. In addition, the Company is

currently drilling 0 gross development wells and testing 1 gross exploratory

well.

GATHERING AND DISTRIBUTION SYSTEM

Transportation and marketing of crude oil to be produced from Emerald

Mountain is expected to be achieved through the construction of a 36 mile

pipeline northwest from Emerald Mountain to the existing OAM pipeline, a

regulated common carrier, at the town of La Dorado along the Magdalena River

Valley. This pipeline, which is part of the Company's Phase I development plan,

will have the capacity for 250,000 barrels per day but will be constrained by

the existing capacity of 50,000 barrels per day on the OAM pipeline. Through the

OAM pipeline, Emerald Mountain's production will be transported to pipeline

terminal and storage facilities at Vasconia approximately 45 miles north of La

Dorado. At Vasconia, crude oil from Emerald Mountain may then be shipped through

the existing ODC and OCENSA pipelines, regulated common carriers, to the port

city of Covenas on the Caribbean Sea for loading, export and sale. To avoid the

capacity constraints on the OAM pipeline, the Company intends to build its Phase

II pipeline from the end of its Phase I pipeline in La Dorado in Vasconia, where

it will be able to utilize approximately 250,000 barrels per day of currently

available capacity on the ODC and OCENSA pipelines.

Phase I of the transportation plan provides for the construction of a

pumping station, storage facility and 24 inch buried pipeline from the center of

the project north and then northwesterly to connect to the OAM pipeline. The

total cost of infrastructure and pipeline construction of the Phase I

transportation plan is estimated to be $97.9 million and the Company's share of

such costs is estimated to be $34.2 million. Phase I is scheduled to be

completed by the end of the second quarter of 1999.

Phase II of the transportation plan provides for the construction of a new

24 inch pipeline parallel to the existing OAM pipeline along the 45 miles from

La Dorado to Vasconia. The completion of Phase II is scheduled to occur by the

end of the first quarter of 2000 and is designed to provide capacity for

approximately 250,000 barrels per day at a total cost of about $85.8 million

with the Company's share at $24.8 million.

Specifications, planning and engineering studies for the planned pipeline



and associated pumping stations to be constructed from Emerald Mountain to

Vasconia are being conducted by Brown & Root Energy Services and Technivance

Brown & Root S.A., subsidiaries of Halliburton Inc. Construction of additional

pipelines beyond Phase I depends upon the availability of excess capacity on

existing pipelines and the completion of satisfactory contractual arrangements

with respect to such capacity.

Oil produced from the Dindal block to date under the long-term production

tests has been sold to Ecopetrol. 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.

REGULATION

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. In addition, various international laws and

regulations covering the discharge of materials into the environment, the

disposal of oil and gas wastes, or otherwise relating to the protection of the

environment, may affect the Company's operations and costs. 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.

19

<PAGE>

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 integrated oil and gas companies

and 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

concessions 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 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.

EMPLOYEES

At December 31, 1997 the Company had 33 full time employees, primarily

professionals, including geologists, geophysicists, and engineers.

ITEM 3.



LEGAL PROCEEDINGS



There are no material legal proceedings to which the Company is a party or

to which any of its property is subject.

ITEM 4.



SUBMISSION OF MATTERS TO VOTE



None

20

<PAGE>

PART II

ITEM 5.



MARKET FOR REGISTRANTS COMMON EQUITY



The Company's Common Shares have been listed on the American Stock Exchange

under the ticker "SEV" since January 9, 1998 and the Toronto Stock Exchange

("TSE") in Toronto, Ontario, Canada under the ticker "SVS.U" since February 10,

1997. From June 30, 1995 through February 7, 1997, the Company's Common Shares

traded on the Canadian Dealer Network under the symbol "SVS.U". The following

table summarizes the high and low closing prices as reported on the Canadian

Dealer Network for each quarterly period since the commencement of trading on

through February 7, 1997 and the high and low sales prices as reported on the

TSE from February 10, 1997 through December 31, 1997. The prices listed below

are stated in U.S. dollars, which is the currency in which they were quoted:

HIGH

---1996

First Quarter ...............................

Second Quarter ..............................

Third Quarter ...............................

Fourth Quarter ..............................

1997

First Quarter (through February 7,1997) .....

First Quarter (since February 10, 1997) .....

Second Quarter ..............................

Third Quarter ...............................

Fourth Quarter ..............................

ITEM 6.



SELECTED FINANCIAL DATA



LOW

---



TOTAL

VOLUME

------



6.75

10.50

20.00

25.75



0.55

5.25

7.00

14.75



8,402,885

1,974,615

6,655,958

8,537,978



19.00

17.40

13.10

14.10

20.05



15.00

9.00

8.25

9.60

11.80



3,018,441

3,718,929

3,200,200

3,941,940

7,541,766



The following selected financial data should be read in conjunction with

the Consolidated Financial Statements and Notes thereto included herein:



INCOME STATEMENT DATA:

Revenues............................

Net loss............................

Net loss per common share...........

Weighted average shares outstanding.

BALANCE SHEET DATA (END OF PERIOD):

Cash and cash equivalents...........

Total assets........................

Current liabilities.................

Minority interest...................

Stockholders' equity................



PERIOD FROM

INCEPTION

FEBRUARY 3,

YEAR ENDED DECEMBER 31,

1995 TO

----------------------DECEMBER 31,

1997

1996

1995

---------(in thousands, except per share amounts)

$ 1,567

$ 575

$ 152

(7,928)

(2,195)

(2,120)

(0.24)

(0.17)

(0.23)

32,505



12,972



9,247



$ 18,067

291,914

8,205

4,087

184,163



$ 10,620

235,501

2,806

1,060

167,667



$ 3,366

4,170

120

-4,050



21

<PAGE>

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

RESULTS OF OPERATIONS

Seven Seas is an independent international energy company engaged in the

exploration, development and production of oil and natural gas in Colombia. The

Company is the operator of an oil discovery ("Emerald Mountain") held by two

adjoining association contracts covering 109,000 acres in central Colombia. The

Company has focused its efforts on delineating the oil and gas potential of

Emerald Mountain. The Company also has interests in three additional association

contracts in Colombia, which, together with the Emerald Mountain association

contracts, cover over one million gross acres. The Company also has certain

other interests in Australia and Papua New Guinea. As a result of its focus on

its Colombian properties, the Company is in the process of divesting or farming

out its oil and gas interests in Australia and Papua New Guinea.

TERMS OF ASSOCIATION CONTRACTS AND RELATED MATTERS

The Company has a 57.7% working interest (before Colombian government

participation) in the Association Contracts. The Colombian government receives a

royalty equal to 20% of production (after transportation costs are deducted). In

the event of commerciality, Ecopetrol has the right to acquire an initial 50%

working interest in the project. If a commercial field produces in excess of 60

million barrels, Ecopetrol's interest in production and costs will increase to a

maximum interest of 70% in Dindal and 75% in Rio Seco depending upon production

from Emerald Mountain. Until commercial production is initiated, the Company

expects that the working interest owners will fund all costs associated with the

initiation of commercial production and that, upon such initiation, Ecopetrol's

50% share of such costs will be repaid through proceeds from their share of

production.

To date, all oil produced has been from production testing on Emerald

Mountain. Upon Ecopetrol's acceptance of commerciality of the Company's

discovery, oil produced from the Dindal and Rio Seco blocks 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.

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%.

ACCOUNTING POLICIES

ACCOUNTING PRINCIPLES. The Consolidated Financial Statements and Notes

thereto included herein have been prepared in accordance with generally accepted

accounting principles in the United States ("US GAAP"). As a consequence to the

Company's listing on the Toronto Stock Exchange, the Company is required to file

an Annual Information Form with the Ontario Securities Commission with its

Consolidated Financial Statements and Notes thereto, prepared in accordance with

Canadian generally accepted accounting principles ("Canadian GAAP"). To meet its

financial reporting and disclosure requirements in Canada, the Company will file

this document with its Consolidated Financial Statements and Notes thereto

prepared in accordance with Canadian GAAP. The Consolidated Financial Statements

and Notes prepared in accordance with Canadian GAAP do not require certain

entries discussed below or development stage presentation which the Company has

made to conform to US GAAP. The Company recorded deferred income tax liabilities

relating to the acquisitions of GHK Company Colombia, Esmeralda LLC, and 62.963%

of Cimarrona LLC in 1996 and Petrolinson, S.A. on March 5, 1997 pursuant to US

GAAP. The credit to deferred income tax liabilities and the corresponding

increase in unevaluated oil and gas interests amounted to $70,458,512 and

$63,967,775 as of December 31, 1997 and December 31, 1996, respectively. These

liabilities for deferred income taxes recorded in 1997 and 1996 would not be

required by Canadian GAAP. In addition, 1997 general and administrative expense

includes compensation expense of $2,140,250 relating to a change in the exercise

period of stock options held by former executives. Recognition of such expense

would not be required by Canadian GAAP.

DEVELOPMENT STAGE ACCOUNTING. The Company's exploration and development



activities have generated an insignificant 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

22

<PAGE>

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 the current period 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

financial statements are required to identify the enterprise as development

stage. The Company will cease presentation as a development stage enterprise

when significant revenues from planned operations are generated.

OIL AND GAS PROPERTIES. 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 employee costs related to exploratory and

property evaluation efforts of $140,628. No such costs were capitalized during

1997. The Company capitalized interest of $600,000 in 1997.

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 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.

As of December 31, 1997, the Company's historical results of operations have

been presented as a development stage company under US GAAP; 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 materially dependent upon the success of the Company's

Emerald Mountain operations.

RESULTS OF DEVELOPMENT STAGE OPERATIONS

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 on

Emerald Mountain, which comprised four wells in 1997 and two wells in 1996.

Revenues from oil sales were $779,767, $233,682, and $ -0- in 1997, 1996, and

for the period from inception on February 3, 1995 to December 31, 1995 (the

"1995 Period"), respectively. Lease operating expenses were $907,218 and

$252,504 in 1997 and 1996, respectively.

Interest income increased from $341,599 in 1996 to $787,189 in 1997. The

increase was the consequence of higher cash balances resulting from the private

placements of the Company's securities. The increase from $152,383 for the 1995

Period to $341,599 for the year ended December 31, 1996 was also the consequence

of higher cash balances resulting from private placements of the Company's

securities.

General and administrative costs under US GAAP were $8,714,333 in 1997 as

compared to $2,454,884 for 1996. The increase 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 added to its professional staff in the U. S. and Colombia.

General and administrative costs increased from $1,070,765 for the 1995 Period

to $2,452,546 for the year ended December 31, 1996 primarily as a result of a

full year of expenses incurred by the Company in 1996 as compared to 1995, and

the increase in activities associated primarily with the acquisition of GHK

Company Colombia, Esmeralda LLC, and Cimarrona LLC.

Depreciation and amortization increased from $111,334 for the year ended

December 31,1996 to $148,065 for the year ended December 31, 1997. The increase

was primarily attributable to the amortization of costs incurred in issuing the

Special Notes in August 1997 (see "-Liquidity and Capital Resources" below).

Depreciation and amortization increased from $37,671 for the 1995 Period to

$111,334 for the year ended December 31, 1996 primarily as a result of the

23

<PAGE>

acquisitions mentioned above and the inclusion of a full year of expenses

incurred by the Company in 1996 as compared to 1995. As of December 31, 1997,

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.

The Company incurred net losses of $7.9 million and $2.2 million for the

years ended December 31, 1997 and 1996, respectively, and $2.1 million for the



1995 Period.

LIQUIDITY AND CAPITAL RESOURCES

The Company's activities have been funded primarily by the proceeds from

private placements of the Company's securities from inception through December

1997, resulting in aggregate cash proceeds of $47.0 million. In 1996, the

Company acquired an additional 36.7% interest in the Association Contracts in

Colombia in exchange for the issuance of the Company's securities valued at

$153.1 million in the aggregate. From inception through December 31, 1997, the

Company had capital expenditures of $22.4 million for the acquisition,

exploration, and development of its oil and gas properties including $20.3

million with respect to its interests in Colombia and approximately $2.1

million, of which $1.1 million has been expensed, with respect to its interests

in other countries. Such expense included $500,800 for the cost of an option to

acquire a 5% participating interest in three exploration blocks in North Africa

and $622,006 associated with a dry hole in the San Jorge Basin, Argentina. The

Company's activities in North Africa and Argentina have been discontinued.

The Company's primary capital commitments include Phases I and II of its

development program. The Company's capital expenditures estimated for Phase I

include $16.2 million for field development and delineation and $34.2 million

for pipeline and production facilities. The Company's capital expenditures

estimated for Phase II include $63.4 million for field development and

delineation and $24.8 million for pipeline and production facilities. The

Company may finance its operations and investments through the issuance of

public and private debt, equity, and convertible securities, as well as through

commercial banking credit facilities. However, there can be no assurance that

debt or equity financing will be available to the Company on economically

acceptable terms. If sufficient funds are not available 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 forfeit

its interest in such property.

COLOMBIA. During the remainder of 1998, the Company plans to drill a total

of seven additional wells on the Dindal and Rio Seco blocks, construct a 36-mile

pipeline to provide transportation capacity of 50,000 barrels per day, conduct

seismic operations, and carry out other development activities for an aggregate

estimated cost of $67.6 million. The pipeline is scheduled for completion in

mid-1999. An exploratory well on the Company's non-operated Tapir Block in

Colombia commenced drilling in March 1998. The Company's share of budgeted costs

are approximately $400,000.

For the years ended December 31, 1997 and 1996, the Company had oil sales of

$779,767 and 233,682, respectively, solely from production testing of the

Company's wells on Emerald Mountain, which comprised four wells in 1997 and two

wells in 1996. Although the Company intends to continue to sell oil resulting

from production tests; significant production is not expected until further

evaluation and development of the field through the drilling of additional wells

and construction of producing facilities and pipelines. The Company has received

preliminary plans for the construction of pipelines and producing facilities,

and permitting and final planning for pipelines and production facilities is now

proceeding. Completion of the first phase of these facilities is scheduled for

mid-1999.

AUSTRALIA AND PAPUA NEW GUINEA. The Company is in the process of eliminating

any mandatory capital commitments outside of Colombia. In Papua New Guinea, the

Company signed a farm-out agreement with ARCO Papua New Guinea Inc. whereby the

Company will retain a 20% carried interest with no required capital

expenditures. In the Western Perth Basin in Australia, the Company has signed a

purchase and sale agreement with Forcenergy International Inc. in which the

Company will exchange its 11.77% working interest for $850,000. The Company will

retain a small overriding interest and will also be reimbursed $263,000 for

certain capital expenditures. The agreement is pending its final approval by an

aboriginal council in West Australia. In the Bass Strait Basin in Australia, the

Company is seeking to farm-out its interests. The Company has no required

capital commitments for this prospect.

24

<PAGE>

CONVERTIBLE DEBENTURES. In August 1997, the Company issued $25 million of

Special Notes in a private transaction with institutional and accredited

investors. Interest on the Special Notes is payable in arrears at a rate of 6%

per annum on December 31 and June 30 in each year until maturity, commencing on

December 31, 1997.

The Special Notes are exchangeable for a like principal amount of

convertible redeemable debentures (the "Convertible Debentures") on the earlier

occurring of (i) the effectiveness of a registration statement under the

Securities' Act of 1933 as Amended (the "Securities Act") covering the resale of

the Convertible Debentures and compliance with certain Canadian securities

requirements, and (ii) August 7, 1998. The Convertible Debentures are

convertible into Units totaling 2,173,913 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 expire on August 7, 1998. Upon exercise of all of

the warrants, the Company will receive proceeds of $16 million. The Convertible

Debentures are convertible into common shares at the option of the Company if a

registration statement of the common shares has been declared effective under

the Securities Act and has been effective during the seven day notice period

required to be given by the Company to the holders of the Convertible Debentures

of its intent to exercise its conversion rights, provided that the Company's

shares have traded at or above U.S. $14.00 per share for 20 consecutive trading

days on the Toronto Stock Exchange. The Company intends to file a registration

statement covering the common shares in April 1998. The Special Notes and

Debentures are secured by a pledge of shares of certain of the subsidiaries of

the Company and are guaranteed by Seven Seas Petroleum Holdings Inc.



25

<PAGE>

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

<TABLE>

<CAPTION>

Index to Consolidated Financial Statements



PAGE



Seven Seas Petroleum Inc. and Subsidiaries

<S>

Report of Independent Public Accountants................................



F-1



Consolidated Balance Sheets as of December 31, 1997 and 1996............



F-2



Statements of Consolidated Operations for the years ended

December 31, 1997 and 1996 and from Inception (February 3,

1995) to December 31, 1995............................................



F-3



Statements of Consolidated Stockholders' Equity

for the years ended December 31, 1997 and 1996 and from

Inception (February 3, 1995) to December 31, 1995......................



F-4



Statements of Cash Flows for the years ended December 31, 1997 and 1996

and from Inception (February 3, 1995) to

December 31, 1995.....................................................



F-5



Notes to Financial Statements...........................................

</TABLE>



<C>



F-6



26

<PAGE>

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Stockholders of 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)

and subsidiaries as of December 31, 1997 and 1996, and the related consolidated

statements of operations and accumulated deficit, stockholders' equity and cash

flows for the years then ended and for the period from inception (February 3,

1995) to December 31, 1995. 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, 1997 and 1996, and the results of their

operations and their cash flows for the years then ended and for the period from

inception (February 3, 1995) to December 31, 1995 in conformity with generally

accepted accounting principles.

Arthur Andersen LLP

Houston, Texas

February 27, 1998

F-1

<PAGE>

SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES

(A DEVELOPMENT STAGE ENTERPRISE)

CONSOLIDATED BALANCE SHEETS

<TABLE>

<CAPTION>

DECEMBER 31,

1997

-------------ASSETS

<S>

CURRENT

Cash and cash equivalents

Marketable securities

Accounts receivable

Prepaids and other



Note receivable from related party

Evaluated oil and gas interests, full-cost method

Unevaluated oil and gas interests, full-cost method

Fixed assets, net of accumulated depreciation of $42,716 at

December 31, 1997 and $12,194 at December 31, 1996

Other assets, net of accumulated amortization of $194,166

at December 31, 1997 and $76,622 at December 31, 1996

TOTAL ASSETS

LIABILITIES AND STOCKHOLDERS' EQUITY



DECEMBER 31,

1996

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



<C>



<C>



$ 18,067,189

43,795

3,865,180

118,447

-----------22,094,611



$ 10,620,477

43,795

1,241,430

-----------11,905,702



200,000

46,116,873

221,713,473



1,611,665

221,884,126



303,623



74,219



1,485,544

-----------$ 291,914,124

=============



25,270

-----------$ 235,500,982

=============



CURRENT

Accounts payable

Accrued compensation

Other accrued liabilities



$ 6,885,573

1,228,000

91,917

------8,205,490



Long-term debt

Deferred income taxes

Minority interest

Commitents and Contengencies (Note 10)

STOCKHOLDERS' EQUITY

Share capital - Authorized unlimited common shares without par value and

unlimited Class A preferred shares without par value;

35,071,606 and 13,315,796 issued and outstanding common shares

at December 31, 1997 and December 31, 1996, respectively

Preferred share subscriptions - 5,002,972 shares at

December 31, 1996

Special warrant subscriptions - 14,274,171 warrants at

December 31, 1996

Deficit accumulated during development stage

Treasury stock, 29 shares held at December 31, 1997 and

December 31, 1996

Total Stockholders' Equity

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY



$ 2,560,665

245,000

------2,805,665



25,000,000

70,458,512

4,087,022

--



63,967,775

1,060,433

--



196,405,889



6,781,616



-



45,652,120



(12,242,557)



119,548,227

(4,314,622)



(232)

----184,163,100

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



(232)

----167,667,109

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



$ 291,914,124

==============



$ 235,500,982

=============



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

</TABLE>

F-2

<PAGE>

STATEMENTS OF CONSOLIDATED OPERATIONS AND ACCUMULATED DEFICIT

<TABLE>

<CAPTION>



YEAR ENDED DECEMBER 31,

----------------------1997

1996

------<C>



<S>

<C>

REVENUE

Crude oil sales

Interest income



EXPENSES

General and administrative

Lease operating expenses

Depreciation and amortization

Dry hole and abandonment costs

Geological and geophysical

Other (income) expense

Loss on sale of resource properties



NET LOSS BEFORE MINORITY INTEREST

MINORITY INTEREST

NET LOSS

DEFICIT ACCUMULATED DURING THE

DEVELOPMENT STAGE , BEGINNING OF PERIOD

DEFICIT ACCUMULATED DURING THE

DEVELOPMENT STAGE , END OF PERIOD

BASIC AND DILUTED NET LOSS PER COMMON SHARE

WEIGHTED AVERAGE

COMMON SHARES OUTSTANDING



$ 779,767

787,189

--------1,566,956



$ 233,682

341,599

---------575,281



8,714,333

907,218

148,065

16,952

27,372

(25,331)

--------9,788,609



2,454,884

252,504

111,334

4,910

10,521

---------2,834,153



PERIOD FROM INCEPTION

(FEBRUARY 3, 1995)

TO DECEMBER 31,

--------------1995

---<C>

$



152,383

--------152,383



CUMULATIVE

TOTAL FROM INCEPTION

(FEBRUARY 3, 1995)

TO DECEMBER 31,

--------------1997

---<C>

$ 1,013,449

1,281,171

---------2,294,620



1,070,765

37,671

1,122,806

9,769

31,357

--------2,272,368



12,239,982

1,159,722

297,070

1,144,668

47,662

(25,331)

31,357

---------14,895,130



(8,221,653)



(2,258,872)



(2,119,985)



(12,600,510)



293,718

--------$ (7,927,935)

=============



64,235

---------$ (2,194,637)

=============



--------$ (2,119,985)

=============



357,953

---------$ (12,242,557)

==============



(4,314,622)



(2,119,985)



$ (12,242,557)

==============

$ (0.24)

========



$ (4,314,622)

=============

$ (0.17)

========



$ (2,119,985)

=============

$ (0.23)

========



32,504,872

===========



12,971,871

===========



9,247,101

==========



-



$ (12,242,557)

==============

$ (0.66)

========

18,515,541

==========



</TABLE>

The accompanying notes are an integral part of these financial statements

F-3

<PAGE>

STATEMENT OF CONSOLIDATED STOCKHOLDERS' EQUITY

FOR THE PERIOD FROM INCEPTION (FEBRUARY 3, 1995) THROUGH DECEMBER 31, 1997

<TABLE>

<CAPTION>

DATE

----



COMMON STOCK

----------------------NUMBER

AMOUNT

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



<S>

<C>

Issuance of common

Issuance of common

Issuance of common

($0.25 per share)

Issuance of common

($0.75 per share):



<C>

share to founder

shares to founder for cash

shares in a private placement for cash



February 3, 1995

February 27, 1995



<C>

1

999,999



$ 1



March 22, 1995



4,000,000



1,000,000



May 31, 1995

June 9, 1995



5,687,666

979,000



4,265,750

734,250



shares in private placements for cash



Issuance of common shares in settlement of agents' fees

($0.75 per share):

Less: Common share issuance cost

Issuance of common shares in connection with the May 5, 1995

amalgamation agreement with Rusty Lake Resouces ($0.25 per share)

Net loss



May 31,1995

June 9, 1995

May 31 - June 9, 1995

June 29-30, 1995



680,464

---------12,680,463



BALANCE AT DECEMBER 31, 1995

Issuance of special warrants in a brokered private placement for cash

($2.75 per warrant)

Issuance of common shares to the Company's 401(k) plan

($7.875 per share)

Purchase Treasury Stock ($8.00 per share)

Exercise of stock options for cash ($.75 per share)

Exercise of stock options for cash ($7.125 per share)

Issuance of exchangeable preferred stock in connection with business

combination ( $9.125 per share)

Issuance of special warrants in connection with business combination

( $9.125 per warrant)

Issuance of convertible special warrants in a brokered private placement

for cash ($15.00 per warrant)

Exercise of stock options for cash ($.75 per share)

Net loss



March 15, 1996



-



April 29,1996

June 26, 1996

Jan. - June 1996

April 29, 1996



213,287

36,713

(250,000)

170,116

--------6,170,117

-



10,000

305,000

10,000



78,750

228,750

71,250



July 26, 1996



-



-



July 26, 1996



-



-



October 16, 1996

July - December 1996



310,333

---------13,315,796



232,749

--------6,781,616



February 7, 1997



11,774,171



107,439,309



February 7, 1997

February 7, 1997

February 7, 1997



5,002,972

500,000

2,000,000



45,652,120

7,013,370

5,095,548



March 5, 1997



1,000,000



18,550,000



BALANCE AT DECEMBER 31, 1996

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)

Conversion of privately placed special warrants for cash

($3.50 per warrant)

Exercise of stock options ($.75 - 10.90 per share)

Net loss



284,383

48,950

-



March 14, 1997

Jan.-December 1997



1,000,000

478,667

--------------35,071,606

===============



BALANCE AT DECEMBER 31, 1997



3,500,000

2,373,926

------------$ 196,405,889

=============



<PAGE>

STATEMENT OF CONSOLIDATED STOCKHOLDERS' EQUITY

FOR THE PERIOD FROM INCEPTION (FEBRUARY 3, 1995) THROUGH DECEMBER 31, 1997

(Continued)



Issuance of common

Issuance of common

Issuance of common

($0.25 per share)

Issuance of common

($0.75 per share):



share to founder

shares to founder for cash

shares in a private placement for cash



PREFERRED STOCK

-------------------NUMBER

AMOUNT

----------$ -



SPECIAL WARRANTS

--------------------NUMBER

AMOUNT

----------$ -



-



-



-



-



-



-



-



-



-



-



-



-



-



-



-



-



-



-



-



-



-



-



-



-



shares in private placements for cash



Issuance of common shares in settlement of agents' fees

($0.75 per share):

Less: Common share issuance cost

Issuance of common shares in connection with the May 5, 1995

amalgamation agreement with Rusty Lake Resouces ($0.25 per share)

Net loss

BALANCE AT DECEMBER 31, 1995

Issuance of special warrants in a brokered private placement for cash

($2.75 per warrant)

Issuance of common shares to the Company's 401(k) plan

($7.875 per share)

Purchase Treasury Stock ($8.00 per share)

Exercise of stock options for cash ($.75 per share)

Exercise of stock options for cash ($7.125 per share)

Issuance of exchangeable preferred stock in connection with business

combination ( $9.125 per share)

Issuance of special warrants in connection with business combination

( $9.125 per warrant)

Issuance of convertible special warrants in a brokered private placement

for cash ($15.00 per warrant)

Exercise of stock options for cash ($.75 per share)

Net loss

BALANCE AT DECEMBER 31, 1996



5,002,972



45,652,120



2,000,000



5,095,548



-



-



-



-



-



-



11,774,171



107,439,309



-



-



500,000

-



7,013,370

-



14,274,171



119,548,227



5,002,972



45,652,120



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)

Conversion of privately placed special warrants for cash

($3.50 per warrant)

Exercise of stock options ($.75 - 10.90 per share)

Net loss

BALANCE AT DECEMBER 31, 1997



-



-



(5,002,972)

-



(45,652,120)

-



-



(11,774,171)



(107,439,309)



(500,000)

(2,000,000)



(7,013,370)

(5,095,548)



-



----------===========



-



----------$ ===========



-



----------===========



-----------$ ============



<PAGE>

STATEMENT OF CONSOLIDATED STOCKHOLDERS' EQUITY

FOR THE PERIOD FROM INCEPTION (FEBRUARY 3, 1995) THROUGH DECEMBER 31, 1

(Continued)



Issuance of common

Issuance of common

Issuance of common

($0.25 per share)

Issuance of common

($0.75 per share):



DEFICIT

ACCUMULATED

DURING

DEVELOPMENT

PHASE

----$ -



TREASURY STOCK

----------------NUMBER

AMOUNT

----------$ -



share to founder

shares to founder for cash

shares in a private placement for cash



TOTAL

----$ 1



-



-



-



1,000,000



-



-



-



4,265,750

734,250



-



-



-



-



-



(2,119,985)



170,116

(2,119,985)



-



-



(2,119,985)



4,050,132



-



-



shares in private placements for cash



Issuance of common shares in settlement of agents' fees

($0.75 per share):

Less: Common share issuance cost

Issuance of common shares in connection with the May 5, 1995

amalgamation agreement with Rusty Lake Resouces ($0.25 per share)

Net loss

BALANCE AT DECEMBER 31, 1995

Issuance of special warrants in a brokered private placement for cash

($2.75 per warrant)

Issuance of common shares to the Company's 401(k) plan

($7.875 per share)

Purchase Treasury Stock ($8.00 per share)

Exercise of stock options for cash ($.75 per share)

Exercise of stock options for cash ($7.125 per share)

Issuance of exchangeable preferred stock in connection with business

combination ( $9.125 per share)

Issuance of special warrants in connection with business combination

( $9.125 per warrant)

Issuance of convertible special warrants in a brokered private placement

for cash ($15.00 per warrant)

Exercise of stock options for cash ($.75 per share)

Net loss

BALANCE AT DECEMBER 31, 1996



29

-



BALANCE AT DECEMBER 31, 1997



(232)

-



-



5,095,548

78,750

(232)

228,750

71,250



-



-



-



45,652,120



-



-



-



107,439,309



-



-



29



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)

Conversion of privately placed special warrants for cash

($3.50 per warrant)

Exercise of stock options ($.75 - 10.90 per share)

Net loss



-



213,287

36,713

(250,000)



(2,194,637)



(232)



(4,314,622)



7,013,370

232,749

(2,194,637)

167,667,109



-



-



-



-



-



-



-



-



-



-



-



----29

=====



------$ (232)

=======



(7,927,935)

----------$ (12,242,557)

===========



18,550,000

3,500,000

2,373,926

(7,927,935)

----------$ 184,163,100

============



</TABLE>

The accompanying notes are an integral part of these financial statements

F-4

<PAGE>

STATEMENTS OF CONSOLIDATED CASH FLOWS

<TABLE>

<CAPTION>



<S>

<C>

OPERATING ACTIVITIES



YEAR ENDED DECEMBER 31,

----------------------1997

1996

------<C>



PERIOD FROM

CUMULATIVE TOTAL

INCEPTION

FROM INCEPTION

(FEBRUARY 3, 1995) (FEBRUARY 3, 1995)

TO DECEMBER 31,

TO DECEMBER 31,

1995

---<C>



1997

---<C>



Net loss

Add (subtract) items not requiring (providing) cash:

Compensation Expense

Minority interest

Common stock contribution to 401(k) retirement plan

Dry hole and abandonment costs

Loss on sale of resource properties

Depreciation and amortization

Changes in working capital excluding changes to

cash and cash equivalents:

Accounts receivable

Prepaids and other, net

Accounts payable

Other accrued liabilities

Cash Flow Used in Operating Activities

INVESTING ACTIVITIES

Exploration of oil and gas properties

Proceeds from acquisition

Proceeds from sale of property

Note Receivable from related party

Other asset additions

Cash Flow Used in Investing Activities

FINANCING ACTIVITIES

Proceeds from special warrants issued

Proceeds from share capital issued

Proceeds from additional paid-in capital contributed

Proceeds from issuance of special notes

Costs of issuing special notes

Contributions by minority interest

Purchase of treasury stock

Cash Flow Provided by Financing Activities

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

Cash and cash equivalents, beginning of period

CASH AND CASH EQUIVALENTS, END OF PERIOD



$ (7,927,935)



$ (2,194,637)



2,140,250

(293,718)

16,952

148,065



(64,235)

78,750

111,334



(2,082,750)

(118,447)

1,389,194

(153,083)

-----------(6,881,472)

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



(316,431)

482

(17,472)

245,000

----------(2,157,209)

-----------



(43,642)

(482)

120,305

----------(851,970)

-----------



(2,442,823)

(118,447)

1,492,027

91,917

-----------(9,890,651)

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



(16,359,726)

(200,000)

(280,194)

-----------(16,839,920)

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



(4,309,446)

630,226

(64,135)

----------(3,743,355)

-----------



(1,696,943)

84,336

(169,821)

----------(1,782,428)

-----------



(22,366,115)

630,226

84,336

(200,000)

(514,150)

-----------(22,365,703)

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



4,961,726

25,000,000

(1,572,929)

2,779,307

-----------31,168,104

-----------7,446,712

10,620,477

-----------$ 18,067,189

=============



12,108,917

532,750

999

513,004

(232)

----------13,155,438

----------7,254,874

3,365,603

----------$ 10,620,477

=============



6,000,001

----------6,000,001

----------3,365,603

----------$ 3,365,603

============



12,108,917

11,494,477

999

25,000,000

(1,572,929)

3,292,311

(232)

-----------50,323,543

-----------18,067,189

-----------$ 18,067,189

============



</TABLE>

The accompanying notes are an integral part of these financial statements

F-5

<PAGE>

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 engaging in acquisition,

exploration, and development of interests in oil and gas projects

worldwide. The Company's primary business operations to date have been

the exploration and development of its interests in Colombia, South

America.

The Company has yet to generate any significant revenue from oil and gas

sales and has no assurance of future revenues. The Company's principal

asset is its 57.7 percent working interest in the Dindal Association

Contract and Rio Seco Association Contract (collectively, the

"Association Contracts" or the "Emerald Mountain Project"). The

Association Contracts were issued by Empresa Colombiana de Petroleos

("Ecopetrol"), the National Oil Company of Colombia, in March 1993 and

August 1995, respectively, and entitle the Company to engage in

exploration, development, and production activities in Colombia. In

1994, a predecessor to the Company drilled the Escuela #1, which was

non-commercial. The final exploratory wells completed to date on Emerald

Mountain have encountered an average 303 feet of net pay at verticle

depths between 6,000 and 7,500 feet. For the five wells when production

testing has been completed, actual per well production rate realized

ranged from 3,415 to 13,123 barrels per day with average in excess of

7,079 barrels per day. The Company plans to rapidly and efficiently

continue its field development and delineation drilling program and to

build the production facilities and pipeline infrastructure to allow its

production to reach existing transportation lines for access to export

markets.

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. The Company

has expended, and plans to expend, significant amounts of capital on the

acquisition and exploration of its properties, and most of such

properties have not been fully evaluated for hydrocarbon potential. The

exploration and development of current properties and any properties

acquired in the future are expected to require substantial amounts of

additional capital which the Company may be required to raise through

debt or equity financings, which might involve encumbering properties or

entering into arrangements where certain costs of exploration will be

paid by others to earn an interest in the property. Seven Seas' success



$ (2,119,985)

1,122,806

31,357

37,671



$ (12,242,557)

2,140,250

(357,953)

78,750

1,139,758

31,357

297,070



currently depends to a high degree on its activities in Colombia.

However, there are risks that result because the Company has acquired,

and intends to continue to acquire, interests in properties outside of

North America, in some cases in countries that may be considered

politically and economically unstable.

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 fair valued and

Rusty Lake Resources Ltd. has been prospectively reflected in the

Company's financial statements since June 29, 1995. The net assets of

Rusty Lake Resources Ltd. were recorded on the books of Seven Seas as

follows:

F-6



<PAGE>

Marketable securities

Goods and services tax receivable

Resource properties

Other assets (organization costs)

Accounts payable

Share capital (680,464 shares)



$



3,370

3,099

115,693

87,481

(39,527)

(170,116)



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 totaling $153,091,430. 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 $217,090,298 assigned to oil and

gas properties (which are subject to future evaluation based on further

appraisal drilling) 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, $63,967,775 of deferred Colombian and

U.S. income taxes was also recorded in this acquisition (see Notes 3 and

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, 1997 and 1996.

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. On July 26, 1997, one-third of

the 11,744,000 common shares or 3,914,667 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 stock. 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.

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. common stock. 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

F-7

<PAGE>

as described above. This six percent interest will be carried through

exploration by the other 94 percent participating interest parties. This

transaction has been 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 shares were recorded based on the weighted average

closing stock price of Seven Seas for the period beginning 30 days prior

to and 30 days subsequent to the date the Letter of Intent was signed,

November 22, 1996, or $18.55. This represents a transaction cost of

$18,550,000. Net assets acquired include $25,035,701 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, $6,490,737 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.

RECLASSIFICATION OF PRIOR PERIOD STATEMENTS

Consistent with the asset/liability method of accounting for income

taxes, the Company recorded deferred income tax liabilities relating to

the acquisitions of GHK Company Colombia, Esmeralda LLC, and 62.963% of

Cimarrona LLC in 1996 and Petrolinson, S.A. on March 5, 1997. The credit

to deferred income tax liabilities and the corresponding increase in

unevaluated oil and gas interests amounted to $70,458,512 and

$63,967,775 at December 31, 1997 and 1996, respectively. The nature of

the amounts recorded is described in Note 5. Certain adjustments have

been made to the 1996 net operating loss carryforward, deferred tax

assets, and the related valuation allowances, none of which affected

reported results of operations, as estimates used in the calculation of

the assets have been revised. Additionally, certain other minor

reclassifications have been made to conform to current reporting

practices.

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.

STATEMENT OF CASH FLOWS

Cash and cash equivalents include bank deposits and short-term

investments, which upon acquisition have a maturity of three months or

less. The Company made a cash payment for interest of $600,000 in 1997.

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. As described in Note 6, the Company

issued $25 million of convertible Special Notes, with a 6% stated

interest rate, which matures in 2003. It is not practical to estimate

the fair value of these Special Notes as a quoted market price has not

yet been obtained. The Company intends to file the required registration

statement in order to comply with the conversion option on these notes.

F-8



<PAGE>

MARKETABLE SECURITIES

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. 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, 1997 and

1996:

DECEMBER 31,1997

---------------Crude oil sales

Joint interest billing

Advances

Other



$



Total Accounts

Receivable



291,049

3,013,318

541,000

19,813

-----$ 3,865,180

=============



DECEMBER 31, 1996

----------------$



58,845

1,117,635

64,950

-----$

1,241,430

=============



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 $140,628. No such costs were

capitalized during 1997. The Company capitalized interest of $600,000 in

1997.

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.

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.

F-9

<PAGE>

INCOME TAXES

The Company follows the asset/liability method of accounting for income

taxes in accordance with Statement of Financial Accounting Standards

109, "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 normal cost of incorporating the

Company. In association with the amalgamation agreement with Rusty Lake



Resources Ltd., organization costs of $87,481 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.

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") and applies to entities with

publicly held common stock or potential common stock. 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. This

statement is effective for financial statements issued for periods

ending after December 15, 1997. The statement requires restatement of

all prior-period EPS data presented. Considering the guidelines as

prescribed by SFAS 128, the Company's adoption of this statement does

have a significant effect on EPS since the exercise or conversion of any

potential shares would be antidilutive and result in a lower loss per

share. Options to purchase 3,878,500 common shares at a weighted average

option exercise price of $13.15 per share were outstanding at December

31, 1997.

All shares issued in connection with the conversion of preferred shares

and special warrants 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.

4.



CASH AND CASH EQUIVALENTS:

DECEMBER 31,1997

---------------Cash

Short-term investments



$



Total cash and cash

equivalents



2,156,973

15,910,216

----------



$ 18,067,189

==============



DECEMBER 31, 1996

----------------$



170,684

10,449,793

---------$

10,620,477

==============



The carrying value of short-term investments approximates fair value.

F-10

<PAGE>

5.

INCOME TAXES:

The geographical sources of loss before minority interest were as

follows:

<TABLE>

<CAPTION>



<S>

United States

Foreign

Loss before Minority

interest



PERIOD ENDED

DECEMBER 31,1997

---------------<C>

$

(4,515,142)

(3,706,511)

-----------



PERIOD ENDED

DECEMBER 31, 1996

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



$

(8,221,653)

===============



$

(2,258,872)

================



(277,456)

(1,981,416)

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



PERIOD ENDED

DECEMBER 31, 1995

----------------<C>

(2,119,985)

----------$ (2,119,985)

==============



</TABLE>

No deferred taxes were recorded during the periods presented, as there

were no significant changes in the temporary differences between the

book and tax bases of assets and liabilities. Deferred U.S. and

Colombian income taxes have been provided for the book-tax basis

differences related to the Colombian acquisitions discussed further 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:

DECEMBER 31,1997

---------------Deferred Tax Liabilities

Deferred Tax Asset

Valuation Allowance

Total Deferred Tax

Liabilities



$



70,458,512

3,128,306

(3,128,306)

-----------



$

70,458,512

===============



DECEMBER 31, 1996

----------------63,967,775

2,058,506

(2,058,506)

----------$

63,967,775

==============



The Company did not record any current or deferred income tax provision

or benefit in any of the periods presented. The Company's provision for

income taxes differs from the amount computed by applying the statutory

rates, which are 45% in Canada and 35% in the United States and

Colombia, due pricipally to the valuation allowance recorded against its

deferred tax asset account relating primarily to net operating tax-loss

carryforwards.



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

$6,490,737 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, 1997 and 1996, the Company's subsidiaries had net

operating loss carryforwards in various foreign jurisdictions (primarily

Canada) of approximately $3,700,000 and $2,200,000, respectively. These

loss carryforwards will expire beginning in 2002 if not utilized to

reduce Canadian income taxes. In addition, the Company had during 1997

and 1996 approximately $1,537,000 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 deferred tax

assets resulting primarily from these loss carryforwards because their

future realization is not currently deemed probable by management.

6.



LONG-TERM DEBT

In August 1997, the Company issued $25 million of Special Notes in a

private transaction to institutional and accredited investors. Interest

on the Special Notes is due and payable in arrears at a rate of 6% per

annum on December 31 and June 30 in each year until maturity, commencing

on December 31, 1997. At the option of the Company, the Debentures are

convertible into common shares if a registration statement for resale of

the common shares has been declared effective under the Securities Act

of 1993, as amended (the "Securities Act") and has been effective during

the seven-day notice period required by the Company to the holders of

Debentures of its intent to exercise its conversion rights, provided

that the Company's common shares have traded at or above $14.00 per

share for 20 consecutive trading days on the Toronto Stock Exchange. The

Special Notes and Debentures are secured by a pledge of the shares of

the Company's subsidiaries and a guarantee by Seven Seas Petroleum

Holdings Inc.

F-11



<PAGE>

The Special Notes are exchangeable for a like principal amount of

convertible redeemable debentures (the "Debentures") on or before August

7, 1998. The Special Notes will be deemed to be exchanged upon the

earlier to occur of (i) the effectiveness of a registration statement

under the Securities Act, covering the resale of the Debentures and

compliance by the Company with certain Canadian securities requirements

and (ii) August 7, 1998. The Debentures are convertible into units (the

"Units") on the basis of one Unit for each $11.50 principal amount of

Debentures outstanding (initially 2,173,913 Units), subject to

adjustment. Each Unit consists of one common share and one-half of a

common share purchase warrant (the "Warrants"). The Debentures mature on

August 7, 2003. Each whole Warrant is exercisable for one common share

at an exercise price of $15.00 per share. The Warrants expire August 7,

1998.

7.



EQUITY:

On March 15, 1996, a brokered private placement was carried out in

Canada. The Company issued 2,000,000 special warrants at $2.75 per

warrant for a net offering after commissions and expenses of $5,095,548

to a third party financial brokerage institution. 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 $3,500,000.

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 $7,013,370. 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 $18.50

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.

The 250,000 common share purchase warrants were not converted at $18.50

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, which is subject to approval by the shareholders (collectively

referred to as "the Plans"). Pursuant to the Plans, 6,000,000 shares

were authorized for issuance, of which 3,878,500 were outstanding as of

December 31, 1997. The options granted under the Amended 1996 Stock

Option Plan were not subject to vesting requirements and expire five

years from the date of grant. 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. 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.

F-12

<PAGE>

The following table presents a summary of stock option transactions for

the three years ended December 31, 1997:



COMMON SHARES

Granted

-----------------------------DECEMBER 31, 1995

Granted

Exercised

-----------------------------DECEMBER 31, 1996

Granted

Exercised

Revoked

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

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



985,000

------------------------985,000

805,000

(625,333)

------------------------1,164,667

3,197,500

(478,667)

(5,000)

------------------------3,878,500

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



WEIGHTED AVERAGE

OPTION PRICE PER

SHARE

$ .75

--------------------.75

12.86

.85

--------------------9.07

13.56

3.05

12.25

--------------------$ 13.51

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



Exercisable stock options amounted to 1,697,665; 764,667; and 985,000 at

December 31, 1997, 1996, and 1995, respectively. The weighted average

fair value of options granted during 1997, 1996, and 1995 were $7.68;

$4.65; and $0.19, respectively. The following table summarizes stock

options outstanding and exercisable at December 31, 1997:

<TABLE>

<CAPTION>

Weighted

Weighted

Average

Average

Exercise

Exercise

Exercise

Price Range

Shares

Average Life

Price

Shares

Price

-------------- ------------- -------------- ------------- -------------- ------------<S>

<C>

<C>

<C>

<C>

$.75

33,000

2.5

$ .75

33,000

$ .75

7.13

325,000

3.5

7.13

325,000

7.13

10.70-10.90

1,458,000

7.0

10.76

774,665

10.81

12.25-13.23



740,000



9.7



13.18



160,000



13.17



18.23-18.75

1,322,500

8.1

18.61

405,000

18.74

-------------- ------------- -------------- ------------- -------------- ------------3,878,500

1,697,665

-------------- ------------- -------------- ------------- -------------- ------------</TABLE>

As part of the arrangements surrounding the resignations of four former

officials, the exercise period of the options 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 $2,140,250 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. The extension of the exercise period is subject to approval

by vote of the shareholders. Should the extension of the exercise period

be approved for all employees, the Company will be required to record

additional compensation expense of $3,603,425 using the March 26, 1998

closing stock price.

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 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:

<TABLE>

<CAPTION>

DECEMBER 31, 1997

DECEMBER 31, 1996

DECEMBER 31, 1995



<C>



<C>



<S>

Pro Forma Net Loss

Pro Forma

Net Loss per Share

</TABLE>



----------------<C>

($32,426,733)



--------------------------------<C>

($5,938,372)

($2,309,940)



($1.00)



($.46)



<C>



($.25)



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

future amounts.

F-13

<PAGE>

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, 1997:

weighted average risk free interest rate of 6.28 percent; no dividend

yield; volatility of .3555; and expected life of five to ten years. The

Company granted options prior to public trading on the Canadian Dealer

Network on June 30, 1995. Consequently, the underlying common stock 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 stock.

9.



OPERATIONS BY GEOGRAPHIC AREA:

The Company operates in one industry segment. Information about the

Company's operations for 1997, 1996, and from inception February 3, 1995

to December 31, 1995 by geographic area is shown below:



<TABLE>

<CAPTION>

CANADA

-----<S>

<C>



UNITED STATES

------------<C>



COLOMBIA

-------<C>



OTHER FOREIGN AREAS

------------------<C>



TOTAL

----<C>



Year ended December 31, 1997

Revenues

Operating Loss

Capital Expenditures

Identifiable Assets

Depreciation and Amortization



$ 753,433

(1,780,784)

17,462,002

110,695

CANADA

------



$ 2,020

(4,515,142)

57,572

488,463

20,708

UNITED STATES

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



$ 810,077

(1,837,368)

19,050,432

272,981,939

16,662

COLOMBIA

--------



$ 1,426

(88,359)

471,046

981,720

-



$ 1,566,956

(8,221,653)

19,579,050

291,914,124

148,065



OTHER FOREIGN AREAS

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



TOTAL

-----



Year ended December 31, 1996

Revenues

Operating Loss

Capital Expenditures

Identifiable Assets

Depreciation and Amortization



$ 333,598

(1,402,204)

10,497,084

-



$ (277,456)

46,939

66,490



CANADA

COLOMBIA

------------Period from inception through December 31, 1995

Revenues

Operating Loss

Capital Expenditures

Identifiable Assets

Depreciation and Amortization

</TABLE>

10.



$ 147,372

(863,787)

3,565,647

36,875



$



(3,147)

369,723

385,999

297



$ 239,345

(438,948)

4,335,166

224,436,899

42,755

ARGENTINA

--------$



$ 2,338

(140,264)

271,405

520,060

2,089

NORTH AFRICA

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



(625,771)

622,006

-



COMMITMENTS AND CONTINGENCIES:

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 materially adverse effect on the

financial position or results of the Company.

The Company leases property and equipment under various operating

leases. Aggregate minimum lease payments under existing contracts as of

December 31, 1997, are as follows: $84,732 for 1998; $41,182 for 1999;

$4,495 for 2000 and thereafter. Rental expense amounted to $84,492 in

1997; $82,928 in 1996; $58,536 in 1995.



F-14

<PAGE>

The Company has certain commitments under existing oil and gas

exploration concession agreements. Management estimates future

expenditures for such commitments to be approximately of $863,000 in

1998; $2,385,000 in 1999; $30,000 in 2000; and $30,000 in 2001.

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 $2,020 in 1997.

The Company's Chairman and Chief Executive Officer wholly owns GHK

Company LLC ("GHK"). Effective July 1, 1997, the Company has entered

into an administrative service agreement with GHK . The Company



$



(509,878)

500,800

-



$ 575,281

(2,258,872)

4,606,571

235,500,982

111,334

OTHER FOREIGN AREAS

------------------$



TOTAL

-----



5,011 $

152,383

(117,402) (2,119,985)

204,414

1,696,943

218,791

4,170,437

499

37,671



recognized $10,500 of such expenses in 1997. In addition, GHK pays

certain miscellaneous costs incurred on behalf of the Company. The

Company reimbursed GHK $381,267 and $288,505 in 1997 and 1996,

respectively, for such costs.

MTV Investments Limited Partnership owns 37.037 percent of Cimarrona

LLC, an Oklahoma company; Cimarrona is a consolidated subsidiary of the

Company. Resulting from cash calls, MTV owed $541,000 to the Company at

December 31, 1997.

12.



SUBSEQUENT EVENTS (Unaudited):

The Company has signed a letter of intent to sell its 11.77 percent

interest in the Southern Perth Basin Permits (EP381 and EP408) located

in Southwestern Australia. The Company will receive cash of $850,000,

reimbursement of $263,000 for certain capital expenditures, and retain a

small overriding royalty interest in each permit. Completion of the

transaction contemplated by the letter of intent is subject to several

conditions, including obtaining approvals of third parties and

governmental authorities. No assurance can be given that the Company

will complete this sale.



13.



SUPPLEMENTAL OIL AND GAS INFORMATION (Unaudited):

Capitalized costs at December 31, 1997 and 1996, respectively, relating

to the Company's oil and gas activities are shown below:



As of December 31, 1997

Proved properties ....................

Unproved properties ..................

Less: Dry Hole and Abandonment .......

Unproved properties, net .............

As of December 31, 1996

Proved properties ....................

Unproved properties ..................

Less: Dry Hole and Abandonment .......

Unproved properties, net .............



Colombia

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



Others

---------



Total

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



$ 46,116,873

============

$220,771,518

------------$220,771,518

============



$

-=========

$ 941,955

---------$ 941,955

=========



$ 46,116,873

=============

$ 221,713,473

-------------$ 221,713,473

=============



$ 1,611,665

============

$221,413,217

------------$221,413,217

============



$

-=========

$ 475,819

(4,910)

--------$ 470,909

=========



$

1,611,665

=============

$ 221,889,036

(4,910)

------------$ 221,884,126

=============



F-15

<PAGE>

Costs incurred during the years ended December 31, 1997, 1996, and 1995,

respectively, were as follows:

<TABLE>

<CAPTION>

COLOMBIA

ARGENTINA

NORTH AFRICA OTHERS

TOTAL

--------------------------- ---------<S>

<C>

<C>

<C>

<C>

Year ended December 31, 1997

Development cost ..................$

165,829

$

-$

-$

-$

165,829

Property acquisition cost:

Proved ........................

4,331,169

---4,331,169

Unproved ...................... 20,704,532

---20,704,532

Exploration cost .................. 18,661,979

--471,046

19,133,025

Total cost incurred ...........$ 43,863,509

$

-$

-$471,046

$ 44,334,555

Year ended December 31, 1996

Property acquisition cost:

Proved ........................$ 1,554,041

Unproved ...................... 215,536,257

Exploration cost ..................

5,564,861

Total cost incurred ...........$222,655,159



$

$



-----



$

$



-----



$



-250,000

21,405

$271,405



Year ended December 31, 1995

Property acquisition cost:

Proved ........................$

-$

-$

-$

-Unproved ......................

106,383

75,000

500,800

6,073

Exploration cost ..................

263,340

547,006

-198,341

Total cost incurred ...........$

369,723

$622,006

$500,800

$204,414

</TABLE>

As of December 31, 1997, the Company has not made a provision for

depletion. To date, 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 1998 and will commence development

immediately if the evaluation proves successful.

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 $25,035,701 and $217,090,298 in 1997 and 1996, respectively.

Capitalized acquisition costs incurred during 1997 and 1996 include

$6,490,737 and $63,967,775, respectively, of deferred income tax as



$



1,554,041

215,786,257

5,586,266

$222,926,564



$

$



-688,256

1,008,687

1,696,943



<C>



disclosed in Note 2, Business Combination.

The Company had oil and gas sales of $779,767 and $233,682 in 1997 and

1996, respectively, pertaining to production testing of the exploratory

wells on the Association Contracts in Colombia.

On May 16, 1995, the Company entered into an agreement whereby Seven

Seas purchased an option for $500,000 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 of 1995. After careful review,

Seven Seas decided not to exercise its option. The cost of the option,

$500,000, plus additional costs of $800 incurred toward purchasing this

option was originally recorded as unproved oil and gas interests and was

subsequently expensed.

F-16

<PAGE>

The El Catamarqueno X-1 test well on the Sur Rio Deseado Block in the

San Jorge Basin, Argentina, was determined to be unsuccessful during the

first week of January 1996, prior to release of the 1995 financial

statements. Consequently, the Company determined that further drilling

on the block was not justified and exploration costs of $622,006

incurred in Argentina during 1995 were expensed in 1995.

Ecopetrol has the right to back into Seven Seas' participating interest

in the Association Contracts upon declaration of commerciality at an

initial 50 percent participating interest. Ecopetrol's interest can

increase based upon accumulated production levels. Ecopetrol will at the

time of commerciality bear 50 percent of the future costs in the field

and reimburse the other parties in these two blocks for 50 percent of

previously incurred costs associated with successful wells.

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 future recoverable oil reserves and projected future net

revenues were provided by Ryder Scott Company Petroleum Engineers. The

Company's proved reserves were comprised entirely of crude oil in

Colombia.

Proved developed and undeveloped reserves (barrels):



Beginning of year ...................

Extensions and discoveries ..........

End of year .........................



1997

----------818,000

31,342,245

32,160,245



Proved developed ....................



11,494,236



1996

----------818,000

818,000

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 $6.85 to reference prices. 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:

<TABLE>

<CAPTION>

1997

1996

<S>

<C>

Future cash inflows ........................ $326,426,492

$12,520,000

Future costs

Production ............................

50,986,737

2,112,000

Development ...........................

33,740,255

1,939,000

Future net cash flows before income taxes ..

241,699,500

8,469,000

Future income taxes ........................

78,141,020

4,027,000

Future net cash flows ......................

163,558,480

4,442,000

10% discount factor ........................

62,941,503

641,000

Standardized measure of discounted future

net cash flows ............................. $100,616,977

$ 3,801,000

</TABLE>

F-17

<PAGE>

Principal sources of changes in the standardized measure of discounted

future net cash flows during 1997:

Beginning of year ..........................

Net change in production costs .............



$



3,801,000

(1,741,552)



<C>



Extensions, discoveries, and additions,

less related costs .........................

Net change in future development costs .....

Net change in income taxes .................

Accretion of discount ......................

End of year ................................



141,402,293

(1,611,820)

(41,969,044)

736,100

$ 100,616,977



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.

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.

F-18

<PAGE>

SUPPLEMENTARY FINANCIAL INFORMATION (unaudited)

SELECTED QUARTERLY DATA. Results of development stage

quarter for the years ended December 31, 1997, and 1996 were:

<TABLE>

<CAPTION>



<S>



operations by



(in thousands, except per share amounts)

1997 QUARTER ENDED

----------------------------------------------------------------------------------MARCH 31

JUNE 30

SEPT. 30

DEC. 31

--------------------------<C>

<C>

<C>

Operating revenues

$ 434

$ 237

$ 308

$ 588

Less costs and expenses

1,194

2,408

1,340

4,847

(760)

---------38

----------



(2,171)

--------35

---------



(1,032)

------59

-------



(4,259)

--------162

---------



Net loss



$ (722)

=========



$ (2,137)

=========



$ (972)

=======



$(4,097)

=========



Net loss per share



$(.03)

=========



$(.06)

=========



$ (.03)

=======



$(.12)

=========



Minority Interest



1996 QUARTER ENDED

----------------------------------------------------------------------------------MARCH 31

JUNE 30

SEPT. 30

DEC. 31

--------------------------Operating revenues

$ 45

$ 87

$ 221

$ 222

Less costs and expenses

311

619

765

1,140

(266)



(532)



(544)



(917)

64



Minority Interest

Net loss



$(266)

======



$ (532)

========



$ (544)

=========



$(853)

=====



Net loss per share



$(.02)

======



$(.04)

======



$ (.04)

=========



$(.07)

=====



</TABLE>

ITEM 9.



CHANGES AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL

DISCLOSURE



None

27

<PAGE>

PART III

ITEM 10.



DIRECTORS AND EXECUTIVE OFFICERS



The following table sets forth certain information regarding each director

and executive officers the Company:

<TABLE>

<CAPTION>

NAME

AGE

POSITION

<S>

<C>

Robert A. Hefner III........................

63

Chairman,

Chief

Executive

Officer, and Managing Director

Breene M. Kerr..............................



68



Vice Chairman



<C>



Brian Egolf.................................



49



Director



Sir Mark Thomson Bt.........................



57



Director



Robert B. Panero............................



68



Director



Gary F. Fuller..............................



61



Director



James D. Scarlett...........................



44



Director



Larry A. Ray................................



50



Director,

President,

Officer



Executive

Vice

and Chief Operating



Herbert C. Williamson, III..................



49



Director,

President,

Officer



Executive

Vice

and Chief Financial



</TABLE>

Set forth below is a description of the backgrounds of the directors and

executive officers of the Company.

ROBERT A. HEFNER III has served as Chairman of the Board, Chief Executive

Officer and Managing Director of the Company since May 1997 and a director of

the Company since November 1996. Since 1959, Mr. Hefner has been Owner and

Managing Member of The GHK Company L.L.C., a private oil and gas exploration

company.

BREENE M. KERR has served as Vice Chairman and director of the Company since

June 1997. Since 1994, Mr. Kerr has served as general partner of Talbot

Fairfield II L.P., an oil and gas exploration undertaking. From 1969 to 1995, he

has served as Chairman and director of Kerr Consolidated, an equipment sales

and leasing undertaking. Since 1993, Mr. Kerr has served as a director of

Chesapeake Energy Corp., a publicly trade oil and gas exploration company.

LARRY A. RAY has served as Executive Vice President and Chief Operating

Officer of the Company since September 1997 and as director of the Company since

June 1997. Mr. Ray served as Executive Vice President-Operations from June 1997

to September 1997. Since 1990, he has served in a management capacity for The

GHK Company L.L.C.

HERBERT C. WILLIAMSON, III has served as Executive Vice President, Chief

Financial Officer and director of the Company since September 1997. From 1995

through September 1997, Mr. Williamson served as Director in the Investment

Banking Department of Credit Suisse First Boston. He served as Vice Chairman and

Executive Vice President of Parker & Parsley Petroleum Company, an oil and gas

exploration company from 1985 through 1995.

BRIAN EGOLF has been a director of the Company since November 1996. Mr.

Egolf is President of Petroleum Management Corporation, a private oil and gas

exploration company.

28

<PAGE>

SIR MARK THOMSON BT. has been a director of the Company since June 1997. He

is Managing Director of B&N Investments Limited, an investment management

company.

ROBERT B. PANERO has been a director of the Company since June 1997. Mr.

Panero is Founder and President of Robert Panero Associates, international

strategic policy and project studies advisors.

GARY F. FULLER has been a director of the Company since June 1997. Mr.

Fuller is a Shareholder and Director of McAfee & Taft, attorneys-at-law.

JAMES D. SCARLETT has been a director of the Company since June 1997. Mr.

Scarlett is a Partner in McMillan, Binch, attorneys-at-law.

Each director holds office until the next annual meeting of stockholders for

the election of directors and until his successor has been duly elected and

qualified. Vacancies on the Board are filled by the remaining directors, and

directors elected to fill such vacancies hold office until the next annual

meeting of the Company's shareholders. Executive officers generally are elected

annually by the Board of Directors to serve, subject to the discretion of the

Board of Directors, until their successors are elected or appointed.

There is no family relationship between any of the directors or between any

director and any executive officer of the Company. For information regarding

certain business relationships between the Company and certain of its directors

and executive officers, see "CERTAIN/RELATED TRANSACTIONS."

COMMITTEES OF THE BOARD

The Company has established three standing committees of the Board of

Directors: an Executive Committee, an Audit Committee and a Stock Option and

Compensation Committee. Messrs. Hefner (Chairman), Kerr and Ray are members of

the Executive Committee. Messrs. Kerr, Thomson and Scarlett are members of the

Audit Committee. Messrs. Kerr, Egolf and Fuller are members of the Stock Option

and Compensation Committee (the "Compensation Committee").

The Executive Committee is delegated, during the intervals between the

meetings of the Board of Directors, all the powers of the Board in respect of

the management and direction of the business and affairs of the Company (except

only those specified in Subsection 116(2) of the Yukon Business Corporation Act)

in all cases in which specified direction in writing shall not have been given

by the Board.

The Audit Committee consults with the auditors of the Company and such other



persons as the members deem appropriate, reviews the preparations for and scope

of the audit of the Company's annual financial statements, makes recommendations

concerning the engagement and fees of the independent auditors, and performs

such other duties relating to the financial statements of the Company as the

Board of Directors may assign from time to time.

The Compensation Committee has all the powers of the Board of Directors,

including the authority to issue shares or other securities of the Company, in

respect of any matters relating to the administration of the Company's 1996

stock Option Plan, 1997 Stock Option Plan and compensation of officers,

directors, employees and other persons performing substantial services for the

Company. See "-Executive Compensation-Employee Benefit Plans-1996 Stock Option

Plan and 1997 Stock Option Plan."

DIRECTOR COMPENSATION

Directors who are also officers or employees of the Company are not

separately compensated for serving on the Board of Directors or as members of

Board committees. Directors who are not officers or employees of the Company are

eligible to participate in the Company's Amended 1996 Stock Option Plan and are

reimbursed for their out-of-pocket expenses incurred in connection with their

service as directors, including travel expenses. In July 1996, each non-employee

director received a five year option to purchase 10,000 Common Shares at an

exercise price of $7.125 per share. In November 1996, upon their election as

directors, Messrs. Hefner and Egolf each received a five year option to purchase

50,000 Common Shares at an exercise price of $18.75 per share. In May 1997, each

non-officer director received an option for 15,000 shares of common stock at

$10.90. Messrs. Hefner and Egolf declined to accept such options. In June 1997,

the

29

<PAGE>

Company granted Mr. Ray an option to purchase 200,000 Common Shares at a price

of $10.70 per share. Such options vest one-third immediately with the remaining

vesting 50% at the end of one year from the date of grant and the remaining 50%

at the end of the second year from the date of grant. On September 9, 1997, the

Company granted Mr. Ray options to purchase an additional 200,000 Common Shares

at a price of $13.23 per share. Such options vest one-third each on the third,

fourth and fifth anniversaries of the date of grant. The Company granted options

to the other directors as follows on July 17, 1997 at an exercise price of

$10.70 per share: Mr. Hefner - 300,000; Mr. Egolf - 75,000; Mr. Kerr - 75,000;

Mr. Fuller - 75,000; Mr. Panero - 50,000; Mr. Scarlett - 75,000; and Mr. Thomson

- - 75,000. One-third of the options are vested immediately, with the remaining

vesting 50% at the end of one year from the date of grant and the remaining 50%

at the end of the second year from the date of grant. Mr. Panero's options will

vest 50% at the end of one year from the date of grant and the remaining 50% at

the end of the second year from the date of grant. Mr. Panero also received a

payment of $37,500 in lieu of 25,000 options which would have vested

immediately. On November 25, 1997, the Company granted options at an exercise

price of $18.55 per share to the directors: Mr. Hefner-150,000; Mr.

Williamson-150,000; Mr. Egolf-100,000; Mr. Kerr-75,000; Mr. Fuller-75,000; Mr.

Panero-25,000; Mr. Scarlet-25,000; Mr. Thomson-25,000; and Mr. Ray-150,000. Such

options vest one-third on the first, second, and third anniversaries of the

grant date. In each case, the Company granted these options at the approximate

prevailing market price on the date of grant.

BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

The Securities and Exchange Act requires the Company's officers, directors,

and certain beneficial owners to file reports of ownership and changes in

ownership with the Commission and the American Stock Exchange. Based on its

review of such forms received, the Company believes that during the period from

January 1, 1997 through March 27, 1998 its officers, directors, and certain

beneficial owners complied with all applicable filing requirements except that

Robert A. Hefner III and Breene M. Kerr are late in filing two monthly reports.

INDEMNIFICATION AND LIMITATION OF LIABILITY

The Yukon BUSINESS CORPORATIONS ACT and the Company's Bylaws provide the

following authority to indemnify directors or officers or former directors or

officers of the Company or of a company of which the Company is or was a

shareholder:

(1) Except in respect of an action by or on behalf of the corporation or a

body corporate to procure a judgment in its favor, a corporation may

indemnify a director or officer of the corporation, a former director or

officer of the corporation or a person who acts or acted at the

corporation's request as a director or officer of a body corporate of

which the corporation is or was a shareholder or creditor, and his heirs

and legal representatives, against all costs, charges and expenses,

including an amount paid to settle an action or satisfy a judgment,

reasonably incurred by him in respect of any civil, criminal or

administrative action or proceeding to which he is made a party by

reason of being or having been a director or officer of that corporation

or body corporate, if (a) he acted honestly and in good faith with a

view to the best interests of the corporation, and (b) in the case of a

criminal or administrative action or proceeding that is enforced by a

monetary penalty, he had reasonable grounds for believing that his

conduct was lawful.

(2) A corporation may, with the approval of the Supreme Court, indemnify a

person referred to in subsection (1) in respect of an action by or on

behalf of the corporation or body corporate to procure a judgment in its

favor, to which he is made a party by reason by being or having been a

director or an officer of the corporation or body corporate, against all

costs, charges and expenses reasonably incurred by him in connection

with the action if he fulfills the conditions set out in paragraphs



(1)(a) and (b).

The Yukon BUSINESS CORPORATIONS ACT also provides that:

(3) Notwithstanding anything in subsections (1) through (6), a person

referred to in subsection (1) is entitled to indemnity from the

corporation in respect of all costs, charges and expenses reasonably

incurred by him in connection with the defense of any civil, criminal or

administrative action or proceeding to which he is made a party by

reason of being or having been a director or officer of the corporation

or body corporate, if the person seeking indemnity (A) was substantially

successful on the merits of his defense of the action or proceeding, (B)

fulfills the conditions set out in paragraphs (1)(a) and (b), and (C) is

fairly and reasonably entitled to indemnity.

(4) A corporation may purchase and maintain insurance for the benefit of any

person referred to in subsection (1) against any liability incurred by

him (a) in his capacity as a director or officer of the corporation,

except when the

30

<PAGE>

liability relates to his failure to act honestly and in good faith with

a view to the best interests of the corporation, or (b) in his capacity

as a director or officer of another body corporate if he acts or acted

in that capacity at the corporation's request, except when the liability

relates to his failure to act honestly and in good faith with a view to

the best interests of the body corporate.

(5)A corporation or a person referred to in subsection (1) may apply to

the Supreme Court for an order approving an indemnity under this section

and the Supreme Court may so order and make any further order it thinks

fit.

(6) On an application under subsection (5), the Supreme Court may order

notice to be given to any interested person and that person is entitled

to appear and be heard in person or by counsel.

The Bylaws of the Company also provide that the provisions for

indemnification contained in the Bylaws (outlined in subsections (1) and (2)

above) shall not be deemed exclusive of any other rights to which a person

seeking indemnification may be entitled under any Bylaws, agreement, vote of

shareholders or disinterested directors or otherwise both as to an action in his

official capacity and as to an action in any other capacity while holding such

office and shall continue as to a person who has ceased to be a director of

officer and shall enure to the benefit of the heirs and legal representatives of

such person. The Company maintains director's and officer's insurance.

Insofar as indemnification for liabilities arising under the Securities Act

of 1933 may be permitted to directors, officers, or persons controlling the

Company pursuant to the foregoing provisions, the Company has been informed that

in the opinion of the Securities and Exchange Commission, such indemnification

is against public policy as expressed in the Act and is therefore unenforceable.

31

<PAGE>

ITEM 11. EXECUTIVE COMPENSATION

The following table sets forth certain summary information concerning the

compensation paid by the Company to its Chief Executive Officer and each of the

other persons who served as executive officers of the Company whose annual

salary and bonus exceeded $100,000 for the fiscal year ended December 31, 1997

(the "Named Executive Officers"). The table does not include perquisites and

other personal benefits for individuals for whom the aggregate amount of such

compensation does not exceed the lesser of (i) $50,000 or (ii) 10% of individual

combined salary and bonus for the Named Executive Officers in that year.

SUMMARY COMPENSATION TABLE

<TABLE>

<CAPTION>



NAME AND

PRINCIPLE POSITION

- -----------<S>

<C>

Robert A. Hefner III ................

Chairman, Chief

Executive Officer and

Managing Director



LONG TERM COMPENSATION

------------------------ANNUAL COMPENSATION

AWARDS

PAYOUTS

-----------------------------OTHER

SECURITIES

ALL

ANNUAL

RESTRICTED UNDERLYING

LTIP

OTHER

COMPENSTOCK

OPTIONS/SARS PAYOUTS

COMPENYEAR

SALARY($) BONUS($) SATION($) AWARDS($)

(#)

($)

SATION($)

------------ -------- --------- --------------------<C>

<C>

<C>

<C>

<C>

1997

1996



-0-0-



-0-0-



-0-0-



-0-0-



450,000

50,000(7)



-0-0-



-0-0-



Malcolm Butler (4)...................

Chief Executive

Officer



1997



13,301



-0-



-0-



-0-



200,000



-0-



250,000



Albert E Whitehead (4)...............

Chairman and Chief

Executive Office



1997

1996

1995



77,308

150,000

125,000



-0-0-0-



-0-0-0-



-0-0-0-



50,000

185,000

200,000



-0-0-0-



125,000(4)

14,634(3)

-0-



Timothy T Stephens (4)...............

President



1997

1996

1995



67,644

135,000

106,875



-0-0-0-



-0-0-0-



-0-0-0-



525,000(4)

13,170(3)

-0-



-093,840

-0-



50,000

172,000(5)

250,000



Larry A. Ray (2).....................

Executive VicePresident, Chief

Operating Officer, and

Director



1997



139,062



John P. Dorrier (6) .................

Executive VicePresident



1997

1996

1995



107,981

120,000

80,000



-0-



-083,520

-0-



-0-



-0-



550,000



-0-



33,330(3)



-0-0-0-



-0-0-0-



40,000

151,000

125,000



-0-0-0-



392,019

11,707(3)

-0-



</TABLE>

(1) Except as otherwise indicated, the dollar value of perquisites and other

personal benefits for each of the Named Executive Officers was less than

established reporting thresholds.

(2) Represents salary received from commencement of employment through December

31, 1997 from the Company, which amount does not reflect an annual rate of

compensation.

(3) Consists solely of amounts contributed by the Company to the Named Executive

Officer's account in the Company's 401(k) Plan.

(4) On May 20, 1997, Messrs. Whitehead and Stephens resigned as executive

officers and directors of the Company. As part of a settlement agreement

with Mr. Stephens, the Company agreed to pay Mr. Stephens $525,000. The

Company also entered into a consulting agreement with Mr. Whitehead for a

three-year term for $200,000 per annum. Mr. Malcolm Butler was named Chief

Executive Officer of the Company in May 1997 and received 200,000 options at

$10.90, but resigned on May 20, 1997 when Mr. Hefner was named Chief

Executive Officer. Mr. Butler received a lump sum payment of $250,000,

representing one year's salary, as part of the settlement agreement with

him.

(5) In May 1997, Messrs. Whitehead and Stephens were each granted options

exercisable for 50,000 shares of common stock at $10.90 per share. As part

of the arrangements surrounding the resignation of such persons, the

exercise period of the options for Messrs. Whitehead and Stephens was

extended from 90 days to 18 months.

(6) Mr. Dorrier terminated his employment by the Company in September 1997 and

received payment for the remainder of compensation due under his contract of

employment. See "Employment Agreements"below.

(7) Mr. Hefner was granted options exercisable for 50,000 shares of common stock

at $18.75 for his participation as a member of the Board of Directors.

32

<PAGE>

OPTION/SAR GRANTS DURING 1997

The following table sets forth information regarding individual grants of

Options by the Company during the fiscal year ended December 31, 1997 to each of

the Named Executive Officers, and their potential realizable values.

INDIVIDUAL GRANTS

----------------------------------------------<TABLE>

<CAPTION>

NUMBER OF

SHARES

UNDERLYING

OPTIONS/SARS

% OF TOTAL

GRANTED

OPTIONS/SARS

NAME

(#)

GRANTED

- -----------<S>

<C>

<C>

<C>

<C>

Robert A. Hefner III ..................

300,000

9.4%

150,000(2)

4.7%



EXERCISE

OR

BASE

PRICE

($/SH)

-----<C>



EXPIRATION

DATE

---<C>



POTENTIAL

REALIZABLE

VALUE

AT ASSUMED ANNUAL

RATES

OF

SHARE

PRICE APPRECIATION

FOR OPTION TERM(1)

-------------------5%

10%

---<C>



$10.70

18.55



07/17/2007

11/24/2007



2,018,752

1,749,899



5,115,913

4,434,538



Albert Whitehead ......................



50,000



1.6%



$10.90



04/30/2002



150,573



332,728



Malcolm Butler ........................



200,000



6.3%



$10.90



04/30/2002



602,294



1,330,912



Larry A. Ray ..........................



200,000

200,000(3)

150,000(2)



6.3%

6.3%

4.7%



$10.70

13.23

18.55



06/12/2007

09/08/2007

11/24/2007



1,345,835

1,664,835

1,749,899



3,410,609

4,217,043

4,434,588



Timothy Stephens ......................



50,000



1.6%



$10.90



04/30/2002



150,573



332,728



John P. Dorrier .......................



40,000



1.3%



$10.90



04/30/2002



120,459



266,182



</TABLE>

(1) The assumed rates of annual appreciation are calculated from the date of

grant through the assumed expiration date. Actual gains, if any, on stock

option exercises and Common Share holdings are dependent on the future

performance of the Common Shares and overall stock market conditions. There

can be no assurance that the value reflected in the table will be achieved.

(2) Subject to shareholder approval at the 1998 annual meeting.

(3) 105,000 of the options granted to Mr. Ray on September 9, 1997 are subject



to shareholder approval at the 1998 annual meeting.

33

<PAGE>

OPTION EXERCISES DURING 1997 AND FISCAL YEAR END OPTION VALUES

The following table provides information related to Options exercised by the

Named Officers during 1997 and the number and value of unexercised Options held

by the Named Executive Officers at year-end. The Company does not have any

outstanding stock appreciation rights.

<TABLE>

<CAPTION>

SHARES

ACQUIRED

ON

EXERCISE

-------(#)

--<S>

<C>

<C>

NAME

- ---Robert A. Hefner III ...............

Malcolm Butler .....................

Albert E. Whitehead ................

Larry A. Ray .......................

Timothy T. Stephens ................

John P. Dorrier ....................



-0-0-0-021,667

131,000



VALUE

REALIZED

-------($)(1)

-----<C>



-0-0-0-0282,420

1,883,089



VALUE OF UNEXERCISED

NUMBER OF UNEXERCISED

IN-THE-MONEY

OPTIONS, WARRANTS/SARS

AT OPTIONS, WARRANTS/SARS

FISCAL YEAR-END (#)(1)

AT FISCAL YEAR-END ($)(2)

----------------------------- ---------------------------EXERCISABLE

UNEXERCISABLE EXERCISABLE

UNEXERCISABLE

----------------------- ----------------------<C>

<C>

<C>



150,000

200,000

235,000

66,666

222,000

135,000



</TABLE>

(1) Represents the difference between the exercise price of the option and the

closing price on the date of exercise.

(2) Based on a closing price on December 31, 1997 of $17.55 per share.

EMPLOYMENT AGREEMENTS

The Company and Mr. Dorrier entered into a three year employment contract

which provided that he would receive an annual base salary of $150,000 and, in

the sole discretion of the Compensation Committee of the Board, could have

received annual merit increases, annual bonuses and stock option awards. The

contract could have been terminated for "cause" which includes death or serious

incapacity and the executive officer could have resigned upon three months'

prior written notice. The Company and Mr. Dorrier also entered into an agreement

which provides for payments to the executive in the event there is a Change of

Control of the Company and the executive's employment is terminated (i) by the

Company within twelve months thereafter, (ii) by the executive within six months

thereafter, or (iii) by the executive between six and twelve months after a

Change of Control if a Triggering Event has occurred. In any such event, the

executive shall be entitled to a payment equal to the aggregate salary payable

for the remaining term of his employment agreement and the Company shall pay the

executive's health insurance premium for a period of one year unless the

executive has secured comparable health insurance prior thereto. If bonuses were

paid by the Company for the year in which the executive's employment terminated,

the executive shall be entitled to a bonus equal to the most recent annual bonus

paid to him for each year or part of the year remaining on his employment

agreement, provided that such bonus payment shall only be paid with respect to a

year that the Company otherwise pays bonuses to some or all of its employees. In

addition, all stock options held by the executive shall be extended until the

earlier to occur of the expiration date of the option or eighteen months after

the date of the termination of his employment by the Company or the date of his

notice of intent to terminate his employment if he elected to resign. The

agreement also provides that in the event the exercise price of any option

granted simultaneously with the option issued to the executive is reduced, the

exercise price of the executive's option shall also be reduced. As a result of

the resignation by the directors of the Company in May 1997, a change of control

occurred with respect to such officers.

The Company has entered into a five year employment agreement with Mr. Larry

A. Ray that provides for an annual base salary of $262,500 and in the sole

discretion of the Compensation Committee of the Board, Mr. Ray may receive

annual merit increases, annual bonuses and stock option awards. As part of his

employment agreement, Mr. Ray was granted options to purchase 200,000 Common

Shares at an exercise price of $10.70 per share. One-third of the options vested

immediately and the remainder vest one-half each on the first and second

anniversaries of the date of grant. On September 9, 1997, the Company granted

Mr. Ray options to purchase an additional 200,000 Common Shares 95,000 under the

Amended 1996 Stock Option Plan and 105,000 under the 1997 Stock Option Plan at a

price of $13.23 per share. Options granted under the 1997 Stock Option Plan are

subject to shareholder approval at the next annual or special meeting. Such

options vest one-third each on the third, fourth, and fifth anniversaries of the

date of grant. The employment agreement may

34

<PAGE>

be terminated for "cause" which includes death or serious incapacity. Under the

terms of the employment agreement, Mr. Ray will receive payments equal to the

amounts remaining to be paid under the agreement in the event of a "change in

control" and his employment terminates for any reason, including resignation by

Mr. Ray. For purposes of this Agreement, the term "Change in Control" shall mean

(1) any merger, consolidation, or reorganization in which the Company is not the

surviving entity (or survives only as a subsidiary of an entity), (2) any sale,

lease, exchange, or other transfer of (or agreement to sell, lease, exchange, or

otherwise transfer) all or substantially all of the assets of the Company to any

other person or entity (in one transaction or a series of related transactions),



350,000

-0-0483,334

-0-0-



685,000

1,330,000

1,375,000

456,662

1,270,750

576,600



1,370,000

-0-01,777,338

-0-0-



(3) dissolution or liquidation of the Company, (4) when any person or entity,

including a "group" as contemplated by Section 13(d) of the Securities Exchange

Act of 1934, as amended, acquires or gains ownership or control (including

without limitation, power to vote) of more than 50% of the outstanding shares of

the Company's voting stock (based upon voting power), or (5) as a result of or

in connection with a contested election of directors, the persons who were

directors of the Company before such election cease to constitute a majority of

the Board of Directors; provided, however, that the term "Change in Control"

shall not include any reorganization, merger, consolidation, sale, lease,

exchange, or similar transaction involving solely the Company and one or more

previously wholly-owned subsidiaries of the Company.

The Company has entered into a five year employment agreement with Mr.

Herbert C. Williamson, III that provides for an annual base salary of $100,000,

and in the sole discretion of the Compensation Committee of the Board, Mr.

Williamson may receive annual merit increases, annual bonuses and stock option

awards. As part of his employment agreement, Mr. Williamson was granted options

to purchase 500,000 Common Shares at an exercise price of $13.23 per share.

Options to purchase 150,000 Common Shares vest immediately, options to purchase

150,000 Common Shares vest on September 9, 1998, and options to purchase 50,000

Common Shares each vest on September 9, 1999, 2000, 2001 and 2002, respectively.

Of the options granted to Mr. Williamson, 150,000 are under the 1996 Stock

Option Plan and 350,000 are subject to approval of the 1997 Stock Option Plan by

the stockholders at the next annual or special meeting. The remaining terms and

conditions of Mr. Williamson's employment agreement are substantially similar to

Mr. Ray's employment agreement.

EMPLOYEE BENEFIT PLANS

1996 STOCK OPTION PLAN

The Company's Amended 1996 Stock Option Plan provides a means whereby

selected employees, senior officers and directors of the Company, or of any

affiliate thereof, may be granted incentive stock options to purchase Common

Shares of the Company in order to attract and retain the services or advice of

such employees, senior officers and directors, and to provide added incentive to

such persons by encouraging share ownership in the Company. The Amended 1996

Stock Option Plan may provide options to purchase up to 3,000,000 of the

Company's Common Shares (without par value) that are presently authorized but

unissued or subsequently acquired by the Company. The Amended 1996 Stock Option

Plan will terminate no later than June 10, 2006.

Pursuant to the Board's authorization, the Amended 1996 Stock Option Plan is

administered by the Compensation Committee. In the event a member of the Board

or the Compensation Committee is eligible for options under the Amended 1996

Stock Option Plan, such member of the Board or Compensation Committee will not

vote with respect to the granting of any option to himself or herself, as the

case may be. The Compensation Committee has the authority, in its discretion, to

determine all matters relating to options granted under the plan, including

selection of the individuals to be granted options, the number of shares to be

subject to each option, the exercise price, and all other terms and conditions

of the options. Grants under the Amended 1996 Stock Option Plan do not have to

be identical in any respect, even when made simultaneously. The Compensation

Committee's interpretation and construction of any terms or provisions of the

Amended 1996 Stock Option Plan on any option issued thereunder, or of any rule

or regulation promulgated in connection therewith, will be conclusive and

binding on all interested parties.

Grants of incentive stock options may be made under the Amended 1996 Stock

Option Plan only to an individual who, at the time the option is granted, is an

employee, senior officer or director of the Company or an affiliate of the

Company, as that term is defined in the Business Corporations Act (Yukon

Territory), a trustee on behalf of such individual, or an entity, all of the

voting securities of which are beneficially owned by an employee or director.

35

<PAGE>

The Compensation Committee will establish the maximum number of shares that

may be reserved pursuant to the exercise of each option and the price per share

at which such option is exercisable, provided that the number of shares that may

be reserved pursuant to the exercise of such options and granted to any person

shall not exceed 5% of the issued and outstanding share capital of the Company.

Furthermore, the exercise price of such options must not be less than the

closing price of the Company's shares on The Toronto Stock Exchange on the day

immediately preceding the date of grant of such options. The Compensation

Committee may establish the term of each option, but if not so established, the

term of each option will be 5 years from the date it is granted, but in no event

shall the term of any option exceed 10 years.

Subject to any vesting schedule established by the Compensation Committee,

each option may be exercised in whole or in part at any time and from time to

time. Options must be exercised by delivery to the Company of a notice of the

number of shares with respect to which the option is being exercised, together

with payment of the exercise price. Payment of the option exercise price must be

made in full at the time notice of exercise of the option is delivered to the

Company and may be in cash or, to the extent permitted by the Compensation

Committee and applicable laws and regulations, by delivery of Common Shares of

the Company held by the optionee having a fair market value (as determined in

the discretion of the Compensation Committee) equal to the exercise price.

Payment by the optionee in Common Shares will not be accepted unless the

optionee has owned the Common Shares for a period of at least 6 months.

Options granted under the Amended 1996 Stock Option Plan may not be

transferred, assigned, pledged, or hypothecated in any manner other than by will

or by the applicable laws of descent and distribution and shall not be subject

to execution, attachment, or similar process. In the event of death of an

optionee, the option may be exercised by the personal representative of the



optionee's estate or by the persons to whom the optionee's rights pass by will

or by the applicable laws of descent and distribution.

If the optionee's relationship with the Company or any affiliate ceases for

any reason other than termination for cause, death, or total disability, and

unless by its terms the option sooner terminates or expires, then the optionee

may exercise, for a 90-day period thereafter that portion of the optionee's

option that is exercisable at the time of such cessation, but the optionee's

option shall terminate at the end of such 90-day period as to all shares for

which it has not theretofore been exercised, unless such expiration has been

waived in the agreement evidencing the option or by resolution adopted at any

time by the Compensation Committee. Upon the expiration of the 90-day period

following cessation of an optionee's relationship with the Company or an

affiliate, the Compensation Committee has sole discretion in a particular

circumstance to extend the exercise period following such cessation beyond such

90-day period, subject to any such extension being pre-cleared by The Toronto

Stock Exchange. If an optionee is terminated for cause, any option granted under

the Amended 1996 Stock Option Plan will automatically terminate as of the first

discovery by the Company of any reason for termination for cause, and such

optionee will thereupon have no right to purchase any shares pursuant to such

option. "Termination for cause" means dismissal for dishonesty, conviction or

confession of a crime punishable by law (except a minor violation), fraud,

misconduct, or disclosure of confidential information.

Subject to the terms and conditions and within the limitations of the

Amended 1996 Stock Option Plan, the Compensation Committee may modify or amend

outstanding options granted under the plan, subject to the prior approval of The

Toronto Stock Exchange. The modification or amendment of an outstanding option

will not, without the consent of the optionee, impair or diminish any of such

optionee's rights or any of the Company's obligations under such option.

The aggregate number and class of shares for which options may be granted

under the Amended 1996 Stock Option Plan, the number and class of shares covered

by each outstanding option and the exercise price per share thereof (but not the

total price), and each such option, must all be proportionately adjusted for any

increase or decrease in the number of issued Common Shares of the Company

resulting from a split-up or consolidation of shares or any like capital

adjustment, or the payment of any share dividend out of the ordinary course. In

the event of a liquidation or reorganization of the Company in which the

shareholders of the Company receive cash, shares, or other property in exchange

for or in connection with their Common Shares, any option granted under the

Amended 1996 Stock Option Plan will terminate, but the optionee will have the

right immediately prior to such liquidation or reorganization to exercise his

option to the extent the vesting requirements set forth in the option agreement

have been satisfied. If the shareholders of the Company receive shares in the

capital of another corporation in exchange for their Common Shares, all options

granted under the Amended 1996 Stock Option Plan must be converted into options

to purchase such other corporation's shares, unless the Company and such other

corporation, in their sole discretion, determine that any or all such options

must terminate in accordance with the foregoing provisions applicable to a

liquidation or reorganization. The amount and price of such converted options

must be adjusted

36

<PAGE>

in the same proportion as used for determining the number of shares the holders

of the Common Shares receive in any such exchange. Unless accelerated by the

Compensation Committee, the vesting schedule set forth in the option agreement

will continue to apply to such converted options.

The Board of Directors of the Company may at any time suspend, amend, or

terminate the Amended 1996 Stock Option Plan, but in the case of amendments to

the plan, such amendments must be pre-cleared with The Toronto Stock Exchange.

Any amendment to the Amended 1996 Stock Option Plan that increases the number of

shares that may be issued under the plan, changes the designation of the

participants or class of participants eligible for participation in the plan, or

otherwise materially increases the benefits accruing to the participants under

the plan, must be approved by the holders of a majority of the Company's

outstanding voting shares, voting either in person or by proxy at a duly held

shareholders meeting, within 12 months before or after any such amendment.

1997 STOCK OPTION PLAN

The 1997 Stock Option Plan will give certain directors, officers, and

employees of the Company, and its subsidiaries and affiliates an opportunity to

develop a sense of proprietorship and personal involvement in the development

and financial success of the Company, and to encourage them to remain with and

devote their best efforts to the business of the Company, thereby advancing the

interests of the Company and its shareholders. Accordingly, the Company may

grant to certain directors, officers, and employees options to purchase up to an

aggregate of 3,000,000 shares of the common stock of the Company ("Stock")

pursuant to the 1997 Stock Option Plan. Such Stock may consist of authorized but

unissued Stock or previously issued Stock reacquired by the Company. The 1997

Stock Option Plan is an amendment and restatement of the plan as previously

adopted by the Board on September 9, 1997, and supersedes and replaces in its

entirety such previously adopted plan. Effectiveness of the 1997 Stock Option

Plan is subject to approval by the Company's shareholders at the annual meeting

scheduled in June 1998. If the 1997 Stock Option Plan is not so approved by the

shareholders, then all options granted thereunder will be void and of no further

force and effect, and no additional options will be granted under the plan. All

options granted under the 1997 Stock Option Plan are subject to, and contingent

upon, such shareholder approval. Except with respect to options then

outstanding, the 1997 Stock Option Plan, as amended and restated, will terminate

upon and no further options will be granted thereunder after September 8, 2007.

The 1997 Stock Option Plan will be administered by the Compensation

Committee, which will have sole authority to select the optionees from among



those individuals eligible under the plan and to establish the number of shares

of Stock which may be issued under each option. The maximum number of shares of

Stock that may be subject to options granted under the plan to an individual

optionee may not exceed 5% of the Company's total Stock outstanding and during

any calendar year may not exceed 1,000,000 (subject to adjustment under certain

conditions described below). The Compensation Committee is authorized to

interpret the 1997 Stock Option Plan and may from time to time adopt such rules

and regulations, consistent with the provisions of the plan, as it may deem

advisable to carry out the plan. All decisions made by the Compensation

Committee in selecting optionees, in establishing the number of shares of Stock

which may be issued under each option and in construing the provisions of the

1997 Stock Option Plan will be final.

Options granted under the 1997 Stock Option Plan may be either incentive

stock options, within the meaning of section 422 of the Internal Revenue Code of

1986, as amended (the "Code"), ("Incentive Stock Options") or options which do

not constitute Incentive Stock Options ("Non-Qualified Stock Options").

Incentive Stock Options may be granted only to individuals who are employees

(including officers and directors who are also employees) of the Company or any

parent or subsidiary corporation (as defined in section 424 of the Code) of the

Company at the time the option is granted. Non-Qualified Stock Options may be

granted to individuals who are directors (but not also employees), officers and

employees of the Company, any parent or subsidiary corporation of the Company,

or any other affiliate of the Company. Options may be granted to the same

individual on more than one occasion. No Incentive Stock Option will be granted

to an individual if, at the time the option is granted, such individual owns

stock possessing more than 10% of the total combined voting power of all classes

of stock of the Company or of its parent or subsidiary corporation, within the

meaning of section 422(b)(6) of the Code, unless at the time such option is

granted the option price is at least 110% of the fair market value of Stock

subject to the option and such option by its terms is not exercisable after the

expiration of five years from the date of grant.

Each option that is an Incentive Stock Option and all rights granted

thereunder will not be transferable other than by will or the laws of descent

and distribution or pursuant to a qualified domestic relations order as defined

by the Code or Title

37

<PAGE>

I of the Employee Retirement Income Security Act of 1974, as amended, or the

rules thereunder, and will be exercisable during the optionee's lifetime only by

the optionee or the optionee's guardian or legal representative. Each option

that is a Non-Qualified Stock Option will bear the same transfer restrictions as

an Incentive Stock Option except a Non-Qualified Stock Option may be assigned to

a limited liability company or partnership if (i) the terms of such transfer are

approved in advance by the Compensation Committee, (ii) 95% or more of all the

member or partnership interests in such limited liability company or partnership

are held by the holder of the option and members of his family, determined in

accordance with section 318(a)(1) of the Code, or trusts for their benefit,

(iii) such limited liability company or partnership is treated as a partnership

for federal income tax purposes, and (iv) such limited liability company or

partnership is controlled, directly or indirectly, as a fiduciary or otherwise,

by the holder of the option.

The purchase price of Stock issued under each option will be determined by

the Compensation Committee, but such purchase price must not be less than the

fair market value of Stock subject to the option on the date the option is

granted. Each option must be evidenced by a written agreement between the

Company and the optionee which shall contain such terms and conditions as may be

approved by the Compensation Committee, provided that each such option must

expire not later than 10 years after its date of grant. The terms and conditions

of the respective option agreements need not be identical. An option agreement

may provide for the surrender of the right to purchase shares of Stock under the

option in return for a payment in cash or Stock equal in value to the excess of

the fair market value of the shares of Stock with respect to which the right to

purchase is surrendered over the option price therefor ("Stock Appreciation

Rights"), on such terms and conditions as the Compensation Committee in its sole

discretion may prescribe. The Compensation Committee will retain final authority

(i) to determine whether an optionee will be permitted, or (ii) to approve an

election by an optionee, to receive cash in full or partial settlement of such

Stock Appreciation Rights. Moreover, an option agreement may provide for the

payment of the option price, in whole or in part, by the delivery of a number of

shares of Stock (plus cash if necessary) having a fair market value equal to

such option price.

Shares of Stock with respect to which options may be granted are shares of

Stock as presently constituted, but if, and whenever, prior to the expiration of

an option theretofore granted, the Company effects a subdivision or

consolidation of Stock or the payment of a stock dividend on Stock without

receipt of consideration by the Company, the number of shares of Stock with

respect to which such option may thereafter be exercised (i) in the event of an

increase in the number of outstanding shares will be proportionately increased,

and the purchase price per share will be proportionately reduced, and (ii) in

the event of a reduction in the number of outstanding shares will be

proportionately reduced, and the purchase price per share will be

proportionately increased.

If the Company recapitalizes, reclassifies its capital stock, or otherwise

changes its capital structure (a "recapitalization"), the number and class of

shares of Stock covered by an option theretofore granted will be adjusted so

that such option will thereafter cover the number and class of shares of Stock

and securities to which the optionee would have been entitled pursuant to the

terms of the recapitalization if, immediately prior to the recapitalization, the

optionee had been the holder of record of the number of shares of Stock then

covered by such option. If the Company declares an extraordinary dividend, which

arises from any sale or exchange of assets, payable in cash or any other



property, then the purchase price per share of Stock under any option

theretofore granted shall be reduced by the amount of such extraordinary

dividend payable on a share of Stock if paid in cash or the fair market value

(as determined by the Compensation Committee) of any property distributable on a

share of Stock if paid in kind. If in the event of any "Corporate Change", as

defined in the 1997 Stock Option Plan, the Compensation Committee, acting in its

sole discretion without the consent or approval of any optionee, will act to

effect one or more of the following alternatives, which may vary among

individual optionees and which may vary among options held by any individual

optionee: (1) accelerate the time at which options then outstanding may be

exercised so that such options may be exercised in full for a limited period of

time on or before a specified date (before or after such Corporate Change) fixed

by the Compensation Committee, after which specified date all unexercised

options and all rights of optionees thereunder will terminate, (2) require the

mandatory surrender to the Company by selected optionees of some or all of the

outstanding options held by such optionees (irrespective of whether such options

are then exercisable under the provisions of the plan) as of a date, before or

after such Corporate Change, specified by the Compensation Committee, in which

event the Compensation Committee will thereupon cancel such options and the

Company will pay to each optionee an amount of cash per share of Stock according

to a formula specified in the 1997 Stock Option Plan, (3) make any adjustments

to options then outstanding as the Compensation Committee, in its sole

discretion, deems appropriate to reflect such Corporate Change, or (4) provide

that the number and class of shares of Stock covered by an option theretofore

granted will be adjusted so that such option will thereafter cover the number

and class of shares of Stock or securities or property (including, without

limitation, cash) to which the optionee would have been entitled pursuant to the

38

<PAGE>

terms of any Corporate Change if, immediately prior to such Corporate Change,

the optionee had been the holder of record of the number of shares of Stock then

covered by such option.

The Board in its discretion may terminate the 1997 Stock Option Plan at any

time with respect to Stock for which options have not theretofore been granted.

The Board has the right to alter or amend the plan, or any part thereof from

time to time. No change in any outstanding option will be made which would

impair the rights of the optionee without the consent of such optionee. The

Board may not make any alteration or amendment which would increase the

aggregate number of shares which may be issued pursuant to the provisions of the

1997 Stock Option Plan or change the class of individuals eligible to receive

options under the plan without the approval of the shareholders of the Company.

39

<PAGE>

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth certain information as of February 28, 1997,

with respect to the beneficial ownership of the Common Shares, by (i) each

person known by the Company to own beneficially more than 5% of the issued and

outstanding Common Shares, (ii) each director of the Company and each of the

Named Officers, and (iii) all executive officers and directors of the Company as

a group.



BENEFICIAL OWNER

- ---------------Robert A. Hefner III............................

c/o

Seven Seas Petroleum Inc.

Suite 960, Three Post Oak Central

1990 Post Oak Boulevard

Houston, Texas 77056

Breene M. Kerr..................................

c/o Brookside Company

115 Bay Street

Easton, Maryland 21601



NUMBER OF

COMMON

SHARES (1)

---------6,565,300(2)



PERCENT

OF CLASS

-------19%



3,048,417(3)



9%



George Soros and Stanley F. Drunkenmiller.......

888 Seventh Avenue, 33rd Floor

New York, NY 10106



3,058,000



9%



Robert W. Moore.................................

MTV Investments Limited Partnership

3600 West Main Street, Suite 150

Norman, Oklahoma 73072

Brian Egolf.....................................

Sir Mark Thomson Bt.............................

Robert B. Panero................................

Gary F. Fuller..................................

James D. Scarlett...............................

Herbert C. Williamson, III

Timothy T. Stephens.............................

Albert E. Whitehead.............................

Malcom Butler...................................

Larry A. Ray....................................

John P. Dorrier.................................

All executive officers and directors as a group

(13 persons)....................................

- ----------------* Less than 1%



2,184,900



6%



126,386(4)

452,566(5)

17,445(6)

27,000(7)

25,000(7)

150,256(8)

353,500(9)(15)

1,246,758(10)(15)

200,000

193,887(11)

277,486(13)(15)

12,684,001

(14)



*

1%

*

*

*

*

1%

4%

*

*

*

36%



(1) Unless otherwise indicated, each of the parties listed has sole voting and

investment power over the shares owned. The number of shares indicated

includes, in each case, the number of Common Shares issuable upon exercise

of stock options ("Options") subject to the Amended 1996 Stock Option Plan,



to the extent that such Options are currently exercisable. For purposes of

this table, Options are deemed to be "currently exercisable" if they may be

exercised within 60 days following February 28, 1997.

(2) Includes 150,000 Common Shares currently issuable upon exercise of Options,

20,000 shares held by an entity in which Mr. Hefner has a substantial

interest and 3,360,607 Common Shares beneficially owned by Mr. Hefner and

held in escrow pursuant to the Escrow Agreement.

(3) Includes 25,000 Common Shares currently issuable upon exercise of an Option,

consists of 828,579 shares beneficially owned by a limited partnership in

which Mr. Kerr serves as a general partner and includes 2,194,838 Common

Shares held in escrow pursuant to the Escrow Agreement.

40

<PAGE>

(4) Includes 12,650 Common Shares owned by a member of Mr. Egolf's family,

2,000 Common Shares owned by a trust for the benefit of members of Mr.

Egolf's family, 50,000 Common Shares currently issuable upon exercise of

Options and 39,147 shares held in escrow pursuant to the Escrow Agreement.

(5)



Includes 25,000 Common Shares currently issuable upon exercise of an Option

and 199,531 shares held in escrow pursuant to the Escrow Agreement.



(6)



Includes 16,666 CommonShares currently exercisable upon exercise of an

Option, 234 shares held by Mr. Panero's wife, and 363 shares held in escrow

pursuant to the Escrow Agreement.



(7)



Includes 25,000 Common Shares currently issuable upon exercise of an

Option.



(8)



Includes 150,000 Common Shares currently issuable upon the exercise

options.



(9)



Includes 222,000 Common Shares currently issuable upon exercise of Options.

Mr. Stephens resigned as an officer and director of the Company in May

1997.



(10) Includes 235,000 Common Shares currently issuable upon exercise of Options

and 166,667 Common Shares held in escrow pursuant to the Founder's Escrow

Agreement. Mr. Whitehead resigned as an officer and director of the Company

in May 1997.

(11) Includes 66,667 Common Shares currently issuable upon exercise of an Option

and an additional 124,500 owned by Mr. Ray's wife.

(12) Of the Common Shares identified, Mr. Soros, Mr. Drunkenmiller, and Soros

Fund Management LLC may be deemed the beneficial owner of 1,258,700 Common

Shares. Mr. Drunkenmiller and Duquesne Capital Management, LLC may also be

deemed the beneficial owner of the remaining 1,799,300 Common Shares.

(13) Includes 135,000 Common Shares currently issuable upon exercise of Options.

(14) Includes 1,100,333 Common Shares currently issuable upon exercise of

Options and an aggregate of 5,794,486 Common Shares and 166,667 Common

Shares held in escrow pursuant to the GHK Escrow Agreement and the

Founder's Escrow Agreement, respectively.

(15) Number of shares held by the former executive is based on information

available to the Company as of October 27, 1997.

VOTING SUPPORT AGREEMENT

Under the terms of a voting support agreement by and between the Company and

Hazel Ventures Ltd., the sole shareholder of Petrolinson ("Hazel Ventures"),

Hazel Ventures agreed that prior to July 19, 1998, it will vote all Common

Shares of the Company owned or controlled by it in favor of the slate of

directors proposed by the Company's chief executive officer and will require any

purchaser of its shares to agree to be bound by the terms of the agreement

unless the purchaser acquires the shares in the open market. Hazel acquired

1,000,000 Common Shares, or 2.9% of the Company's outstanding Common Shares, in

exchange for the transfer of its ownership of Petrolinson, the holder of a 6%

interest in the Association Contracts, to a subsidiary of the Company.

ITEM 13.



CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS



TRANSACTIONS WITH DIRECTORS, OFFICERS, AND SECURITY HOLDERS

On November 1, 1997, the Company made a loan of $200,000 at 6.06% to Larry

A. Ray, Executive Vice President and Chief Operating Officer. Interest on the

loan is payable monthly with a single principle payment due November 1, 2002.

The Company's Chairman and Chief Executive Officer wholly owns GHK Company

LLC ("GHK").Effective July 1, 1997, the Company has entered into an

administrative service agreement with GHK. The Company recognized fees of

$10,500 of such expenses in 1997. In addition, GHK pays certain miscellaneous

costs incurred on behalf of the Company. The Company reimbursed GHK $381,270 and

$288,505 in 1997 and 1996, respectively, for such costs.

MTV Investments Limited Partnership ("MTV"), beneficial owner

6% of the Company and owner of the minority interest in Cimarrona

consolidated subsidiary of the Company. Resulting from cash calls

and gas exploration activities, an account receivable of $541,000

MTV at December 31, 1997.

41

<PAGE>



of more than

LLC, a

to fund oil

was due from



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:

NO.

- ---



EXHIBIT DOCUMENT

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



(1)



Not Applicable



(2)



Not Applicable



(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



(9)



Not Applicable



(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

42



<PAGE>

NO.



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

July 26, 1996 by and between the

certain individuals

*(I) Shareholders'

of July 26,



dated as of

Company and



Voting Support Agreement dated as

1996 by and between Seven Seas



Petroleum

Inc.

and

Messrs.

Whitehead, Plewes and Stephens



Hefner,



Kerr,



*(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

43

<PAGE>

NO.



EXHIBIT DOCUMENT

*(Q)



Form of Agreement between the Company and each of

Messrs. Stephens, Dorrier and DeCort relating to

a change of control



*(R)



Form of Employment

and Larry A. Ray



*(S)



Settlement

Agreement between the

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



(11.1)



Not Applicable



(12)



Not Applicable



(13)



Not Applicable



(16)



Not Applicable



(18)



Not Applicable



(21)



Not Applicable



Agreement



*(22)



Subsidiaries of the Registrant



(23)



Consent of experts and counsel



Company



and



*(A)



Consent of Jerry L. Williams, Independent Public

Accountants



*(B)



Consent of Arthur Andersen LLP

44



<PAGE>

NO.

- ---



between the Company



EXHIBIT DOCUMENT

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



(24)



Not Applicable



*(27)



Financial Data Schedule



(28)



Not Applicable



(23)



Consent of Arthur Andersen LLP



(30)



Consent of Ryder Scott Company Petroleum Engineers



(31)



The Association Contract by and between Ecopetrol and

Seven Seas Petroleum Colombia Relating to the Rosablanca

block



(32)



The Association Contract by and Between Ecopetrol and

Seven Seas Petroleum Colombia relating to the Montecristo

block.



(99)



Not Applicable



* Incorporated herein by reference to Exhibit on like registration on Form 10

(File No.022483)

(b) Reports on Form 8-K

None

45

<PAGE>

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, this

report has been signed as of the 3rd day of April, 1998 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



By: /s/ HERBERT C. WILLIAMSON,III

Herbert C. Williamson, III

Chief Financial Officer



By: /s/ RAY A. HOUSLEY, JR.

Ray A. Housley, Jr.

Treasurer and Controller

Pursuant to the requirements of the Securities and Exchange Act of 1934, this

report has been signed as of the 3rd day of April, 1998 by the following

persons in their capacity as directors of the Registrant.

/s/



ROBERT A. HEFNER III

Robert A. Hefner III



/s/



HERBERT C. WILLIAMSON, III

Herbert C. Williamson, III



/s/



BREENE M. KERR

Breene M. Kerr



/s/



JAMES D. SCARLETT

James D. Scarlett



/s/



LARRY A. RAY



/s/



GARY F. FULLER

Gary F. Fuller



/s/



SIR MARK THOMSON Bt.

Sir Mark Thomson Bt.

Larry A. Ray

/s/



BRIAN EGOLF

Brian Egolf



/s/



ROBERT B. PANERO

Robert B. Panero

46



</TEXT>

</DOCUMENT>

<DOCUMENT>

<TYPE>EX-10.B

<SEQUENCE>2

<TEXT>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives

- -------------------------------------------------------------------------------ASSOCIATION CONTRACT - with Gas Incentives

ASSOCIATION CONTRACT

ASSOCIATE SEVEN SEAS PETROLEUM COLOMBIA

SECTOR: ROSABLANCA

EFFECTIVE DATE 28 February 1998

The contracting parties, namely: on the one part THE "EMPRESA COLOMBIANA DE

PETROLEOS", hereinafter ECOPETROL, an industrial and commercial state-owned

enterprise authorized under Law 165 of 1948, currently ruled by its by laws,

amended by Decree 1209 of 15th June 1994, having its head office in Santafe de

Bogota, D.C. represented by ENRIQUE AMOROCHO CORTEZ, of legal age, bearer of

citizenship card No 5.555.193 issued in Bucaramanga, domiciled in Santafe de

Bogota, who states that: 1. As president of ECOPETROL, he acts herein on behalf

of said Company, and 2. The ECOPETROL Board of Directors authorized him to enter

into this Contract, as witnessed by Minutes No. 2169. of 16th October 1997; and

on the other part SEVEN SEAS PETROLEUM COLOMBIA, a company organized-pursuant to

the laws of CANADA, hereinafter referred to as "THE ASSOCIATE", with a duly

established Colombian branch and its main domicile in Santafe de Bogota,

pursuant to public deed no 2771 of 28th September 1995, made before the

Sixteenth (16) Notary Public of the Santa Fe de Bogota circuit, represented by



GUSTAVO VASCO MUNOZ of legal age, a citizen of Colombia bearer of identity card

No 17029136 issued in Bogota who represents that: 1. In his capacity as legal

representative he acts on behalf of SEVEN SEAS PETROLEUM COLOMBIA INC and, 2. He

is fully authorized to sign this contract as witnessed by the certificate of

incorporation and legal representation issued by the Chamber of Commerce of

Santafe de Bogota. Under the above conditions, ECOPETROL and the ASSOCIATE

declare they have entered into the contract contained in the following ClausesCHAPTER I - GENERAL PROVISIONS

CLAUSE 1 - PURPOSE OF THIS CONTRACT

1.1 The purpose of this contract is to explore the Contract Area and develop

such nationally-owned Hydrocarbons as may be found therein, as described in

Clause 3 below.

1.2 Pursuant to article lst of Decree 2310/1974, ECOPETROL is entrusted with

exploring and developing nationally owned hydrocarbons and may carry out said

activities either directly or through contracts with private parties. Based on

this provision, ECOPETROL and THE ASSOCIATE have agreed to explore the Contract

Area and produce such Hydrocarbons as may be found therein under the

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives

Page 2

- -------------------------------------------------------------------------------terms and conditions set forth in this document, in Appendix "A!' and Appendix

"B" ("Operating Agreement) which are made an integral part hereof.

1.3 Subject to the provisions hereof, it is understood that the rights and

obligations of THE ASSOCIATE regarding the Hydrocarbons produced in the Contract

Area, and its share thereof, are the same as those assigned under Colombian law

to anyone producing nationally-owned Hydrocarbons in the country.

1.4 ECOPETROL and THE ASSOCIATE agree to explore and develop the land of the

Contract Area, to share the costs and risks thereof in the proportion and under

the terms contemplated in this Contract, and the properties they may acquire and

the Hydrocarbons produced and stored shall belong to each Party in the

stipulated proportions.

CLAUSE 2 - APPLICATION OF THE CONTRACT

This Contract applies to the Contract Area whose boundaries are described in

Clause 3 below, or to any portion thereof subject to the terms hereof whenever

Clause 8 has been applied.

CLAUSE 3 - CONTRACT AREA

The Contract Area is called "ROSABLANCA" and covers an extension of one hundred

twenty eight thousand one hundred and eighty eight (128,188) hectares and five

thousand (5,000) square meters, located in the following municipal

jurisdictions: Gamarra, Aguachica, La Gloria, Pelaya and Tamalameque in Cesar

Department; Morales in Bolivar Department- and Carmen in the Northern Santander

Department. This area is described here in below and shown in the map enclosed

as appendix ",N' which is made a part hereof, as well as the corresponding

calculation charts. The reference point is the Geodesic Vertex "TABLAR-848" of

the Agustin Codazzi Geographic Institute whose Gauss flat coordinates origin

Santa Fe de Bogota are- N-1,401.053.89 meters, E1,021,264.81 meters

corresponding to geographic coordinates Latitude 80 13' 31 ".808 North of the

Equator, Longitude 73 0 53'1 6".538 West of Greenwich. From this Vertex, head N

340 9' 25".673 W for 2,237.83 meters until reaching the starting point "A",

whose coordinates are: N-1,402,900.oo meters, E-1,020,000.oo meters. Head NORTH

from point "N' for 27,100.oo meters until reaching Point "B" whose coordinates

are-. N-1,430,000.oo meters E- 1,020,000.oo meters. Head EAST from point "B" for

10,000.oo meters until reaching point "C" whose coordinates are-. N-1,430,000.oo

meters, E-1,030,000.oo meters. Head NORTH from point "C" for 30,000.oo meters up

to point "D" whose coordinates are- N1,460,000.oo meters, E-1,030,000.oo meters.

Go EAST from point "D" for

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives

Page 3

- -------------------------------------------------------------------------------30,000.oo meters until reaching point "E" whose coordinates are N-1,460,000.oo

meters, E-1,060,000.oo meters. Head SOUTH for 35,000.oo meters from point "E"

until reaching point "F" is reached whose coordinates are N-1,425,000.oo meters,

E-1,060,000.oo meters. From point "F" head WEST for 8,000.oo meters up to point

"G" whose coordinates are N-1,425,000.oo meters, E-1,052,000.oo meters. Go WEST

from point G" for 15,478.oo meters up to point "H" whose coordinates areN-1,425,000.oo meters, E-1,036,522.oo meters. Take a direction S 10 36' 13".906

W for 4,001.57 meters from point "H" until reaching point "I" whose coordinates

are N-1,421,000.oo meters, E-1,036,410.oo meters. The whole of lines "G-H" and

"H-1" run alongside lines "D-C" and "C-B" of the Bolivar Association Contract

operated by Harken de Colombia Limited. From point "I" head WEST for 10,000.oo

meters up to point "J" whose coordinates are N1,421,000.oo meters,

E-1,026,410.oo meters. From point "J" head SOUTH for 18,100.00 meters until

reaching point "K' whose coordinates are N-1,402,900.oo meters, E-1,026,410.oo

meters. Lines "I-J" and "J-K' run alongside ECOPETROL's Buturama sector. Head

WEST for 6,410.oo meters from point "K' until reaching starting point "A!' which

closes the boundaries. The whole of line "K-A" runs alongside line "B-A" of the

Montecristo Association Contract signed with Seven Seas Petroleum Colombia Inc.

Paragraph 1: Whenever somebody files a claim asserting ownership of the

Hydrocarbons in the subsoil within the Contract Area, ECOPETROL shall deal with

the case, assuming such obligations as may arise.

Paragraph 2: If part of the Contract Area extends to areas that are or have been

reserved and declared as falling within the National Park System, THE ASSOCIATE

must meet all conditions imposed by the pertinent authorities in keeping with



Clause 30 (numeral 30.4) hereof. This neither amends the contract nor

constitutes grounds for filing any claim against ECOPETROL.

CLAUSE 4- DEFINITIONS

For Contract purposes, the terms listed below shall have the meaning set out

hereunder:

4.1 Contract Area- The land described in Clause 3 here in above, subject to

Clause 8.

4.2 Field: Portion of the Contract Area where one or more structures exist,

totally or partially overlying, with one or Reservoirs that are producing or

whose Hydrocarbon-producing capacity has been tested. These Reservoirs may be

separated by geological causes such as: synclines, faults, wedging of producing

strata, changes in porosity and permeability- likewise they may be of different

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives

Page 4

- -------------------------------------------------------------------------------geological ages, separated by strata that is reasonably watertight,

totally/partially overlapping or not overlapping at all.

4.3 Commercial Field- A field that ECOPETROL accepts as able to produce

Hydrocarbons of a quality and quantity that is economically viable in one or

more Production Targets to be defined by ECOPETROL.

4.4 Gas Field: A field that ECOPETROL qualifies as a producer of Natural

Non-Associated Gas (or Free Natural Gas) when defining its commerciality and

using information furnished by THE ASSOCIATE.

4.5 Executive Committee: The body that will supervise, control and approve all

operations and actions performed throughout the contract and to be established

within thirty (30) days following acceptance of the first Commercial Field.

4.6 Direct Exploration Costs: Any monetary expenditures reasonably incurred by

THE ASSOCIATE in seismic surveys and drilling Exploration Wells, as well as for

locations, completion, equipping and testing of such wells. Direct Exploration

Costs do not include administrative or technical support from the Company's head

or central office.

4.7 Joint Account- Accounting records kept pursuant to Colombian law for

crediting or debiting the Parties with their share in the Joint Operation of

each Commercial Field.

4.8 Budgetary Execution: The resources effectively expended and/or committed for

each program and project approved for a given calendar year.

4.9 Structure: The geometrical form with geological closure (anticline, syncline

etc.) that is revealed by formations having accumulations of fluid.

4.10 Effective Date: The sixtieth (60) calendar day following contract

signature, and the starting date for all time limits agreed to herein and

subject to the validity of the same contract.

4.11 Cash Flow: The physical flow of money (income and expenditure) incurred by

the Joint Account to handle the obligations contracted by the Association in the

normal course of operations.

4.12 Associate Natural Gas: Mixture of light hydrocarbons existing in the

Reservoir in the form of a gas layer or in solution and produced together with

liquid hydrocarbons.

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives

Page 5

- -------------------------------------------------------------------------------4.13 Non-Associate Natural Gas (Production of): Those hydrocarbons produced in

gaseous state at surface and reported at standard conditions, with an initial

average (production weighted) Gas/Oil ratio of over 15,000 standard cubic feet

of gas per barrel of liquid Hydrocarbon, and heptane plus (C7 +) molar

composition below 4%.

4.14 Direct Expenses: All expenditures charged to the Joint Account as a result

of payment to personnel directly working for the Association, purchase of

materials and supplies, service contracts made with third parties and any

overhead required by the Joint Operation in the normal course of its activities.

4.15 Indirect Expenses: Those disbursements charged to the Joint Account for

administrative/technical support for the Joint Operation that Operator may

furnished through his own organization.

4.16 Commercial Interest : For Colombian Pesos, it shall be the interest rate

for ninety-day (90) CDs certified by the Banking Superintendency, or whoever

replaces same, applicable to the respective period. In the case of US dollars,

it shall be the prime rate established by CITIBANK New York, or the entity

appointed for this purpose.

4.17 Interest in the Operation: The share in the rights and obligations acquired

by each Party in the exploration and development of the Contract Area.

4.18 Development Investment: Refers to the amount of money invested in goods and

equipment capitalized as Joint Operation assets in a Commercial Field, once the

Parties have accepted the existence thereof.

4.19 Hydrocarbons: Any organic compound consisting mainly of the natural mixture

of hydrogen and carbon, as well as substances related thereto or derived

therefrom, except for helium and rare gases.



4.20 Gaseous Hydrocarbons: All hydrocarbons produced in gaseous state

at the surface and reported at standard conditions (1 atmosphere of

absolute pressure and a temperature of 60 deg. F).

4.21 Liquid Hydrocarbons: Includes crude oil and condensates, as well those

produced in such state as a result of gas treatment when pertinent, reported at

standard conditions.

4.22 Production Targets: Reservoirs located within the Commercial Field

discovered and that have tested as commercial producers.

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ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives

Page 6

- -------------------------------------------------------------------------------4.23 Joint Operation: The tasks and work performed, or being performed, on

behalf of the Parties and for their account.

4.24 Operator: The person appointed by the Parties to act on their behalf in

directly carrying out the operations needed to explore and produce the

Hydrocarbons discovered in the Contract Area.

4.25 Parties: On the effective Date, ECOPETROL and the ASSOCIATE. Subsequently

and at any time, ECOPETROL on the one part, and THE ASSOCIATE and/or its

assignees on the other part.

4.26 Exploration Period: The term for THE ASSOCIATE to comply with the

obligations set forth in Clause 5 here in below, not to exceed six (6) years

from the Effective Date, except as provided for in Clauses 9 (numerals 9.3, 9.8)

and 34.

4.27 Exploitation

Period:

The time elapsed from the end

Exploration or Retention Period up to the end of the contract.



of



the



4.28 Retention Period: Time lapse granted by ECOPETROL when THE ASSOCIATE asks

for more time to start the Exploitation Period of each Gas Field discovered

within the Contract Area, because special conditions mean the field cannot be

developed in the short term and consequently additional time is needed to build

the infrastructure and/or develop the market

4.29 Exploration Well: Any well so designated by THE ASSOCIATE that is to be

drilled or deepened for its account in the Contract Area for the purpose of

seeking new Reservoirs, checking the extension of a reservoir, or establishing

the stratigraphy of an area. In order to comply with the obligations agreed upon

in Clause 5 hereof, the respective Exploration Well will be previously qualified

by ECOPETROL and the ASSOCIATE.

4.30 Development or Exploitation Well : Any well previously scheduled by the

Executive Committee for producing Hydrocarbons discovered in the Production

Targets within each Commercial Field.

4.31 Budget: A basic planning tool earmarking funds for specific projects to be

used within a calendar year or part thereof in order to attain the goals and

targets proposed by the ASSOCIATE or Operator.

4.32 Extensive Production Tests: Operations performed in one or more

producing

Exploration Wells to appraise

producing

conditions and

reservoir behavior.

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives

Page 7

- -------------------------------------------------------------------------------4.33 Reimbursement: Payment of fifty percent (50%) of the Direct Exploration

Costs incurred by THE ASSOCIATE.

4.34 Exploration Work: Operations performed by THE ASSOCIATE in search

for and discovery of hydrocarbons in the Contract Area

4.35 Reservoir: Any sub-surface rock with hydrocarbon accumulation in its porous

space, producing or able to produce hydrocarbons and behaving as an independent

unit with respect to petrophysical and fluid properties and having a single

pressure system throughout.

CHAPTER II - EXPLORATION

CLAUSE 8 - TERMS AND CONDITIONS

5.1.1 During the first two years following Effective Contract Date, THE

ASSOCIATE must reprocess three hundred (300) ) kms. of existing seismic on the

area, acquire/interpret Landsat images and surface Geological and geochemical

work; acquire/process and interpret one hundred (100) kilometers of 2D seismic.

the Area. At the end of the second year, THE ASSOCIATE shall have the option to

relinquish the contract providing it has met the above obligations. If THE

ASSOCIATE wishes to go ahead into the third year, it must relinquish areas so

that it remains with an area not to exceed one hundred thousand (100,000)

hectares.

5.1.2 During the third year, THE ASSOCIATE shall drill one (1) Exploratory Well

to penetrate the potential Hydrocarbon-producing formations in the Area. The

contract shall terminate at the end of this year unless an extension has been

applied for and authorized pursuant to numeral 5.2 of this Clause, or a

commercial field has been discovered, except as set out in Clause 9 (numeral

9.5).

5.2 If THE ASSOCIATE has satisfactorily met the obligations of Clause 5, it may

request ECOPETROL to extend the Exploration Period annually up to three (3)

additional years and during each extension THE ASSOCIATE shall perform

Exploration Work in the Contract Area, consisting of drilling one (1)



Exploration Well until it penetrates the Hydrocarbon producing formations in the

area.

5.3 If, during any year of the Exploration Period, THE ASSOCIATE should decide

to carry out work on the following year's obligations, it must obtain permission

therefor from ECOPETROL. If ECOPETROL agrees, it shall decide

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ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives

Page 8

- -------------------------------------------------------------------------------on how such obligations are to be transferred and the amount thereof.

5.4 Throughout the life of this contract, THE ASSOCIATE may carry out

Exploration Work on the areas retained in keeping with Clause 8, and will be

solely responsible for the risks and costs of such activities and thus have

complete and exclusive control thereon. This will not change maximum life of

this contract.

CLAUSE 6 - HANDING OVER INFORMATION DURING EXPLORATION

6.1 When THE ASSOCIATE so requests, ECOPETROL shall supply any information it

holds on the Contract Area. The costs of reproducing and supplying such

information shall be charged to THE ASSOCIATE.

6.2 During the Exploration Period, THE ASSOCIATE shall hand over the following

data to ECOPETROL as such becomes available and in keeping with the ECOPETROL

data supply manual-. all geological/geophysical data, cores, edited magnetic

tapes, processed seismic sections and all supporting field data, magnetic and

gravimetric logs, all of this in reproducible originals; copies of geophysical

reports, reproducible originals of all logs for wells drilled by THE ASSOCIATE,

including the final composite graph for each well and copies of the final

drilling report, including core sample analyses, results of production tests and

any other information relating to the drilling, study or interpretation of any

kind performed by THE ASSOCIATE for the Contract Area without any limitation.

ECOPETROL is entitled to witness any operations and verify the information

listed here in above doing so at any time and using any procedure it may

consider appropriate,

6.3 The parties agree that all geological, geophysical and engineering

information obtained from the Contract Area while this contract is in force, is

to be held confidential for three (3) years following acquisition thereof.

Thereafter such information shall be released except for any interpretations

thereof made by the Parties. The released information mainly concerns seismic,

potential methods, remote sensors and geochemical data, with respective support

documents, surface and sub-surface mapping, wells reports, electric logs,

formation tests, biostratigraphic/petrophysical/fluid analyses and production

history. However, the parties agree that in each case they may exchange

information with ECOPETROL's associates and non-associates. It is understood

that what is agreed here shall not affect the requirement of providing the

Ministry of Mines and Energy with all the information it requests under current

legal resolutions and regulations. Nonetheless, it is understood and accepted

that the Parties can, at their own discretion, provide their affiliates,

consultants, contractors and financial entities with the information they

require and called for by authorities having jurisdiction on the parties and

their affiliates, as well as by norms established by

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 9 .

- -------------------------------------------------------------------------------any stock

exchange

quoting the stock of the parties or related

corporations.

CLAUSE 7 - BUDGET AND EXPLORATION SCHEDULES

Respecting the terms of this contract, THE ASSOCIATE must prepare the programs

and work schedule for exploring the Contract Area, together with a short-term

Budget (following calendar year) and estimated Budget giving an overview for the

next two (2) years. Such overview, programs, time schedules and Budgets shall be

submitted to ECOPETROL for the first time within sixty (60) calendar days

following contract signature, and thereafter within the first ten (1 0) calendar

days of each year.

THE ASSOCIATE shall give ECOPETROL a quarterly technical and financial report,

listing exploratory work performed, prospects revealed by the information

acquired, the assigned Budget and exploration costs incurred up to date of the

report, commenting in each case on causes of the main variances. When ECOPETROL

so requests, THE ASSOCIATE shall provide explanations on the report doing so at

meetings that can be scheduled every six months. Information submitted by THE

ASSOCIATE in the reports and explanations mentioned in this clause shall under

no circumstances be understood as accepted by ECOPETROL. ECOPETROL may audit

financial information as set out in Clause 22 of Appendix B hereto (Operating

Agreement).

CLAUSE 8 - RESTITUTION OF AREAS

8.1 If a Commercial Field has been discovered in the Contact Area by the end of

the initial three-year exploration period, or of the extensions obtained by THE

ASSOCIATE in keeping with Clause 5 (numeral 5.2), the Contract Area will be

reduced by 50%- two (2) years thereafter the area will be reduced to fifty

percent (50%) of the remaining Contract Area; and two years thereafter, such

area will be reduced to the Commercial Fields(s) that are producing or under

development plus a reserve belt two and a half kilometers (2.5) wide surrounding

each Field and this will be the only part of the Contract Area that continues to

be subject to the terms of this contract. In order to apply this clause, an

imaginary grid or net will be placed over the initial contract area and then

divided into ten rows and columns running north-south, limited by the maximum

and minimum north and east coordinates of the boundaries, and they will define

the cells on which relinquishment of areas referred to in this numeral will be



based. Each time areas are returned, the imaginary grid or net will be modified

in keeping with the new coordinates of the Contract Area.

8.2 THE ASSOCIATE shall decide what areas are to be returned to ECOPETROL based

on the imaginary grid or net mentioned in the preceding

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 1 0.

- -------------------------------------------------------------------------------numeral. To this end, the relinquishment may be made in one or two lots,

comprising one or more adjoining cells and trying to conserve a single polygon,

unless THE ASSOCIATE shows that this is either impossible or unsuitable, in such

case approval must be obtained from ECOPETROL. Notwithstanding the requirement

to relinquish areas referred to in Clause 8 (numeral 8.1). THE ASSOCIATE is not

obliged to return areas under development or production, including the 2.5 km.

wide belt surrounding said areas, unless development or production are suspended

continuously for over a year without just cause and for reasons attributable to

THE ASSOCIATE, in which case the areas will be returned to ECOPETROL, thus

terminating the contract for said areas of part of the area. These stipulations

are also applicable to development under the sole risk mode.

8.3 Retention Period: If THE ASSOCIATE has discovered a Gas Field and applied

for commerciality thereof as set out in Clause 9 (numeral 9.1), he may

simultaneously ask ECOPETROL for a Retention Period, giving reasons to fully

justify this request.

8.3.1 THE ASSOCIATE must apply for the Retention Period, and ECOPETROL grant

same, prior to the date for final relinquishment of areas referred to in numeral

8.1 hereof.

8.3.2 The Retention Period may not exceed four (4) years. If the initial term

were to be insufficient, ECOPETROL may extend same following a written and

justified application from THE ASSOCIATE, but the initial period plus any

extension may not exceed four (4) years.

CHAPTER III - EXPLOITATION

CLAUSE 9 - TERMS AND CONDITIONS

9.1 To initiate the Joint Operation hereunder, it is considered that

exploitation work starts on the date the Parties accept the existence of the

first Commercial Field or upon compliance with the provisions of Clause 9

(numeral 9.5). THE ASSOCIATE shall prove the existence of a Commercial Field by

drilling sufficient wells to reasonably define the hydrocarbon-producing area

and the commerciality of the Field. In this case, THE ASSOCIATE will notify

ECOPETROL in writing about such commercial discovery, furnishing the studies

that have led to this conclusion. ECOPETROL must accept or reject the existence

of such Commercial Field within ninety (90) calendar days from the date THE

ASSOCIATE hands over all support information and makes the technical

presentation. ECOPETROL may request any additional information it deems

necessary within thirty (30) days following submittal of the initial support

information.

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ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives

Page 11

- -------------------------------------------------------------------------------9.2.1 Should ECOPETROL accept the existence of a Commercial Field, it shall so

advise THE ASSOCIATE within the ninety (90) day term referred to in Clause 9

(numeral 9.1) stipulating the area of the Commercial Field. Then it shall begin

to participate in the development of the Commercial Field discovered by THE

ASSOCIATE as set out in the terms of the Contract.

9.2.2 ECOPETROL shall reimburse fifty percent (50%) of the Direct Exploration

Costs incurred by THE ASSOCIATE for its own risk and account in the Contract

Area prior to the date when commerciality studies for the new commercial

discovery were submitted, in keeping with numeral 9.

1. hereof.

9.2.3 The amount of such Direct Costs shall be established in dollars of the

United States of America, the reference date being that when THE ASSOCIATE made

such disbursements-, consequently, the costs incurred in Colombian pesos shall

be liquidated at the market representative rate for such date as certified by

the Banking Superintendency, or entity replacing same.

Paragraph:

Once the amount of Direct Exploration Costs to be reimbursed in United States

Dollars has been established, such will be inflation-adjusted for each year or

part thereof as of the disbursement date up to the date defined by the Ministry

of Mines & Energy as the initiation of the exploitation period, using the

international inflation rate for the respective year or, failing this, that for

the previous year. The international inflation rate to be used shall be the

annual percentage variation of the consumer price index for industrialized

countries, taken from "International Financial Statistics" published by the

International Monetary Fund (page S63 or replacement) or, failing this, the

publication agreed by the Parties.

9.2.4 As soon as Operator puts the Field on-stream, ECOPETROL shall reimburse

THE ASSOCIATE for Direct Exploration Costs according to Clause 9 (numeral 9.2.2)

with the amount of dollars equivalent to fifty percent (50%) of its direct share

in the total production of such Field, after deducting the royalty percentage.

Paragraph-. For Commercial Gas Fields, ECOPETROL shall reimburse the ASSOCIATE

with the amount of dollars equivalent to one hundred percent (100%) of its

direct share in the total production of such Field, after deducting the royalty

percentage, doing so as soon as Operator puts the Field on-stream.

9.3 If ECOPETROL rejects the existence of the Commercial Field referred to in



Clause 9 (numeral 9.1), it may notify THE ASSOCIATE of additional work it

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 12.

- -------------------------------------------------------------------------------considers necessary to demonstrate such existence. The cost of this work may not

exceed TWO MILLION DOLLARS (US$2,000,000) nor last for more than one (1) year,

in which case the Exploration Period for the Contract Area will automatically be

extended by the same period as that agreed by the Parties for the performance of

the additional work requested by ECOPETROL in this Clause but without prejudice

to the reduction of areas stipulated in Clause 8 (numeral 8.1).

9.4 If, upon completion of the additional work requested in Clause 9 (numeral

9.3), ECOPETROL accepts the existence of a Commercial Field as stipulated in

Clause 9 (numeral 9.1), it will begin to participate in the development of said

field as stipulated herein, and will reimburse THE ASSOCIATE as set forth in

Clause 9 (numeral 9.2.3-9.2.4) for fifty percent (50%) of the cost of such

additional work referred to in Clause 9 (numeral 9.3) and the work carried out

will become Joint Account property.

9.5 If ECOPETROL continues to reject the existence of a Commercial Field after

the additional work referred to in Clause 9 (numeral 9.3) has been carried out,

THE ASSOCIATE may go ahead with the work it deems necessary to exploit such

field and reimburse itself for two hundred percent (200%) of the total cost of

the work performed at its own risk and account in the respective Field and up to

fifty percent (50%) of the Direct Exploration Costs it incurred prior to

submitting commerciality studies for such Field. For the purposes of this

Clause, the reimbursement will be made with the value of Hydrocarbons produced,

less the royalties established in Clause 13, deducting production, collection,

transportation and sales costs. If THE ASSOCIATE avails itself of the sole risk

modality, it is understood that the exploitation term begins on the date

ECOPETROL notifies it that commerciality is rejected. The dollar equivalence of

disbursements made in pesos will be calculated using the market representative

rate certified by the Banking Superintendency, or entity replacing same, for the

date THE ASSOCIATE made such disbursements. For the purposes of this clause, the

value of each barrel of Hydrocarbon produced in said Field during a calendar

month, shall be the average price per barrel received by THE ASSOCIATE for the

sale of its share in the Hydrocarbons produced in the Contract area during the

same month. The contents of the paragraph of Clause 9 (numeral 9.2.3.) shall

apply to reimbursement of Direct Exploration Costs.

Once THE ASSOCIATE has reimbursed itself with the percentage established herein,

all wells drilled, the facilities and all property acquired by THE ASSOCIATE to

exploit the field and paid as set forth in this Clause, shall become the

property of the Joint Account free of any charge whatsoever, and after ECOPETROL

agrees to participate in the development of such field.

9.6

At any time, ECOPETROL may start to participate in the operation

of the

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 13.

- -------------------------------------------------------------------------------field discovered and developed by THE ASSOCIATE, subject to the latter's right

to reimburse itself for investments made at its own expense as stipulated in

Clause 9 (numeral 9.5). Once THE ASSOCIATE has repaid itself, ECOPETROL shall

start to participate in the financial results of the wells developed at the

exclusive expense of THE ASSOCIATE.

9.7 When defining the boundaries of a Commercial Field, consideration will be

given to all geological/geophysical information on such field plus that of all

wells drilled therein or related thereto.

9.8 If THE ASSOCIATE has drilled one or more Exploration Wells pointing to the

possible existence of a Commercial Field by the end of the six-year (6)

Exploration Period referred to in Clause 5 (numeral 5.2), it may ask ECOPETROL

to extend the Exploration Period for the time necessary, but not to exceed one

(1) year, to demonstrate the existence of said Commercial Field, without

prejudice to the provisions of Clause 8.

9.9 If THE ASSOCIATE continues performing the exploration obligations agreed

upon in Clause 5 after one or more fields have been declared commercial, it can

simultaneously exploit such Fields before the end of the Exploration Period

defined in Clause 4.26 but the 22-year Exploitation Period will run as of the

expiry date of the Exploration Period. When ECOPETROL has granted a Retention

Period for Gas Fields, the Exploitation Period for each Field will run from the

expiry date of the respective Retention Period.

9.10 If THE ASSOCIATE shows that Exploration Wells drilled after the Field has

been declared commercial contain additional Hydrocarbon accumulations associated

to said field, it shall ask ECOPETROL to extend the area of the Commercial Field

and its commerciality, following the procedures of Clause 9 (numerals 9.1 and

9.2.1). If ECOPETROL accepts the commerciality, it shall reimburse THE ASSOCIATE

for fifty percent (50%) of the Direct Exploration Costs exclusively related to

the extension of the Commercial Field, as set out in numerals 9.2.3 and 9.2.4.

If ECOPETROL rejects the commerciality, THE ASSOCIATE may reimburse itself for

up to two hundred percent (200%) of the total costs of work performed for, its

own risk and account in exploiting the Exploration Wells that have become

producers and up to fifty percent (50%) of the Direct Exploration Costs it

incurred solely with regard to the commerciality application. Such reimbursement

shall be made with production coming from the producing Exploration Wells, after

deducting the royalty, and following the procedure of Clause 21 (numeral 21.2)

until reaching the mentioned percentages.

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 14.

- -------------------------------------------------------------------------------CLAUSE 10 - TECHNICAL CONTROL OF THE OPERATIONS



10.1 The parties agree that THE ASSOCIATE is the Operator and as such shall

control all operations and activities it deems necessary for an efficient,

technical and economic development of Hydrocarbons existing within the

Commercial Field, respecting the restrictions contained in this contract.

10.2 The Operator must follow standard industry practices in performing

development/production work, using the technical methods and systems best suited

to an economic and efficient Hydrocarbon production, and complying with

pertinent legal and regulatory provisions on this matter.

10.3 The Operator shall be considered an entity distinct from the Parties hereto

for all contract purposes, as well as for application of civil, labor and

administrative law, and with regard to its employees as set out in

Clause 32.

10.4 The Operator may resign as such by giving the Parties six-months (6)

advance written notice of the effective date of such resignation. The Executive

Committee shall then appoint a new Operator pursuant to Clause 19 (numeral

19.3.2)

CLAUSE 11 - DEVELOPMENT PROGRAMS AND BUDGETS

11. 1 Within three (3) months following acceptance of a Commercial Field in the

Contract Area, Operator shall present the Parties with a work program and a

Budget for the rest of the calendar year together with a proposed development

plan, to be agreed by the Executive Committee. If there are less than six and a

half (6-1/2) months to run before the end of said year, Operator shall prepare

and submit the Budget and programs for the following calendar year within a term

of three (3) months.

11.1.1 Future Budgets and programs shall be submitted to the Parties in May each

year, and Operator shall send its proposal to the Parties in the first ten (10)

days of May. The Parties shall notify Operator in writing of any changes they

wish to propose, doing so within twenty (20) days of receiving the Budgets and

programs. When this occurs, Operator shall consider such proposals in preparing

the Budget and programs to be submitted for final approval by the Executive

Committee at its ordinary meeting held each July. Should the total Budget not be

approved before July, the Executive Committee shall approve those items on which

there is agreement, and the remainder shall be submitted to the Parties for

subsequent review and final decision as provided for in Clause 20.

11.1.2 The development program shall become a guide for the technical, efficient

and economic exploitation of each Field. It will describe work to be

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ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 15.

- -------------------------------------------------------------------------------carried out and estimated investments and expenses for the next five years, with

details of the annual operating program and Budget for the next calendar year.

11.2 The parties may propose Budget additions or revisions to the Budget but not

more often than every three (3) months except in emergencies. The Executive

Committee shall decide on these proposed revisions or additions at a meeting to

be scheduled within thirty (30) days following submittal thereof.

11.3



The programs and Budget are intended to-



11.3.1 Determine the operations to be carried out during the following calendar

year, as well as expenditures and investments (Budget) the Operator is

authorized to undertake.

11.3.2

Field.



Maintain a medium and long-term



view of



development



at each



11.4 The terms program and Budget refer to the proposed work plan and estimated

expenditures and investments that the Operator shall carry out, such as11.4.1

Capital investments in production: drilling for reservoir

development,

workovers or reconditioning of wells and specific production facilities.

11.4.2 General construction and equipment- industrial and camp facilities,

transport and building equipment, drilling and production equipment. Other

construction and equipment.

11.4.3

Maintenance and operating expenses-. production expenses,

geological expenses and administrative overhead for the operation.

11.4.4



Working capital needs



11.4.5



Contingency funds



11.5 Operator shall make all expenditures and investments and handle development

and production in keeping with the programs and Budgets referred to in Clause 1

1 (numeral 1 1. 1), without exceeding the total annual Budget by ten percent (1

0%), except when so authorized by the Parties in special cases.

11.6 The Operator may no start any project on its own initiative, nor charge the

Joint Account with non-Budgeted expenditure exceeding forty thousand United

States dollars (US$40,000), or the equivalent in Colombian currency, per project

or quarter.

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ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 16.

- -------------------------------------------------------------------------------11.7 The Operator is authorized to effect expenses chargeable to the Joint

Account without prior authorization from the Executive Committee when it is a

matter of taking emergency steps to safeguard persons or property of the

Parties, emergency expenses originating in fire, floods, storms or other



disasters; emergency expenses essential for the operation and maintenance of

production facilities, including keeping wells at maximum production efficiencyemergency expenses essential to protect/safeguard material/equipment needed for

operations. In such cases, the Operator shall call a special meeting of the

Executive Committee as soon as possible in order to obtain approval for

continuing with the emergency measures.

CLAUSE 12 - PRODUCTION

12.1 Whenever necessary and duly approved by the Executive Committee, Operator

shall determine the Maximum Efficiency Rate (MER) for each Commercial Field.

This Maximum Efficiency Rate (MER) shall be the maximum rate for lifting

Hydrocarbons from a reservoir in order to attain maximum final recovery of

reserves. Estimated production should be diminished as necessary to compensate

for real or anticipated operating conditions, such as wells under repair and not

producing, limited capacity of gathering lines, pumps, separators, tanks,

pipeline and other facilities.

12.2 Periodically, at least once a year and with the approval of the Executive

Committee, Operator shall determine the area capable of commercial Hydrocarbon

production in each Field.

12.3 Every three (3) months, the Operator shall prepare and give each Party two

schedules, one showing production share and the other production distribution

for each one over the following six (6) months. The production forecast shall be

based on the Maximum Efficiency Rate (MER), as set forth in Clause 12 (numeral

12.1) and adjusted to the rights of each Party hereunder. The production

distribution schedule shall be based on periodic requests from each Party and in

keeping with Clause 14 (numeral 14.2), with such corrections as may be necessary

to ensure that no Party having capacity to make withdrawals will receive less

than the amount to which it is entitled under Clause 14, and subject to Clauses

21 (numeral 21.2) and 22 (numeral 22.5).

12.4 If any Party foresees that it will be unable to receive the full capacity

of Hydrocarbons set out in the forecast furnished Operator, it shall so advise

the latter as soon as possible. If such reduction is caused by an emergency, the

Party shall notify the Operator within twelve (12) hours following the

occurrence of the respective event. In consequence, the Party concerned shall

provide the Operator with a new receiving schedule based on the reduction.

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ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 17.

- -------------------------------------------------------------------------------12.5 Operator may use the Hydrocarbons consumed in production operations in the

Contract Area, and such shall be exempt from the royalties referred to in Clause

13 (numerals 13.1 and 13.2).

CLAUSE 13 - ROYALTIES

13.1 Liquid Hydrocarbons-. During exploitation of the Contract Area, and before

distributing production among the Parties, Operator shall give ECOPETROL

royalties corresponding to twenty percent (20%) of the certified production of

liquid hydrocarbons coming from said area. ECOPETROL, for its own risk and

account, shall take the royalty production in kind from the tanks belonging to

the Joint Account.

13.2 Gaseous Hydrocarbons- Operator shall give ECOPETROL a royalty in the form

of twenty percent (20%) of the production of gaseous Hydrocarbons reported at

standard conditions. If such Hydrocarbons need to be treated at a gas plant, the

twenty percent (20%) royalty production shall be established as the sum of dry

gas produced at the plants plus the dry gas equivalent of liquid products

produced, considering the conversion factors set out in current legislation.

Regarding fields exploited under the sole risk mode, THE ASSOCIATE shall give

ECOPETROL the royalty percentage of Hydrocarbons.

13.3 ECOPETROL shall use the royalty production to pay the entities legally

appointed to receive the royalties due the State on the full production of the

Commercial Field, doing so in the manner and respecting the time limits set out

in law, and the ASSOCIATE shall in no case be liable for any payments to these

entities.

CLAUSE 14 - DISTRIBUTION AND AVAILABILITY OF HYDROCARBONS

14.1 The Hydrocarbons produced shall be transported to the jointly-owned tanks

or to other measuring facilities agreed by the Parties, except for those used

and inevitably consumed in operations hereunder. In the absence of an agreement,

the measuring point for gaseous Hydrocarbons shall be- i. The gas line of each

separator when they are not to be treated in gas plants, or ii) at the exit of

the gas plants when such treatment is required. The Hydrocarbons shall be

measured via accepted industry standards and such measurement shall be the basis

for calculating the percentages of Clause 13. Thereafter, the remaining

Hydrocarbons belong to each Party in the proportion specified in this Contract.

14.2 Production Distribution

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 18.

- -------------------------------------------------------------------------------14.2.1 After deducting the royalty percentage, the remaining Hydrocarbons

produced in each Commercial Field belong to the parties thus- Fifty percent

(50%) for ECOPETROL and fifty percent (50%) for THE ASSOCIATE until cumulative

production for each Commercial Field reaches 60 million barrels of liquid

Hydrocarbons or 420 giga cubic feet of gaseous Hydrocarbons at standard

conditions, whichever occurs first (1 cubic giga foot = 1 x 10 9- cubic feet)

14.2.2 Notwithstanding the fact that ECOPETROL has classified the Field as being

commercial, when production at each Commercial Field (after deducting the



royalty percentage) exceeds the limits of 14.2.1, distribution among the Parties

will use the R factor as set out hereunder.

14.2..2.1 If liquid Hydrocarbons first reach the limit set out in numeral 14.2.1

hereof, the following table shall apply-.

R



FACTOR Production Distribution after Royalties (%)

ASSOCIATE ECOPETROL



0.0 - 1.0

50

1.0 - 2.0

50/R

2.0 or more 25



50

100-50/R

75



14.2..2.2 If gaseous Hydrocarbons first reach the limit set out in numeral

14.2.1 hereof, the following table shall applyR



FACTOR Production Distribution after Royalties (%)

ASSOCIATE ECOPETROL



0.0 - 2.0

50

2.0 - 3.0

50/(R-1)

2.0 or more 25



50

100-[50/(R-1)]

75



14.2.3 The R factor is defined as the ratio between accrued income and accrued

disbursements made by THE ASSOCIATE for each Commercial Field, as followsIA

R

------------------ID + A - B + GO

Where<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 19.

- -------------------------------------------------------------------------------1A (The Associates Accrued Income)- is the valuation of income accrued by THE

ASSOCIATE for hydrocarbons produced, after royalties, at the reference price

agreed by the Parties, excluding hydrocarbons reinjected in Contract Area

Fields, and those consumed in the operation and burnt gas.

The parties shall jointly establish the average reference price for

hydrocarbons.

Accrued Income will be based on the Monthly Income which, in turn, will be

obtained from multiplying the average monthly reference price by the monthly

production in keeping with respective form issued by the Ministry of Mines &

Energy.

ID (Accrued Development Investment)-. Is fifty percent (50%) of the accrued

development investment approved by the Association Executive Committee. Accrued

Development Investment made prior to the exploitation start-up date of the Field

as defined by the Ministry of Mines and Energy, shall be adjusted to such date

in the same way as Direct Exploration Costs in the paragraph of Clause 9

(numeral 9.2.3).

A. Direct Exploration Costs incurred by THE ASSOCIATE according to Clause o

hereof and adjusted as set out in the paragraph of 9.2.3 .

B. Accrued reimbursement of the afore-mentioned Direct Exploration Costs, in

keeping with Clause 9 hereof.

GO (Accrued Operating Expenses)-. accrued operating expenses approved by the

Association Executive Committee, in the proportion corresponding to the

ASSOCIATE plus the latter's accrued transportation costs. Transportation costs

are investment and operating expenses for transporting hydrocarbons produced in

the Commercial Fields within the Contract Area up to the exportation port or the

place agreed for taking the price to be used in the IA calculation. Such

transportation costs will be jointly determined by the parties once the Fields

that ECOPETROL has declared to be commercial initiate the exploitation stage.

Operating expenses include special levies or similar items directly applied to

Hydrocarbon exploitation in the Contract Area.

All values included in the R factor calculation following the exploitation

start-up date established by the Ministry of Mines & Energy will be taken in

current dollars.

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 20.

- -------------------------------------------------------------------------------To this end, expenses in pesos shall be converted to dollars at the Market

Representative Rate certified by the Banking Superintendency, or entity

replacing same, in force on the date the respective disbursements were made.

14.2.4 Calculation of the R Factor: Production distribution based on the R

factor will be applied as of the first day of the third calendar month following

that when the accrued production in the Contract Area reached 60 million barrels

of liquid Hydrocarbons or 420 giga cubic feet of gaseous Hydrocarbons at

standard conditions, in keeping with 14.2.1

The R Factor for calculation each Commercial Field will be based on the

accounting closing for the calendar month when accrued production reached 60

million barrels of liquid Hydrocarbons or 420 giga cubic feet of gaseous

Hydrocarbons at standard conditions, in keeping with 14.2.1

The resulting distribution will be applied until 30th June of the following

year. Thereafter, R factor production distribution will be made for one-year

periods (lst July to 30th June) for liquidation thereof based on accrued value

at 31st December of the previous year as shown in the respective accounting

closing.



14.3 In addition to the jointly owned tanks and other facilities, each Party may

build its own production facilities in the Contract Area for its exclusive use

and in keeping with legal regulations. When Hydrocarbons belonging to each Party

are transported and delivered to pipelines and depots that are not jointly

owned, this will be for the risk and cost of the Party receiving such

Hydrocarbons.

14.4 When production sites are not connected to a pipeline, the Parties may

agree to install pipelines up to a point connecting to the pipeline or where the

Hydrocarbons can be sold, this work will be charged to the Joint Account. If the

Parties agree to build such pipelines, they will enter into the contracts they

deem suitable for this purpose and appoint the Operator pursuant to current

legislation.

14.5 Each Party shall own the Hydrocarbons produced and stored as a result of

the operation hereunder and made available to it pursuant to the provisions of

this contract. Likewise, each Party must assume the expense of receiving such

Hydrocarbons in kind or selling or disposing of them separately, as provided for

in Clause 14 (numeral 14.3).

14.6 Should one Party, for any reason, be unable to separately dispose all or

part of the Hydrocarbons to which it is entitled hereunder, or withdraw same

from the Joint Account tanks, the following stipulations shall apply14.6.1

If ECOPETROL is the Party that is unable to fully or

partially

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 21.

- -------------------------------------------------------------------------------withdraw its quota of Hydrocarbons (share plus royalty) pursuant to Clause 12

(numeral 12.3), Operator may continue producing the field and deliver to THE

ASSOCIATE not only the quota to which the latter is entitled based on a hundred

percent (100%) MER operation, but also all the Hydrocarbons that THE ASSOCIATE

chooses and is able to withdraw up to a limit of one hundred percent (1 00%) of

the MER, crediting ECOPETROL for subsequent delivery of the quota it did not

withdraw. However, regarding the volumes not taken that correspond royalties for

the month, ECOPETROL may ask THE ASSOCIATE to pay for the difference between the

Hydrocarbon volume withdrawn and the volumes corresponding to royalties as set

out in Clause 13.1 and 13.2, doing so in United States dollars. It is understood

that any Hydrocarbons withdrawn by ECOPETROL shall first be used for payment in

kind of the royalties, and thereafter, additional withdrawals will be credited

to its share as set out in Clause 14 (numeral 14.2).

14.6.2 If THE ASSOCIATE is unable to fully or partially withdraw its quota under

Clause 12 (numeral 12.3), the Operator shall deliver ECOPETROL not only its

share based on a hundred percent (100%) MER operation, but all those

Hydrocarbons that ECOPETROL is able to receive up to a limit of one hundred

percent (100%) of the MER, crediting THE ASSOCIATE for subsequent delivery of

the quota which it was unable to withdraw.

14.7 When both Parties are able to receive the Hydrocarbons allocated under

Clause 12. (numeral 12.3), the Operator shall proceed as follows. When so

requested by the Party previously unable to receive its quota, it shall deliver

such Party its share in the operation plus at least ten percent (10%) a month of

the monthly production corresponding to the other Party and by mutual agreement

up to one hundred percent (100%) of the non-received quota, until such time when

the total amounts credited to the non-receiving party are offset.

14.8 Subject to legal provisions on this matter, each Party is free at all times

to sell or export is share of Hydrocarbons, in keeping with this contract, or to

dispose thereof in anyway.

CLAUSE 15 - USE OF ASSOCIATE NATURAL GAS

When one or more fields with Associate Natural Gas are discovered, Operator

shall submit a project for using this gas for the benefit of the Joint Account,

this must be done within two (2) years following the starting date for field

exploitation as established by the Ministry of Mines and Energy. The Executive

Committee shall approve the project and establish a schedule for performance

thereof. If Operator fails to submit a project within the two-year period, or

fails to perform

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 22.

- -------------------------------------------------------------------------------same within the time limits established by the Executive Committee, ECOPETROL

may take all the Associate Natural Gas coming from the Reservoirs being

exploited and not needed for efficient field production, without having to pay

for same.

CLAUSE 16 - UNIFICATION

When an economically exploitable reservoir extends continuously into another

area or areas located outside the Contract Area, the Operator, ECOPETROL and

other interested parties should agree on a unified development program. Such

program should respect engineering techniques for Hydrocarbon production and be

approved by the Ministry of Mines and Energy.

CLAUSE 17 - INFORMATION SUPPLY AND INSPECTION DURING EXPLOITATION

17.1 The Operator shall give the Parties reproducible originals (sepias) and

copies of the electric, radioactive and sonic logs for the wells drilled,

histories, core analyses, cores, production tests, reservoir studies and other

pertinent technical data, as well as any routine reports made or received in

connection with the operations and activities carried out in the Contract Area,

doing so as these become available.

17.2 Each Party shall be entitled to inspect the wells and facilities in the



Contract Area and related activities, doing so at its own cost, expense and risk

and through authorized representatives. Such representatives shall have the

right to examine cores, samples, maps, drilling logs, surveys, books and any

other source of information connected with the performance of this contract.

17.3 Operator shall prepare all reports called for by the Colombian government

and hand them over to ECOPETROL so the latter may comply with the provisions of

Clause 29,

17.4 Information and data connected with exploitation operations shall be

treated as confidential, under the same terms as those of Clause 6 (numeral 6.3)

hereof.

CHAPTER IV - EXECUTIVE COMMITTEE

CLAUSE 18 - CONSTITUTION

18.1 Within thirty (30) days following acceptance of the first Commercial Field,

each Party should appoint a representative and his first and second alternates

to the Executive Committee, and notify the other Party in writing of the names

and

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 23.

- -------------------------------------------------------------------------------addresses of such persons. The Parties may change the representative or

alternates at any time, but should so notify the other Party in writing. The

vote or decision of each Party representative is binding on said Party. If the

main representative of either Party is unable to attend a Committee meeting, he

will be replaced by the first or second alternate, in that order, and such shall

have the same authority as the principal.

18.2 The Executive Committee will hold ordinary meetings in March, July and

November to review the development program being carried out by Operator, the

development plan and other immediate plans. In the July meeting every year, the

Operator shall submit an annual operating program and the investment and

expenditure Budget for the next calendar year.

18.3 The Parties and Operator may ask that special Executive Committee meetings

be convened to study specific operating conditions. The representative of the

interested party shall give ten (10) calendar days advance written notice of the

data and agenda for such meeting. The meeting may address any matter not

included in the agenda, provided the Party representatives agree.

18.4 For all matters discussed in the Executive Committee, the Party

representatives shall have a vote equal to the percentage held by the respective

party in the Joint Operation. Any decision or resolution taken by the Executive

Committee will only be valid if approved by over fifty percent (50%) of the

total Interest. In keeping with the mentioned procedure, decisions taken by the

Executive Committee shall be compulsory and final for the Parties and for

Operator.

CLAUSE 19 - FUNCTIONS

19.1 The Party representatives shall constitute the Executive Committee which

has full authority and responsibility to establish and adopt production,

development and operations schedules and Budgets for this contract. Operator

shall send a representative to Executive Committee meetings.

19.2 The Executive Committee shall appoint a Secretary to keep complete and

detailed records and minutes of all matters discussed and decisions taken by the

Committee. Party representatives should sign and approve the Minutes within the

ten (10) business days following adjournment of the meeting, otherwise they will

not be valid. Minutes should be delivered to the Parties as soon as possible.

19.3 The Executive Committee has the following duties, among others-.

19.3.1

Adopt its own regulations

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 24.

- -------------------------------------------------------------------------------19.3.2 Appoint the Operator in the event of resignation or removal, and issue

regulations to be met by Operator when such is a third party, setting out all

causes for removal.

19.3.3



Appoint an External Auditor for the Joint Account



19.3.4 Approve or reject the annual operations program and expenditure Budget,

any modification or revision thereof, and approve extraordinary expenses.

19.3.5



Establish expenditure policies and norms



19.3.6 Approve or reject expenditure recommended by Operator (not included in

the approved Budget) when such expenditure exceeds forty thousand dollars of the

United States of America (US$40,000) or the equivalent in Colombian currency.

19.3.7

Committee.



Advise



Operator



and



decide



on



matters



referred



to



the



19.3.8 Create such sub-committees as it deems necessary, setting out their

duties which will be performed under the supervision of the Committee.

19.3.9 Define the type and frequency of drilling, operation and production

reports and any other information that Operator must furnish the Parties

chargeable to the Joint Account.

19.3.10



Supervise handling of the Joint Account



19.3.11 Authorize the Operator to enter into contracts on behalf of the Joint

Operation when the amount thereof exceeds forty thousand dollars of the United

States of America (US$40,000) or the equivalent in Colombian currency.

19.3.12 In general, assume all functions authorized hereunder and not assigned

to another entity or person through a specific clause hereof, or legal or

regulatory provision.

CLAUSE 20 - DECISION WHEN THERE IS DISAGREEMENT IN THE OPERATION

20.1 When the Party representatives cannot agree on a Joint Operation project

that requires approval from the Executive Committee, as set out hereunder, such

matter shall be referred directly to the highest ranking executive of each Party

who

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 25.

- -------------------------------------------------------------------------------is resident in Colombia, in order that they may reach a joint decision. If the

Parties reach an agreement or decision on the matter in question within sixty

(60) calendar days after such referral, they shall so notify the Executive

Committee Secretary who should call a meeting within the fifteen (1 5) calendar

days following receipt of the notice and committee members must ratify the

agreement or decision in said meeting.

20.2 If the Parties fail to reach agreement within the sixty (60) calendar days

following the consultation, operations may go ahead pursuant to Clause 21.

CLAUSE 21 - SOLE RISK OPERATIONS

21.1 If, at any time, one Party wishes to drill an Exploitation Well that has

not been approved in the operating schedule, it shall so notify the other Party

at least thirty (30) calendar days prior to the next meeting of the Executive

Committee, together with data on location, drilling recommendation, depth and

estimated costs. The Operator shall include this proposal in the Agenda for the

next committee meeting. If the Committee approves the proposal, said well shall

be drilled for the Joint Account- otherwise the Party wishing to drill the well,

hereinafter the participating Party, shall be entitled to drill, complete,

produce or abandon such well at its own risk and for its account. The Party not

wishing to participate in the afore-mentioned operation shall be referred to as

nonparticipating Party. The participating Party should spud the well within one

hundred eighty (180) days following rejection by the Executive Committee. If

drilling does not start within this period, it must be re-submitted to the

Executive Committee. When requested by the participating Party, Operator shall

drill the afore-mentioned well for the risk and account of said Party, provided

Operator considers that such operation will not interfere with normal Field

operations, and that it has received the sums it considers necessary from the

participating Party. If Operator is unable to drill the mentioned well, the

participating Party may drill it directly or via a competent service company

and, in such case, the participating Party will be responsible for the

operation, without interfering in normal Field operations.

21.2 If the well referred to in Clause 21 (numeral 21.1) is completed as a

producer, it shall be administered by Operator and its production, after

deducting the royalty referred to in Clause 13, will belong to the participating

Party. This Party will assume all operating costs for the well until net

production value, after deducting costs of production, gathering, storage,

transport and similar, and sales costs, reaches two hundred percent (200%) of

drilling and completion costs. Thereafter, and for all contract purposes, the

well shall belong to the Joint Account as if it had been drilled with the

approval of the Executive Committee and for the

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 26.

- -------------------------------------------------------------------------------account of the Parties. For purposes of this Clause, the value of each barrel of

Hydrocarbon produced in the well during a calendar month and prior to deducting

the afore-mentioned costs, shall be the average price per barrel received by the

participating Party for sales of its share of Hydrocarbons produced in the

Contract Area during the same month.

21.3 If one Party at any time wishes to recondition or deepen a well to

Production Targets, or plug a dry hole or a non-commercial producer drilled for

the Joint Account, and such operations have not been included in the program

approved by the Executive Committee, such Party shall notify the other Party of

its intention to recondition, deepen or plug said well. If equipment is not

available at the location, the procedure of Clause 21 (numerals 21.1 and 21.2)

shall apply. If suitable equipment is available at the well site, the Party

wishing to carry out such operation shall notify the other Party which must

reply in a period of forty-eight (48) hours following receipt of such notice, if

no reply is received in this lapse, it shall be understood that the operation is

performed for the risk and account of the Joint Account. If the proposed work is

performed for the sole risk and account of the participating Party, the well

shall be administered in keeping with Clause 21 (numeral 21.2).

21.4 If, at any time, one Party wishes to build new facilities to extract liquid

from the gaseous hydrocarbons and to transport/export Hydrocarbon production,

these will be referred to as additional facilities and such Party shall notify

the other in writing as follows21.4.1 General description, design, specifications and estimated costs of the

additional facilities.

21.4.2



Planned capacity



21.4.3 Approximate date of construction start-up and duration thereof. Within

ninety (90) days counted from notification, the other Party shall give written

notice of its decision to participate in such additional facilities or not. If

it does not participate, or fails to reply to the participating Party,

hereinafter the building Party, the latter may proceed with the additional



installation and order the Operator to build/operate/maintain same for the sole

risk and account of the building Party, without hindering normal Joint

Operations. The building Party may negotiate with the other Party on using these

facilities for the Joint Operation. While the facilities are operated for the

risk and account of the building Party, the Operator shall charge the latter

with all operating/maintenance costs therefor, doing so in keeping with

generally accepted accounting principles.

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 27.

- -------------------------------------------------------------------------------CHAPTER V - JOINT ACCOUNT

CLAUSE 22 - MANAGEMENT

22.1 Subject to other provisions set out herein, Exploration expenses shall be

for the risk and account of THE ASSOCIATE.

22.2 Once the Parties accept the existence of a Commercial Field, and subject to

the provisions of Clauses 5 (numerals 5.2) and 13 (numerals 13.1 and 13.2), the

rights or Interest in Contract Area Operation shall be owned thus ECOPETROL

fifty percent (50%) and THE ASSOCIATE fifty percent (50%). Thereafter, all

expenses, payments, investments, costs and liabilities made and contracted for

operations hereunder and Direct Exploration Costs made by the ASSOCIATE prior to

acceptance of each Commercial Field and extensions thereto, in keeping with

Clause 9 (numeral 9.10), shall be charged to the Joint Account. Except as set

out in Clauses 14 (numeral 14.3) and 21, all assets acquired or used thereafter

for operating the Commercial Field shall be owned and paid for by the Parties as

set out in this clause.

22.3 The Parties shall pay Operator their share of budget requirements, doing so

in the currency in which expenditure is to be disbursed, that is Colombian pesos

or United States dollars as called for by Operator in keeping with programs and

Budgets approved by the Executive Committee. This payment shall be made in the

first five (5) days of each month and at the bank chosen by Operator. When THE

ASSOCIATE lacks sufficient Colombian pesos to cover its pesos share, ECOPETROL

may supply these funds and have them credited to its dollar obligation, using

the market representative rate certified by the Banking Superintendency, or the

entity acting in this capacity, on the day that ECOPETROL should make the

respective payment, provided such transaction is legally acceptable.

22.4 The Operator shall give the Parties a monthly statement showing the funds

advanced, expenses incurred, outstanding liabilities and a report on all debits

and credits made to the Joint Account, this report should follow Appendix B

hereto. The statement and report should be submitted monthly within the fifteen

(15) calendar days following the end of each month. If the payments mentioned

under Clause 22 (numeral 22.3) are not made within stipulated term and Operator

chooses to pay same, the delinquent Party shall pay commercial interest in the

same currency for the time of such delay.

22.5 If one Party fails to pay the Joint Account on the due date, it shall be

considered thereafter as the delinquent Party and the other as the Prompt party.

If

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives

Page 28.

- -------------------------------------------------------------------------------the Prompt party were to pay both its own share and that of the delinquent

Party, after sixty (60) days of delay, it shall be shall be entitled to receive

from Operator the full share of the delinquent Party in the Contract Area

(excluding royalty percentage). This will continue until production provides the

prompt Party with a net income from sales equal to the sum not paid by the

delinquent Party, plus annual interest at the Commercial rate as of the sixtieth

(60) day following the delinquency date. Net income is understood as the

difference between the sales price of the Hydrocarbons taken by the prompt

Party, less the cost of transport, storage, loading and other reasonable

expenses disbursed by such Party in selling such production. The prompt Party

may exercise this right at any time after thirty (30) calendar days of having

notified the delinquent Party in writing of its intention to take part or all

such Party's production.

22.6.1 All Direct Expenses of the Joint Operation will be charged to the Parties

in the same proportion as for production distribution after royalties.

22.6.2 Indirect Expenses will be charged to the Parties in the same proportion

as for Direct Expenses set out in 22.6.1 hereof. These expenses shall be the

result of applying the equation a+m (X-b) to the total annual amount for

investment and direct expenditures (excluding technical and administrative

overhead).

Where:

x Is total annual investments and expenditures "a", "m", and "b" are constants

whose values are set out in the table hereunder depending on the amount of

annual investment and expenditures

INVESTMENTS AND EXPENDITURE - CONSTANT VALUES

x

(US$)

a(US$)

1

0

25,000,000 0

2

25,000,001 50,000,000 2,500,000

3

50,000,001 100,000,000 4,500,000

4

100,000,001 200,000,000 8,000,000

5

200,000,001 300,000,000 14,000,000

6

300,000,001 400,000,000 18,000,000

7

400,000,001 onwards

20,000,000



0.10

0.08

0.07

0.06

0.04

0.02

0.01



m(fract)

"b"(US$)

0

25,000,000

50,000,000

100,000,000

200,000,000

300,000,000

400,000,000



The equation will be applied once a year in each case, applying the constants



that correspond to the total sum of annual investments and expenditure.

22.7 Either Party may review or question the monthly statements of account

referred to in Clause 22 (numeral 22.4) from the time they are received up to

two years following the end of the respective calendar year, clearly indicating

the

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 29.

- -------------------------------------------------------------------------------corrected or questioned items and the reasons therefor. Any account that has not

been corrected or questioned in this period, shall be considered as final and

correct.

22.8 The Operator shall keep accounting books, vouchers and reports for the

Joint Account, in Colombian pesos and according to Colombian law. Any credit or

debit to the Joint Account shall follow the accounting procedure set out in

Appendix B which is a part hereof. In the event of any discrepancy between said

accounting procedure and the terms of the contract, the latter shall prevail.

22.9 Operator may sell material or equipment during the first twenty (20) years

of the Exploitation Period, or the first twenty eight (28) years in the case of

a Gas Field, crediting the proceeds to the Joint Account when the amount does

not exceed five thousand dollars of the United States of America (US$5,000) or

the equivalent in Colombian currency. In any calendar year, operations of this

type may not exceed fifty thousand dollars of the United States of America

(US$50,000) or the equivalent in Colombian currency. The Executive Committee

must approve sales of real estate or those exceeding the afore-mentioned

amounts. These materials or equipment shall be sold at a reasonable price

considering their condition.

22.10 All machinery, equipment or other assets or chattels purchased by Operator

for contract performance and charged to the Joint Account shall belong to the

Parties in equal shares. However, if one Party decides to terminate its interest

in the contract during the first seventeen (1 7) years of the Exploitation

Period, except as set out in Clause 25th, said Party must sell all or part of

its share in said items to the other Party at a reasonable commercial price or

at book value, whichever is lower. If the other Party is not interested in

purchasing them within ninety (90) days following the formal sales offer, the

withdrawing Party shall be entitled to assign its interest in said machinery,

equipment, and items to a third party. If THE ASSOCIATE wishes to withdraw after

seventeen (17) years of the Production Period have elapsed, its rights in the

Joint Operation shall pass to ECOPETROL free of charge, once the latter has

accepted.

CHAPTER VI - CONTRACT DURATION

CLAUSE 23 - MAXIMUM DURATION

This contract shall last for a maximum period of twenty eight (28) years running

from the Effective Date and broken down thus: up to six (6) years for the

Exploration Period in keeping with Clause 5 and subject to Clause 9 (numerals

9.3 and 9.8); and twenty-two years for the Exploitation Period counted from the

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 30.

- -------------------------------------------------------------------------------termination date of the Exploration Period. It is understood that when the

Exploration Period is extended as provided for in this contract, this shall

never signify an extension to the total twenty-eight (28) year term, except as

stipulated in paragraph I hereunder.

Paragraph 1: The Exploitation Period for Gas Fields discovered in the Contract

Area shall have a maximum duration of thirty (30) years counted from the expiry

date of the Exploration Period, or of the Retention Period. In any case, the

total contract term for such Fields cannot exceed forty (40) years counted from

the Effective Date.

Paragraph 2: Notwithstanding the above, at least five (5) years prior to the

expiry of the Exploitation Period for each Field, ECOPETROL and THE ASSOCIATE

will study conditions for continuing exploitation beyond the term stipulated in

this Clause. If the Parties agree to continue with such exploitation, they will

define the terms and conditions therefor.

CLAUSE 24 - TERMINATION

This contract shall terminate in the following cases:

24.1 Upon expiry of the Exploration Period if THE ASSOCIATE has not discovered a

Commercial Field, except as set out in Clauses 9 (numerals 9.5 and 9.8) and 34.

24.2 Upon expiry of contract duration, as stipulated in Clause 23.

24.3 At any date when THE ASSOCIATE so wishes and provided it has met its

obligations stipulated in Clause 5th, and all others contracted

hereunder.

24.4 For the special causes set out in Clause 25th.

CLAUSE 25 - CAUSES FOR UNILATERAL TERMINATION

25.1 ECOPETROL may unilaterally declare this contract terminated at any time

prior to expiry of the period agreed to in Clause 23, in the following cases.

25.1.1



Death or dissolution of THE ASSOCIATE or its assignees.



25.1.2

If THE ASSOCIATE or its assignees were to transfer this

contract,

fully or partially,

without

giving

compliance to the

provisions of Clause 27.



<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 31.

- -------------------------------------------------------------------------------25.1.3 For financial incapacity of THE ASSOCIATE and its assignees which shall

be assumed when bankruptcy proceedings are filed.

25.1.4 When THE ASSOCIATE defaults on its obligations contracted under this

contract.

Upon expiry of each period defined for exploratory work, THE ASSOCIATE shall

submit a written report showing performance of the obligations for the

respective period. If such have not been performed, THE ASSOCIATE shall be given

sixty (60) calendar days to diligently perform same in keeping with good

petroleum practices. If such period is insufficient, the Parties may mutually

agree to establish a longer period for performance. If the agreed work has still

not been performed at the end of this new extension, there will be default and

consequently ECOPETROL may proceed as set out in clause 25.3

25.2 When unilateral termination is declared, the rights of THE ASSOCIATE set

out in this contract will lapse, both as interested Party and as Operator, if at

such time the ASSOCIATE is acting in both capacities.

25.3 ECOPETROL may only declare unilateral termination of this contract when it

has given the ASSOCIATE or its assignees sixty (60) calendar days advance

written notice thereof, clearing stating the reasons for such decision, and when

THE ASSOCIATE has failed to provide ECOPETROL with satisfactory explanations or

to correct the default in contract performance. This does prevent THE ASSOCIATE

from filing any appeal it considers to be in order.

CLAUSE 26 - OBLIGATIONS IN EVENT OF TERMINATION

26.1 When the contract is terminated under Clause 24th during the Exploration,

Retention or Exploitation Periods, THE ASSOCIATE shall hand over the buildings,

pipelines, transfer lines and other movable items belonging to the Joint Account

(located in the Contract Area), leaving any producing wells in production, and

all of this will pass to ECOPETROL free-of-charge together with the

rights-of-way and assets acquired for the contract, even though these may be

located outside the Contract Area.

26.2 If this contract is terminated for any reason after the first

seventeen (17) years of the Production Period, all interest of THE

ASSOCIATE in the machinery, equipment or other assets or movables used

or purchased by THE ASSOCIATE or the OPERATOR for contract performance,

shall pass to ECOPETROL free-of charge.

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 32.

- -------------------------------------------------------------------------------26.3 If this contract terminates in the first seventeen (17) years of the

Exploitation Period, the terms of Clause 22 (numeral 22.10) shall apply.

26.4 If this contract is terminated unilaterally at any time, all chattels and

real estate acquired exclusively for the Joint Account shall pass to ECOPETROL

free-of-charge.

26.5 Upon contract termination at any time and for any reason, the Parties

commit to give satisfactory compliance to their legal obligations both among

themselves and with third parties, as well as those contracted hereunder.

CHAPTER VII - MISCELLANEOUS PROVISIONS

CLAUSE 27 - ASSIGNMENT RIGHTS

27.1 THE ASSOCIATE is entitled to fully or partially cede or transfer its

rights, interests, and obligations in the Association Contract to another

person, company or group, with the consent of the Minister of Mines & Energy and

the President of ECOPETROL

Consequently, THE ASSOCIATE must notify the Ministry of Mines & Energy and the

President of ECOPETROL via a certified document of any project that implies

total/partial assignment or transfer of its interest, rights and obligations

hereunder, indicating essential points of the transaction such as possible

assignee, price, interest, rights and obligations to be assigned, scope of the

operation etc. The Minister of Mines & Energy and President of the Empresa

Colombiana de Petroleos - ECOPETROL shall have thirty (30) business days to

exercise their discretionary powers and appraise the possible assignees, and

subsequently take a decision without being obliged to give reasons therefor. In

any case, the criterion of the Minister of Mines & Energy shall prevail.

27.2 If the ASSOCIATE has not received a reply thirty (30) business after

submitting the application to the Minister of Mines & Energy, it will be

understood for all purposes that such has been approved.

27.3 Assignments made during the Exploration Period among companies legally

established in Colombia shall not be subject to the above mentioned procedure,

they shall be formalized by written authorization from ECOPETROL and signing the

respective document.

27.4 Any change in the contractual relations between THE ASSOCIATE and ECOPETROL

resulting from direct, total or partial transactions of the interest,

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 33.

- -------------------------------------------------------------------------------quotas or stock of the former must also be approved by the Minister of Mines and

Energy and President of ECOPETROL.

27.5 However, such changes shall not require authorization from the Minister of

Mines and Energy and Ecopetrol in the following cases-.



27.5.1 When the transactions are made in an open stock exchange.

27.5.2 When the transfer/cession is the result of matters beyond the control of

the ASSOCIATE or the companies that control or direct same, such as governmental

decisions, judicial sentences, division and award of assets and auctions.

27.5.3 When the negotiations take place between companies that control or direct

THE ASSOCIATE, or their subsidiaries or affiliates, or between companies making

up a single economic group, it suffices to notify the Minister of Mines & Energy

and ECOPETROL of such assignment or cession in a timely way.

27.6 Except for the above cases, any cession, transfer, negotiation, transaction

or operation referred to in this Clause that is made without approval or consent

of the Minister of Mines & Energy and the President of ECOPETROL, when called

for, shall give rise to the application of Clause 25th of the Association

Contract.

27.7 If the operations carried out under this Clause give rise to taxes under

Colombian law, such shall be paid.

CLAUSE 28 - DISAGREEMENT

28.1 Whenever there is a discrepancy or contradiction in interpreting the

clauses hereunder as compared to those of Appendix B known as the Operating

Agreement, the former shall prevail.

28.2 Disagreements of a legal nature arising among the Parties with regard to

contract interpretation and performance and that cannot be resolved in a

friendly way, shall be referred to the decision of the jurisdictional branch of

Colombian public power.

28.3 Any difference of a technical nature arising among the parties with regard

to contract interpretation and performance and that cannot be resolved in a

friendly way shall be referred to the final decision of experts appointed thus:

one by each Party and a third chosen by the first two. If the latter are unable

to reach agreement on such third expert, either Party may ask the Board of

Directors of the Colombian Society of Engineers - SCI - having its head office

in Santafe de

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 34.

- -------------------------------------------------------------------------------Bogota to appoint same.

28.4 Any difference of an accounting nature arising among the parties with

regard to contract interpretation and performance and that cannot be resolved in

a friendly way shall be referred to the final decision of experts who should be

public accountants appointed thus- one by each Party and a third chosen by the

first two. If the latter are unable to reach agreement on such third expert,

either Party may ask the Central Board of Accountants of Bogota to appoint same.

28.5 Both Parties declare that the decision of the experts shall have the force

of a settlement among themselves, and consequently shall be final.

28.6 If the Parties fail to agree on whether the controversy is of a legal,

technical or accounting nature, such shall be considered legal and subject to

Clause 28th (numeral 28.2).

CLAUSE 29 - LEGAL REPRESENTATION

Without impairing the legal rights of the ASSOCIATE as set out in law or in this

Contract, ECOPETROL shall represent the Parties with Colombian authorities in

matters regarding the development of the Contract Area, whenever such is called

for, furnishing government offices and entities with all information and reports

they may legally require. Operator must prepare the respective reports and hand

them over to ECOPETROL. Any expenses incurred by ECOPETROL to attend matters

referred to in this Clause shall be charged to the Joint Account. When such

expenses exceed five thousand dollars of the United States of America (US$5,000)

or the equivalent in Colombian currency, the Operator must first approve same.

Regarding any relations with third parties, the Parties represent that neither

the provisions of this or any other Clause in the contract, implies granting a

general power-of-attorney, nor that the Parties have set up a civil or

commercial association or any other relationship whereby either Party may be

held jointly liable for the acts or failure to act of the other Party, or have

authority or mandate to commit the other Party with regard to any obligation.

This contract refers to operations within the Republic of Colombia and while

ECOPETROL is an industrial and commercial company belonging to the Colombian

State, the Parties agree that THE ASSOCIATE, if such were the case, may choose

to be excluded from the provisions of sub-chapter K entitled Partners and

Partnerships of the Internal Income Code of the United States of America. The

ASSOCIATE may make such choice in a suitable way.

CLAUSE 30 - RESPONSIBILITIES

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 35.

- -------------------------------------------------------------------------------30.1 The Operator shall perform operations hereunder in a manner that is

diligent, responsible, efficient, economically and technically sound and in

keeping with internationally accepted industry practices for this type of

operation, it being understood that at no time shall it be liable for errors of

judgment, or loss or damage that is not directly attributable to it.

30.2 Liabilities contracted by ECOPETROL and THE ASSOCIATE hereunder with third

parties shall not be joint, therefore each Party is individually liable for its

share in the expenses, investments and obligations resulting therefrom.

30.3 Operator alone shall be liable with third parties for expenses incurred and



contracts entered into for amounts exceeding forty thousand United States

dollars (US$40,000) or the equivalent in Colombian currency when such have not

been duly authorized by the Executive Committee, except as ruled in Clause 1 1

(numeral 11.7) and therefore it shall assume the full cost thereof. When the

Executive Committee accepts such expenditure, it will pay Operator for the work,

study or purchase in keeping with the guidelines it has set out in this respect.

If the Executive Committee rejects the expense or asset, Operator if possible

should withdraw same and reimburse the partners for any expense incurred in such

withdrawal. When Operator is unable or refuses to withdraw the assets, the

resulting equity increase or profit from such expenditure or contract shall

belong to the Parties in proportion to their share in the Operation.

30.4 Ecological Control. In performing work hereunder, THE ASSOCIATE should

comply with the provisions of the National Code for Renewable Natural Resources

and Environmental Protection and other legal provisions on this matter. THE

ASSOCIATE undertakes to carry out a permanent prevention plan to guarantee

conservation and restoration of natural resources within the zones where it

carries out Exploration, development and transport hereunder.

THE ASSOCIATE should make these plans and programs known to the communities and

to national and regional entities involved in this matter. Likewise, specific

contingency plans should be established to deal with emergencies and take

pertinent remedial action. To this end, THE ASSOCIATE should coordinate plans

and action with the authorized entities.

THE ASSOCIATE must prepare the respective Budgets and programs as set out in the

pertinent clauses of this contract.

All costs incurred shall be assumed by THE ASSOCIATE in the Exploration Period

and in sole risk operations during the Exploitation Period. During the

Exploitation Period these costs will be charged to the Joint Account and shared

by both Parties.

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 36.

- -------------------------------------------------------------------------------CLAUSE 31 - TAXES, LEVIES AND OTHERS

Taxes and levies related to Hydrocarbon production, caused after the Joint

Account has been set up but before the Parties receive their production share,

shall be charged to the Joint Account. Each Party shall be exclusively liable

for its own taxes on income, capital and similar.

CLAUSE 32 - PERSONAL

32.1 When THE ASSOCIATE is Operator, it should consult ECOPETROL before

appointing the Manager for Operator.

32.2 According to the terms hereof, and subject to norms to be established,

Operator shall be free to appoint the personnel needed for operations hereunder,

and may fix salary, duties, categories and conditions thereof. Operator shall be

diligent in training Colombian personnel needed to replace the foreign personnel

that it considers necessary for operations hereunder. In any case, Operator

shall comply with legal provisions on the proportion of local and foreign

personnel.

32.3 Transfer of Technology: THE ASSOCIATE commits to assume the cost of a

program to train ECOPETROL professionals in areas related to contract

performance.

In the Exploration Period, this obligation could be met by training in- geology,

geophysics and related areas, reserve appraisal, reservoir characterization,

drilling and production, among others. Supervised training should take place

throughout the initial exploration period and its extension by integrating the

ECOPETROL professionals to the work group THE ASSOCIATE sets up for either the

Contract Area or other similar activities.

If THE ASSOCIATE wishes to resign as set out in Clause 5, it must have first

given compliance to these training programs.

The Association Executive Committee shall establish the scope, duration, place,

participants, conditions and other aspects of training during the Exploitation

Period.

THE ASSOCIATE shall assume all costs of supervised training during the

Exploration Period, except for labor costs of the professionals attending same.

During the Exploitation Period both parties shall assume these costs via the

Joint Account.

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 37.

- -------------------------------------------------------------------------------PARAGRAPH: To comply with Technology Transfer called for hereunder, THE

ASSOCIATE commits to run annual supervised training programs for Ecopetrol

professionals for each of the first three years of the Exploration Period, in an

amount of fifty thousand (US$50,000) United States dollars per year. ECOPETROL

and THE ASSOCIATE shall first agree on the subject and type of training. If the

Exploration Period is extended, the supervised training will be similar to that

set out here.

32.4 During the Exploitation Period, Operator may perform any work through

contractors, subject to the Executive Committee approval when the amount of the

contract exceeds forty thousand dollars of the United States of America

(US$40,000) or the equivalent n Colombian currency.

CLAUSE 33 - INSURANCE

The Operator shall take all insurance called for under Colombia law. Likewise,



it shall require any contractor engaged in work hereunder to obtain such

insurance as the Operator considers necessary and keep same in force. Likewise,

Operator shall take such additional insurance as the Executive Committee deems

suitable.

CLAUSE 34 - FORCE MAJEURE or FORTUITOUS CIRCUMSTANCES

The obligations referred to hereunder shall be suspended for such time as either

Party is unable to fully or partially perform same because of unforeseen events

that constitute force majeure or fortuitous circumstances, such as strikes,

shutouts, wars, earthquakes, floods or other catastrophes, laws, decrees or

government regulations that prevent procurement of essential materials and, in

general, any non-financial reason that effectively impedes work, even when not

listed above, but that affects the Parties and is outside their control. If

force majeure or fortuitous circumstances prevent one Party from performing its

duties hereunder, it should immediately notify the other Party, setting out the

causes of

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 38.

- -------------------------------------------------------------------------------such impediment. Under no circumstances shall force majeure or fortuitous

circumstances extend or prolong the total period of exploration, retention or

exploitation beyond maximum contract term set out in Clause 23rd. However, any

force majeure event during the six (6) year exploration period set out in Clause

5 and which lasts for over thirty consecutive days, shall extend this six-year

(6) period for the same time as that of the impediment.

CLAUSE 25 -APPLICATION OF COLOMBIAN LAW

The Parties establish Santa Fe de Bogota, Republic of Colombia, as the domicile

for all contract purposes. This contract is fully ruled by Colombian law and THE

ASSOCIATE accepts the jurisdiction of Colombian courts and waives diplomatic

claim regarding its rights and duties hereunder, except in the case of denial of

justice. It is understood there shall not be denial of justice when THE

ASSOCIATE as Party or Operator has had access to all remedies and means of

action that may be exercised with the jurisdictional branch of public power

under Colombian law.

CLAUSE 36 - NOTICES

Notices or communications among the Parties regarding this contract must be sent

to the following addresses and mention the pertinent clauses in order to be

considered valid:

ECOPETROL - Carrera 13 No. 36-24, Santafe de Bogota, Colombia

THE ASSOCIATE - Calle 114 No. 9-01, Torre A, of.707 Santafe de

Colombia



Bogota,



Any change of address shall be notified to the other Party in advance.

CLAUSE 37 - VALUATION OF HYDROCARBONS

Payments or reimbursements referred to in Clauses 9 (numerals 9.2 and 9.4) and

22 (numeral 22.5) shall be made in dollars of the United States of America or in

Hydrocarbons, based on the price in force and the restrictions existing or to be

applied under Colombian law for sale of the dollar portion of hydrocarbons

coming from the contract area and destined for domestic refining.

CLAUSE 38 - HYDROCARBON PRICES

38.1 Hydrocarbons belonging to the ASSOCIATE hereunder and destined for domestic

refining or supply shall be paid for at the refinery where they are to be

processed or at the receiving station agreed to by the Parties, in keeping with

current governmental measures or those replacing same.

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 39.

- -------------------------------------------------------------------------------38.2 Differences arising in the application of this Clause shall be settled via

the means set out in this Contract.

CLAUSE 40 - DELEGATION AND ADMINISTRATION

In keeping with ECOPETROL regulations, its President delegates the

administration of this contract to the Vice President for Exploration and

Production, with power to take all action pertinent to contract performance. The

Vice-President of Exploration and Production may exercise this delegation via

the Assistant Vice President for Joint Operations.

CLAUSE 41 -VALIDITY

This contract must be approved by the Ministry of Mines & Energy in order to be

valid (and the incorporation and approval of the Colombian branch, if

pertinent).

In witness whereof, the parties sign in the presence of witnesses in Santa Fe de

Bogota, on the 30th day of the month of December nineteen hundred and

ninety-seven (1997)

EMPRESA COLOMBIANA DE PETROLEOS

ECOPETROL

ENRIQUE AMOROCHO CORTEZ

President

SEVEN SEAS PETROLEUM COLOMBIA INC.

GUSTAVO VASCO MUNOZ



Legal Representative

Witnesses

<PAGE>

ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 40.

- -------------------------------------------------------------------------------EMPRESA COLOMBIANA DE PETROLEOS

Calculation of area,

origin

Santafe de Bogota.



direction



and distances



using Gauss



coordinates,



Data and results of ROSABLANCA sector

Point Norte

A 1,402,900

B 1,430,000

c 1,430,000

D 1,460,000

E 1,460,000

F 1,425,000

G 1,425,000

H 1,425,000

I 1,421,000

J 1,421,000

K 1,402,900

A 1,402,900



East

1,020,000

1,020,000

1,030,000

1,030,000

1,060,000

1,060,000

1,052,000

1,036,522

1,036,410

1,026,410

1,026,410

1,020,000



Distance

27,100

10,000

30,000

30,000

35,000

8,000

15,478

4,001.57

10,000

18,100

6,410 0.00



Dif. N.

27,100

0.0

30,000

0.00

-35,000

0.00

0.00

-4,000

0.00

-18,100

-6,41



Dif. E

0.00

10,000

0.00

30,000

0.00

- 8,000

-15,478

-112

-10,000

0.00

0.00



Direction

North

East

North

East

South

West

West

Si 36.13.0.906w

West

South

West



Polygonal area: 128,188 hectares, 5,000 M2

<PAGE>

CONTENTS

Page

PART I - TECHNICAL ASPECTS .........................................

1

Section One - Exploration

CLAUSE 1 INFORMATION TO BE SUPPLIED DURING EXPLORATION .............

1

CLAUSE 2 AREAS DEVOLUTION ..........................................

4

Section Two - Production ...........................................

1

CLAUSE 3 EXTENSIVE PRODUCTION TESTS ................................

5

CLAUSE 4 COMMERCIAL FIELD ..........................................

6

CLAUSE 5 OWN RISK MODALITY .........................................

6

CLAUSE 6 OPERATIONS INSPECTION .....................................

7

CLAUSE 7 PRODUCTION ................................................

7

CLAUSE 8 HYDROCARBON DISTRIBUTION AND AVAILABILITY .................

7

CLAUSE 9 EXPORT HYDROCARBON SUPPLY .................................

8

PART II - ACCOUNTING AND FINANCIAL ASPECTS .........................

8

Section One - Programs and Budgets

CLAUSE 10 EXPLORATION PROGRAMS AND BUDGETS .........................

8

CLAUSE 11 PRODUCTION PROGRAMS AND BUDGETS ..........................

8

CLAUSE 12 BUDGET MANUAL ............................................

8

CLAUSE 13 INCOME BUDGET ............................................

9

CLAUSE 14 EXPENSES BUDGET .......................................... 10

CLAUSE 15 OTHER PROVISIONS ......................................... 17

Section Two. Accounting procedures ................................. 17

CLAUSE 16 ACCOUNTING PROCEDURE ..................................... 20

CLAUSE 17 CASH CALLS, BILLS AND ADJUSTMENTS ........................ 21

CLAUSE I8 CHARGES .................................................. 23

CLAUSE 19 CREDITS .................................................. 27

CLAUSE 20 DISPOSAL OF EXCESS MATERIAL AND EQUIPMENT ................ 28

CLAUSE 21 INVENTORY ................................................ 28

CLAUSE 22 AUDIT .................................................... 30

CLAUSE 23 FEES TABLE ............................................... 30

CLAUSE 24 CONTRIBUTIONS IN KIND .................................... 32

PART III - ADMINISTRATIVE ASPECTS AND SUNDRY PROVISIONS ............ 32

Section One - The Executive Committee

CLAUSE 25 OPERATING CONDITIONS ..................................... 32

Section Two - Subcommittees

CLAUSE 26 SUBCOMMITTEES ORGANIZATION ............................... 33

Section Three - Operator

CLAUSE 27 RIGHTS AND OBLIGATIONS ................................... 34

Section Four - Contracting Procedures .............................. 35

CLAUSE 28 SUPPLIERS REGISTER AND LIST OF PROPONENTS ................ 35

CLAUSE 29 TENDER PROCEDURES ........................................ 35

CLAUSE 30 CONTRACT AWARD AND PURCHASE ORDERS ....................... 37

CLAUSE 31 CONTRACTS AND PURCHASE ORDERS MANAGEMENT ................. 39

CLAUSE 32 INSURANCE ................................................ 40

CLAUSE 33 FORCE MAJEURE OR ACTS OF GOD ............................. 40

CLAUSE 34 OPERATION AGREEMENT REVISION ............................. 41

<PAGE>

EXHIBIT B TO THE OPERATION AGREEMENT

ASSOCIATION CONTRACT "ROSA BLANCA" SECTOR

EXHIBIT B - OPERATION AGREEMENT

EXHIBIT TO "ROSABLANCA" ASSOCIATION CONTRACT

Entered into between EMPRESA COLOMBIANA DE PETROLEOS ECOPETROL and SEVEN SEAS

PETROLEUM COLOMEBIA INC., with Effective Date on the 28th day of

the month of February, of nineteen hundred ninety-eight (1998, hereinafter the

Contract.

PART I- TECHNICAL FACTORS.

CLAUSE 1 - INFORMATION SUPPLY DURING EXPLORATION

Geological and geophysical information to be supplied by the ASSOCIATE to

ECOPETROL shall be provided according to international standards accepted by

the industry, compatible with standards applied by ECOPETROL (included in

ECOPETROL Information Supply Manual) to enable regional sedimentary basins

evaluation. To complement Contract Clause 6 (section 6.2) the ASSOCIATE or the

Operator shall deliver to ECOPETROL, as obtained, the following information

associated to exploration activities conducted by the ASSOCIATE:



1.1 Geological, geophysical, magnetometric, gravimetric, remote sensors,

electric meters information and in general any Exploration Work conducted by

the ASSOCIATE in development of the Contract, shall be submitted in magnetic

media, original and reproducible copy with the respective support information,

including acquisition and interpretation maps, acquired data processing and

interpretation.

1.2 Processed seismic section for each line, obtained in two scales, together

with an interpretation report containing: information used, background, seismic

programs, geological information and geophysical, geological and economic

considerations supporting technical conclusions and recommendations.

1.3 Two (2) sets of seismic lines magnetic tapes, one of them containing

demultiplexed information and the other containing stack information and the

respective support

<PAGE>

information and processing report. In the event of vibration a copy of the field

tape instead of demultiplexed tape shall be delivered.

1.4 Seismic programs shooting points map in reproducible sepia and copy,

containing coordinates and elevations identification. This information shall

also be supplied in magnetic tape.

1.5 Magnetic and gravimetric profiles and residual maps in reproducible

originals, copies and magnetic tapes including all information generated.

1.6 Seismic, gravimetric and magnetometric interpretation report, together

with all interpreted sections profiles and maps submitted in accordance with

ECOPETROL standards for this type of information.

1.7 Geological, structural, isopachous, isolitic, facies, seismic, etc. maps

of the Contract Area in reproducible sepia and copies in scales determined by

ECOPETROL for each basin.

1.8 Before well drilling: Intention to drill (Ministry of Mines and Energy

Form 4-CR), drilling program, well location map, prospect area isochrone or

structural map and drilling geological prognosis, duly approved by the Ministry

of Mines and Energy. Exploration wells location shall be referred to the

seismic maps on which basis the prospect was defined. At each Exploration Well

to be drilled in the Contract Area, a geodesic precision point accepted by

"Instituto Geografico Agustin Codazzi - IAGC", obtained by satellite shall be

materialized with its respective azimuth line.

1.9 Daily drilling and geology reports. These reports shall be directly

delivered to ECOPETROL, preferably via fax and shall contain basic well

information, drilling conditions, drilling fluid properties, Hydrocarbon

expressions as obtained, penetrated geological formations description and daily

and accumulated costs together with the program to be developed.

<PAGE>

The ASSOCIATE or the Operator shall report sufficiently in advance to ECOPETROL

on electric logging, cores sampling and test to be performed for ECOPETROL to

send a representative to witness all operations.

1.10 Copy of bi-weekly reports forwarded to the Ministry of Mines and Energy

(Form 5CR).

1.11 Final geology report: This report is mandatory for any well drilled in the

country, whether exploration, stratigraphic or development and shall be

submitted in Spanish by a registered geologist no later than ninety (90) days

after well completion or abandonment; the report shall include the following

information by chapters;

1.11.1



A summary of all activities developed during drilling



1.11.2



Well location and 1:250,000 scale maps



1.11.3

Stratigrapy: Shall include the stratigraphic column, environments

determination and each drilled formation age.

1.11.4

Biostratigraphy: shall include dispersion charts, analysis conducted

and potential correlation.

1.11.5

Geochemistry: shall include all analysis performed both on ditch

samples and each of the recovered cores.

1.11.6

Electric logging: shall include all RW, SW determination

calculations. Speed logging analysis shall be included in this chapter.

1.11.7

Formation tests: shall include all results obtained from each of the

tests taken and water and Hydrocarbon laboratory analysis.

1.11.8

The Final Geological Report shall be accompanied of the following

exhibits:

Exhibit A: Description of ditch samples taken every ten (IO) feet.

Exhibit B: Detailed description of cores and wall samples recovered.

Exhibit C: All cores and wall samples lab analysis.

Exhibit D: Composed graphic log in reproducible sepia and copy in 1:500 scale.

For the different lithologies included in the composed graph log symbols used

for such cases by the American Association of Petroleum Geologists (AAPG) shall

be used.

Exhibit E: Final report issued by the well logging company, including the

"Grapholog".



1.12 Reproducible sepias and copies of each well logs including speed logging

in 1:200 and 1:500 scales. Additionally deliver magnetic tapes in LIS format

containing all

<PAGE>

logs, accompanied of computer tabulates using forms provided by ECOPETROL for

such cases.

1.13 Formation and/or production tests report including bottom pressure

analysis (open and closed well).

1.14 Shall deliver to ECOPETROL two sets of ditch samples, one of them unwashed

taken every thirty (30) feet and the other dry taken every ten (10) feet

including a detailed lithological samples description.

1.15 Coring report, when performed, including a detailed description thereof

and all analysis performed. Together with this report the ASSOCIATE shall

deliver to ECOPETROL photographs and fifty percent (50%) core.

1.16 Report all materials used for drilling.

1.17 Biostratigraphic reports including the respective dispersion chart. These

analyses shall be performed for Exploration wells considering this information

defines sedimentation environments and each drilled formation age. This type

of analyses may also be performed on the different cores recovered.

1.18 Geochemical ditch, wall and core samples analysis.

1.19 Official well completion, plugging or abandonment report (form 6CR or 10A

CR) and in general, any other report referring to well completion (subsequent

work, multiple completion).

1.20 Final well report. Shall include all engineering information and a final

geologic report summary. Shall be submitted in Spanish no later than ninety

(90) days after well completion or abandonment, and approved by a duly

registered Petroleum engineer.

1.21 Copy of the Annual Technical report (Geology and Geophysics and

Engineering Report) including the respective supports, submitted to the

Ministry of Mines and Energy according to applicable legal regulations.

1.22 Any other engineering or geology study conducted.

CLAUSE 2 - AREAS DEVOLUTION

Areas to be returned ECOPETROL by the ASSOCIATE, according to Contract Clause

8, shall be, as far as possible, regular polygonal lots to facilitate

boundaries determination without prejudice of commercial areas.

SECTION TWO - PRODUCTION

CLAUSE 3 - EXTENSIVE PRODUCTION TESTS

The following will be the procedures applied to extensive Hydrocarbon

production tests management previous Commercial Field acceptance.

3.1 For obtained volumes management and handling, tests permit shall have been

obtained from the Ministry of Mines and Energy and accepted by ECOPETROL.

3.2 Production obtained from tests will be distributed according to

proportions provided under the Contract Clause 14 (section 14.2), after

discounting twenty percent (20%) royalties, according to Contract Clause 13;

ECOPETROL will be responsible of direct payment thereof.

3.3 Test volumes produced will be recovered from the well during the maximum

test period approved by the Ministry of Mines and Energy under the respective

permit, discounting any Hydrocarbon volume consumed for operations.

3.4 The ASSOCIATE will be responsible of one hundred percent (100%) expenses

incurred during the production test period, which shall be charged as higher

well value and taken as direct cost for reimbursement purposes, according to

disbursement origin.

3.5 The ASSOCIATE shall enter into the necessary agreements with the transport

to provide Hydrocarbon transportation. Hydrocarbon ECOPETROL is entitled to

plus royalties transportation will be paid by ECOPETROL after receiving the

respective bills and supports.

3.6 ECOPETROL shall have advanced knowledge of the Hydrocarbon transportation

contract and shall approve it before extensive production tests start.

3.7 The ASSOCIATE shall maintain ECOPETROL duly informed about the production

test program and shall deliver any permits required from government

authorities, as well as any other information as obtained.

3.8 In the event Hydrocarbon is used for reimbursement, bills shall be

submitted each month from well production start.

<PAGE>

CLAUSE 4 - COMMERCIAL FIELD

4.1 After the ASSOCIATE has obtained sufficient information related to Field

development, the ASSOCIATE shall conduct a study to define petrophysical

parameters, better productive area boundaries and reserves calculation. The

study shall be conducted by the ASSOCIATE, at its expense, applying available

technical methods in the country or abroad; and when the circumstances so

require the pertinent revisions shall be made.



4.2 For new facilities or expansions/modifications, basic production and

detailed engineering design shall be submitted to the Technical Subcommittee

for consideration.

4.3 Production facilities engineering shall be contracted with domestic

companies except if in the opinion of the Technical Subcommittee technological

complexity requires assistance from a foreign company, preferably in consortium

with a domestic company.

4.4 Final mechanical completion of wells to become Joint Account property shall

be agreed by the Technical Subcommittee. Such Exploration Wells Reimbursement

will be subject to Contract Clause 9 (sections 9.2.2, 9.2.3 and 9.2.4).

4.5 Regarding dry Exploration Wells, the ASSOCIATE shall abandon subject to

applicable legal and environmental regulations.

CLAUSE 5 - OWN RISK MODALITY

5.1 Reimbursement refers to two hundred percent (200%) total work developed at

the ASSOCIATE's own expense and risk to produce the respective Field and up to

fifty percent (50%) Direct Exploration Costs incurred by the ASSOCIATE at its

own expense and risk within the Contract Area before the respective Field

commercial feasibility studies submittal date. ECOPETROL shall audit to

determine reimbursable investments.

5.2 During the Own Risk Field production, the ASSOCIATE shall deliver to

ECOPETROL a quarterly report including all technical, economic, legal and

administrative information such as contracts entered into, wells completion,

flow lines,

<PAGE>

production facilities, metering systems, storage capacity, production wells,

restriction orifices, production reports, economic studies, etc. Different

Contract Clause and clarifications herein are understood fully applicable in the

event of Contract Clause 21 "One of the Parties Own Risk Operations" for timely

information, technical reserves control and all other administrative activities

purposes.

CLAUSE 6 - OPERATIONS INSPECTION

Regarding activities developed in the Contract Area inspection and audit,

ECOPETROL will have the right to send its representatives to the field. The

ASSOCIATE or the Operator shall provide the officer designated by ECOPETROL

stay conditions similar to those provided it engineers.

CLAUSE 7 - PRODUCTION

7.1 The Operator shall also deliver to the Parties any information on

technical production improvements developed during the Production Period.

7.2 For Hydrocarbon losses and environmental damage control and prevention,

the Operator and the Parties shall take the necessary measures applying methods

generally accepted by the Oil industry to prevent Hydrocarbon losses or

spilling in any way during drilling, production, transportation and storage

activities.

7.3 The Operator shall keep daily Hydrocarbon consume, if any, operation

records and shall submit a monthly Hydrocarbon consume report accompanied of

forms provided by the Ministry of Mines and Energy for such purpose.

CLAUSE 8 - HYDROCARBON DISTRIBUTION AND AVAILABILITY

Pursuant to Contract Clause 14 (section 14.4), the Operator shall be responsible

of metering, sampling and controlling Hydrocarbon quality in accordance with

standards and methods accepted by the oil industry (ASTM, AGA, and API) and

applicable legal regulations referring to net Hydrocarbon received and delivered

at standard conditions volumes calculation.

Hydrocarbon volumes accepted by the Operator for transportation will be

determined using meters installed by the Operator for such purpose in receiving

stations and points of delivery.

<PAGE>

CLAUSE 9 - EXPORT HYDROCARBON SUPPLY

For Contract Clause 14 purposes, the ASSOCIATE Hydrocarbon exports shall take

into consideration primarily country needs before exporting Hydrocarbon subject

to legal regulations on the matter.

PART II - ACCOUNTING AND FINANCIAL MATTERS

SECTION ONE - PROGRAMS AND BUDGETS

CLAUSE 10 - PRODUCTION PROGRAMS AND BUDGET

10.1 Pursuant to Contract Clause 7, the ASSOCIATE shall deliver to ECOPETROL

within sixty (60) days following Contract signature date, the programs,

schedule of activities and the budget to be executed in the short term (the

following year) and the following two (2) years estimated budget projection

broken down by type of Exploration Work to be developed and indicating the

disbursement currency. After the first year, the ASSOCIATE shall submit the

aforementioned information within the first ten (10) calendar days each year.

10.2 The ASSOCIATE shall submit on a quarterly basis, within fifteen (15)

calendar days following the respective quarter end, the technical and financial

report provided in Contract Clause 7.

CLAUSE 11 - PRODUCTION PROGRAMS AND BUDGETS



1 1.1 For Contract Clause I 1 effects, the Operator shall submit a Field

development plan proposal envisaging in detail the short and mid term. The

short term budget shall be submitted by year and by quarter to facilitate

execution and to prepare the respective treasury flows.

11.2 The Operator shall submit to ECOPETROL the Commercial Field organization

chart which shall be agreed at Technical Subcommittee level and approved by the

Executive Committee.

CLAUSE 12 - BUDGET MANUAL

Standards and procedures listed below constitute the budget manual applicable

to Budgets preparation, submittal and control during production of Commercial

Field or

<PAGE>

Fields discovered in development of the Contract. This manual has three (3)

parts, as follows:

12.1 Income budget

12.2 Expense budget

12.3 Other provisions

CLAUSE 13 - INCOME BUDGET

This budget is in turn divided into two (2) sections: current income budget and

capital contributions.

13.1 Current Income

Covers all contributions regularly obtained to the favor of the Joint Account

and foreseeable by the Operator. Includes the following items as the case may

be:

13.1.1 Sale of products:

Income from Operator Hydrocarbon sales to one of the Parties or to third

parties on behalf of the Association (such sales are understood other than each

of the Parties participation in the Association).

13.1.2 Services Provided:

Covers all services provided by the Operator to one of the Parties or to third

parties, according to fees agreed by Subcommittees and approved by the

Executive Committee.

13.1.3

Disposal of assets or materials:

Covers equipment or materials sold by the Operator to the Parties or to third

parties subject to this Agreement Clause 20 (section 20.2) provisions.

13.1.4 Other income

Includes all funds received by the Operator and destined to the Joint Account,

on the account of transitory financial investments and all other income

projected by the Operator.

13.2 Capital contributions:

Refers to all contributions received by the Operator on the account of cash

calls delivered by the each of the Parties according to Contract participation.

Such income is designated cash calls and is managed on the basis of procedures

provided under this Agreement Clause 15 (section 15.5).

<PAGE>

CLAUSE 14 - EXPENSE BUDGET

As previous step to budget preparation, the Executive Committee will have the

respective Subcommittees determine general policies and parameters to be taken

into account to prepare the budget plan for the respective Commercial Field.

The expense or appropriations budget includes the operation expenses budget and

the investment budget. Each of these Budgets will be prepared according to

monetary origin, whether pesos or dollars.

14.1 Operation Expenses Budget

The operation budget will be prepared by the Operator on the basis of standards

and policies on the matter issued by the Association Executive Committee

pursuant to Contract Clause 19 (section 19.3.5) and on the basis of economic

parameters and indexes defined by the Joint Operation as the most

representative for the budget term.

14.1 Preparation Procedure

The Operator shall submit the operation expense budget identifying Joint

Operation needs and broken down by expense item according to classification

provided in this Agreement Clause 14 (section 14.1.2).

Cost factors used to evaluate the different activities programmed to be

developed during the Budget year will refer to actual figures known upon budget

preparation or the best information available. In all cases the operation

expenses budget will be calculated taking into consideration costs required by

units which directly provide their services to the Joint Operation and shall

be, therefore, one hundred percent (100%) assumed by the Joint Account and

charged to the Parties in the proportion provided under Contract Clause 22

(section 22.6.1). Indirect Expenses to be assumed by the Joint Account will be

charged to the Parties and determined as provided under Contract Clause 22

(section 22.6.2).

<PAGE>

14.1.2 Expenses Budget Classification

For all expenses budget submittal purposes, the budget will be divided into

programs, groups and expense items. Budget expense programs represent



homogeneous activities required to develop the Joint Operation, including

programs associated to investment. Each of the programs numerical and

sequential expense groups reflect the expense objective, shall be duly

supported and explained and separated by expense item. The following are major

expense items to be used

14.1.2.1 Organization chart expenses

Salaries

Fringe Benefits and parafiscal contributions

14.1.2.2 Operation materials and supplies

Repair and maintenance materials

14.1.2.3 Contracted services

Technical field operation and maintenance services

Services provided by the Operator

Other services

14.1.2.4 Overhead

Equipment and Office leases

Shared expenses

Insurance

Utilities

Assistance to the community

Other overhead

14.1.2.5 Environmental management

<PAGE>

Materials

Contracted services

Other expenses

14.1.2.6 Aggregated value tax - IVA

14.1.2.7 Indirect expenses

14.1.3 Calculation base

Operation expenses budget calculation basis will be the following:

The salaries and fringe benefits budget will be calculated on the basis of

organization charts approved for the Association and estimates will be subject

to this Agreement Clause 18 (section 18.1.1). Salaries, fringe benefits and all

other voluntary bonus to domestic and foreign personnel will be separately

listed by disbursement origin for Association Subcommittees and Executive

Committee information purposes.

Materials and supplies costs estimates will be based on actual prices or

updated quotations and, in general on the basis of the best information

available.

Import expenses will be based on subsequently imported materials and/or

equipment FOB prices taking into account the following factors: freight,

insurance, Colombian ports use taxes, import taxes and all other import

expenses.

Contracted operation and maintenance services value will be estimated on the

basis of contracts entered into or to be entered into by the Joint Operation

upon Budget preparation.

Indirect expenses to be assumed by the Joint Account for services provided or

to be provided by the Operator will be calculated according to procedures

provided in Contract Clause 22 (section 22.6.2).

The environmental expenses budget objective is to appropriate the necessary

annual funds to comply with environmental regulations.

Overhead will be calculated on the basis of concrete needs required by the

Joint Operation in development of its normal activities. Shared expenses are

disbursements to be assumed by the Joint Account as a result of facilities

and/or services shared by

<PAGE>

Fields or Associations. The budget and these Joint Account charges shall be

recommended by the Association Subcommittee and approved by the Executive

Committee. Assistance to the community will be budgeted on the basis of

petitions from interested parties and policies dictated by the Executive

Committee. Under special conditions so deserving the Operator will have the

right to accept petitions according to procedures, previous notice to each of

the Parties.

14.1.4 Budget execution.

Operation expenses budget execution will be based on the following

considerations:

14.1.4.1 All services, purchases or contracts charged to the Joint Account as

operation expenses shall be budgeted and fully justified.

14.1.4.2 If the service or activity to be contracted does not imply

disbursements exceeding the limits provided for the Joint Operation, the

Operator will be fully autonomous to contract subject to internal

responsibility and authority procedures.

14.1.4.3 Purchases, contracts or any other act implying a higher partial or

global cost exceeding limits provided shall be previously submitted to the

Association Technical Subcommittee for study and recommendation.



14.1.5 Budget Execution Control.

Expenses budget execution control will be the responsibility of the Operator

which shall monitor correct expenses appropriation.

During the first fifteen (I 5) calendar days following the respective quarter

end, the Operator shall prepare a budget report explaining budget execution

results, which report shall contain:

14.1.5.1 Accumulated expenses to date broken down by expense item provided

under this Agreement Clause 14 (section 14.1.2).

14.1.5.2 Special comments on items which execution has significantly deviated

with respect to the average budget or quarterly estimate.

14.1.5.3 Projected expenses to be disbursed on a quarterly basis or the

remaining year.

14.1.5.4 Justification of potential budget additions, adjustments or transfers

the Operator deems convenient or if proposed by one of the Parties.

<PAGE>

14.2 Investment budget

Will be each of the programs and investment projects to be developed by the

Joint Operation basic planning, execution and control tool and will be the

means to estimate funds required to develop the different programs approved by

the Executive Committee.

14.2.1

The investment budget will include the respective entries for the

following items:

14.2.1.1 Acquisition of lasting goods, materials and services required to

develop the different projects determined by the Association.

14.2.1.2 Acquisition of major equipment and tools destined to Association

workshops with the purpose of guaranteeing normal operations development.

14.2.1.3 Constructions and/or buildings expansion as required by operations,

including facilities destined to Joint Account staff.

14.2.2 Investment budget classification

For investment budget submittal purposes, the budget will be grouped by

programs and projects. Each Budget programs in numerical order will reflect

groups of common objective projects to be developed by the Operator for the

Joint Operation. Each Program project in numerical sequential order will be

duly supported and explained. The following are major activities and project

types to be used:

14.2.2.1 Development wells

Pumping or surface equipment, recompletion and services to wells potentially

capitalized.

Production wells

Locations

14.2.2.2 Production facilities

Hydrocarbon collection system

Storage system

Hydrocarbon treatment system

Improved recovery system

Pumping Stations

Transfer lines

Other

14.2.2.3 Civil works

Roads

<PAGE>

Bridges

Construction (camps, workshops, warehouses, offices)

14.2.2.4 Other assets

Automotive equipment

Fire fighting equipment

Communications equipment

Office equipment

Electromechanical maintenance equipment

Major tools

Cleaning or workover equipment

14.2.2.5 Special Projects



Environmental management

Deposits studies

Simulation studies

Interference tests

14.2.2.6 Warehouses

For projects

For maintenance materials

14.2.2.7 Each of these project may be divided into as may subprojects as

necessary, always maintaining uniform identification to be finally submitted by

project, according to the above classification and using for such purpose forms

provided by ECOPETROL, which may be adapted by mutual agreement of the Parties

by the Financial Subcommittee. With the purpose of further clarifying

investment budget preparation, the following shall be taken into consideration:

14.2.2.7.1 Maintenance projects

Refers to all investments in equipment, materials and constructions destined to

maintain the facilities in efficient operation conditions subject to original

capacity and yield limits.

14.2.2.7.2 Expansion projects

Are investments with the purpose of increasing facilities capacity, increasing

authorized automotive equipment number, office equipment, etc.

<PAGE>

14.2.2.7.3 Special Projects

Will include all projects which value, importance for industrial activities or

impact at the social or ecological level deserves a special classification.

14.2.3 Each and all investment budget projects shall be fully justified and

analyzed before including in the general budget. In this sense, the Operator

shall prepare an initial investment project containing the following general

information:

Needs analysis

Project justification

General project description

Estimated investment value

Schedule of activities

Project critical route

Economic assessment

The initial investment project containing the above information in addition to

any other information deemed necessary for evaluation, will be jointly studied

by Association Subcommittees which will recommend or object project feasibility

on the basis of policies dictated by the Executive Committee.

After the Subcommittees have recommended a given project, such project will be

included in the general budget to the approved by the Association Executive

Committee.

All general information included in each project justification will be recorded

in a technical-financial Exhibit to serve as support to budget submittal and

approval by the Executive Committee.

14.2.4 Budget consolidation

After determining Joint Operation needs, the Operator will consolidate each of

the Commercial Fields expenses and investment budget according to

classification provided in this Agreement Clause 14 (sections 14.1.2 and

14.2.2, respectively) and will submit to the Executive Committee for final

approval. Both the expense budget and the investment budget will be listed in

four (4) columns showing dollars origin accrual and

<PAGE>

pesos origin accrual, a dollar consolidated and a pesos consolidated, on the

basis of the respective year exchange rate projection.

Additionally, the Operator shall prepare, for information purposes, a schedule

of disbursements indicating short term funds requirements broken down by

quarter and currency origin, at group expense and investment program level.

14.2.5 Budget execution

In all cases the Operator is empowered to make all operation expenses and

investments required by the Joint Operation according to approved Budget not to

exceed ten percent (10%) appropriations assigned to each expense group and to

each project during the respective budget term (Contract Clause I 1, section

11.5). Budget execution will be the responsibility of the different Operator

units subject to previously determined execution schedule.

Appropriations assigned each project will be identified using a previously

defined code to be used in all documents associated to Budget Execution

procedures.

14.2.6

Budget Control.

The Operator will be responsible of developing each of the programs and

investment projects and shall account for execution thereof subject to approval



conditions.

Additionally, the Operator will be responsible of monitoring timely and correct

projects development. In the event any trouble preventing normal projects

development arises, the Operator shall forthwith report such trouble in writing

to the Parties for trouble encountered to be solved. The Operator, as the

person responsible of the development plan, programs and projects, shall

prepare quarterly reports on budget and technical progress thereof to be

delivered to each of the Parties for study and subsequent approval by the

Association Executive Committee.

The quarterly report shall be prepared and submitted by the Operator within

fifteen (15) calendar days following each quarter end and shall contain the

following information:

Period covered by the report.

Project code and description

<PAGE>

Total project budget

Financial progress from start to closing date.

project accumulated to date.



Investments by current year



Technical work progress

Quarterly projection of work to be developed for the remaining year, for

information purposes.

14.2.7 Investments during the Retention Period

Investments during the Retention Period will be asswned by the Association

Joint Account or by the ASSOCIATE, depending on whether ECOPETROL has accepted

Field commercial feasibility.

CLAUSE 15 - OTHER PROVISIONS

15.1 Budget additions.

In the event during Budget execution appropriations approved by the Executive

Committee would require additions, the Parties may be required extraordinary

amendments to be ratified by the Executive Committee at its next meeting.

Expenses and investment Budgets additions or transfer requests may be

periodically submitted when the Executive Committee holds its regular meetings.

However, the Executive Committee will have the right to meet on an

extraordinary basis to discuss budget issues any time a special situation so

deserves.

Therefore, every time a budget revision is requested, the Operator shall start

the respective procedures duly in advance submitting the requests to the

respective Subcommittee for study and subsequent recommendation to the

Executive Committee.

<PAGE>

In any case, budget addition requests shall be fully justified explaining the

reasons originating appropriated entries variation and including the respective

technical and financial exhibits provided in this Agreement Clause 14 (section

14.2.3).

15.2 Budget transfers.

Appropriations carried from one year to the next due to projects not concluded

during the budgeted term (for reasons such as lack of equipment, import

procedures, bad weather, etc.) will be deemed budget transfers.

Non developed project full value will be carried to the following year budget

and will be subject to Executive Committee approval. These projects will be

expressly included in the budget taking into account the disbursement schedule

provided in this Agreement Clause 15 (section 15.4). Additionally, budget

transfers will originate an exhibit explaining budget transfer causes and how

will the budget be executed within the next term.

15.3 Approvals.

The Executive Committee will be the body in charge of approving the programs and

the budget recommended by Association Subcommittees and to authorize the

Operator to purchase or contract on behalf of the Association all goods and

services required by the Joint Operation.

15.4 Disbursement schedule.

Together with the budget recommended by the Association Subcommittees, the

Executive Committee will approve the quarterly budget submitted by the Operator

for the immediately following year which will serve as the basis to calculate

monthly cash calls.

15.5 Cash calls.

Cash calls or funds advances will be placed by the Operator to each of the

Parties on the basis of obligations assumed by the Joint Operation for the

month immediately following the cash call, consulting the Budget approved by

the last Executive Committee

<PAGE>

and the projected cash flow. Cash calls under this Clause will be deposited in a

bank account opened by the Operator for such purpose to be exclusively used by

the Joint Operation. Cash calls preparation and submittal shall be subject to

the following requirements:

15.5.1 Preparation



On the basis of the approved budget and obligations assumed by the Association

in the subsequent month, the Operator will prepare cash calls taking into

account the following conditions:

15.5.1.1 The Operator will place a separate cash call for each of the

producing Commercial Fields in the Contract Area, identifying pesos and dollars

expenses and investments according to projected disbursement origin.

15.5.1.2 The cash call shall be open by programs and project in the event of

investments and by group and expense item in the event of expenses, as shown in

the budget approved by the Executive Committee.

15.5.1.3 For each of the projects and expense group listed in the cash call to

be considered, it must be included in the budget; otherwise, total cash call

value will be discounted.

15.5.1.4 Projects and expense groups budgeted value shall be sufficient.

Nonetheless, in special cases, the value appropriated for the term may be

exceeded by ten percent (10%) according to Contract Clause I 1 (section 11.5).

15.5.2 Submittal

Every cash call will be submitted for processing using the form previously

agreed by the Parties in the Financial Subcommittee and shall show actual and

estimated expense charges and will include the following documents:

15.5.2.1 Cash call letter

15.5.2.2 Cash call form showing each of the programs, projects or expense item

financial status on cash call date, and

15.5.2.3 General comments of the technical nature identifying cash call

destination for major projects or expense items.

<PAGE>

SECTION TWO - ACCOUNTING PROCEDURES

CLAUSES 16 - ACCOUNTING PROCEDURE

From Exploration Period start the ASSOCIATE shall deliver to ECOPETROL on a

quarterly basis within fifteen (15) calendar days following each quarter end,

the exploration costs report provided in Contract Clause 7, expressly

identifying Direct Exploration Costs subject to reimbursement pursuant to

Contract Clause 9.2.2, as detailed in the budget indicating the disbursement

currency and a US dollars consolidated. Additionally, and in the same report

the ASSOCIATE shall include the preliminary accumulated value to be included as

R Factor denominator provided in Contract Clause 14 (section 14.2.3), clearly

showing Direct Exploration Costs detail and calculation parameters applied. It

is hereby understood that Direct Exploration Costs reported by the ASSOCIATE

will only be firm after ECOPETROL has audited and accepted such costs.

During the Production period. credits and charges incurred by the interested

Parties and covering operations defined in the Contract, will be subject to the

following conditions: All charges will go to the Joint Account to be opened as

provided under Contract Clause 22.

The Joint Account defined in Contract Clause 4 (section 4.7) will be divided

into three major records as follows:

16.1 General Joint Account (clarification, charges and entries). This account

will record all movement as detailed below and will be fully distributed to the

Parties on a monthly basis, in the proportion of fifty percent (50%) to

ECOPETROL and fifty percent (50%) to the ASSOCIATE with respect to investments,

and in the proportion provided in Contract Clause 22 (sections 22.6.1 and

22.6.2) for Direct Expenses and Indirect Expenses, that is, will serve as the

basis for monthly billing as therein provided, leaving a zero (0) balance each

month. All accounting transactions associated to this account will be recorded

by the Operator in Colombian pesos subject to the laws of the Republic

<PAGE>

of Colombia, but the operator will have the right to, in turn, keep ancillary

records showing disbursements incurred in any currency other than Colombian

pesos.

16.2 Operation Joint Account. This account will record

from the Parties and credit charges associated to their

all times a balance to the favor or against each of the

may be. This account will be divided into sub-accounts

transaction currency origin, whether pesos of dollars.



cash calls received

billing and shall show

Parties, as the case

according to



16.3 Joint property records. The Operator shall keep under the Joint Account

records of all goods acquired and subject to inventory indicating each asset in

detail, acquisition date and original cost. Accounts mentioned in this

Agreement Clause 16 (sections 16.1, 16.2 and 16.3) will form part of the

Operator's official accounting records but shall not mix with accounting

records other than the Joint Account. The three accounts will be subject to

this Agreement Clause 22.

16.4 The Operator shall deliver to ECOPETROL on a monthly basis, together with

information provided in this Agreement Clause 17 (section 17.2.2) in the form

of a separate exhibit, R Factor parameters and calculation pursuant to Contract

Clause 13 (section 14.2.3).

CLAUSE 17 - CASH CALLS, BILLING AND ADJUSTMENTS

17.1 Cash calls. Although the Operator will pay and discharge in the first

place all costs and expenses incurred according to the Contract, charging each

Party's participation percentage, it is hereby agreed, with the purpose of

funding such participation, that each of the Parties, upon request from the

Operator and as provided further below, shall deliver cash calls to the



Operator, from Commercial Field acceptance by the Parties and no later than

within the first five (5) calendar days each month, the respective month's

estimated operations expenses portion. The cash call shall be accompanied to

detailed information as provided under clause 15 (section 15.5.1.2) hereof Such

cash calls will be made in US dollars or Colombian pesos, according to needs

contemplated in the budget and cash calls prepared by the Operator. The

Operator shall place the cask call within the first twenty (20) calendar days

the month immediately prior to the month when the cash call is to be delivered.

If the Operator would have to incur in extraordinary expenses not contemplated

under the monthly cash call, the Operator shall make special cash calls to the

Parties covering

<PAGE>

such disbursements participation. Each participant shall advance its

proportional funds within fifteen (15) calendar days following the Operator cash

call.

17.2 Billing

17.2.1

The Operator shall prepare an initial bill to ECOPETROL after each

Commercial Field acceptance covering fifty percent (50%) Direct Exploration

Costs incurred before submitting each discovered Commercial Field commercial

feasibility studies, which costs have been audited and accepted by ECOPETROL

according to Clause 22 hereof. Exploration wells costs will include all costs

incurred to drill, terminate and test in the event of producing wells and dry

Exploration Wells abandonment costs. Said bill shall also include fifty

percent (50%) additional work costs provided in Contract Clause 9 (section 9.3)

which will be paid according to said Clause. Said bill shall include a costs

summary separately stating the investment and expenses currency, that is,

Colombian pesos or US dollars.

17.2.2 From the initial bill date on, the Operator will bill the Parties, within

fifteen (15) calendar days following the last day each month, its proportional

participation in costs and expenses for the month. Bills shall list Operator

accounting procedures details, including a detailed accounts summary, separately

listing costs and expenses originated in dollars or in pesos.

17.3 Adjustments. Bills will be adjusted by the Operator and the Parties after

subtracting cash calls in dollars and pesos.

If any of the Parties' cash calls differ from their participation in actual

costs determined for each period, the difference will be adjusted in the

following month's bills.

17.4 Bills acceptance. Bills payment will not affect the Parties right to

oppose or inquire about bills accuracy subject to Contract Clause 22 (section

22.7) provisions.

CLAUSE 18 - CHARGES

Subject to limitations described below, the Operator will charge the Joint

Account and bill each of the Parties according to percentages provided under

this Agreement Clause 16 (section 16. 1), the following expenses:

<PAGE>

18. 1 Labor

18.1.1



Domestic and foreign employees



18.1.1.1 Operator's employees salaries if directly working for the Joint

Operation, including overtime, night overcharge, Sundays and holidays and the

respective compensation rest payment and in general any salary payment.

18.1.1.2 Fringe benefits, indemnification, insurance, subsidies and bonus and

in general any benefit other than salary granted workers and/or their families

or dependents, whether individually or collectively or granted in virtue of the

work contract, the law agreements and/or arbitration awards, with the exception

of housing plans in which respect a special agreement will be required. Some

of the above could be the following, among other: severance, vacation,

retirement and disability pensions, benefits granted retired personnel and

their families, benefits and assistance in the event of illness and

professional or non professional, accidents, service bonuses, life insurance,

contract termination indemnification, union assignments, all type of bonuses,

assignments and savings, health and/or education assistance and social security

in general. Additionally, contributions to Instituto Colombiano de Bienestar

Familiar -ICBF (Family Welfare), Servicio Nacional de Aprendizaje - SENA

(National Apprenticeship Service), Instituto de Seguros Sociales - ISS (Social

Security) and other similar required.

18.1.1.3 All expenses incurred on behalf of the Joint Operation for camp

maintenance and operation, field offices or services facilities. These

expenses also include - not taxatively but for information purposes - expenses

listed below regardless of whether services are provided gratuitously or for

remuneration, or whether to workers, their dependents or relatives or whether

voluntary or mandatory. Some of such services are:

18.1.1.3.1



Medical, pharmaceutical, surgical or hospital services.



18.1.1.3.2



Camp and complete services therein, including repair and hygiene.



18.1.1.3.3



Training and qualification costs



18.1.1.3.4



Workers entertainment



18.1.1.3.5



Schools for workers, their children and dependent relatives.



18.1.1.3.6

Security or social assistance plans and camp surveillance.

<PAGE>

18.1.1.4 Expenses and services listed in the above Clause 18 (sections



18.1.1.1, 18.1.1.2 and 18.1.1.3) are understood with charge to the Joint

Account in the event applicable regulations, collective labor agreements and/or

arbitration awards directly or jointly applicable to contractors

subcontractors, intermediaries and/or their employees at the service of the

operation.

18.1.1.5 Regarding retirement pensions and disability assistance, the

Executive Committee will have the right to proceed according to the Social

Security and Pensions system provided by Law 100 of 1993 and all other

regulating provisions.

18.2 Materials and supplies

Materials and supplies required to develop operations will be charged to the

Joint Account. Materials and supplies shall be acquired and stored in the

project warehouse or the maintenance material warehouse as convenient for the

operation and credited the operation at book cost as they leave the warehouse

to be used. Capital equipment units will be directly charged to the Joint

Account. The book value is determined as follows:

18.2.1 Book value

Book value is understood as the last average price for warehouse stock on the

basis of costs taken from imports calculation worksheets or local cost, as

follows:

18.2.1.1 For imported materials, equipment and supplies the book value shall

include net manufacturer or supplier bill cost, purchase cost, freight and

delivery charges at supply site and port of embarkation, freight to destination

port, insurance, import duties or any other tax, cargo handing from the ship to

customs warehouse and transportation to operations site.

18.2.1.2 For locally acquired materials, equipment and supplies the book value

shall include net seller bill plus sales tax, purchase cost, transportation and

insurance and similar costs paid to third parties from the purchase place to

operations site.

18.2.1.3 Materials will be charged to the Joint Account according to

acquisition currency origin to be subsequently charged to each of the Parties.

18.2.2 Materials devolution to the Joint Account warehouse, as the case may be.

<PAGE>

Materials, equipment and supplies returned to the Joint Operation warehouses

value will be estimated following the same procedures.

18.2.2.1 New materials will be recorded at book value.

18.2.2.2 The Operator will have the right to reincorporate used materials, in

good operating conditions and equipment fit to be subsequently used with no

need for repairs to the respective warehouse at seventy five percent (75%) book

value, crediting the respective Joint Account project.

18.2.2.3 The Operator will have the right to reincorporate repaired used

materials, in good operating conditions to the respective warehouse at fifty

percent (50%) book value. When such materials are used again will be charged

at the new book value.

18.2.3

Sales by the Parties. Materials, equipment and supplies value sold

by the Parties to the Joint Operation will be estimated on the basis of

replacement cost agreed by the Parties. The respective transportation costs

will be assumed by the Joint Operation. In the event of Joint Operation sales

to one of the Parties, goods value will be estimated on the basis of

replacement cost agreed by the Parties and transportation costs will be assumed

by the buying Party.

18.2.4



Local Materials transportation



18.2.4.1 Materials shipped by an external carrier at cost according to the

carrier company bill.

18.2.4.2 Materials shipped in carrier units property of the Parties, at the

rates calculated to cover actual expenses, according to this Agreement Clause

18 (section 18.2 and 23 (section 23. 1. 1).

18.2.5

Canceled, postponed or changed projects. In the event stock

accumulated in the warehouse due to projects approved by the Parties change,

postponing or cancellation, such materials cost will be charged to the

warehouse account. Such materials may be sold to third parties according to

this Agreement Clause 20 (section 20.2.1) and the produce credited to the Joint

Account.

Excess material from projects, if such material purchase has been directly

charged, shall be returned to the warehouse upon such projects completion and

credited to the

<PAGE>

respective project. The Operator shall report such transaction to the Parties at

regular Financial Subcommittee meetings when held.

18.3 Travel expenses

All travel expenses incurred on behalf of the Joint Operation by domestic or

foreign personnel, such as transportation, hotels, feeding, etc.

18.4 Service units and facilities

Services provided using equipment and facilities property of either of the

Parties will be charged to the Joint Account at reasonable rates as provided in

this Agreement Clause

23. Rates determined shall apply until amended by mutual agreement.



18.5 Services

Services provided the Joint Operation by third parties, including contractors,

at actual cost. Likewise, technical services such as lab analyses and special

studies requiring Technical Subcommittee recommendation and Executive Committee

approval.

18.6 Repairs

Repairs to equipment or goods property of any of the Parties destined for Joint

Operation use, except if such costs have been previously charged under leases

or otherwise.

18.7 Litigation

Joint Operation expenses associated to actual or threatened litigation

(including investigation and proof taking), attachments release, awards or

court decisions, legal claims and claim filings, accidents compensation,

arrangements in the event of death and funeral, provided such charges have not

been acknowledged by an insurance company or covered by the respective charges

provided in this Agreement Clause 18

<PAGE>

(section 18. 1. 1). In the event legal counseling is provided on such matters by

permanent or external attorneys whose full or partial remuneration has been

included in indirect expenses, no additional service charges will be recorded

but will be charged to Direct Costs incurred for such proceedings.

18.8 Joint Operation propertied and equipment loss or damage. All costs and

expenses required to replace or repair losses or damages caused by fire,

floods, storm, robbery or any similar act. The Operator shall notify the

Parties in writing any losses or damages suffered, as soon as practical.

18.9 Taxes and leases

All taxes paid or accrued in development of the Joint Operation will be charged

to the Joint Account, subject to applicable legal provisions.

The Joint Account will also be charged leases, rights of way and

indemnification paid on improvements, soil occupation, etc.

18.10



Insurance



18.10.1 Insurance premiums on insurance taken for the benefit of operations

subject to the Contract together will all expenses and indemnification accrued

and paid, and all losses, claims and other expenses not covered by insurance

companies, including legal counseling mentioned in this Agreement Clause 18

(section 18.7) well be charged to the Joint Account.

18.10.2 In the event no insurance has been taken aforementioned actual

expenses incurred and paid by the Operator will also be charged to the Joint

Account.

CLAUSE 19- CREDITS

19.1The Operator shall credit the Joint Account the following income items:

<PAGE>

19.1.1

Insurance returns associated to the Joint Operation which premiums

have been charged to said operations.

19.1.2

Geological information sales previously authorized by the Parties

provided associated recoveries have not been charged to the Joint Account.

19.1.3

The sale of properties, plants, equipment and materials property of

the Joint Operation.

19.1.4

Lease rents received, customs taxes or transportation claims refunds,

etc. shall be credited to the Joint Operation if rents or refunds associate to

such operation.

19.1.5

Any other operational income or contracts authorized by the Executive

Committee for the Joint Account service.

19.2 Warranty

In the event of defective equipment when the Operator has received the

respective adjustment from the manufacturer or its agents, such amount will be

credited to the Joint Operation.

CLAUSE 20 - DISPOSING OF MATERIAL AND EXCESS EQUIPMENT

20.1 Excess materials and equipment

The Operator shall inform the Parties in writing about any Joint Operation

excess materials or equipment, thirty (30) days after completing the inventory

provided in Clause 21 hereof Each of the Parties shall designate a

representative to review the condition thereof and to determine which materials

or equipment may be sold. In the event of usable materials or equipment

ECOPETROL will have the first option and the ASSOCIATE will have the second

option; such options shall be exercised within sixty (60) days following notice

date. In the event the aforementioned parties do not buy the Operator shall

notify them in writing and will proceed to auction.

<PAGE>

20.2 Disposing of Capital equipment and materials: pursuant to Contract Clause

22 (section 22.9) The Operator will have the right to sell materials and

equipment property of the Joint Account subject to the following conditions:

20.2.1



Major material and capital equipment sold by the Operator and



previously charged to the Joint Account will be subject to previous Executive

Committee approval. The produce thereof will be credited to the Joint Account.

For such purpose only, major materials are defined as any assets which

estimated sale value exceeds forty thousand US dollars (US$40,000) or the

equivalent Colombian currency.

20.2.2

Minor materials charged to the Joint Account and not required for

operations or reincorporated to the respective warehouse may be sold by the

Operator and the produce thereof credited to the Joint Account.

20-2.3 Any assets which cost or estimated value exceeds forty thousand US

dollars (US$40,000) or the equivalent Colombia currency abandonment or

dismantling requires previous Executive Committee authorization.

20-2.4 None of the Parties will have the obligation to purchase the other

Party's interest in excess materials, whether new or used. Disposal of major

excess materials, such as towers, tanks, engines, pumping units and piping will

be subject to Executive Committee

approval. The Operator will, however, have the right to reject damaged or

unusable materials in any way.

20.2.5

All taxes accrued by reason of Joint Account materials or assets sale

or disposal shall be the responsibility of the Operator with charge to the

Joint Account.

CLAUSE 21 - INVENTORY

Upon request from ECOPETROL the Operator shall submit the necessary information

to analyze warehouse stock and the Parties shall agree upon joint participation

to control inventories. The Operator shall provide any facilities required by

ECOPETROL to take a fixed assets physical inventory at the Association

facilities, previous Financial Subcommittee agreement on the date, time and

number of persons designated to take said inventory.

<PAGE>

21.1 Inventory and Audit

Subject to applicable regulations and no less than once every three (3) years

the Operator shall take all Joint Operation assets inventory.

21.2 The notice of intention to take an inventory shall be given by the

Operator in writing to the Parties one (1) month in advance to said inventory

taking date for the Parties to be represented. But if one of the Parties is

not present the inventory so taken by the Operator shall be no less valid.

21.3 The Operator shall provide the Parties copy of each inventory including

copy of the reconciliation and will submit results to the Association

Subcommittees which shall study the report and propose action to be taken on

the matter.

21.4 Excess and shortage inventory adjustments will be reported to the Executive

Committee for consideration and approval.

21.5 At midnight on the last day of the Exploration Period provided, the Parties

shall take an inventory of both material in the warehouse property of the Joint

Account and extracted products in the collection batteries and piping from

collection batteries to storage tanks or in storage tanks all within production

fields, and such inventories will be distributed to the Parties, after deducting

royalties, in the proportion provided under Contract Clause 13.

CLAUSE 22 - AUDIT

Subject to Clause 17 (section 17.4) hereof the Parties will have the right to

have their own Auditors or representatives examine and control Operator's

accounting books and records associated to properties and operation activities

thereof. However, with the purpose of facilitating Direct Exploration Costs

revision under this Agreement Clause 17 (section 17.2. 1) as soon as the

Operator notifies the Parties any reimbursable Exploration Work initiation, the

ASSOCIATE or the Operator shall permit, previous due notice, ECOPETROL auditors

to periodically examine such Exploration Work accounts, for the mentioned

revision to have been performed under the best conditions and time when the

Commercial Field is declared. During audits herein provided representatives

from the General Accountant of the Republic will have the right to participate

if such body deems convenient. Such audit costs and expenses will be paid by

the interested Party.

<PAGE>

22.1 After the audit report has been delivered, the ASSOCIATE or the Operator

will have a maximum six (6) months term to answer or sustain objections

submitted; upon said term expiration if the Operator has not answered,

objections will be deemed accepted and consequently the audit will proceed

accordingly. Audit notes or comments not resolved within the three (3)

following months will be resolved according to Contract clause 20.

CLAUSE 23 - FEES TABLE

23.1 Subject to limitations provided above, services provided the Joint

Operation by facilities exclusively owned by ECOPETROL or the ASSOCIATE will be

charged the respective fees with the purpose of recovering actual costs. Such

costs shall include normal work, salaries, fringe benefits, depreciation costs

and other operation expenses taking the following into account:

23.1.1 The transportation units fee usually calculated on the basis of operation

time shall include loading and unloading time, the time spent waiting for

loading and the time spent waiting to be unloaded. Transportation unit charges

assigned the operation shall include Sundays and holidays, except if out of

service for repairs.

23.1.2

In the event material required for the mentioned operations is

transported together with other material by fluvial or land carrier exclusively

owned by ECOPETROL or the ASSOCIATE the charge shall be based on transported

tons at rates which shall not exceed commercial rates.



23.2 Equipment and tools lease fees

The procedure to calculate equipment and tools property of the Parties leases,

excluding drilling equipment and major equipment which fees must be separately

calculated and approved by the Executive Committee, shall cover a depreciation

value in addition to a maintenance value and the procedure will be the

following:

23.2.1 Equipment description, model, number, purchase date and original cost.

23.2.2

Site where the equipment will be used, reasons for leasing and

estimated use period.

<PAGE>

23.2.3

Annual equipment depreciation value, calculated on the basis of

depreciated book value and remaining useful life (minimum book value to be

considered will be ten percent (10%) original cost or the salvage value).

23.2.4

The annual maintenance value will be a percentage of the original

cost which will range from five percent (5%) for new equipment to fifteen

percent (15%) for depreciated equipment, depending on depreciation period, for

instance:

Equipment A: (Five [5] years useful life)

Period (years) 1, 2, 3, 4, 5: one hundred percent (I 00%) depreciated equipment.

Maintenance: 5, 6, 7, 8, 9: 15 %

Equipment B: (Ten [10] years useful life)

Period (years) 1, 2, 3, 4, 5, 6, 7, 8, 9, 10: one hundred percent (100%)

depreciated equipment.

Maintenance:



5, 6, 7, 8, 9, 10, 1,, 12, 13, 14, 15: 15%



Note: Useful life period and depreciation will be determined on the basis of

accounting practices applicable to oil operations.

23.2.5

Annual lease fee equals the value provided under Clause 23 (section

23.2.3) hereof plus the value specified in section 23.2.4 hereof.

23.2.6

Monthly or daily equipment lease fee will be as provided under Clause

23 (section 23.2.5)hereof divided into twelve (12) or three hundred and sixty

five 365, as the case may be.

23.2.7

No "standby" fee will be charged but this fee will be charged in the

event of third parties.

23.2.8

The above lease fees do not include transportation, installation,

operation, lubricants and fuel costs which will be charged the operation

equipment is destined to.

23.2.9

The above lease fees will apply to eventual equipment and tools one

hundred percent (100%) property of the ASSOCIATE or the Operator and vice

versa.

23.2.10 In each case, the Technical Subcommittee will recommend the Executive

Committee the need to use leased equipment and the Financial Subcommittee will

have the right to apply the fee system recommended herein.

<PAGE>

23.2.11 Equipment lease fee will be calculated in US dollars but the

respective bill will be in pesos at the rate agreed by the Parties.

23.2.12 Warehouses and fixed assets lease fee.

For full or partial use of warehouses property of one of the Parties or the

Joint Operation lease fee calculation the procedure agreed by the Financial

Subcommittee will apply.

CLAUSE 24 - CONTRIBUTIONS IN KIND

ECOPETROL or the ASSOCIATE shall contribute in kind any materials deemed

convenient as agreed between the Parties.

PART III - ADMINISTRATIVE ISSUES AND SUNDRY PROVISIONS

SECTION ONE - THE EXECUTIVE COMMITTEE

CLAUSE 25 - OPERATING CONDITIONS

In development of its functions the Executive Committee shall comply with

conditions provided in Contract Clause 19, as follows:

25.1 The Executive Committee will be alternatively chaired by the Parties

starting with ECOPETROL.

25.2 The Executive Committee shall designate its Secretary alternating people

designated by ECOPETROL and the ASSOCIATE. The Chairman and the Secretary will

be members of the same Party.

25.3 The Executive Committee shall hold regular meetings during the months of

March, July and November, and shall hold extraordinary meetings any time the

Parties and/or the Operator deem necessary. At said meetings the production

program developed by the Operator, the development plan and immediate plans

will be discussed. This Executive Committee may be attended by each of the

Parties counselors as deemed convenient, being understood each of the companies

shall designate the less possible number of people.

25.4 In the event of Executive Committee regular meetings, the representative



chairing the coming meeting shall notify all other representatives (principal

and alternates) from the other Party and the Operator ten (10) calendar days in

advance indicating the meeting time and place and matters to be discussed

(agenda).

<PAGE>

25.5 In development of Contract Clause 18 (section 18.3), during both regular

and extraordinary Executive Committee meetings, matters to be discussed and not

included in the agenda may be discussed during the meeting previous agreement

of the Parties representatives attending the Committee.

SECTION TWO - SUBCOMMITTEES

CLAUSE 26 - SUBCOMMITTEES ORGANIZATION

In development of the function provided under Contract Clause 19 (section

19.3.8), the Executive Committee will have the right to designate any advisory

subcommittees deemed necessary. In any case the Executive Committee shall

designate a Technical Subcommittee and a Financial Subcommittee.

The above subcommittees will be the organizations in charge of controlling and

defining Contract technical, financial and legal recommendations to the

Executive Committee and shall be governed by the Contract and this Agreement.

Each subcommittee shall issue its own internal regulations to be approved by

the Executive Committee.

Section Three - Operator

CLAUSE 27 - RIGHTS AND OBLIGATIONS

27.1 Pursuant to Contract Clause 30, the Operator has the right to conduct Joint

Operations by itself or retaining subcontractors subject to general Executive

Committee direction. In any case, the Operator will be responsible of the Joint

Operation according to Contract provisions.

27.2 Some of the Operator's obligations are the following, among other:

27.2.1 To prepare, submit and implement the development plan, expenses budgets

and exploration/ production programs as well as expenses approval.

27.2.2 To direct and control all operation expenses statistical and accounting

services.

27.2.3 To plan and obtain all services and materials required for good Joint

Operation development.

27.2.4 To provide all techniques and assistance required for good Joint

Operation development.

<PAGE>

27.2.5 To plan tax effects and to comply with all tax obligations derived from

operations developed and to provide a timely report to the Parties in their

respective proportion.

27.3 The Operator shall not have the right to constitute any lien on Joint

Operation properties.

27.4 Operator resignation will be without prejudice of any right, obligation or

responsibility acquired during the time the Operator acted in such condition; if

the Operator resigns or is removed before obligations provided under the

Contract have been satisfied, the Joint Account shall not be charged any

expenses incurred by such change. But if the Executive Committee approves, these

costs and expenses may be charged to the Joint Account.

27.5 If the Operator has been removed or if its resignation has been accepted,

for obligations transfer purposes ECOPETROL will audit the Joint Account and

take an inventory of all Joint Operation properties. Said inventory will be

used for devolution and accounting purposes as regards said obligations

transfer procedures. All costs and expenses incurred with respect to inventory

taking and audit shall be charged to the Joint Account.

27.6 The Operator shall not be responsible for any loss or damage caused by

Joint Operation except if such losses or damage are imputable to:

27.6.1



The Operator's fault



27.6.2 The Operator's default to take and maintain any of the insurance required

under Contract Clause 33, except if the Operator has made every possible effort

to obtain and maintain such insurance with fruitless results, which case shall

be timely notified to the Parties.

SECTION FOUR - CONTRACTING PROCEDURES

CLAUSE 28 - SUPPLIERS REGISTER AND LIST OF PROPONENTS

28.1 The Operator will be responsible of keeping an updated suppliers register,

classified according to the different activities required by the operation and

shall determine qualification criteria applicable to companies to be included in

the list of proponents. The Technical Subcommittee will have the right to review

criteria before approving the list of proponents.

<PAGE>

28.2 ECOPETROL will have the right to review the Operator suppliers register on

an annual basis and will have the right to have the Technical Subcommittee

suggest including or excluding suppliers from the record. The above

notwithstanding, ECOPETROL will have the right, any time, by duly motivated

petition, to require individuals or entities to be removed from the record.

28.3 In any cases implying invitations to bid for contracting purposes the

suppliers register shall be consulted placing the act on record in the



respective document.

28.4 Individuals or entities listed in the suppliers register shall evidence

technical, moral and economic solvency in addition to experience not only

regarding the company but also its partners and technicians working for such

companies on a steady basis.

28.5 On the basis of the above parameters, the Operator shall keep a qualified

suppliers register, which shall be periodically updated according to their

performance.

CLAUSE 29 - TENDER PROCEDURE

29.1 Responsibility. The Operator will be responsible of preparing duly in

advance the invitation to bid and will submit it to the Technical Subcommittee

for consideration.

29.2 The list of entities invited to bid will be prepared on the basis of

Suppliers Register information.

29.3 If the estimated contract value subject to bidding exceeds US$40,000, the

Operator shall invite no less than three (3) companies. If this would not be

possible, justification will be placed on record in the recommendation report to

the Technical Subcommittee.

29.4 The Operator shall endeavor to invite no more than 6 companies to bid with

the purpose of preventing excessive tender evaluation costs and also to give

participant companies a better opportunity to be awarded the respective

contract.

29.5 Being all other factors equivalent, the priority order to have the right to

be included in the list of proponents will be: Companies organized and domiciled

in the Department or Departments where the Commercial Field or Fields is or are

located - Colombian companies domiciled outside the Department or Departments

where the Commercial Field or Fields is or are located, but having a branch in

the Department - Colombian companies with their main domicile outside the

Department or Departments where the Commercial Field or Fields is or are located

not having a branch in said

<PAGE>

Department Foreign companies with a branch organized in Colombia - Foreign

companies without a branch in Colombia.

29.6 Companies invited to bid list will also take into account companies

technically and commercially qualified which have not been provided the

opportunity to participate in similar tenders in the past.

29.7 The Operator shall prepare the tender Reference Terms and will submit them

to the Technical Subcommittee for consideration, duly in advance.

29.8 Tender Reference Terms shall clearly specify that:

29.8.1

Costs will be one of the criteria to be taken into account for

contract award and

management:

29.8.2



All tenders exceeding such activity actual cost will be disqualified.



29.8.3

Tender evaluation will take into consideration factors other than

costs, which factors will be included in the Reference Terms

29.8.4

Offers shall be submitted according to invitation to bid Reference

Terms and if this requirement is not complied with the offer may be considered

invalid.

29.8.5

The invitation to bid will include a detailed price table to be

filled out by proponents to facilitate proposals evaluation.

29.9 The list of proponents will be reviewed and approved by the Technical

Subcommittee before delivering to parties invited.

29.10

As soon as the Reference Terms have been distributed, the following

rules will apply:

29.10.1 Any original Reference Terms information, amendment or clarification

will be delivered all proponents. The Operator Purchases and Supplies Unit will

be responsible of such changes. Changes must be duly justified by written

document.

29.10.2 No proponents shall be added or removed from the proponent list

originally approved by the Technical Subcommittee.

29.10.3 Every proponent who does not comply with tender procedures and rules,

or who violates the Operator business ethics code will be forthwith

disqualified.

29.11

All invitation to bid contents and form shall meet "Documentation

Submitted to the Technical Subcommittee Form" procedure requirements and shall

be submitted to the Technical Subcommittee for consideration.

<PAGE>

29.12

Internal approvals required by the Operator and ECOPETROL will depend

on contract estimated value on the basis of their respective internal

procedures.

CLAUSE 30 - CONTRACT AWARDING AND PURCHASE ORDERS

30.1 The Operator will be responsible of awarding contracts and purchase

orders. For this purpose the Operator shall submit its recommendation to the



Technical Subcommittee which is the body in charge of approving and will be

ratified by the Executive Committee if awarded value equals or exceeds

US$40,000.

30.2 Value: Awarding will be based on the best global value. The lowest price

is not always the best, because value will also take into consideration

proponents programming and quality, experience, reputation, and Colombian

contents. In the event the contract is not awarded to the lower value offer,

such decision shall be justified.

30.3 Written justification. The Operator shall submit a written recommendation

to the Technical Subcommittee justifying each contract and purchase order

awarded if the value equals or exceeds US$40,000. Such justification shall

include a summary of proposals submitted commercial and technical evaluation

and the basis for Operator recommendation.

30.4 Direct contracting: Direct contracting shall be supported and submitted in

writing to the respective Subcommittees clearly stating justification. The

Operator will have the right to contract directly with no need for tender in

any of the following events:

30.4.1 In the event only one supplier is available within the term required to

meet project schedule;

30.4.2 In the event there is no equivalent or satisfactory substitute for the

item or service previously directly contracted.

30.4.3 In the event the service or work derives from previous service or work or

in the event of and addition to a contract or purchase order opened within the

past ninety (90) days and if commercial conditions have not been modified or

when a recent tender evidences justify awarding with no need for tender.

30.4.4

In the event the Operator has standardized a specific item or service

for all applications within its operations area and there is only one known

supplier for such item or service.

<PAGE>

30.4.5 In the event only one item or service is deemed meeting Operator's

requirements within the specified delivery ten-n.

30.4.6 In the event an item or service is obtained for testing or evaluation.

30.4.7 In the event of an emergency. The Operator shall notify ECOPETROL at the

Technical Subcommittee immediately following such emergency.

30.5 Partial awards: A tender may be partially awarded two or more bidders,

provided the following conditions are fully satisfied:

30.5.1 The possibility to partially award is clearly specified in the Invitation

to Bid

30.5.2 Favored bidders have met Invitation to Bid requirements

30.5.3 Partial award reflects the best items or services to be obtained value

30.5.4 Any work scope change or awarding criteria shall be clearly communicated

to all proponents before partial award.

30.6 Rejected offers: The Operator will have the right to declare the tender

void when the Technical Subcommittee finds motives justifying such decision

and/or if offers are distant from actual costs.

30.7 Notice to non favored bidders: Awarding results will be notified all

participants in writing.

30.8 Clarification: During the evaluation period, the Operator will have the

right to require clarifications from proponents. The Technical Subcommittee

shall approve significant commercial clarifications. No new approval from the

Technical Subcommittee will be required in the event of technical

clarifications. Clarifications capable of affecting the tender shall be notified

all proponents in writing.

CLAUSE 31 - CONTRACT MANAGEMENT AND PURCHASE ORDERS

31.1 The Operator will be responsible of managing contracts and purchase orders

and of execution thereof.

31.2 Contracts or purchase orders management basis will consist in execution

thereof, which shall include agreed costs, schedules and quality requirements.

31.3 The operator shall keep written record of all original contract

amendments, Each contract costs change impact will be evaluated by the Operator

and negotiated with the supplier or contractor before changing contract price.

<PAGE>

31.4 If the proposed change exceeds US$40,000 or 10% originally approved value

not to exceed the US$40,000 limit the change will have to be submitted to the

Technical Subcommittee for consideration.

31.5 The Operator shall be responsible of Costs Control.

31.6 Any additional work or item within contract terms shall be authorized by

the Operator Project or Operations Manager, who shall consult with the Purchase

and Logistics Department or substituting units before amending the contract in

any way. This double responsibility ensures change process integrity. In the

event changes imply amending the contract text, such changes will be subject to

the Operator Legal Department approval.

31.7 Quality control will be managed subject to the QA/QC ("Quality Assurance



and Quality Control) process which shall include independent work inspection and

monitoring at the right time during work development.

31.8 Procedures applied by the Operator to control costs are described in a

Costs Control procedure.

31.9 The Parties will be delivered a monthly report on work progress accompanied

of costs documentation and schedules including major contracts and purchase

orders originally agreed budget variations analysis.

31.10

After major contracts and purchase orders have been completed a

detailed analysis will be conducted to evaluate experiences learned and

applicable to similar contracts or purchase orders to improve their control.

CLAUSE 32 - INSURANCE

For the purposes of Contract Clause 33, as regards insurance, the Operator

shall deliver to ECOPETROL the following information for ECOPETROL to insure

fifty percent (50%) Commercial Field assets.

32.1 Assets description, separated as far as possible in the following way:

31.1.1



Offices, camps and other non industrial assets.



31.1.2

Collection stations specifying tanks (quantity and capacity) and

other equipment

31.1.3

Sundry warehouses and other facilities

<PAGE>

NOTE: External pipelines and wells are not covered by the fire policy because

in such case ECOPETROL directly assumes the risk.

32.2 Assets value indicating only the portion property of ECOPETROL value and

indicating the full value percentage it represents.

32.3 Geographical location

32.4 Reception date from the time the risk is transferred to the Joint

Operation.

CLAUSE 33 - FORCE MAJEURE OR ACTS OF GOD

Contract Clause 34 only suspends compliance with specific obligation of the

Parties if development thereof is impossible due to events of force majeure or

acts of God. Additionally, obligations associated to goods, properties,

production facilities etc. are only suspended if affected by such circumstances.

The affected Party shall notify force majeure termination detailing damages

magnitude and corrective actions affecting the system.

CLAUSE 34 - OPERATION AGREEMENT REVISION

This Operation Agreement may be revised when the Parties deem convenient, upon

request from either of them; the Executive Committee is fully empowered to

review and amend this Agreement. This Operation Agreement will be in force until

one of the following events occurs:

34.1 Contractor termination

34.2 Written agreement of the Parties

34.3 Entering into a new Agreement

In witness the Parties sign this Operation Agreement in ECOPETROL contract

paper on the 30th day of the month of December 1997.

EMPRESA COLOMBIANA DE PETROLEOS "ECOPETROL"

Enrique Amorocho Cortes

President

SEVEN SEAS PETROLEUM COLOMBIA INC.

Gustavo Vasco Munoz

Legal Representative

</TEXT>

</DOCUMENT>

<DOCUMENT>

<TYPE>EX-10.C

<SEQUENCE>3

<TEXT>

ASSOCIATION CONTRACT - WITH GAS INCENTIVES

ASSOCIATION CONTRACT

ASSOCIATE: SEVEN SEAS PETROLEUM COLOMBIA

SECTOR: MONTECRISTO

EFFECTIVE DATE: 28 FEBRUARY 1998

The contracting parties, namely: on the one part THE "EMPRESA COLOMBIANA DE

PETROLEOS", hereinafter ECOPETROL, an industrial and commercial stateowned

enterprise authorized under Law 165 of 1948, currently ruled by its bylaws,

amended by Decree 1209 of 15th June 1994, having its head office in Santafe de

Bogota, D.C. represented by ENRIQUE AMOROCHO CORTEZ, of legal age, bearer of

citizenship card No 5.555.193 issued in Bucaramanga, domiciled in Santafe de

Bogota, who states that- 1. As president of ECOPETROL, he acts herein on behalf

of said Company, and 2. The ECOPETROL Board of Directors authorized him to enter

into this Contract, as witnessed by Minutes No. 2169. of 16th October 1997- and



on the other part SEVEN SEAS PETROLEUM COLOMBIA INC., a company organized

pursuant to the laws of CANADA, hereinafter referred to as "THE ASSOCIATE", with

a duly established Colombian branch and its main domicile in Santafe de Bogota,

pursuant to public deed no. 2771 of 28th September 1995, made before the

Sixteenth (16) Notary Public of the Santa Fe de Bogota circuit, represented by

Gustavo Vasco Munoz of legal age, a citizen of Colombia, bearer of identity card

No. 17.029.136 issued in Bogota, who represents that: 1. In his capacity as

Legal Representative he acts on behalf of SEVEN SEAS PETROLEUM COLOMBIA INC.

and, 2. He is fully authorized to sign this contract as witnessed by the

certificate of incorporation and legal representation issued by the Chamber of

Commerce of Santafe de Bogota. Under the above conditions, ECOPETROL and the

ASSOCIATE declare they have entered into the contract contained in the following

ClausesCHAPTER 1 - GENERAL PROVISIONS

CLAUSE 1 - PURPOSE OF THIS CONTRACT

1.1 The purpose of this contract is to explore the Contract Area and develop

such nationally-owned Hydrocarbons as may be found therein, as described in

Clause 3 below.

1.2 Pursuant to article l of Decree 231011974, ECOPETROL is entrusted with

exploring and developing nationally owned hydrocarbons and may carry out said

activities either directly or through contracts with private parties. Based on

this provision, ECOPETROL and THE ASSOCIATE have agreed to explore the Contract

Area and produce such Hydrocarbons as may be found therein under the terms and

conditions set forth in this document, in Appendix "A" and Appendix "B"

("Operating Agreement) which are made an integral part hereof.

1.3 Subject to the provisions hereof, it is understood that the rights and

obligations of THE ASSOCIATE regarding the Hydrocarbons produced in the Contract

Area, and its share thereof, are the same as those assigned under Colombian law

to anyone producing nationally-owned Hydrocarbons in the country.

1.4 ECOPETROL and THE ASSOCIATE agree to explore and develop the land of the

Contract Area, to share the costs and risks thereof in the proportion and under

the terms contemplated in this Contract, and the properties they may acquire and

the Hydrocarbons produced and stored shall belong to each Party in the

stipulated proportions.

CLAUSE 2 - APPLICATION OF THE CONTRACT

This Contract applies to the Contract Area whose boundaries are describes in

Clause 3 below, or to any portion thereof subject to the terms hereof whenever

Clause 8 has been applied.

CLAUSE 3 - CONTRACT AREA

The Contract Area is called "MONTECRISTO" and covers an extension of one hundred

fifty one thousand nine hundred and thirty three (1 51,933) hectares and five

thousand nine hundred and fifty (5,950) square meters, located in the following

municipal jurisdictions: municipal jurisdiction of San Alberto, San Martin,

Aguachica, Rio de Oro and Gonzales in Cesar Department; Morales and Simiti in

Bolivar Department; Puerto Wilches, Rio Negro, and Sabana de Torres in Santander

Department. The reference point is the Geodesic Vertex "TABLAR848" of the

Agustin Codazzi Geographic Institute, and the Gauss flat coordinates origin

Santa Fe de Bogota are: N-1,401.053.89 meters, E-1,021,264.81 meters

corresponding to geographic coordinates Latitude 8" 13' 31".808 North of the

Equator, Longitude 730 53'1 6".538 West of Greenwich. Starting from this Vertex,

head N 340 9' 25".673 W for 2,237.83 meters until reaching the starting point

"A" whose coordinates are: N-1,402,900.oo meters, E-1,020,000.oo meters. From

point "A" head EAST for 6,410.oo meters until reaching Point "B whose

coordinates are: N-1,402,900 meters E 1,026,410 meters. The whole of line "A-B"

runs alongside fine "A-K' of the "Rosablanca" Association Contract signed with

Seven Seas Petroleum Colombia Inc. Head EAST from point "B" for 2,790.oo meters

until reaching point "C" whose coordinates are- N-1,402,900 meters,

E-1,039,200.oo meters. The whole of line "B-C" runs alongside the "Buturama"

block belonging to Ecopetrol. Head SOUTH from point "C" for 27,200.oo meters

until reaching point "D" whose coordinates are N-1,375,700.oo meters,

E-1,029,200.oo meters. Head EAST from point "D" for 23,120.oo meters until

reaching point "E" whose coordinates are N-1,375,700.oo meters, E-1,052,320.oo

meters. The lines "C-D" and "D-E" run alongside lines "Q-P" and "P-O" of the

Bolivar 'Association Contract operated by Harken de Colombia Limited. From point

"E" head S 1 1 0 6' 13".551 E for 4,088.76 meters until reaching point "F" whose

coordinates are N1,371,687.78 meters, E-1,053,107.44 meters. The whole of line

"E-F" runs alongside Concession 1120 "Tisquirama". Head @ 4" 53'00".460 W for

14,183.60 meters from point "F" until reaching point "G" whose coordinates are

N1,357,555.67, E-1,051,900.oo meters. The whole of line "F-G" runs alongside

line "G-F" of the "Torcoroma" Association Contract operated by Repsol

Exploration Colombia S.A. Head WEST from point "G" for 5,867.32 meters until

reaching point "H" whose coordinates are N-1,357,555.67 meters, E-1,046,032.68

meters. Take a direction S 35 <' 14' 51".407 W from point "H" for 8,027.36

meters until reaching point "I" whose coordinates are N-1,351,000.oo meters,

E-1,041,400.oo meters. From point "I" head SOUTH for 4,900.oo meters up to point

"J" whose coordinates are: N-1 I 346,100.oo meters, E 1,041.400.oo meters. The

whole of lines "G-H","H-I" and "I-J" run alongside lines "A-F", "F-E" and "E-D"

of the Tisquirama Association Contract operated by Petroleos del Norte S.A. Head

S 89" 54'54". 1 96 E from point "J" for 8,094.01 meters until reaching point "K'

whose coordinates are N1,346,088.oo meters, E-1,049,494 meters. Head 400

34'27".390 W from point "K' for 19,274.23 meters until reaching point "L" whose

coordinates are N1,331,448.oo meters, E-1,036,957.40 meters. Head S 260 20'

16".725 E from point "L" for 2,096.62 meters until reaching point "M" whose

coordinates are N1,329,569.02 meters, E-1,037,887.60 meters. The whole of lines

"K-L" and "L-M" run alongside the Playon block belonging to Ecopetrol. From

point "M" head N 890 59" 59".605 W for 20,887.60 meters until reaching point "N"



whose coordinates are N-1,329,569.06 meters, E-1,017,000.oo meters. Head NORTH

from point "N" for 15,030.94 meters until reaching point "O" whose coordinates

are N1,344,600.oo meters and E-1,017,000.oo meters. The whole of line "M-N" runs

alongside the "La Cira-infantas" block belonging to Ecopetrol. Head EAST from

point "O" for 3,000.oo meters until reaching point "P" whose coordinates are

N1,344.600.oo meters, E-1,020,000.oo meters. Head NORTH from point "P" for

58,300.oo meters until reaching starting point "A:' and thus close the

boundaries.

PARAGRAPH 1: Whenever somebody files a claim asserting ownership of the

Hydrocarbons in the subsoil within the Contract Area, ECOPETROL shall deal with

the case, assuming such obligations as may arise.

PARAGRAPH 2- lf part of the Contract Area extends to areas that are or have been

reserved and declared as falling within the National Park System, THE ASSOCIATE

must meet all conditions imposed by the pertinent authorities in keeping with

Clause 30 (numeral 30.4) hereof. This neither amends the contract nor

constitutes grounds for filing any claim against ECOPETROL.

CLAUSE 4- DEFINITIONS

For Contract purposes,

out hereunder-



the terms



listed below shall have the meaning set



4.1 CONTRACT AREA-. The land describes in Clause 3 hereinabove, subject to

Clause 8.

4.2 FIELD: Portion of the Contract Area where one or more structures exist,

totally or partially overlying, with one or Reservoirs that are producing or

whose Hydrocarbon-producing capacity has been tested. These Reservoirs may be

separated by geological causes such as: synclines, faults, wedging of producing

strata, changes in porosity and permeability; likewise they may be of different

geological ages, separated by strata that is reasonably watertight, totally,

partially overlapping or not overlapping at all.

4.3 COMMERCIAL FIELD- A field that ECOPETROL accepts as able to produce

Hydrocarbons of a quality and quantity that is economically viable in one or

more Production Targets to be defined by ECOPETROL.

4.4 GAS FIELD: A field that ECOPETROL qualifies as a producer of Natural

Non-Associated Gas (or Free Natural Gas) when defining its commerciality and

using information furnished by THE ASSOCIATE.

4.5 EXECUTIVE COMMITTEE: The body that will supervise, control and approve all

operations and actions performed throughout the contract and to be established

within thirty (30) days following acceptance of the first Commercial Field.

4.6 DIRECT EXPLORATION COSTS: Any monetary expenditures reasonably incurred by

THE ASSOCIATE in seismic surveys and drilling. Exploration Wells, as well as for

locations, completion, equipping and testing of such wells. Direct Exploration

Costs do not include administrative or technical support from the Company's head

or central office.

4.7 JOINT ACCOUNT: Accounting records kept pursuant to Colombian law for

crediting or debiting the Parties with their share in the Joint Operation of

each Commercial Field.

4.8 BUDGETARY EXECUTION: The resources effectively expended and/or committed for

each program and project approved for a given calendar year.

4.9 STRUCTURE: The geometrical form with geological closure (anticline, syncline

etc.) that is revealed by formations having accumulations of fluid.

4.10 EFFECTIVE DATE: The sixtieth (60) calendar day following contract

signature, and the starting date for all time limits agreed to herein and

subject to the validity of the same contract.

4.11 CASH FLOW- The physical flow of money (income and expenditure) incurred by

the Joint Account to handle the obligations contracted by the Association in the

normal course of operations.

4.12 ASSOCIATE NATURAL GAS: Mixture of light hydrocarbons existing in the

Reservoir in the form of a gas layer or in solution and produced together with

liquid hydrocarbons.

4.13 NON-ASSOCIATE NATURAL GAS (PRODUCTION OF): Those hydrocarbons produced in

gaseous state at surface and reported at standard conditions, with an initial

average (production weighted) Gas/Oil ratio of over 15,000 standard cubic feet

of gas per barrel of liquid Hydrocarbon, and heptane PIUS (C7 +) molar

composition below 4%.

4.14 DIRECT EXPENSES: All expenditures charged to the Joint Account as a result

of payment to personnel directly working for the Association, purchase of

materials and supplies, service contracts made with third parties and any

overhead required by the Joint Operation in the normal course of its activities.

4.15 INDIRECT EXPENSES: Those disbursements charged to the Joint Account for

administrative/technical support for the Joint Operation that Operator may

furnished through his own organization.

4.16 COMMERCIAL INTEREST: For Colombian Pesos, it shall be the interest rate for

ninety-day (90) CDs certified by the Banking Superintendency, or whoever

replaces same, applicable to the respective period. In the case of US dollars,

it shall be the prime rate established by CITIBANK New York, or the entity

appointed for this purpose.

4.17 INTEREST in THE OPERATION: The share in the rights and obligations acquired



by each Party in the exploration and development of the Contract Area.

4.18 DEVELOPMENT INVESTMENT- Refers to the amount of money invested in goods and

equipment capitalized as Joint Operation assets in a Commercial Field, once the

Parties have accepted the existence thereof.

4.19 HYDROCARBONS: Any organic compound consisting mainly of the natural mixture

of hydrogen and carbon, as well as substances related thereto or derived

therefrom, except for helium and rare gases.

4.20 GASEOUS HYDROCARBONS- All hydrocarbons produced in gaseous state at the

surface and reported at standard conditions (1 atmosphere of absolute pressure

and a temperature of 60 deg. F).

4.21 LIQUID HYDROCARBONS- lncludes crude oil and condensates, as well as those

produced in such state as a result of gas treatment when pertinent, reported at

standard conditions.

4.22 PRODUCTION TARGETS: Reservoirs located within the Commercial Field

discovered and that have tested as commercial producers.

4.23 JOINT OPERATION: The tasks and work performed, or being performed, on

behalf of the Parties and for their account.

4.24 OPERATOR: The person appointed by the Parties to act on their behalf in

directly carrying out the operations needed to explore and produce the

Hydrocarbons discovered in the Contract Area.

4.25 PARTIES: On the effective Date, ECOPETROL and the ASSOCIATE. Subsequently

and at any time, ECOPETROL on the one part, and THE ASSOCIATE and/or its

assignees on the other part.

4.26 EXPLORATION PERIOD- The term for THE ASSOCIATE to comply with the

obligations set forth in Clause 5 herein below, not to exceed six (6) years from

the Effective Date, except as provided for in Clauses 9 (numerals 9.3, 9.8) and

34.

4.27 EXPLOITATION PERIOD: The time elapsed from the end of the Exploration or

Retention Period up to the end of the contract.

4.28 RETENTION PERIOD: Time lapse granted by ECOPETROL when THE ASSOCIATE asks

for more time to start the Exploitation Period of each Gas Field discovered

viithin the Contract Area, because special conditions mean the field cannot be

developed in the short term and consequently additional time is needed to build

the infrastructure andlor develop the market

4.29 EXPLORATION WELL: Any well so designated by THE ASSOCIATE that is to be

drilled or deepened for its account in the Contract Area for the purpose of

seeking new Reservoirs, checking the extension of a reservoir, or establishing

the stratigraphy of an area. In order to comply with the obligations agreed upon

in Clause 5 hereof, the respective Exploration Well will be previously qualified

by ECOPETROL and the ASSOCIATE.

4.30 DEVELOPMENT OR EXPLOITATION WELL : Any well previously scheduled by the

Executive Committee for producing Hydrocarbons discovered in the Production

Targets within each Commercial Field.

4.31 BUDGET: A basic planning tool earmarking funds for specific projects to be

used within a calendar year or part thereof in order to attain the goals and

targets proposed by the ASSOCIATE or Operator.

4.32 EXTENSIVE PRODUCTION TESTS- Operations performed in one or more producing

Exploration Wells to appraise producing conditions and reservoir behavior.

4.33 REIMBURSEMENT: Payment of fifty percent (50%) of the Direct Exploration

Costs incurred by THE ASSOCIATE.

4.34 EXPLORATION WORK- Operations performed by THE ASSOCIATE in search for and

discovery of hydrocarbons in the Contract Area

4.35 RESERVOIR: Any sub-surface rock with hydrocarbon accumulation in its porous

space, producing or able to produce hydrocarbons and behaving as an independent

unit with respect to petrophysical and fluid properties and having a single

pressure system throughout.

CHAPTER 11 - EXPLORATION

CLAUSE 5 - TERMS AND CONDITIONS

5.1.1 During the first two years following Effective Contract Date, THE

ASSOCIATE must reprocess five hundred (500) kms. of existing seismic on the

area, acquire/interpret Landsat images and surface Geological and geochemical

work; acquire/process and interpret one hundred (100) kilometers of 2D seismic.

At the end of the second year, THE ASSOCIATE shall have the option to relinquish

the contract providing it has met the above obligations. lf THE ASSOCIATE wishes

to go ahead into the third year, it must relinquish areas so that it remains

with an area not to exceed one hundred thousand (100,000) hectares.

5.1.2 During the third year, THE ASSOCIATE shall drill one (1) Exploratory Well

to penetrate the potential Hydrocarbon-producing formations in the Area. The

contract shall terminate at the end of this year unless an extension has been

applied for and authorized pursuant to numeral 5.2 of this Clause, or a

commercial field has been discovered, except as set out in Clause 9 (numeral

9.5).

5.2 lf THE ASSOCIATE has satisfactorily met the obligations of Clause 5, it may

request ECOPETROL to extend the Exploration Period annually up to three (3)



additional years and during each extension THE ASSOCIATE shall perform

Exploration Work in the Contract Area, consisting of drilling one (1)

Exploration Well until it penetrates the Hydrocarbon producing formations in the

area.

5.3 lf, during any year of the Exploration Period, THE ASSOCIATE should decide

to carry out work on the following year's obligations, it must obtain permission

therefor from ECOPETROL. lf ECOPETROL agrees, it shall decide on how such

obligations are to be transferred and the amount thereof.

5.4 Throughout the life of this contract, THE ASSOCIATE may carry out

Exploration Work on the areas retained in keeping with Clause 8, and will be

solely responsible for the risks and costs of such activities and thus have

complete and exclusive control thereon. This will not change maximum life of

this contract.

CLAUSE 6 - HANDING OVER INFORMATION DURING EXPLORATION

6.1 When THE ASSOCIATE so requests, ECOPETROL shall supply any information it

holds on the Contract Area. The costs of reproducing and supplying such

information shall be charged to THE ASSOCIATE.

6.2 During the Exploration Period, THE ASSOCIATE shall hand over the following

data to ECOPETROL as such becomes available and in keeping with the ECOPETROL

data supply manual: all geological/geophysical data, cores, edited magnetic

tapes, processed seismic sections and all supporting field data, magnetic and

gravimetric logs, all of this in reproducible originals; copies of geophysical

reports, reproducible originals of all logs for wells drilled by THE ASSOCIATE,

including the final composite graph for each well and copies of the final

drilling report, including core sample analyses, results of production tests and

any other information relating to the drilling, study or interpretation of any

kind performed by THE ASSOCIATE for the Contract Area without any limitation.

ECOPETROL is entitled to witness any operations and verify the information

listed hereinabove doing so at any time and using any procedure it may consider

appropriate,

6.3 The parties agree that all geological, geophysical and engineering

information obtained from the Contract Area while this contract is in force, is

to be held confidential for three (3) years following acquisition thereof.

Thereafter such information shall be released except for any interpretations

thereof made by the Parties. The released information mainly concerns seismic,

potential methods, remote sensors and geochemical data, with respective support

documents, surface and sub-surface mapping, wells reports, electric logs,

formation tests, biostratigraphic/petrophysical/fluid analyses and production

history. However, the parties agree that in each case they may exchange

information with ECOPETROL's associates and non-associates. It is understood

that what is agreed here shall not affect the requirement of providing the

Ministry of Mines and Energy with all the information it requests under current

legal resolutions and regulations. Nonetheless, it is understood and accepted

that the Parties can, at their own discretion, provide their affiliates,

consultants, contractors and financial entities with the information they

require and called for by authorities having jurisdiction on the parties and

their affiliates, as well as by norms established by any stock exchange quoting

the stock of the parties or related corporations.

CLAUSE 7 - BUDGET AND EXPLORATION SCHEDULES

Respecting the terms of this contract, THE ASSOCIATE must prepare the programs

and work schedule for exploring the Contract Area, together with a short-term

Budget (following calendar year) and estimated Budget giving an overview for the

next two (2) years. Such overview, programs, time schedules and Budgets shall be

submitted to ECOPETROL for the first time within sixty (60) calendar days

following contract signature, and thereafter Within the first ten (10) calendar

days of each year.

THE ASSOCIATE shall give ECOPETROL a quarterly technical and financial report,

listing exploratory work performed, prospects revealed by the information

acquired, the assigned Budget and exploration costs incurred up to date of the

report, commenting in each case on causes of the main variances. When ECOPETROL

so requests, THE ASSOCIATE shall provide explanations on the report doing so at

meetings that can be scheduled every six months. lnformation submitted by THE

ASSOCIATE in the reports and explanations mentioned in this clause shall under

no circumstances be understood as accepted by ECOPETROL. ECOPETROL may audit

financial information as set out in Clause 22 of Appendix B hereto (Operating

Agreement).

CLAUSE 8 - RESTITUTION OF AREAS

8.1 lf a Commercial Field has been discovered in the Contact Area by the end of

the initial three-year exploration period, or of the extensions obtained by THE

ASSOCIATE in keeping with Clause 5 (numeral 5.2), the Contract Area will be

reduced by 50%- two (2) years thereafter the area will be reduced to fifty

percent (50%) of the remaining Contract Area- and two years thereafter, such

area will be reduced to the Commercial Fields(s) that are producing or under

development plus a reserve belt two and a half kilometers (2.5) wide surrounding

each Field and this will be the only part of the Contract Area that continues to

be subject to the terms of this contract. In order to apply this clause, an

imaginary grid or net will be placed over the initial contract area and then

divided into ten rows and columns running north-south, limited by the maximum

and minimum north and east coordinates of the boundaries, and they will define

the cells on which relinquishment of areas referred to in this numeral will be

based. Each time areas are returned, the imaginary grid or net will be modified

in keeping with the new coordinates of the Contract Area.

8.2 THE ASSOCIATE shall decide what areas are to be returned to ECOPETROL based

on the imaginary grid or net mentioned in the preceding numeral. To this end,

the relinquishment may be made in one or two lots, comprising one or more



adjoining cells and trying to conserve a single polygon, unless THE ASSOCIATE

shows that this is either impossible or unsuitable, in such case approval must

be obtained from ECOPETROL. Notwithstanding the requirement to relinquish areas

referred to in Clause 8 (numeral 8.1). THE ASSOCIATE is not obliged to return

areas under development or production, including the 2.5 km. wide belt

surrounding said areas, unless development or production are suspended

continuously for over a year without just cause and for reasons attributable to

THE ASSOCIATE, in which case the areas will be returned to ECOPETROL, thus

terminating the contract for said areas of part of the area. These stipulations

are also applicable to development under the sole risk mode.

8.3 Retention Period- lf THE ASSOCIATE has discovered a Gas Field and applied

for commerciality thereof as set out in Clause 9 (numeral 9.1), he may

simultaneously ask ECOPETROL for a Retention Period, giving reasons to fully

justify this request.

8.3.1 THE ASSOCIATE must apply for the Retention Period, and ECOPETROL grant

same, prior to the date for final relinquishment of areas referred to in numeral

8.1 hereof.

8.3.2 The Retention Period may not exceed four (4) years. lf the initial term

were to be insufficient, ECOPETROL may extend same following a written and

justified application from THE ASSOCIATE, but the initial period plus any

extension may not exceed four (4) years.

CHAPTER III - EXPLOITATION

CLAUSE 9 - TERMS AND CONDITIONS

9.1 To initiate the Joint Operation hereunder, it is considered that

exploitation work starts on the date the Parties accept the existence of the

first Commercial Field or upon compliance with the provisions of Clause 9

(numeral 9.5). THE ASSOCIATE shall prove the existence of a Commercial Field by

drilling sufficient wells to reasonably define the hydrocarbon-producing area

and the commerciality of the Field. In this case, THE ASSOCIATE will notify

ECOPETROL in writing about such commercial discovery, furnishing the studies

that have led to this conclusion. ECOPETROL must accept or reject the existence

of such Commercial Field within ninety (90) calendar days from the date THE

ASSOCIATE hands over all support information and makes the technical

presentation. ECOPETROL may request any additional information it deems

necessary within thirty (30) days following submittal of the initial support

information.

9.2.1 Should ECOPETROL accept the existence of a Commercial Field, it shall so

advise THE ASSOCIATE within the ninety (90) day term referred to in Clause 9

(numeral 9.1) stipulating the area of the Commercial Field. Then it shall begin

to participate in the development of the Commercial Field discovered by THE

ASSOCIATE as set out in the terms of the Contract.

9.2.2 ECOPETROL shall reimburse fifty percent (50%) of the Direct Exploration

Costs incurred by THE ASSOCIATE for its own risk and account in the Contract

Area prior to the date when commerciality studies for the new commercial

discovery were submitted, in keeping with numeral 9. l.

hereof.

9.2.3 The amount of such Direct Costs shall be established in dollars of the

United States of America, the reference date being that vihen THE ASSOCIATE made

such disbursements; consequently, the costs incurred in Colombian pesos shall be

liquidated at the market representative rate for such date as certified by the

Banking Superintendency, or entity replacing same.

PARAGRAPH:

Once the amount of Direct Exploration Costs to be reimbursed in United States

Dollars has been established, such will be inflation-adjusted for each year or

part thereof as of the disbursement date up to the date defined by the Ministry

of Mines & Energy as the initiation of the exploitation period, using the

internacional inflation rate for the respective year or, failing this, that for

the previous year. The international inflation rate to be used shall be the

annual percentage variation of the consumer price index for industrialized

countries, taken from "international Financial Statistics" published by the

International Monetary Fund (page S63 or replacement) or, failing this, the

publication agreed by the Parties.

9.2.4 As soon as Operator puts the Field on-stream, ECOPETROL shall reimburse

THE ASSOCIATE for Direct Exploration Costs according to Clause 9 (numeral 9.2.2)

with the amount of dollars equivalent to fifty percent (50%) of its direct share

in the total production of such Field, after deducting the royalty percentage.

For Commercial Gas Fields, ECOPETROL shall reimburse the ASSOCIATE with the

amount of dollars equivalent to one hundred percent (1 00%) of its direct share

in the total production of such Field, after deducting the royalty percentage,

doing so as soon as Operator puts the Field on-stream.

9.3 lf ECOPETROL rejects the existence of the Commercial Field referred to in

Clause 9 (numeral 9.1), it may notify THE ASSOCIATE of additional work it

considers necessary to demonstrate such existence. The cost of this work may not

exceed TWO MILLION DOLLARS (US$2,000,000) nor last for more than one (1) year,

in which case the Exploration Period for the Contract Area will automatically be

extended by the same period as that agreed by the Parties for the performance of

the additional work requested by ECOPETROL in this Clause but without prejudice

to the reduction of areas stipulated in Clause 8 (numeral 8. l).

9.4 lf, upon completion of the additional work requested in Clause 9 (numeral

9.3), ECOPETROL accepts the existence of a Commercial Field as stipulated in

Clause 9 (numeral 9.1), it will begin to participate in the development of said

field as stipulated herein, and will reimburse THE ASSOCIATE as set forth in



Clause 9 (numeral 9.2.3-9.2.4) for fifty percent (50%) of the cost of such

additional work referred to in Clause 9 (numeral 9.3) and the work carried out

will become Joint Account property.

9.5 lf ECOPETROL continues to reject the existence of a Commercial Field after

the additional work referred to in Clause 9 (numeral 9.3) has been carried out,

THE ASSOCIATE may go ahead with the work it deems necessary to exploit such

field and reimburse itself for two hundred percent (200%) of the total cost of

the work performed at its own risk and account in the respective Field and up to

fifty percent (50%) of the Direct Exploration Costs it incurred prior to

submitting commerciality studies for such Field. For the purposes of this

Clause, the reimbursement will be made with the value of Hydrocarbons produced,

less the royalties established in Clause 13, deducting production, collection,

transportation and sales costs. lf THE ASSOCIATE avails itself of the sole risk

modality, it is understood that the exploitation term begins on the date

ECOPETROL notifies it that commerciality is rejected. The dollar equivalence of

disbursements made in pesos will be calculated using the market representative

rate certified by the Banking Superintendency, or entity replacing same, for the

date THE ASSOCIATE made such disbursements. For the purposes of this clause, the

value of each barrel of Hydrocarbon produced in said Field during a calendar

month, shall be the average price per barrel received by THE ASSOCIATE for the

sale of its share in the Hydrocarbons produced in the Contract area during the

same month. The contents of the paragraph of Clause 9 (numeral 9.2.3.) shall

apply to reimbursement of Direct Exploration Costs.

Once THE ASSOCIATE has reimbursed itself with the percentage established herein,

all wells drilled, the facilities and all property acquired by THE ASSOCIATE to

exploit the field and paid as set forth in this Clause, shall become the

property of the Joint Account free of any charge whatsoever, and after ECOPETROL

agrees to participate in the development of such field.

9.6 At any time, ECOPETROL may start to participate in the operation of the

field discovered and developed by THE ASSOCIATE, subject to the latter's right

to reimburse itself for investments made at its own expense as stipulated in

Clause 9 (numeral 9.5). Once THE ASSOCIATE has repaid itself, ECOPETROL shall

start to participate in the financial results of the wells developed at the

exclusive expense of THE ASSOCIATE.

9.7 When defining the boundaries of a Commercial Field, consideration will be

given to all geological/geophysical information on such field plus that of all

wells drilled therein or related thereto.

9.8 lf THE ASSOCIATE has drilled one or more Exploration Wells pointing to the

possible existence of a Commercial Field by the end of the six-year (6)

Exploration Period referred to in Clause 5 (numeral 5.2), it may ask ECOPETROL

to extend the Exploration Period for the time necessary, but not to exceed one

(1) year, to demonstrate the existence of said Commercial Field, without

prejudice to the provisions of Clause 8.

9.9 lf THE ASSOCIATE continues performing the exploration obligations agreed

upon in Clause 5 after one or more fields have been declared commercial, it can

simultaneously exploit such Fields before the end of the Exploration Period

defined in Clause 4.26 but the 22-year Exploitation Period will run as of the

expiry date of the Exploration Period. When ECOPETROL has granted a Retention

Period for Gas Fields, the Exploitation Period for each Field will run from the

expiry date of the respective Retention Period.

9.10 lf THE ASSOCIATE shows that Exploration Wells drilled after the Field has

been declared commercial contain additional Hydrocarbon accumulations associated

to said field, it shall ask ECOPETROL to extend the area of the Commercial Field

and its commerciality, following the procedures of Clause 9 (numerals 9.1 and

9.2.1). lf ECOPETROL accepts the commerciality, it shall reimburse THE ASSOCIATE

for fifty percent (50%) of the Direct Exploration Costs exclusively related to

the extension of the Commercial Field, as set out in numerals 9.2.3 and 9.2.4.

lf ECOPETROL rejects the commerciality, THE ASSOCIATE may reimburse itself for

up to two hundred percent (200%) of the total costs of work performed for its

own risk and account in exploiting the Exploration Wells that have become

producers and up to fifty percent (50%) of the Direct Exploration Costs it

incurred solely with regard to the commerciality application. Such reimbursement

shall be made with production coming from the producing Exploration Wells, after

deducting the royalty, and following the procedure of Clause 21 (numeral 21.2)

until reaching the mentioned percentages.

CLAUSE 10 - TECHNICAL CONTROL OF THE OPERATIONS

10.1 The parties agree that THE ASSOCIATE is the 0perator and as such shall

control all operations and activities it deems necessary for an efficient,

technical and economic development of Hydrocarbons existing within the

Commercial Field, respecting the restrictions contained in this contract.

10.2 The Operator must follow standard industry practices in performing

development/production work, using the technical methods and systems best suited

to an economic and efficient Hydrocarbon production, and complying with

pertinent legal and regulatory provisions on this matter.

10.3 The Operator shall be considered an entity distinct from the Parties hereto

for all contract purposes, as well as for application of civil, labor and

administrative law, and with regard to its employees as set out in Clause 32.

10.4 The Operator may resign as such by giving the Parties six-months (6)

advance written notice of the effective date of such resignation. The Executive

Committee shall then appoint a new Operator pursuant to Clause 19 (numeral

19.3.2)

CLAUSE 11 - DEVELOPMENT PROGRAMS AND BUDGETS



11.1 Within three (3) months following acceptance of a Commercial Field in the

Contract Area, Operator shall present the Parties with a work program and a

Budget for the rest of the calendar year together with a proposed/development

plan, to be agreed by the Executive Committee. lf there are less than six and a

half (6-112) months to run before the end of said year, Operator shall prepare

and submit the Budget and programs for the following calendar year within a term

of three (3) months.

11.1.1 Future Budgets and programs shall be submitted to the Parties in May each

year, and Operator shall send its proposal to the Parties in the first ten (10)

days of May. The Parties shall notify Operator in writing of any changes they

wish to propose, doing so within twenty (20) days of receiving the Budgets and

programs. When this occurs, Operator shall consider such proposals in preparing

the Budget and programs to be submitted for final approval by the Executive

Committee at its ordinary meeting held each July. Should the total Budget not be

approved before July, the Executive Committee shall approve those items on which

there is agreement, and the remainder shall be submitted to the Parties for

subsequent review and final decision as provided for in Clause 20.

11.1.2 The development program shall become a guide for the technical, efficient

and economic exploitation of each Field. it will describe work to be carried out

and estimated investments and expenses for the next five years, wih details of

the annual operating program and Budget for the next calendar year.

11.2 The parties may propose Budget additions or revisions to the Budget but not

more often than every three (3) months except in emergencies. The Executive

Committee shall decide on these proposed revisions or additions at a meeting to

be scheduled within thirty (30) days following submittal thereof.

11.3



The programs and Budget are intended to:



11.3.1 Determine the operations to be carried out during the following calendar

year, as well as expenditures and investments (Budget) the Operator is

authorized to undertake.

11.3.2 Maintain a medium and long-term view of development at each Field.

11.4 The terms program and Budget refer to the proposed work plan and estimated

expenditures and investments that the Operator shall carry out, such as:

11.4.1 Capital investments in production-. drilling for reservoir development,

workovers or reconditioning of wells and specific production facilities.

11.4.2 General construction and equipment: industrial and camp facilities,

transport and building equipment, drilling and production equipment. Other

construction and equipment.

11.4.3 Maintenance and operating expenses: production expenses, geological

expenses and administrative overhead for the operation.

11.4.4 Working capital needs

11.4.5 Contingency funds

11.5 Operator shall make all expenditures and investments and handle development

and production in keeping with the programs and Budgets referred to in Clause 1

1 (numeral 1 1. l), without exceeding the total annual Budget by ten percent (1

0%), except when so authorized by the Parties in special cases.

11.6 The Operator may no start any project on its own initiative, nor charge the

Joint Account with non-Budgeted expenditure exceeding forty thousand United

States dollars (US$40,000), or the equivalent in Colombian currency, per project

or quarter.

11.7 The Operator is authorized to effect expenses chargeable to the Joint

Account without prior authorization from the Executive Committee when it is a

matter of taking emergency steps to safeguard persons or property of the

Parties; emergency expenses originating in fire, floods, storms or other

disasters; emergency expenses essential for the operation and maintenance of

production facilities, including keeping wells at maximum production efficiency;

emergency expenses essential to protect/safeguard material/equipment needed for

operations. In such cases, the Operator shall call a special meeting of the

Executive Committee as soon as possible in order to obtain approval for

continuing with the emergency measures.

CLAUSE 12 - PRODUCTION

12.1 Whenever necessary and duly approved by the Executive Committee, Operator

shall determine the Maximum Efficiency Rate (MER) for each Commercial Field.

This Maximum Efficiency Rate (MER) shall be the maximum rate for lifting

Hydrocarbons from a reservoir in order to attain maximum final recovery of

reserves. Estimated production should be diminished as necessary to compensate

for real or anticipated operating conditions, such as wells under repair and not

producing, limited capacity of gathering lines, pumps, separators, tanks,

pipeline and other facilities.

12.2 Periodically, at least once a year and with the approval of the Executive

Committee, Operator shall determine the area capable of commercial Hydrocarbon

production in each Field.

12.3 Every three (3) months, the Operator shall prepare and give each Party two

schedules, one showing production share and the other production distribution

for each one over the following six (6) months. The production forecast shall be

based on the Maximum Efficiency Rate (MER), as set forth in Clause 12 (numeral

12.1) and adjusted to the rights of each Party hereunder. The production

distribution schedule shall be based on periodic requests from each Party and in

keeping with Clause 14 (numeral 14.2), with such corrections as may be necessary



to ensure that no Party having capacity to make withdrawals will receive less

than the amount to which it is entitled under Clause 14, and subject to Clauses

21 (numeral 21.2) and 22 (numeral 22.5).

12.4 lf any Party foresees that it will be unable to receive the full capacity

of Hydrocarbons set out in the forecast furnished Operator, it shall so advise

the latter as soon as possible. lf such reduction is caused by an emergency, the

Party shall notify the Operator within twelve (1'2) hours following the

occurrence of the respective event. In consequence, the Party concerned shall

provide the Operator with a new receiving schedule based on the reduction.

12.5 Operator may use the Hydrocarbons consumed in production operations in the

Contract Area, and such shall be exempt from the royalties referred to in Clause

13 (numerals 13.1 and 13.2).

CLAUSE 13 - ROYALTIES

13.1 Liquid Hydrocarbons: During exploitation of the Contract Area, and before

distributing production among the Parties, Operator shall give ECOPETROL

royalties corresponding to twenty percent (20%) of the certified production of

liquid hydrocarbons coming from said area. ECOPETROL, for its own risk and

account, shall take the royalty production in kind from the tanks belonging to

the Joint Account.

13.2 Gaseous Hydrocarbons-. Operator shall give ECOPETROL a royalty in the form

of twenty percent (20%) of the production of gaseous Hydrocarbons reported at

standard conditions. lf such Hydrocarbons need to be treated at a gas plant, the

twenty percent (20%) royalty production shall be established as the sum of dry

gas produced at the plants plus the dry gas equivalent of liquid products

produced,considering the conversion factors set out in current legislation.

Regarding fiels exploited under the sole risk mode, THE ASSOCIATE shall give

ECOPETROL the royalty percentage of Hydrocarbons.

13.3 ECOPETROL shali use the royalty production to pay the entities legally

appointed to receive the royalties due the State on the full production of the

Commercial Field, doing so in the manner and respecting the time limits set out

in law, and the ASSOCIATE shall in no case be liable for any payments to these

entities.

CLAUSE 14 - DISTRIBUTION AND AVAILABILITY OF HYDROCARBONS

14.1 The Hydrocarbons produced shall be transported to the jointly-owned tanks

or to other measuring facilities agreed by the Parties, except for those used

and inevitably consumed in operations hereunder. In the absence of an agreement,

the measuring point for gaseous Hydrocarbons shall be- i) The gas line of each

separator when they are not to be treated in gas plants, or ii) at the exit of

the gas plants when such treatment is required. The Hydrocarbons shall be

measured via accepted industry standards and such measurement shall be the basis

for calculating the percentages of Clause 13. Thereafter, the remaining

Hydrocarbons belong to each Party in the proportion specified in this Contract.

14.2



PRODUCTION DISTRIBUTION



14.2.1 After deducting the royalty percentage, the remaining Hydrocarbons

produced in each Commercial Field belong to the parties thus: Fifty percent

(50%) for ECOPETROL and fifty percent (50%) for THE ASSOCIATE until cumulative

production for each Commercial Field reaches 60 million barreis of liquid

Hydrocarbons or 420 giga cubic feet of gaseous Hydrocarbons at standard

conditions, whichever occurs first (1 cubic giga foot = 1 x 10 9, cubic feet)

14.2.2 Notwithstanding the fact that ECOPETROL has classified the Field as being

commercial, when production at each Commercial Field (after deducting the

royalty percentage) exceeds the limits of 14.2. 1, distribution among the

Parties will use the R factor as set out hereunder.

14.2.2.1 lf liquid Hydrocarbons first reach the limit set out in numeral 14.2.1

hereof, the following table shall apply:

R FACTOR



PRODUCTION DISTRIBUTION AFTER ROYALTIES (%)

ASSOCIATE

ECOPETROL

50

50

50/R

100-50/R

25

75



0.0 - 1.0

1.0 - 2.0

2.0 or more



14.2.2.2 lf gaseous Hydrocarbons first reach the limit set out in numeral 14.2.1

hereof, the following table shall applyR FACTOR



PRODUCTION DISTRIBUTION AFTER ROYALTIES

ASSOCIATE

ECOPETROL



0.0 - 1.0

1.0 - 2.0

2.0 or more



50

50/R

25



50

100-50/R

75



14.2.3 The R factor is defined as the ratio between accrued income and accrued

disbursements made by THE ASSOCIATE for each Commercial Field, as follows:

R



=



IA

------------------ID+A-B+GO



Where:

1A (The Associates Accrued lncome)- is the valuation of income accrued by THE

ASSOCIATE for hydrocarbons produced, after royalties, at the reference price

agreed by the Parties, excluding hydrocarbons reinjected in Contract Area

Fields, and those consumed in the operation and burnt gas.



The parties shall jointly establish the average reference price for

hydrocarbons.

Accrued lncome will be based on the Monthly lncome which, in turn, will be

obtained from multiplying the average monthly reference price by the monthly

production in keeping with respective form issued by the Ministry of Mines &

Energy.

ID (Accrued Development lnvestment)- ls fifty percent (50%) of the accrued

development investment approved by the Association Executive Committee. Accrued

Development lnvestment made prior to the exploitation start-up date of the Field

as defined by the Ministry of Mines and Energy, shall be adjusted to such date

in the same way as Direct Exploration Costs in the paragraph of Clause 9

(numeral 9.2.3).

A. Direct Exploration Costs incurred by THE ASSOCIATE according to Clause hereof

and adjusted as set out in the paragraph of 9.2.3 .

B. Accrued reimbursement of the afore-mentioned Direct Exploration Costs, in

keeping with Clause 9 hereof.

GO (Accrued Operating Expenses)-. accrued operating expenses approved by the

Association Executive Committee, in the proportion corresponding to the

ASSOCIATE plus the latter's accrued transportation costs. Transportation costs

are investment and operating expenses for transporting hydrocarbons produced in

the Commercial Fields within the Contract Area up to the exportation port or the

place agreed for taking the price to be used in the 1A calculation. Such

transportation costs will be jointly determined by the parties once the Fields

that ECOPETROL has declared to be commercial initiate the exploitation stage.

Operating expenses include special levies or similar items directly applied to

Hydrocarbon exploitation in the Contract Area.

All values included in the R factor calculation following the exploitation

start-up date established by the Ministry of Mines & Energy will be taken in

current dollars.

To this end, expenses in pesos shall be converted to dollars at the Market

Representative Rate certified by the Banking Superintendency, or entity

replacing same, in force on the date the respective disbursements were made.

14.2.4 CALCULATION OF THE R FACTOR: Production distribution based on the R

factor will be applied as of the first day of the third calendar month following

that when the accrued production in the Contract Area reached 60 million barreis

of liquid Hydrocarbons or 420 giga cubic feet of gaseous Hydrocarbons at

standard conditions, in keeping with 14.2.1

The R Factor for calculation each Commercial Field will be based on the

accounting closing for the calendar month when accrued production reached 60

million barrels of liquid Hydrocarbons or 420 giga cubic feet of gaseous

Hydrocarbons at standard conditions, in keeping with14.2.1

The resulting distribution will be applied until 30th June of the following

year. Thereafter, R factor production distribution will be made for one-year

periods (lst July to 30th June) for liquidation thereof based on accrued value

at 31st December of the previous year as shown in the respective accounting

closing.

14.3 In addition to the jointly owned tanks and other facilities, each Party may

build its own production facilities in the Contract Area for its exclusive use

and in keeping with legal regulations. When Hydrocarbons belonging to each Party

are transported and delivered to pipelines and depots that are not jointly

owned, this will be for the risk and cost of the Party receiving such

Hydrocarbons.;

14.4 When production sites are not connected to a pipeline, the Parties may

agree to install pipelines up to a point connecting to the pipeline or where the

Hydrocarbons can be sold, this work will be charged to the Joint Account. lf the

Parties agree to build such pipelines, they will enter into the contracts they

deem suitable for this purpose and appoint the Operator pursuant to current

legislation.

14.5 Each Party shall own the Hydrocarbons produced and stored as a result of

the operation hereunder and made available to it pursuant to the provisions of

this contract. Likewise, each Party must assume the expense of receiving such

Hydrocarbons in kind or selling or disposing of them separately, as provided for

in Clause 14 (numeral 14.3).

14.6 Should one Party, for any reason, be unable to separately dispose all or

part of the Hydrocarbons to which it is entitled hereunder, or withdraw same

from the Joint Account tanks, the following stipulations shall apply:

14.6.1 lf ECOPETROL is the Party that is unable to fully or partially withdraw

its quota of Hydrocarbons (share plus royalty) pursuant to Clause 12 (numeral

12.3), Operator may continue producing the field and deliver to THE ASSOCIATE

not oniy the quota to which the latter is entitled based on a hundred percent

(100%) MER operation, but also all the Hydrocarbons that THE ASSOCIATE chooses

and is able to withdraw up to a limit of one hundred percent (100%) of the MER,

crediting ECOPETROL for subsequent delivery of the quota it did not withdraw.

However, regarding the volumes not taken that correspond royalties for the

month, ECOPETROL may ask THE ASSOCIATE to pay for the difference between the

Hydrocarbon volume withdrawn and the volumes corresponding to royalties as set

out in Clause 13.1 and 13.2, doing so in United States dollars. it is understood

that any Hydrocarbons withdrawn by ECOPETROL shall first be used for payment in

kind of the royalties, and thereafter, additional withdrawals will be credited



to its share as set out in Clause 14 (numeral 14.2).

14.6.2 lf THE ASSOCIATE is unable to fully or partially withdraw its quota under

Clause 12 (numeral 12.3), the Operator shall deliver ECOPETROL not only its

share based on a hundred percent (100%) MER operation, but all those

Hydrocarbons that ECOPETROL is able to receive up to a limit of one hundred

percent (100%) of the MER, crediting THE ASSOCIATE for subsequent delivery of

the quota which it was unable to withdraw.

14.7 When both Parties are able to receive the Hydrocarbons allocated under

Clause 12. (numeral 12.3), the Operator shall proceed as follows. When so

requested by the Party previously unable to receive its quota, it shall deliver

such Party its share in the operation plus at least ten percent (10%) a month of

the monthly production corresponding to the other Party and by mutual agreement

up to one hundred percent (100%) of the non-received quota, until such time when

the total amounts credited to the non-receiving party are offset.

14.8 Subject to legal provisions on this matter, each Party is free at all times

to sell or export is share of Hydrocarbons, in keeping with this contract, or to

dispose thereof in any way.

CLAUSE 15 - USE OF ASSOCIATE NATURAL GAS

When one or more fields with Associate Natural Gas are discovered, Operator

shall submit a project for using this gas for the benefit of the Joint Account,

this must be done within two (2) years following the starting date for field

exploitation as established by the Ministry of Mines and Energy. The Executive

Committee shali approve the project and establish a schedule for performance

thereof, lf Operator fails to submit a project within the two-year period, or

fails to perform same within the time limits established by the Executive

Committee, ECOPETROL may take all the Associate Natural Gas coming from the

Reservoirs being exploited and not needed for efficient field production,

without having to pay for same.

CLAUSE 16 - UNIFICATION

When an economically exploitable reservoir extends continuously into another

area or areas located outside the Contract Area, the Operator, ECOPETROL and

other interested parties should agree on a unified development program. Such

program should respect engineering techniques for Hydrocarbon production and be

approved by the Ministry of Mines and Energy.

CLAUSE 17 - INFORMATION SUPPLY AND INSPECTION DURING EXPLOITATION

17.1 The Operator shall give the Parties reproducible originals (sepias) and

copies of the electric, radioactive and sonic logs for the wells drilled,

histories, core analyses, cores, production tests, reservoir studies and other

pertinent technical data, as well as any routine reports made or received in

connection with the operations and activities carried out in the Contract Area,

doing so as these become available.

17.2 Each Party shall be entitled to inspect the wells and facilities in the

Contract Area and related activities, doing so at its own cost, expense and risk

and through authorized representatives. Such representatives shall have the

right to examine cores, samples, maps, drilling logs, surveys, books and any

other source of information connected with the performance of this contract.

17.3 Operator shall prepare all reports called for by the Colombian government

and hand them over to ECOPETROL so the latter may comply with the provisions of

Clause 29,

17.4 lnformation and data connected with exploitation operations shall be

treated as confidential, under the same terms as those of Clause 6 (numeral 6.3)

hereof.

CHAPTER IV - EXECUTIVE COMMITTEE

CLAUSE 18 - CONSTITUTION

18.1 Within thirty (30) days following acceptance of the first Commercial Field,

each Party should appoint a representative and his first and second alternates

to the Executive Committee, and notify the other Party in writing of the names

and addresses of such persons. The Parties may change the representative or

alternates at any time, but should so notify the other Party in writing. The

vote or decision of each Party representative is binding on said Party. lf the

main representative of either Party is unable to attend a Committee meeting, he

will be replaced by the first or second alternate, in that order, and such shall

have the same authority as the principal.

18.2 The Executive Committee will hold ordinary meetings in March, July and

November to review the development program being carried out by Operator, the

development plan and other immediate plans. In the July meeting every year, the

Operator shall submit an annual operating program and the investment and

expenditure Budget for the next calendar year.

18.3 The Parties and Operator may ask that special Executive Committee meetings

be convened to study specific operating conditions. The representative of the

interested party shall give ten (10) calendar days advance written notice of the

data and agenda for such meeting. The meeting may address any matter not

included in the agenda, provided the Party representatives agree.

18.4 For all matters discussed in the Executive Committee, the

representatives shall have a vote equal to the percentage held

party in the Joint Operation. Any decision or resolution taken

Committee will only be valid if approved by over fifty percent



Party

by the respective

by the Executive

(50%) of the



total lnterest. In keeping with the mentioned procedure, decisions taken by the

Executive Committee shall be compulsory and final for the Parties and for

Operator.

CLAUSE 19 - FUNCTIONS

19.1 The Party representatives shall constitute the Executive Committee which

has full authority and responsibility to establish and adopt production,

development and operations schedules and Budgets for this contract. Operator

shall send a representative to Executive Committee meetings.

19.2 The Executive Committee shall appoint a Secretary to keep complete and

detailed records and minutes of all matters discussed and decisions taken by the

Committee. Party representatives should sign and approve the Minutes within the

ten (10) business days following adjournment of the meeting, otherwise they will

not be valid. Minutes should be delivered to the Parties as soon as possible.

19.3



The Executive Committee has the following duties, among others-



19.3.1 Adopt its own regulations

19.3.2 Appoint the Operator in the event of resignation or removal, and issue

regulations to be met by Operator when such is a third party, setting out all

causes for removal.

19.3.3 Appoint an External Auditor for the Joint Account

19.3.4 Approve or reject the annual operations program and expenditure Budget,

any modification or revision thereof, and approve extraordinary expenses.

19.3.5 Establish expenditure policies and norms

19.3.6 Approve or reject expenditure recommended by Operator (not included in

the approved Budget) when such expenditure exceeds forty thousand dollars of the

United States of America (US$40,000) or the equivalent in Colombian currency.

19.3.7 Advise Operator and decide on matters referred to the Committee.

19.3.8 Create such sub-committees as it deems necessary, setting out their

duties which will be performed under the supervision of the Committee.

19.3.9 Define the type and frequency of drilling, operation and production

reports and any other information that Operator must furnish the Parties

chargeable to the Joint Account.

19.3.10 Supervise handling of the Joint Account

19.3.11 Authorize the Operator to enter into contracts on behalf of the Joint

Operation when the amount thereof exceeds forty thousand dollars of the United

States of America (US$40,000) or the equivalent in Colombian currency.

19.3.12 In general, assume all functions authorized hereunder and not assigned

to another entity or person through a specific clause hereof, or legal or

regulatory provision.

CLAUSE 20 - DECISION WHEN THERE IS DISAGREEMENT IN THE OPERATION

20.1 When the Party representatives cannot agree on a Joint Operation project

that requires approval from the Executive Committee, as set out hereunder, such

matter shall be referred directly to the highest ranking executive of each Party

who is resident in Colombia, in order that they may reach a joint decision. lf

the Parties reach an agreement or decision on the matter in question within

sixty (60) calendar days after such referral, they shall so notify the Executive

Committee Secretary who should call a meeting within the fifteen (15) calendar

days following receipt of the notice and committee members must ratify the

agreement or decision in said meeting.

20.2 lf the Parties fail to reach agreement within the sixty (60) calendar days

following the consultation, operations may go ahead pursuant to Clause 21.

CLAUSE 21 - SOLE RISK OPERATIONS

21.1 lf, at any time, one Party wishes to drill an Exploitation Well that has

not been approved in the operating schedule, it shall so notify the other Party

at least thirty (30) calendar days prior to the next meeting of the Executive

Committee, together with data on location, drilling recommendation, depth and

estimated costs. The Operator shall include this proposal in the Agenda for the

next committee meeting. lf the Committee approves the proposal, said well shall

be drilled for the Joint Account; otherwise the Party wishing to drill the well,

hereinafter the participating Party, shall be entitled to drill, complete,

produce or abandon such well at its own risk and for its account. The Party not

wishing to participate in the afore-mentioned operation shall be referred to as

nonparticipating Party. The participating Party should spud the well within one

hundred eighty (180) days following rejection by the Executive Committee. lf

drilling does not start within this period, it must be re-submitted to the

Executive Committee. When requested by the participating Party, Operator shall

drill the afore-mentioned well for the risk and account of said Party, provided

Operator considers that such operation will not interfere with normal Field

operations, and that it has received the sums it considers necessary from the

participating Party. lf Operator is unable to drill the mentioned well, the

participating Party may drill it directly or via a competent service company

and, in such case, the participating Party will be responsible for the

operation, without interfering in normal Field operations.

21.2 lf the well referred to in Clause 21 (numeral 21.1) is completed as a



producer, it shall be administered by Operator and its production, after

deducting the royalty referred to in Clause 13, will belong to the participating

Party. This Party will assume all operating costs for the well until net

production value, after deducting costs of production, gathering, storage,

transport and similar, and sales costs, reaches two hundred percent (200%) of

drilling and completion costs. Thereafter, and for all contract purposes, the

well shall belong to the Joint Account as if it had been drilled with the

approval of the Executive Committee and for the account of the Parties. For

purposes of this Clause, the value of each barrel of Hydrocarbon produced in the

well during a calendar month and prior to deducting the afore-mentioned costs,

shall be the average price per barrel received by the participating Party for

sales of its share of Hydrocarbons produced in the Contract Area during the same

month.

21.3 lf one Party at any time wishes to recondition or deepen a well to

Production Targets, or plug a dry hole or a non-commercial producer drilled for

the Joint Account, and such operations have not been included in the program

approved by the Executive Committee, such Party shall notify the other Party of

its intention to recondition, deepen or plug said well. lf equipment is not

available at the location, the procedure of Clause 21 (numerals 21.1 and 21.2)

shall apply. lf suitable equipment is available at the well site, the Party

wishing to carry out such operation shall notify the other Party which must

reply in a period of forty-eight (48) hours following receipt of such notice, if

no reply is received in this lapse, it shall be understood that the operation is

performed for the risk and account of the Joint Account. lf the proposed work is

performed for the sole risk and account of the participating Party, the well

shall be administered in keeping with Clause 21 (numeral 21.2).

21.4 lf, at any time, one Party wishes to build new facilities to extract liquid

from the gaseous hydrocarbons and to transport/export Hydrocarbon production,

these will be referred to as additional facilities and such Party shall notify

the other in writing as follows:

21.4.1 General description, design, specifications and estimated costs of the

additional facilities.

21.4.2 Planned capacity

21.4.3 Approximate date of construction start-up and duration thereof. Within

ninety (90) days counted from notification, the other Party shall give written

notice of its decision to participate in such additional facilities or not. lf

it does not participate, or fails to reply to the participating Party,

hereinafter the building Party, the latter may proceed with the additional

installation and order the Operator to buiid/operate/maintain same for the sole

risk and account of the building Party, without hindering normal Joint

Operations. The building Party may negotiate with the other Party on using these

facilities for the Joint Operation. While the facilities are operated for the

risk and account of the 'building Party, the Operator shall charge the latter

with all operating/maintenance costs therefor, doing so in keeping with

generally accepted accounting principles.

CHAPTER V - JOINT ACCOUNT

CLAUSE 22 - MANAGEMENT

22.1 Subject to other provisions set out herein, Exploration expenses shall be

for the risk and account of THE ASSOCIATE.

22.2 Once the Parties accept the existence of a Commercial Field, and subject to

the provisions of Clauses 5 (numerals 5.2) and 13 (numerals 13.1 and 13.2), the

rights or lnterest in Contract Area Operation shall be owned thus: ECOPETROL

fifty percent (50%) and THE ASSOCIATE fifty percent (50%). Thereafter, all

expenses, payments, investments, costs and liabilities made and contracted for

operations hereunder and Direct Exploration Costs made by the ASSOCIATE prior to

acceptance of each Commercial Field and extensions thereto, in keeping with

Clause 9 (numeral 9.10), shall be charged to the Joint Account. Except as set

out in Clauses 14 (numeral 14.3) and 21, all assets acquired or used thereafter

for operating the Commercial Field shall be owned and paid for by the Parties as

set out in this clause.

22.3 The Parties shall pay Operator their share of budget requirements, doing so

in the currency in which expenditure is to be disbursed, that is Colombian pesos

or United States dollars as called for by Operator in keeping with programs and

Budgets approved by the Executive Committee. This payment shall be made in the

first five (5) days of each month and at the bank chosen by Operator. When THE

ASSOCIATE lacks sufficient Colombian pesos to cover its pesos share, ECOPETROL

may supply these funds and have them credited to its dollar obligation, using

the market representative rate certified by the Banking Superintendency, or the

entity acting in this capacity, on the day that ECOPETROL should make the

respective payment, provided such transaction is legally acceptable.

22.4 The Operator shall give the Parties a monthly statement showing the funds

advanced, expenses incurred, outstanding liabilities and a report on all debits

and credits made to the Joint Account, this report should follow Appendix B

hereto. The statement and report should be submitted monthly within the fifteen

(1 5) calendar days following the end of each month. lf the payments mentioned

under Clause 22 (numeral 22.3) are not made within stipulated term and Operator

chooses to pay same, the delinquent Party shall pay commercial interest in the

same currency for the time of such delay.

22.5 lf one Party fails to pay the Joint Account on the due date, it shall be

considered thereafter as the delinquent Party and the other as the Prompt party.

lf the Prompt party were to pay both its own share and that of the delinquent

Party, after sixty (60) days of delay, it shall be shall be entitled to receive

from Operator the full share of the delinquent Party in the Contract Area

(excluding royalty percentage). This will continue until production provides the

prompt Party with a net income from sales equal to the sum not paid by the



delinquent Party, plus annual interest at the Commercial rate as of the sixtieth

(60) day following the delinquency date. Net income is understood as the

difference between the sales price of the Hydrocarbons taken by the prompt

Party, less the cost of transport, storage, loading and other reasonable

expenses disbursed by such Party in selling such production. The prompt Party

may exercise this right at any time after thirty (30) calendar days of having

notified the delinquent Party in writing of its intention to take part or all

such Party's production.

22.6.1 All Direct Expenses of the Joint Operation will be charged to the Parties

in the same proportion as for production distribution after royalties.

22.6.2 lndirect Expenses will be charged to the Parties in the same proportion

as for Direct Expenses set out in 22.6.1 hereof. These expenses shall be the

result of applying the equation a+m (X-b) to the total annual amount for

investment and direct expenditures (excluding technical and administrative

overhead).

Wherex is total annual investments and expenditures (pound)(a", "m", and "b" are

constants whose values are set out in the table hereunder depending on the

amount of annual investment and expenditures



1

2

3

4

5

6

7



INVESTMENTS AND EXPENDITURE

X

(US$)

0

25,000,000

25,000,001 50,000,000

50,000,001 100,000,000

100,000,001200,000,000

200,000,001300,000,000

300,000,001400,000,000

400,000,001onwards



- CONSTANT VALUES

"A"(US$)

M(FRACT) "B"$ (US$)

0

0.10

0

2,500,000

0.08

25,000,000

4,500,000

0.07

50,000,000

8,000,000

0.06

100,000,000

14,000,000

0.04

200,000,000

18,000,000

0.02

300,000,000

20,000,000

0.01

400,000,000



The equation will be applied once a year in each case, applying the constants

that correspond to the total sum of annual investments and expenditure.

22.7 Either Party may review or question the monthly statements of account

referred to in Clause 22 (numeral 22.4) from the time they are received up to

two years following the end of the respective calendar year, clearly indicating

the corrected or questioned items and the reasons therefor. Any account that has

not been corrected or questioned in this period, shall be considered as final

and correct.

22.8 The Operator shall keep accounting books, vouchers and reports for the

Joint Account, in Colombian pesos and according to Colombian law. Any credit or

debit to the Joint Account shall follow the accounting procedure set out in

Appendix B which is a part hereof. In the event of any discrepancy between said

accounting procedure and the terms of the contract, the latter shall prevail.

22.9 Operator may sell material or equipment during the first twenty (20) years

of the Exploitation Period, or the first twenty eight (28) years in the case of

a Gas Field, crediting the proceeds to the Joint Account when the amount does

not exceed five thousand dollars of the United States of America (US$5,000) or

the equivalent in Colombian currency. In any calendar year, operations of this

type may not exceed fifty thousand dollars of the United States of America

(US$50,000) or the equivalent in Colombian currency. The Executive Committee

must approve sales of real estate or those exceeding the afore-mentioned

amounts. These materials or equipment shall be sold at a reasonable price

considering their condition.

22.10 All machinery, equipment or other assets or chattels purchased by Operator

for contract performance and charged to the Joint Account shall belong to the

Parties in equal shares. However, if one Party decides to terminate its interest

in the contract during the first seventeen (17) years of the Exploitation

Period, except as set out in Clause 25th, said Party must sell all or part of

its share in said items to the other Party at a reasonable commercial price or

at book value, whichever is lower. lf the other Party is not interested in

purchasing them within ninety (90) days following the formal sales offer, the

Withdrawing Party shall be entitled to assign its interest in said machinery,

equipment, and items to a third party. lf THE ASSOCIATE wishes to withdraw after

seventeen (17) years of the Production Period have elapsed, its rights in the

Joint Operation shall pass to ECOPETROL free of charge, once the latter has

accepted.

CHAPTER VI - CONTRACT DURATION

CLAUSE 23 - MAXIMUM DURATION

This contract shall last for a maximum period of twenty eight (28) years running

from the Effective Date and broken down thus- up to six (6) years for the

Exploration Period in keeping with Clause 5 and subject to Clause 9 (numerals

9.3 and 9.8); and twenty-two years for the Exploitation Period counted from the

termination date of the Exploration Period. it is understood that when the

Exploration Period is extended as provided for in this contract, this shall

never signify an extension to the total twenty-eight (28) year term, except as

stipulated in paragraph 1 hereunder.

PARAGRAPH 1: The Exploitation Period for Gas Fields discovered in the Contract

Area shall have a maximum duration of thirty (30) years counted from the expiry

date of the Exploration Period, or of the Retention Period. In any case, the

total contract term for such Fields cannot exceed forty (40) years counted from

the Effective Date.

PARAGRAPH 2: Notwithstanding the above, at least five (5) years prior to the

expiry of the Exploitation Period for each Field, ECOPETROL and THE ASSOCIATE

will study conditions for continuing exploitation beyond the term stipulated in

this Clause. lf the Parties agree to continue with such exploitation, they will



define the terms and conditions therefor.

CLAUSE 24 - TERMINATION

This contract shall terminate in the following cases-.

24.1 Upon expiry of the Exploration Period if THE ASSOCIATE has not discovered a

Commercial Field, except as set out in Clauses 9 (numerals 9.5 and 9.8) and 34.

24.2 Upon expiry of contract duration, as stipulated in Clause 23.

24.3 At any date when THE ASSOCIATE so -wishes and provided it has met its

obligations stipulated in Clause 5th, and al,l others contracted hereunder.

24.4 For the special causes set out in Clause 25th.

CLAUSE 25 - CAUSES FOR UNILATERAL TERMINATION

25.1 ECOPETROL may unilaterally declare this contract terminated at any time

prior to expiry of the period agreed to in Clause 23, in the following cases.

25.1.1 Death or dissolution of THE ASSOCIATE or its assignees.

25.1.2 lf THE ASSOCIATE or its assignees were to transfer this contract,

partially, without giving compliance to the provisions of Clause 27.

25.1.3 For financial incapacity of THE ASSOCIATE and its assignees which shall

be assumed when bankruptcy proceedings are filed.

25.1,4 When THE ASSOCIATE defaults on its obligations contracted under this

contract.

Upon expiry of each period defined for exploratory work, THE ASSOCIATE shall

submit a written report showing performance of the obligations for the

respective period. lf such have not been performed, THE ASSOCIATE shall be given

sixty (60) calendar days to diligently perform same in keeping with good

petroleum practices. lf such period is insufficient, the Parties may mutually

agree to establish a longer period for performance. lf the agreed work has still

not been performed at the end of this new extension, there will be default and

consequently ECOPETROL may proceed as set out in clause 25.3.

25.2 When unilateral termination is declared, the rights of THE ASSOCIATE set

out in this contract will lapse, both as interested Party and as Operator, if at

such time the ASSOCIATE is acting in both capacities.

25.3 ECOPETROL may oniy declare unilateral termination of this contract when it

has given the ASSOCIATE or its assignees sixty (60) calendar days advance

written notice thereof, clearing stating the reasons for such decision, and when

THE ASSOCIATE has failed to provide ECOPETROL with satisfactory explanations or

to correct the default in contract performance. This does prevent THE ASSOCIATE

from filing any appeal it considers to be in order.

CLAUSE 26 - OBLIGATIONS IN EVENT OF TERMINATION

26.1 When the contract is terminated under Clause 24th during the Exploration,

Retention or Exploitation Periods, THE ASSOCIATE shall hand over the buildings,

pipelines, transfer lines and other movable items belonging to the Joint Account

(located in the Contract Area), leaving any producing wells in production, and

all of this will pass to ECOPETROL free-of-charge together with the

rights-of-way and assets acquired for the contract, even though these may be

located outside the Contract Area.

26.2 lf this contract is terminated for any reason after the first seventeen

(17) years of the Production Period, all interest of THE ASSOCIATE in the

machinery, equipment or other assets or movables used or purchased by THE

ASSOCIATE or the OPERATOR for contract performance, shall pass to ECOPETROL

free-of-charge.

26.3 lf this contract terminates in the first seventeen (17) years of the

Exploitation Period, the terms of Clause 22 (numeral 22. 1 0) shall apply.

26.4 lf this contract is terminated unilaterally at any time, all chattels and

real estate acquired exclusively for the Joint Account shall pass to ECOPETROL

free of charge.

26.5 Upon contract termination at any time and for any reason, the Parties

commit to give satisfactory compliance to their legal obligations both among

themselves and with third parties, as well as those contracted hereunder.

CHAPTER VII - MISCELLANEOUS PROVISIONS

CLAUSE 27 - ASSIGNMENT RIGHTS

27.1 THE ASSOCIATE is entitled to fully or partially cede or transfer its

rights, interests, and obligations in the Association Contract to another

person, company or group, with the consent of the Minister of Mines & Energy and

the President of ECOPETROL.

Consequently, THE ASSOCIATE must notify the Ministry of Mines & Energy and the

President of ECOPETROL via a certified document of any project that implies

total/partial assignment or transfer of its interest, rights and obligations

hereunder, indicating essential points of the transaction such as possible

assignee, price, interest, rights and obligations to be assigned, scope of the

operation etc. The Minister of Mines & Energy and President of the Empresa



Colombiana de Petroleos - ECOPETROL shall have thirty (30) business days to

exercise their discretionary powers and appraise the possible assignees, and

subsequently take a decision without being obliged to give reasons therefor. In

any case, the criterion of the Minister of Mines & Energy shall prevail.

27.2 lf the ASSOCIATE has not received a reply thirty (30) business after

submitting the application to the Minister of Mines & Energy, it will be

understood for all purposes that such has been approved.

27.3 Assignments made during the Exploration Period among companies legally

established in Colombia shall not be subject to the above mentioned procedure,

they shall be formalized by written authorization from ECOPETROL and signing the

respective document.

27.4 Any change in the contractual relations between THE ASSOCIATE and ECOPETROL

resulting from direct, total or partial transactions of the interest, quotas or

stock of the former must also be approved by the Minister of Mines and Energy

and President of ECOPETROL.

27.5 However, such changes shall not require authorization from the Minister of

Mines and Energy and Ecopetrol in the following cases:

27.5.1



When the transactions are made in an open stock exchange.



27.5.2 When the transfer/cession is the result of matters beyond the control of

the ASSOCIATE or the companies that control or direct same, such as governmental

decisions, judicial sentences, division and award of assets and auctions.

When the negotiations take place between companies that control or direct THE

ASSOCIATE, or their subsidiaries or affiliates, or between companies making up a

single economic group, it suffices to notify the Minister of Mines & Energy and

ECOPETROL of such assignment or cession in a timely way.

27.6 Except for the above cases, any cession, transfer, negotiation, transaction

or operation referred to in this Clause that is made without approval or consent

of the Minister of Mines & Energy and the President of ECOPETROL, when calied

for, shali give rise to the application of Clause 25th of the Association

Contract.

27.7 lf the operations carried out under this Clause give rise to taxes under

Colombian law, such shall be paid.

CLAUSE 28 - DISAGREEMENT

28.1 Whenever there is a discrepancy or contradiction in interpreting the

clauses hereunder as compared to those of Appendix B known as the Operating

Agreement, the former shall prevail.

28.2 Disagreements of a legal nature arising among the Parties with regard to

contract interpretation and performance and that cannot be resolved in a

friendly way, shall be referred to the decision of the jurisdictional branch of

Colombian public power.

28.3 Any difference of a technical nature arising among the parties with regard

to contract interpretation and performance and that cannot be resolved in a

friendly way shall be referred to the final decision of experts appointed thusone by each Party and a third chosen by the first two. lf the latter are unable

to reach agreement on such third expert, either Party may ask the Board of

Directors of the Colombian Society of Engineers - SCI - having its head office

in Santafe de Bogota to appoint same.

28.4 Any difference of an accounting nature arising among the parties with

regard to contract interpretation and performance and that cannot be resolved in

a friendiy way shali be referred to the final decision of experts who shouid be

public accountants appointed thus: one by each Party and a third chosen by the

first two. lf the latter are unable to reach agreement on such third expert,

either Party may ask the Central Board of Accountants of Bogota to appoint same.

28.5 Both Parties declare that the decision of the experts shall have the force

of a settlement among themselves, and consequently shall be final.

28.6 lf the Parties fail to agree on whether the controversy is of a legal,

technical or accounting nature, such shall be considered legal and subject to

Clause 28th (numeral 28.2).

CLAUSE 29 - LEGAL REPRESENTATION

Without impairing the legal rights of the ASSOCIATE as set out in law or in this

Contract, ECOPETROL shall represent the Parties Wth Colombian authorities in

matters regarding the development of the Contract Area, whenever such is called

for, furnishing government offices and entities with all information and reports

they may legally require. Operator must prepare the respective reports and hand

them over to ECOPETROL. Any expenses incurred by ECOPETROL to attend matters

referred to in this Clause shall be charged to the Joint Account. When such

expenses exceed five thousand dollars of the United States of America (US$5,000)

or the equivalent in Colombian currency, the Operator must first approve same.

Regarding any relations with third parties, the Parties represent that neither

the provisions of this or any other Clause in the contract, implies granting a

general power-of-attorney, nor that the Parties have set up a civil or

commercial association or any other relationship whereby either Party may be

held jointly liable for the acts or failure to act of the other Party, or have

authority or mandate to commit the other Party with regard to any obligation.

This contract refers to operations within the Republic of Colombia and while

ECOPETROL is an industrial and commercial company belonging to the Colombian

State, the Parties agree that THE ASSOCIATE, if such were the case, may choose

to be excluded from the provisions of sub-chapter K entitled Partners and

Partnerships of the Internal lncome Code of the United States of America. The



ASSOCIATE may make such choice in a suitable way.

CLAUSE 30 - RESPONSIBILITIES

30.1 The Operator shall perform operations hereunder in a manner that is

difigent, responsible, efficient, economically and technically sound and in

keeping with internationally accepted industry practices for this type of

operation, it being understood that at no time shall it be liable for errors of

judgment, or loss or damage that is not directly attributable to it.

30.2 Liabilities contracted by ECOPETROL and THE ASSOCIATE hereunder with third

parties shall not be joint, therefore each Party is individually liable for its

share in the expenses, investments and obligations resulting therefrom.

30.3 Operator alone shall be liable with third parties for expenses incurred and

contracts entered into for amounts exceeding forty thousand United States

dollars (US$40,000) or the equivalent in Colombian currency when such have not

been duiy authorized by the Executive Committee, except as ruled in Clause 1 1

(numeral 11.7) and therefore it shall assume the full cost thereof. When the

Executive Committee accepts such expenditure, it will pay Operator for the work,

study or purchase in keeping with the guidelines it has set out in this respect.

lf the Executive Committee rejects the expense or asset, Operator if possible

should withdraw same and reimburse the partners for any expense incurred in such

withdrawal. When Operator is unable or refuses to withdraw the assets, the

resulting equity increase or profit from such expenditure or contract shall

belong to the Parties in proportion to their share in the Operation.

30.4 ECOLOGICAL CONTROL. In performing work hereunder, THE ASSOCIATE should

comply with the provisions of the National Code for Renewable Natural Resources

and Environmental Protection and other legal provisions on this matter. THE

ASSOCIATE undertakes to carry out a permanent prevention plan to guarantee

conservation and restoration of natural resources within the zones where it

carries out Exploration, development and transport hereunder.

THE ASSOCIATE should make these plans and programs known to the communities and

to national and regional entities involved in this matter. Likewise, specific

contingency plans should be established to deal with emergencies and take

pertinent remedial action. To this end, THE ASSOCIATE should coordinate plans

and action with the authorized entities.

THE ASSOCIATE must prepare the respective Budgets and programs as set out in the

pertinent clauses of this contract.

All costs incurred shall be assumed by THE ASSOCIATE in the Exploration Period

and in sole risk operations during the Exploitation Period. During the

Exploitation Period these costs will be charged to the Joint Account and shared

by both Parties.

CLAUSE 31 - TAXES, LEVIES AND OTHERS

Taxes and levies related to Hydrocarbon production, caused after the Joint

Account has been set up but before the Parties receive their production share,

shall be charged to the Joint Account. Each Party shall be exclusively liable

for its own taxes on income, capital and similar.

CLAUSE 32 - PERSONAL

32.1 When THE ASSOCIATE is Operator, it should consult ECOPETROL before

appointing the Manager for Operator.

32.2 According to the terms hereof, and subject to norms to be established,

Operator shall be free to appoint the personnel needed for operations hereunder,

and may fix salary, duties, categories and conditions thereof. Operator shall be

diligent in training Colombian personnel needed to replace the foreign personnel

that it considers necessary for operations hereunder. In any case, Operator

shall comply with legal provisions on the proportion of local and foreign

personnel.

32.3 TRANSFER OF TECHNOLOGY- THE ASSOCIATE commits to assume the cost of a

program to train ECOPETROL professionals in areas related to contract

performance.

In the Exploration Period, this obligation could be met by training in: geology,

geophysics and related areas, reserve appraisal, reservoir characterization,

drilling and production, among others. Supervised training should take place

throughout the initial exploration period and its extension by integrating the

ECOPETROL professionals to the work group THE ASSOCIATE sets up for either the

Contract Area or other similar activities.

lf THE ASSOCIATE wishes to resign as set out in Clause 5, it must have first

given compliance to these training programs.

The Association Executive Committee shall establish the scope, duration, place,

participants, conditions and other aspects of training during the Exploitation

Period.

THE ASSOCIATE shall assume all costs of supervised training during the

Exploration Period, except for labor costs of the professionals attending same.

During the Exploitation Period both parties shall assume these costs via the

Joint Account.

To comply With Technology Transfer called for hereunder, THE

ASSOCIATE commits to run annual supervised training programs for Ecopetrol

professionals for each of the first three years of the Exploration Period, in an

amount of fifty thousand (US$50,000) United States dollars per year. ECOPETROL

and THE ASSOCIATE shall first agree on the subject and type of training. lf the

Exploration Period is extended, the supervised training will be similar to that



set out here.

32.4 During the Exploitation Period, Operator may perform any work through

contractors, subject to the Executive Committee approval when the amount of the

contract exceeds forty thousand dollars of the United States of America

(US$40,000) or the equivalent in Colombian currency.

CLAUSE 33 - INSURANCE

The Operator shall take all insurance called for under Colombia law. Likewise,

it shall require any contractor engaged in work hereunder to obtain such

insurance as the Operator considers necessary and keep same in force. Likewise,

Operator shall take such additional insurance as the Executive Committee deems

suitable.

CLAUSE 34 - FORCE MAJEURE OR FORTUITOUS CIRCUMSTANCES

The obligations referred to hereunder shall be suspended for such time as either

Party is unable to fully or partially perform same because of unforeseen events

that constitute force majeure or fortuitous circumstances, such as strikes,

shutouts, wars, earthquakes, floods or other catastrophes, laws, decrees or

government regulations that prevent procurement of essential materials and, in

general, any non-financial reason that effectively impedes work, even when not

listed above, but that affects the Parties and is outside their control. lf

force majeure or fortuitous circumstances prevent one Party from performing its

duties hereunder, it should immediately notify the other Party, setting out the

causes of such impediment. Under no circumstances shall force majeure or

fortuitous circumstances extend or prolong the total period of exploration,

retention or exploitation beyond maximum contract term set out in Clause 23rd.

However, any force majeure event during the six (6) year exploration period set

out in Clause 5 and which lasts for over thirty consecutive days, shall extend

this six-year (6) period for the same time as that of the impediment.

CLAUSE 35 - APPLICATION OF COLOMBIAN LAW

The Parties establish Santa Fe de Bogota, Republic of Colombia, as the domicile

for all contract purposes. This contract is fully ruled by Colombian law and THE

ASSOCIATE accepts the jurisdiction of Colombian courts and waives diplomatic

claim regarding its rights and duties hereunder, except in the case of denial of

justice. it is understood there shall not be denial of justice when THE

ASSOCIATE as Party or Operator has had access to all remedies and means of

action that may be exercised with the jurisdictional branch of public power

under Colombian law.

CLAUSE 36 - NOTICES

Notices or communications among the Parties regarding this contract must be sent

to the following addresses and mention the pertinent clauses in order to be

considered valid-.

ECOPETROL - Carrera 13 No. 36-24, Santafe de Bogota, Colombia

THE ASSOCIATE - Calle 114 No. 9-01 Torre A, of.707,Santafe

Colombia



de



Bogota,



Any change of address shall be notified to the other Party in advance.

CLAUSE 37 - VALUATION OF HYDROCARBONS

Payments or reimbursements referred to in Clauses 9 (numerals 9.2 and 9.4) and

22 (numeral 22.5) shall be made in dollars of the United States of America or in

Hydrocarbons, based on the price in force and the restrictions existing or to be

applied under Colombian law for sale of the dollar portion of hydrocarbons

coming from the contract area and destined for domestic refining.

CLAUSE 38 - HYDROCARBON PRICES

38.1 Hydrocarbons belonging to the ASSOCIATE hereunder and destined for domestic

refining or supply shall be paid for at the refinery where they are to be

processed or at the receiving station agreed to by the Parties, in keeping with

current governmental measures or those replacing same.

38.2 Differences arising in the application of this Clause shall be settled via

the means set out in this Contract.

CLAUSE 40 - DELEGATION AND ADMINISTRATION

In keeping with ECOPETROL regulations, its President delegates the

administration of this contract to the Vice President for Exploration and

Production, with power to take all action pertinent to contract performance. The

Vice-President of Exploration and Production may exercise this delegation via

the Assistant Vice President for Joint Operations.

CLAUSE 41 - VALIDITY

This contract must be approved by the Ministry of Mines & Energy in order to be

valid (and the incorporation and approval of the Colombian branch, if pertinent.

In witness whereof, the parties sin in the presence of witnesses in Santa Fe de

Bogota, on the 30th day of the month of December,nineteen hundred and ninety

seven (1997)

EMPRESA COLOMBIANA DE PETROLEOS

ECOPETROL

ENRIQUE AMOROCHO CORTEZ

President



SEVEN SEAS PETROLUEM COLOMBIA INC.

Gustavo Vasco Munoz

Legal Representative

Witnesses

EMPRESA COLOMBIANA DE PETROLEOS

Calculation of area, director and distances using Gauss coordinates, origin

Santafe de Bogota.

Data and results of MONTECRISTO sector

<TABLE>

<CAPTION>

POINT NORTH

EAST

DISTANCE

DIF. N.

DIF. E

DIRECTION

<S> <C>

<C>

<C>

<C>

<C>

A

1,402900.00 1,020,000.00

6,410.00

0.0

6,410.00

East

B

1,402,900.00 1,026,410.00

2,790.00

0.0

2,790.00

East

C

1,402,900.00 1,029,200.00

27,200.00

-27,200.00 0.00

South

D

1,375,700.00 1,029,200.00

23,120.00

0.00

23,120.00

East

E

1,375,700.00 1,052,320.00

4,088.76

- 4,012.22 787.44

S 1 1.6'1 3' 0.551 E

F

1,371,687.78 1,053,107.44

14,183.60

114,132.11 - 1,207.44

S 4 53, 0" 0.460 W

G

1,357,555.67 1,051,900.00

5,867.32

0.00

- 5,867.32

West

H

1,357,555.67 1,046,032.68

8,027.36

- 6,555.67 - 4,632.68

S35 14, 51- 0.407w

I

1,351,000.00 1,041,400.00

4,900.00

-4,900.00

0.00

South

J

1,346,100.00 1,041,400.00

8,094.01

-12.00

8,094.00

S 89,54'54' 0.196E

K

1,346,088.00 1,049,494.00

19,274.23

14,640.00

-12,536.60

S40 34'27" 0.390 W

L

1,331,448.00 1,036,957.40

2,096.62

- 1,878.98 - 930.20

S26 20'16'.0.725E

M

1,329,569.02 1,037,887.60

20,887.60

0.04

-20,887.60

N89 59'59" 0.605 W

N

1,329,569.06 1,017,000.00

15,030.94

15,030.94

0.00

North

O

1,344,600.00 1,017,000.00

3,000.00

0.00

3,00

0.00 East

P

1,344,600.00 1,020,000.00

- W,300.00

58,300.00

0.00

North

A

1,402,900.00 1,020,000.00

</TABLE>

POLYGONAL AREA: 151,933 HECTARES, 5,950 M2

<PAGE>

CONTENTS

Page

PART I - TECHNICAL ASPECTS

Section One - Exploration

1

CLAUSE 1



INFORMATION TO BE SUPPLIED DURING EXPLORATION



1



CLAUSE 2



AREAS DEVOLUTION



4



Section Two - Production



1



CLAUSE 3



EXTENSIVE PRODUCTION TESTS



5



CLAUSE 4



COMMERCIAL FIELD



6



CLAUSE 5



OWN RISK MODALITY



6



CLAUSE 6



OPERATIONS INSPECTION



7



CLAUSE 7



PRODUCTION



7



CLAUSE 8



HYDROCARBON DISTRIBUTION AND AVAILABILITY



7



CLAUSE 9



EXPORT HYDROCARBON SUPPLY



8



PART II - ACCOUNTING AND FINANCIAL ASPECTS

Section One - Programs and Budgets



8



CLAUSE 10



EXPLORATION PROGRAMS AND BUDGETS



8



CLAUSE 11



PRODUCTION PROGRAMS AND BUDGETS



8



CLAUSE 12



BUDGET MANUAL



8



CLAUSE 13



INCOME BUDGET



9



CLAUSE 14



EXPENSES BUDGET



10



CLAUSE 15



OTHER PROVISIONS



17



Section Two . Accounting procedures



17



CLAUSE 16



ACCOUNTING PROCEDURE



20



CLAUSE 17



CASH CALLS, BILLS AND ADJUSTMENTS



21



CLAUSE 18



CHARGES



23



CLAUSE 19



CREDITS



27



CLAUSE 20



DISPOSAL OF EXCESS MATERIAL AND EQUIPMENT



28



CLAUSE 21



INVENTORY



28



CLAUSE 22



AUDIT



30



CLAUSE 23



FEES TABLE



30



CLAUSE 24

CONTRIBUTIONS IN KIND

PART III - ADMINISTRATIVE ASPECTS AND SUNDRY PROVISIONS

Section One - The Executive Committee



32

32



<C>



CLAUSE 25

OPERATING CONDITIONS

Section Two - Subcommittees



32



CLAUSE 26

SUBCOMMITTEES ORGANIZATION

Section Three - Operator



33



CLAUSE 27



34



RIGHTS AND OBLIGATIONS



Section Four - Contracting Procedures



35



CLAUSE 28



SUPPLIERS REGISTER AND LIST OF PROPONENTS



35



CLAUSE 29



TENDER PROCEDURES



35



CLAUSE 30



CONTRACT AWARD AND PURCHASE ORDERS



37



CLAUSE 31



CONTRACTS AND PURCHASE ORDERS MANAGEMENT



39



CLAUSE 32



INSURANCE



40



CLAUSE 33



FORCE MAJEURE OR ACTS OF GOD



40



CLAUSE 34

OPERATION AGREEMENT REVISION

<PAGE>

EXHIBIT B TO THE OPERATION AGREEMENT

ASSOCIATION CONTRACT "MONECRISTO" SECTOR



41



EXHIBIT B - OPERATION AGREEMENT

EXHIBIT TO "MONTECRISTO" ASSOCIATION CONTRACT

Entered into between EMPRESA COLOMBIANA DE PETROLEOS ECOPETROL and SEVEN SEAS

PETROLEUM COLOMBIA INC., with Effective Date on the 28th day of the month of

February, nineteen hundred ninety-eight (1998), hereinafter the Contract.

PART I- TECHNICAL FACTORS.

CLAUSE 1 - INFORMATION SUPPLY DURING EXPLORATION

Geological and geophysical information to be supplied by the ASSOCIATE to

ECOPETROL shall be provided according to international standards accepted by the

industry, compatible with standards applied by ECOPETROL (included in ECOPETROL

Information Supply Manual) to enable regional sedimentary basins evaluation. To

complement Contract Clause 6 (section 6.2) the ASSOCIATE or the Operator shall

deliver to ECOPETROL, as obtained, the following information associated to

exploration activities conducted by the ASSOCIATE:

1.1 Geological, geophysical, magnetometric, gravimetric, remote sensors,

electric meters information and in general any Exploration Work conducted by the

ASSOCIATE in development of the Contract, shall be submitted in magnetic media,

original and reproducible copy with the respective support information,

including acquisition and interpretation maps, acquired data processing and

interpretation.

1.2 Processed seismic section for each line, obtained in two scales, together

with an interpretation report containing: information used, background, seismic

programs, geological information and geophysical, geological and economic

considerations supporting technical conclusions and recommendations.

1.3 Two (2) sets of seismic lines magnetic tapes, one of them containing

demultiplexed information and the other containing stack information and the

respective support information and processing report. In the event of vibration

a copy of the field tape instead of demultiplexed tape shall be delivered.

1.4 Seismic programs shooting points map in reproducible sepia and copy,

containing coordinates and elevations identification. This information shall

also be supplied in magnetic tape.

1.5 Magnetic and gravimetric profiles and residual maps in reproducible

originals, copies and magnetic tapes including all information generated.

1.6 Seismic, gravimetric and magnetometric interpretation report, together with

all interpreted sections profiles and maps submitted in accordance with

ECOPETROL standards for this type of information.

1.7 Geological, structural, isopachous, isolitic, facies, seismic, etc. maps of

the Contract Area in reproducible sepia and copies in scales determined by

ECOPETROL for each basin.

1.8 Before well drilling: Intention to drill (Ministry of Mines and Energy Form

4-CR), drilling program, well location map, prospect area isochrone or

structural map and drilling geological prognosis, duly approved by the Ministry

of Mines and Energy. Exploration wells location shall be referred to the seismic

maps on which basis the prospect was defined. At each Exploration Well to be

drilled in the Contract Area, a geodesic precision point accepted by "Instituto

Geografico Agustin Codazzi - IGAC", obtained by satellite shall be materialized

with its respective azimuth line.

1.9 Daily drilling and geology reports. These reports shall be directly

delivered to ECOPETROL, preferably via fax and shall contain basic well

information, drilling conditions, drilling fluid properties, Hydrocarbon

expressions as obtained, penetrated geological formations description and daily

and accumulated costs together with the program to be developed.

The ASSOCIATE or the Operator shall report sufficiently in advance to ECOPETROL

on electric logging, cores sampling and test to be performed for ECOPETROL to



send a representative to witness all operations.

1.10 Copy of bi-weekly reports forwarded to the Ministry of Mines and Energy

(Form 5CR).

1.11 Final geology report: This report is mandatory for any well drilled in the

country, whether exploration, stratigraphic or development and shall be

submitted in Spanish by a registered geologist no later than ninety (90) days

after well completion or abandonment; the report shall include the following

information by chapters;

1.11.1 A summary of all activities developed during drilling

1.11.2 Well location and 1:250,000 scale maps

1.11.3 Stratigrapy: Shall include the stratigraphic column, environments

determination and each drilled formation age.

1.11.4 Biosratigraphy: shall include dispersion charts, analysis conducted and

potential correlation.

1.11.5 Geochemistry: shall include all analysis performed both on ditch samples

and each of the recovered cores.

1.11.6 Electric logging: shall include all RW, SW determination calculations.

Speed logging analysis shall be included in this chapter.

1.11.7 Formation tests: shall include all results obtained from each of the

tests taken and water and Hydrocarbon laboratory analysis.

1.11.8 The Final Geological Report shall be accompanied of the following

exhibits:

Exhibit A: Description of ditch samples taken every ten (10) feet.

Exhibit B: Detailed description of cores and wall samples recovered.

Exhibit C: All cores and wall samples lab analysis.

Exhibit D: Composed graphic log in reproducible sepia and copy in 1:500 scale.

For the different lithologies included in the composed graph log symbols used

for such cases by the American Association of Petroleum Geologists (AAPG) shall

be used.

Exhibit E: Final report issued by the well logging company, including the

"Grapholog".

1.12 Reproducible sepias and copies of each well logs including speed logging in

1:200 and 1:500 scales. Additionally deliver magnetic tapes in LIS format

containing all logs, accompanied of computer tabulates using forms provided by

ECOPETROL for such cases.

1.13 Formation and/or production tests report including bottom pressure analysis

(open and closed well).

1.14 Shall deliver to ECOPETROL two sets of ditch samples, one of them unwashed

taken every thirty (30) feet and the other dry taken every ten (10) feet

including a detailed lithological samples description.

1.15 Coring report, when performed, including a detailed description thereof and

all analysis performed. Together with this report the ASSOCIATE shall deliver to

ECOPETROL photographs and fifty percent (50%) core.

1.16 Report all materials used for drilling.

1.17 Biostratigraphic reports including the respective dispersion chart. These

analyses shall be performed for Exploration wells considering this information

defines sedimentation environments and each drilled formation age. This type of

analyses may also be performed on the different cores recovered.

1.18 Geochemical ditch, wall and core samples analysis.

1.19 Official well completion, plugging or abandonment report (form 6CR or 10A

CR) and in general, any other report referring to well completion (subsequent

work, multiple completion).

1.20 Final well report. Shall include all engineering information and a final

geologic report summary. Shall be submitted in Spanish no later than ninety (90)

days after well completion or abandonment, and approved by a duly registered

Petroleum engineer.

1.21 Copy of the Annual Technical report (Geology and Geophysics and Engineering

Report) including the respective supports, submitted to the Ministry of Mines

and Energy according to applicable legal regulations.

1.22 Any other engineering or geology study conducted.

CLAUSE 2 - AREAS DEVOLUTION

Areas to be returned to ECOPETROL by the ASSOCIATE, according to Contract Clause

8, shall be, as far as possible, regular polygonal lots to facilitate boundaries

determination without prejudice of commercial areas.

Section Two - Production

CLAUSE 3 - EXTENSIVE PRODUCTION TESTS



The following will be the procedures applied to extensive Hydrocarbon production

tests management previous Commercial Field acceptance.

3.1 For obtained volumes management and handling, tests permit shall have been

obtained from the Ministry of Mines and Energy and accepted by ECOPETROL.

3.2 Production obtained from tests will be distributed according to proportions

provided under the Contract Clause 14 (section 14.2), after discounting twenty

percent (20%) royalties, according to Contract Clause 13; ECOPETROL will be

responsible of direct payment thereof.

3.3 Test volumes produced will be recovered from the well during the maximum

test period approved by the Ministry of Mines and Energy under the respective

permit, discounting any Hydrocarbon volume consumed for operations.

3.4 The ASSOCIATE will be responsible of one hundred percent (100%) expenses

incurred during the production test period, which shall be charged as higher

well value and taken as direct cost for reimbursement purposes, according to

disbursement origin.

3.5 The ASSOCIATE shall enter into the necessary agreements with the transport

to provide Hydrocarbon transportation. Hydrocarbon ECOPETROL is entitled to plus

royalties transportation will be paid by ECOPETROL after receiving the

respective bills and supports.

3.6 ECOPETROL shall have advanced knowledge of the Hydrocarbon transportation

contract and shall approve it before extensive production tests start.

3.7 The ASSOCIATE shall maintain ECOPETROL duly informed about the production

test program and shall deliver any permits required from government authorities,

as well as any other information as obtained.

3.8 In the event Hydrocarbon is used for reimbursement, bills shall be submitted

each month from well production start.

CLAUSE 4 - COMMERCIAL FIELD

4.1 After the ASSOCIATE has obtained sufficient information related to Field

development, the ASSOCIATE shall conduct a study to define petrophysical

parameters, better productive area boundaries and reserves calculation. The

study shall be conducted by the ASSOCIATE, at its expense, applying available

technical methods in the country or abroad; and when the circumstances so

require the pertinent revisions shall be made.

4.2 For new facilities or expansions/modifications, basic production and

detailed engineering design shall be submitted to the Technical Subcommittee for

consideration.

4.3 Production facilities engineering shall be contracted with domestic

companies except if in the opinion of the Technical Subcommittee technological

complexity requires assistance from a foreign company, preferably in consortium

with a domestic company.

4.4 Final mechanical completion of wells to become Joint Account property shall

be agreed by the Technical Subcommittee. Such Exploration Wells Reimbursement

will be subject to Contract Clause 9 (sections 9.2.2, 9.2.3 and 9.2.4).

4.5 Regarding dry Exploration Wells, the ASSOCIATE shall abandon subject to

applicable legal and environmental regulations.

CLAUSE 5 - OWN RISK MODALITY

5.1 Reimbursement refers to two hundred percent (200%) total work developed at

the ASSOCIATE's own expense and risk to produce the respective Field and up to

fifty percent (50%) Direct Exploration Costs incurred by the ASSOCIATE at its

own expense and risk within the Contract Area before the respective Field

commercial feasibility studies submittal date. ECOPETROL shall audit to

determine reimbursable investments.

5.2 During the Own Risk Field production, the ASSOCIATE shall deliver to

ECOPETROL a quarterly report including all technical, economic, legal and

administrative information such as contracts entered into, wells completion,

flow lines, production facilities, metering systems, storage capacity,

production wells, restriction orifices, production reports, economic studies,

etc. Different Contract Clause and clarifications herein are understood fully

applicable in the event of Contract Clause 21 "One of the Parties Own Risk

Operations" for timely information, technical reserves control and all other

administrative activities purposes.

CLAUSE 6 - OPERATIONS INSPECTION

Regarding activities developed in the Contract Area inspection and audit,

ECOPETROL will have the right to send its representatives to the field. The

ASSOCIATE or the Operator shall provide the officer designated by ECOPETROL stay

conditions similar to those provided it engineers.

CLAUSE 7 - PRODUCTION

7.1 The Operator shall also deliver to the Parties any information on technical

production improvements developed during the Production Period.

7.2 For Hydrocarbon losses and environmental damage control and prevention, the

Operator and the Parties shall take the necessary measures applying methods

generally accepted by the Oil industry to prevent Hydrocarbon losses or spilling

in any way during drilling, production, transportation and storage activities.

7.3 The Operator shall keep daily Hydrocarbon consume, if any, operation records



and shall submit a monthly Hydrocarbon consume report accompanied of forms

provided by the Ministry of Mines and Energy for such purpose.

CLAUSE 8 - HYDROCARBON DISTRIBUTION AND AVAILABILITY

Pursuant to Contract Clause 14 (section 14.4), the Operator shall be responsible

of metering, sampling and controlling Hydrocarbon quality in accordance with

standards and methods accepted by the oil industry (ASTM, AGA, and API) and

applicable legal regulations referring to net Hydrocarbon received and delivered

at standard conditions volumes calculation.

Hydrocarbon volumes accepted by the Operator for transportation will be

determined using meters installed by the Operator for such purpose in receiving

stations and points of delivery.

CLAUSE 9 - EXPORT HYDROCARBON SUPPLY

For Contract Clause 14 purposes, the ASSOCIATE's Hydrocarbon exports shall take

into consideration primarily country needs before exporting Hydrocarbon subject

to legal regulations on the matter.

PART II - ACCOUNTING AND FINANCIAL MATTERS

Section One - Programs and Budgets

CLAUSE 10 - PRODUCTION PROGRAMS AND BUDGET

10.1 Pursuant to Contract Clause 7, the ASSOCIATE shall deliver to ECOPETROL

within sixty (60) days following Contract signature date, the programs, schedule

of activities and the budget to be executed in the short term (the following

year) and the following two (2) years estimated budget projection broken down by

type of Exploration Work to be developed and indicating the disbursement

currency. After the first year, the ASSOCIATE shall submit the aforementioned

information within the first ten (10) calendar days each year.

10.2 The ASSOCIATE shall submit on a quarterly basis, within fifteen (15)

calendar days following the respective quarter end, the technical and financial

report provided in Contract Clause 7.

CLAUSE 11 - PRODUCTION PROGRAMS AND BUDGETS

11.1 For Contract Clause 11 effects, the Operator shall submit a Field

development plan proposal envisaging in detail the short and mid term. The short

term budget shall be submitted by year and by quarter to facilitate execution

and to prepare the respective treasury flows.

11.2 The Operator shall submit to ECOPETROL the Commercial Field organization

chart which shall be agreed at Technical Subcommittee level and approved by the

Executive Committee.

CLAUSE 12 - BUDGET MANUAL

Standards and procedures listed below constitute the budget manual applicable to

Budgets preparation, submittal and control during production of Commercial Field

or Fields discovered in development of the Contract. This manual has three (3)

parts, as follows:

12.1



Income budget



12.2



Expense budget



12.3



Other provisions



CLAUSE 13 - INCOME BUDGET

This budget is in turn divided into two (2) sections: current income budget and

capital contributions.

13.1 Current Income

Covers all contributions regularly obtained to the favor of the Joint Account

and foreseeable by the Operator. Includes the following items as the case may

be:

13.1.1 Sale of products:

Income from Operator Hydrocarbon sales to one of the Parties or to third parties

on behalf of the Association (such sales are understood other than each of the

Parties participation in the Association).

13.1.2 Services Provided:

Covers all services provided by the Operator to one of the Parties or to third

parties, according to fees agreed by Subcommittees and approved by the Executive

Committee.

13.1.3 Disposal of assets or materials:

Covers equipment or materials sold by the Operator to the Parties or to third

parties subject to this Agreement Clause 20 (section 20.2) provisions.

13.1.4 Other income

Includes all funds received by the Operator and destined to the Joint Account,

on the account of transitory financial investments and all other income

projected by the Operator.



13.2 Capital contributions:

Refers to all contributions received by the Operator on the account of cash

calls delivered by the each of the Parties according to Contract participation.

Such income is designated cash calls and is managed on the basis of procedures

provided under this Agreement Clause 15 (section 15.5).

CLAUSE 14 - EXPENSE BUDGET

As previous step to budget preparation, the Executive Committee will have the

respective Subcommittees determine general policies and parameters to be taken

into account to prepare the budget plan for the respective Commercial Field. The

expense or appropriations budget includes the operation expenses budget and the

investment budget. Each of these Budgets will be prepared according to monetary

origin, whether pesos or dollars.

14.1 Operation Expenses Budget

The operation budget will be prepared by the Operator on the basis of standards

and policies on the matter issued by the Association Executive Committee

pursuant to Contract Clause 19 (section 19.3.5) and on the basis of economic

parameters and indexes defined by the Joint Operation as the most representative

for the budget term.

14.1 Preparation Procedure

The Operator shall submit the operation expense budget identifying Joint

Operation needs and broken down by expense item according to classification

provided in this Agreement Clause 14 (section 14.1.2).

Cost factors used to evaluate the different activities programmed to be

developed during the Budget year will refer to actual figures known upon budget

preparation or the best information available. In all cases the operation

expenses budget will be calculated taking into consideration costs required by

units which directly provide their services to the Joint Operation and shall be,

therefore, one hundred percent (100%) assumed by the Joint Account and charged

to the Parties in the proportion provided under Contract Clause 22 (section

22.6.1). Indirect Expenses to be assumed by the Joint Account will be charged to

the Parties and determined as provided under Contract Clause 22 (section

22.6.2).

14.1.2 Expenses Budget Classification

For all expenses budget submittal purposes, the budget will be divided into

programs, groups and expense items. Budget expense programs represent

homogeneous activities required to develop the Joint Operation, including

programs associated to investment. Each of the programs numerical and sequential

expense groups reflect the expense objective, shall be duly supported and

explained and separated by expense item. The following are major expense items

to be used

14.1.2.1 Organization chart expenses

Salaries

Fringe Benefits and parafiscal contributions

14.1.2.2 Operation materials and supplies

Repair and maintenance materials

14.1.2.3 Contracted services

Technical field operation and maintenance services

Services provided by the Operator

Other services

14.1.2.4 Overhead

Equipment and Office leases

Shared expenses

Insurance

Utilities

Assistance to the community

Other overhead

14.1.2.5 Environmental management

Materials

Contracted services

Other expenses

14.1.2.6 Aggregated value tax - IVA

14.1.2.7 Indirect expenses

14.1.3 Calculation base

Operation expenses budget calculation basis will be the following:

The salaries and fringe benefits budget will be calculated on the basis of

organization charts approved for the Association and estimates will be subject

to this Agreement Clause 18 (section 18.1.1). Salaries, fringe benefits and all

other voluntary bonus to domestic and foreign personnel will be separately

listed by disbursement origin for Association Subcommittees and Executive

Committee information purposes.

Materials and supplies costs estimates will be based on actual prices or updated



quotations and, in general on the basis of the best information available.

Import expenses will be based on subsequently imported materials and/or

equipment FOB prices taking into account the following factors: freight,

insurance, Colombian ports use taxes, import taxes and all other import

expenses.

Contracted operation and maintenance services value will be estimated on the

basis of contracts entered into or to be entered into by the Joint Operation

upon Budget preparation.

Indirect expenses to be assumed by the Joint Account for services provided or to

be provided by the Operator will be calculated according to procedures provided

in Contract Clause 22 (section 22.6.2).

The environmental expenses budget objective is to appropriate the necessary

annual funds to comply with environmental regulations.

Overhead will be calculated on the basis of concrete needs required by the Joint

Operation in development of its normal activities. Shared expenses are

disbursements to be assumed by the Joint Account as a result of facilities

and/or services shared by Fields or Associations. The budget and these Joint

Account charges shall be recommended by the Association Subcommittee and

approved by the Executive Committee. Assistance to the community will be

budgeted on the basis of petitions from interested parties and policies dictated

by the Executive Committee. Under special conditions so deserving the Operator

will have the right to accept petitions according to procedures, previous notice

to each of the Parties.

14.1.4



Budget execution.



Operation expenses budget execution will be based on the following

considerations:

14.1.4.1 All services, purchases or contracts charged to the Joint Account as

operation expenses shall be budgeted and fully justified.

14.1.4.2 If the service or activity to be contracted does not imply

disbursements exceeding the limits provided for the Joint Operation, the

Operator will be fully autonomous to contract subject to internal responsibility

and authority procedures.

14.1.4.3 Purchases, contracts or any other act implying a higher partial or

global cost exceeding limits provided shall be previously submitted to the

Association Technical Subcommittee for study and recommendation.

14.1.5 Budget Execution Control.

Expenses budget execution control will be the responsibility of the Operator

which shall monitor correct expenses appropriation.

During the first fifteen (15) calendar days following the respective quarter

end, the Operator shall prepare a budget report explaining budget execution

results, which report shall contain:

14.1.5.1 Accumulated expenses to date broken down by expense item provided under

this Agreement Clause 14 (section 14.1.2).

14.1.5.2 Special comments on items which execution has significantly deviated

with respect to the average budget or quarterly estimate.

14.1.5.3 Projected expenses to be disbursed on a quarterly basis or the

remaining year.

14.1.5.4 Justification of potential budget additions, adjustments or transfers

the Operator deems convenient or if proposed by one of the Parties.

14.2 Investment budget

Will be each of the programs and investment projects to be developed by the

Joint Operation basic planning, execution and control tool and will be the means

to estimate funds required to develop the different programs approved by the

Executive Committee.

14.2.1 The investment budget will include the respective entries for the

following items:

14.2.1.1 Acquisition of lasting goods, materials and services required to

develop the different projects determined by the Association.

14.2.1.2 Acquisition of major equipment and tools destined to Association

workshops with the purpose of guaranteeing normal operations development.

14.2.1.3 Constructions and/or buildings expansion as required by operations,

including facilities destined to Joint Account staff.

14.2.2 Investment budget classification For investment budget submittal

purposes, the budget will be grouped by programs and projects. Each Budget

programs in numerical order will reflect groups of common objective projects to

be developed by the Operator for the Joint Operation. Each Program project in

numerical sequential order will be duly supported and explained. The following

are major activities and project types to be used:

14.2.2.1 Development wells Pumping or surface equipment, recompletion and

services to wells potentially capitalized.

Production wells

Locations



14.2.2.2 Production facilities Hydrocarbon collection system Storage system

Hydrocarbon treatment system Improved recovery system Pumping Stations Transfer

lines Other

14.2.2.3 Civil works

Roads

Bridges

Construction (camps, workshops, warehouses, offices)

14.2.2.4 Other assets

Automotive equipment

Fire fighting equipment

Communications equipment

Office equipment

Electromechanical maintenance equipment

Major tools

Cleaning or workover equipment

14.2.2.5 Special Projects

Environmental management

Deposits studies

Simulation studies

Interference tests

14.2.2.6 Warehouses

For projects

For maintenance materials

14.2.2.7 Each of these project may be divided into as may subprojects as

necessary, always maintaining uniform identification to be finally submitted by

project, according to the above classification and using for such purpose forms

provided by ECOPETROL, which may be adapted by mutual agreement of the Parties

by the Financial Subcommittee. With the purpose of further clarifying investment

budget preparation, the following shall be taken into consideration:

14.2.2.7.1 Maintenance projects Refers to all investments in equipment,

materials and constructions destined to maintain the facilities in efficient

operation conditions subject to original capacity and yield limits.

14.2.2.7.2 Expansion projects Areinvestments with the purpose of increasing

facilities capacity, increasing authorized automotive equipment number, office

equipment, etc.

14.2.2.7.3 Special Projects Will include all projects which value, importance

for industrial activities or impact at the social or ecological level deserves a

special classification.

14.2.3 Each and all investment budget projects shall be fully justified and

analyzed before including in the general budget. In this sense, the Operator

shall prepare an initial investment project containing the following general

information: Needs analysis Project justification General project description

Estimated investment value Schedule of activities Project critical route

Economic assessment Theinitial investment project containing the above

information in addition to any other information deemed necessary for

evaluation, will be jointly studied by Association Subcommittees which will

recommend or object project feasibility on the basis of policies dictated by the

Executive Committee.

After the Subcommittees have recommended a given project, such project will be

included in the general budget to the approved by the Association Executive

Committee.

All general information included in each project justification will be recorded

in a technical-financial Exhibit to serve as support to budget submittal and

approval by the Executive Committee.

14.2.4 Budget consolidation

After determining Joint Operation needs, the Operator will consolidate each of

the Commercial Fields expenses and investment budget according to classification

provided in this Agreement Clause 14 (sections 14.1.2 and 14.2.2, respectively)

and will submit to the Executive Committee for final approval. Both the expense

budget and the investment budget will be listed in four (4) columns showing

dollars origin accrual and pesos origin accrual, a dollar consolidated and a

pesos consolidated, on the basis of the respective year exchange rate

projection.

Additionally, the Operator shall prepare, for information purposes, a schedule

of disbursements indicating short term funds requirements broken down by quarter

and currency origin, at group expense and investment program level.

14.2.5 Budget execution

In all cases the Operator is empowered to make all operation expenses and

investments required by the Joint Operation according to approved Budget not to

exceed ten percent (10%) appropriations assigned to each expense group and to

each project during the respective budget term (Contract Clause 11, section

11.5). Budget execution will be the responsibility of the different Operator

units subject to previously determined execution schedule.

Appropriations assigned each project will be identified using a previously

defined code to be used in all documents associated to Budget Execution

procedures.

14.2.6 Budget Control.



The Operator will be responsible of developing each of the programs and

investment projects and shall account for execution thereof subject to approval

conditions.

Additionally, the Operator will be responsible of monitoring timely and correct

projects development. In the event any trouble preventing normal projects

development arises, the Operator shall forthwith report such trouble in writing

to the Parties for trouble encountered to be solved. The Operator, as the person

responsible of the development plan, programs and projects, shall prepare

quarterly reports on budget and technical progress thereof to be delivered to

each of the Parties for study and subsequent approval by the Association

Executive Committee.

The quarterly report shall be prepared and submitted by the Operator within

fifteen (15) calendar days following each quarter end and shall contain the

following information:

Period covered by the report.

Project code and description

Total project budget

Financial progress from start to closing date. Investments by current year

project accumulated to date.

Technical work progress

Quarterly projection of work to be developed for the remaining year, for

information purposes.

14.2.7 Investments during the Retention Period

Investments during the Retention Period will be assumed by the Association Joint

Account or by the ASSOCIATE, depending on whether ECOPETROL has accepted Field

commercial feasibility.

CLAUSE 15 - OTHER PROVISIONS

15.1 Budget additions.

In the event during Budget execution appropriations approved by the Executive

Committee would require additions, the Parties may be required extraordinary

amendments to be ratified by the Executive Committee at its next meeting.

Expenses and investment Budgets additions or transfer requests may be

periodically submitted when the Executive Committee holds its regular meetings.

However, the Executive Committee will have the right to meet on an extraordinary

basis to discuss budget issues any time a special situation so deserves.

Therefore, every time a budget revision is requested, the Operator shall start

the respective procedures duly in advance submitting the requests to the

respective Subcommittee for study and subsequent recommendation to the Executive

Committee.

In any case, budget addition requests shall be fully justified explaining the

reasons originating appropriated entries variation and including the respective

technical and financial exhibits provided un this Agreement Clause 14 (section

14.2.3).

15.2 Budget transfers.

Appropriations carried from one year to the next due to projects not concluded

during the budgeted term (for reasons such as lack of equipment, import

procedures, bad weather, etc.) will be deemed budget transfers.

Nondeveloped project full value will be carried to the following year budget and

will be subject to Executive Committee approval. These projects will be

expressly included in the budget taking into account the disbursement schedule

provided in this Agreement Clause 15 (section 15.4). Additionally, budget

transfers will originate an exhibit explaining budget transfer causes and how

will the budget be executed within the next term.

15.3 Approvals.

The Executive Committee will be the body in charge of approving the programs and

the budget recommended by Association Subcommittees and to authorize the

Operator to purchase or contract on behalf of he Association all goods and

services required by the Joint Operation.

15.4



Disbursement schedule.



Together with the budget recommended by the Association Subcommittees, the

Executive Committee will approve the quarterly budget submitted by the Operator

for the immediately following year which will serve as the basis to calculate

monthly cash calls.

15.5 Cash calls.

Cash calls or funds advances will be placed by the Operator to each of the

Parties on the basis of obligations assumed by the Joint Operation for the month

immediately following the cash call, consulting the Budget approved by the last

Executive Committee and the projected cash flow. Cash calls under this Clause

will be deposited in a bank account opened by the Operator for such purpose to

be exclusively used by the Joint Operation. Cash calls preparation and submittal

shall be subject to the following requirements:

15.5.1 Preparation



On the basis of the approved budget and obligations assumed by the Association

in the subsequent month, the Operator will prepare cash calls taking into

account the following conditions:

15.5.1.1 The Operator will place a separate cash call for each of the producing

Commercial Fields in the Contract Area, identifying pesos and dollars expenses

and investments according to projected disbursement origin.

15.5.1.2 The cash call shall be open by programs and project in the event of

investments and by group and expense item in the event of expenses, as shown in

the budget approved by the Executive Committee.

15.5.1.3 For each of the projects and expense group listed in the cash call to

be considered, it must be included in the budget; otherwise, total cash call

value will be discounted.

15.5.1.4 Projects and expense groups budgeted value shall be sufficient.

Nonetheless, in special cases, the value appropriated for the term may be

exceeded by ten percent (10%) according to Contract Clause 11 (section 11.5).

15.5.2 Submittal

Every cash call will be submitted for processing using the form previously

agreed by the Parties in the Financial Subcommittee and shall show actual and

estimated expense charges and will include the following documents:

15.5.2.1 Cash call letter

15.5.2.2 Cash call form showing each of the programs, projects or expense item

financial status on cash call date, and

15.5.2.3 General comments of the technical nature identifying cash call

destination for major projects or expense items.

Section Two - Accounting Procedures

CLAUSES 16 - ACCOUNTING PROCEDURE

From Exploration Period start the ASSOCIATE shall deliver to ECOPETROL on a

quarterly basis within fifteen (15) calendar days following each quarter end,

the exploration costs report provided in Contract Clause 7, expressly

identifying Direct Exploration Costs subject to reimbursement pursuant to

Contract Clause 9.2.2, as detailed in the budget indicating the disbursement

currency and a US dollars consolidated. Additionally, and in the same report the

ASSOCIATE shall include the preliminary accumulated value to be included as R

Factor denominator provided in Contract Clause 14 (section 14.2.3), clearly

showing Direct Exploration Costs detail and calculation parameters applied. It

is hereby understood that Direct Exploration Costs reported by the ASSOCIATE

will only be firm after ECOPETROL has audited and accepted such costs.

During the Production period. credits and charges incurred by the interested

Parties and covering operations defined in the Contract, will be subject to the

following conditions: All charges will go to the Joint Account to be opened as

provided under Contract Clause 22. The Joint Account defined in Contract Clause

4 (section 4.7) will be divided into three major records as follows:

16.1 General Joint Account (clarification, charges and entries). This account

will record all movement as detailed below and will be fully distributed to the

Parties on a monthly basis, in the proportion of fifty percent (50%) to

ECOPETROL and fifty percent (50%) to the ASSOCIATE with respect to investments,

and in the proportion provided in Contract Clause 22 (sections 22.6.1 and

22.6.2) for Direct Expenses and Indirect Expenses, that is, will serve as the

basis for monthly billing as therein provided, leaving a zero (0) balance each

month. All accounting transactions associated to this account will be recorded

by the Operator in Colombian pesos subject to the laws of the Republic of

Colombia, but the operator will have the right to, in turn, keep ancillary

records showing disbursements incurred in any currency other than Colombian

pesos.

16.2 Operation Joint Account. This account will record cash calls received from

the Parties and credit charges associated to their billing and shall show all

times a balance to the favor or against each of the Parties, as the case may be.

This account will be divided into sub-accounts according to transaction currency

origin, whether pesos of dollars.

16.3 Joint property records. The Operator shall keep under the Joint Account

records of all goods acquired and subject to inventory indicating each asset in

detail, acquisition date and original cost. Accounts mentioned in this Agreement

Clause 16 (sections 16.1, 16.2 and 16.3) will form part of the Operator's

official accounting records but shall not mix with accounting records other than

the Joint Account. The three accounts will be subject to this Agreement Clause

22.

16.4 The Operator shall deliver to ECOPETROL on a monthly basis, together with

information provided in this Agreement Clause 17 (section 17.2.2) in the form of

a separate exhibit, R Factor parameters and calculation pursuant to Contract

Clause 13 (section 14.2.3).

CLAUSE 17 - CASH CALLS, BILLING AND ADJUSTMENTS

17.1 Cash calls. Although the Operator will pay and discharge in the first place

all costs and expenses incurred according to the Contract, charging each Party's

participation percentage, it is hereby agreed, with the purpose of funding such

participation, that each of the Parties, upon request from the Operator and as

provided further below, shall deliver cash calls to the Operator, from

Commercial Field acceptance by the Parties and no later than within the first

five (5) calendar days each month, the respective month's estimated operations



expenses portion. The cash call shall be accompanied to detailed information as

provided under clause 15 (section 15.5.1.2) hereof. Such cash calls will be made

in US dollars or Colombian pesos, according to needs contemplated in the budget

and cash calls prepared by the Operator. The Operator shall place the cask call

within the first twenty (20) calendar days the month immediately prior to the

month when the cash call is to be delivered. If the Operator would have to incur

in extraordinary expenses not contemplated under the monthly cash call, the

Operator shall make special cash calls to the Parties covering such

disbursements participation. Each participant shall advance its proportional

funds within fifteen (15) calendar days following the Operator cash call.

17.2



Billing



17.2.1 The Operator shall prepare an initial bill to ECOPETROL after each

Commercial Field acceptance covering fifty percent (50%) Direct Exploration

Costs incurred before submitting each discovered Commercial Field commercial

feasibility studies, which costs have been audited and accepted by ECOPETROL

according to Clause 22 hereof. Exploration wells costs will include all costs

incurred to drill, terminate and test in the event of producing wells and dry

Exploration Wells abandonment costs. Said bill shall also include fifty percent

(50%) additional work costs provided in Contract Clause 9 (section 9.3) which

will be paid according to said Clause. Said bill shall include a costs summary

separately stating the investment and expenses currency, that is, Colombian

pesos or US dollars.

17.2.2 From the initial bill date on, the Operator will bill the Parties, within

fifteen (15) calendar days following the last day each month, its proportional

participation in costs and expenses for the month. Bills shall list Operator

accounting procedures details, including a detailed accounts summary, separately

listing costs and expenses originated in dollars or in pesos.

17.3 Adjustments. Bills will be adjusted by he Operator and the Parties after

subtracting cash calls in dollars and pesos.

If any of the Parties' cash calls differ from their participation in actual

costs determined for each period, the difference will be adjusted in the

following month's bills.

17.4 Bills acceptance. Bills payment will not affect the Parties right to oppose

or inquire about bills accuracy subject to Contract Clause 22 (section 22.7)

provisions.

CLAUSE 18 - CHARGES

Subject to limitations described below, the Operator will charge the Joint

Account and bill each of the Parties according to percentages provided under

this Agreement Clause 16 (section 16.1), the following expenses:

18.1 Labor

18.1.1 Domestic and foreign employees

18.1.1.1 Operator's employees salaries if directly working for the Joint

Operation, including overtime, night overcharge, Sundays and holidays and the

respective compensation rest payment and in general any salary payment.

18.1.1.2 Fringe benefits, indemnification, insurance, subsidies and bonus and in

general any benefit other than salary granted workers and/or their families or

dependents, whether individually or collectively or granted in virtue of the

work contract, the law agreements and/or arbitration awards, with the exception

of housing plans in which respect a special agreement will be required. Some of

the above could be the following, among other: severance, vacation, retirement

and disability pensions, benefits granted retired personnel and their families,

benefits and assistance in the event of illness and professional or non

professional, accidents, service bonuses, life insurance, contract termination

indemnification, union assignments, all type of bonuses, assignments and

savings, health and/or education assistance and social security in general.

Additionally, contributions to Instituto Colombiano de Bienestar Familiar -ICBF

(Family Welfare), Servicio Nacional de Aprendizaje - SENA (National

Apprenticeship Service), Instituto de Seguros Sociales - ISS (Social Security)

and other similar required.

18.1.1.3 All expenses incurred on behalf of the Joint Operation for camp

maintenance and operation, field offices or services facilities. These expenses

also include - not taxatively but for information purposes - expenses listed

below regardless of whether services are provided gratuitously or for

remuneration, or whether to workers, their dependents or relatives or whether

voluntary or mandatory. Some of such services are:

18.1.1.3.1 Medical, pharmaceutical, surgical or hospital services.

18.1.1.3.2 Camp and complete services therein, including repair and hygiene.

18.1.1.3.3 Training and qualification costs

18.1.1.3.4 Workers entertainment

18.1.1.3.5 Schools for workers, their children and dependent relatives.

18.1.1.3.6 Security or social assistance plants and camp surveillance.

18.1.1.4 Expenses and services listed in the above Clause 18 (sections 18.1.1.1,

18.1.1.2 and 18.1.1.3) are understood with charge to the Joint Account in the

event applicable regulations, collective labor agreements and/or arbitration

awards directly or jointly applicable to contractors subcontractors,

intermediaries and/or their employees at the service of the operation.



18.1.1.5 Regarding retirement pensions and disability assistance, the Executive

Committee will have the right to proceed according to the Social Security and

Pensions system provided by Law 100 of 1993 and all other regulating provisions.

18.2 Materials and supplies

Materials and supplies required to develop operations will be charged to the

Joint Account. Materials and supplies shall be acquired and stored in the

project warehouse or the maintenance material warehouse as convenient for the

operation and credited the operation at book cost as they leave the warehouse to

be used. Capital equipment units will be directly charged to the Joint Account.

The book value is determined as follows:

18.2.1 Book value

Book value is understood as the last average price for warehouse stock on the

basis of costs taken from imports calculation worksheets or local cost, as

follows:

18.2.1.1 For imported materials, equipment and supplies the book value shall

include net manufacturer or supplier bill cost, purchase cost, freight and

delivery charges at supply site and port of embarkment, freight to

destination port, insurance, import duties or any other tax, cargo handing

from the ship to customs warehouse and transportation to operations site.

18.2.1.2 For locally acquired materials, equipment and supplies the book value

shall include net seller bill plus sales tax, purchase cost, transportation and

insurance and similar costs paid to third parties from the purchase place to

operations site.

18.2.1.3 Materials will be charged to the Joint Account according to acquisition

currency origin to be subsequently charged to each of the Parties.

18.2.2 Materials devolution to the Joint Account warehouse, as the case may be.

Materials, equipment and supplies returned to the Joint Operation warehouses

value will be estimated following the same procedures.

18.2.2.1 New materials will be recorded at book value.

18.2.2.2 The Operator will have the right to reincorporate used materials, in

good operating conditions and equipment fit to be subsequently used with no need

for repairs to the respective warehouse at seventy five percent (75%) book

value, crediting the respective Joint Account project.

18.2.2.3 The Operator will have the right to reincorporate repaired used

materials, in good operating conditions to the respective warehouse at fifty

percent (50%) book value. When such materials are used again will be charged at

the new book value.

18.2.3 Sales by the Parties. Materials, equipment and supplies value sold by the

Parties to the Joint Operation will be estimated on the basis of replacement

cost agreed by the Parties. The respective transportation costs will be assumed

by the Joint Operation. In the event of Joint Operation sales to one of the

Parties, goods value will be estimated on the basis of replacement cost agreed

by the Parties and transportation costs will be assumed by the buying Party.

18.2.4 Local Materials transportation

18.2.4.1 Materials shipped by an external carrier at cost according to the

carrier company bill.

18.2.4.2 Materials shipped in carrier units property of the Parties, at the

rates calculated to cover actual expenses, according to this Agreement Clause 18

(section 18.2 and 23 (section 23.1.1).

18.2.5 Canceled, postponed or changed projects. In the event stock accumulated

in the warehouse due to projects approved by the Parties change, postponing or

cancellation, such materials cost will be charged to the warehouse account. Such

materials may be sold to third parties according to this Agreement Clause 20

(section 20.2.1) and the produce credited to the Joint Account.

Excess material from projects, if such material purchase has been directly

charged, shall be returned to the warehouse upon such projects completion and

credited to the respective project. The Operator shall report such transaction

to the Parties at regular Financial Subcommittee meetings when held.

18.3 Travel expenses

All travel expenses incurred on behalf of the Joint Operation by domestic or

foreign personnel, such as transportation, hotels, feeding, etc.

18.4 Service units and facilities

Services provided using equipment and facilities property of either of the

Parties will be charged to the Joint Account at reasonable rates as provided in

this Agreement Clause 23. Rates determined shall apply until amended by mutual

agreement.

18.5 Services

Services provided the Joint Operation by third parties, including contractors,

at actual cost. Likewise, technical services such as lab analyses and special

studies requiring Technical Subcommittee recommendation and Executive Committee

approval.

18.6



Repairs



Repairs to equipment or goods property of any of the Parties destined for Joint

Operation use, except if such costs have been previously charged under leases or

otherwise.

18.7 Litigation

Joint Operation expenses associated to actual or threatened litigation

(including investigation and proof taking), attachments release, awards or court

decisions, legal claims and claim filings, accidents compensation, arrangements

in the event of death and funeral, provided such charges have not been

acknowledged by an insurance company or covered by the respective charges

provided in this Agreement Clause 18 (section 18.1.1). In the event legal

counseling is provided on such matters by permanent or external attorneys whose

full or partial remuneration has been included in indirect expenses, no

additional service charges will be recorded but will be charged to Direct Costs

incurred for such proceedings.

18.8 Joint Operation propertied and equipment loss or damage. All costs and

expenses required to replace or repair losses or damages caused by fire, floods,

storm, robbery or any similar act. The Operator shall notify the Parties in

writing any losses or damages suffered, as soon as practical.

18.9 Taxes and leases

Alltaxes paid or accrued in development of the Joint Operation will be charged

to the Joint Account, subject to applicable legal provisions.

TheJoint Account will also be charged leases, rights of way and indemnification

paid on improvements, soil occupation, etc.

18.10 Insurance

18.10.1 Insurance premiums on insurance taken for the benefit of operations

subject to the Contract together will all expenses and indemnification accrued

and paid, and all losses, claims and other expenses not covered by insurance

companies, including legal counseling mentioned in this Agreement Clause 18

(section 18.7) well be charged to the Joint Account.

18.10.2 In the event no insurance has been taken aforementioned actual expenses

incurred and paid by the Operator will also be charged to the Joint Account.

CLAUSE 19- CREDITS

19.1 The Operator shall credit the Joint Account the following income items:

19.1.1 Insurance returns associated to the Joint Operation which premiums have

been charged to said operations.

19.1.2 Geological information sales previously authorized by the Parties

provided associated recoveries have not been charged to the Joint Account.

19.1.3 The sale of properties, plants, equipment and materials property of the

Joint Operation.

19.1.4 Lease rents received, customs taxes or transportation claims refunds,

etc. shall be credited to the Joint Operation if rents or refunds associate to

such operation.

19.1.5 Any other operational income or contracts authorized by the Executive

Committee for the Joint Account service.

19.2 Warranty

In the event of defective equipment when the Operator has received the

respective adjustment from the manufacturer or its agents, such amount will be

credited to the Joint Operation.

CLAUSE 20 - DISPOSING OF MATERIAL AND EXCESS EQUIPMENT

20.1 Excess materials and equipment

The Operator shall inform the Parties in writing about any Joint Operation

excess materials or equipment, thirty (30) days after completing the inventory

provided in Clause 21 hereof. Each of the Parties shall designate a

representative to review the condition thereof and to determine which materials

or equipment may be sold. In the event of usable materials or equipment

ECOPETROL will have the first option and the ASSOCIATE will have the second

option; such options shall be exercised within sixty (60) days following notice

date. In the event the aforementioned parties do not buy the Operator shall

notify them in writing and will proceed to auction.

20.2 Disposing of Capital equipment and materials: pursuant to Contract Clause

22 (section 22.9) the Operator will have the right to sell materials and

equipment property of the Joint Account subject to the following conditions:

20.2.1 Major material and capital equipment sold by the Operator and previously

charged to the Joint Account will be subject to previous Executive Committee

approval. The produce thereof will be credited to the Joint Account. For such

purpose only, major materials are defined as any assets which estimated sale

value exceeds forty thousand US dollars (US$40,000) or the equivalent Colombian

currency.

20.2.2 Minor materials charged to the Joint Account and not required for

operations or reincorporated to the respective warehouse may be sold by the

Operator and the produce thereof credited to the Joint Account.



20.2.3 Any assets which cost or estimated value exceeds forty thousand US

dollars (US$40,000) or the equivalent Colombia currency abandonment or

dismantling requires previous Executive Committee authorization.

20.2.4 None of the Parties will have the obligation to purchase the other

Party's interest in excess materials, whether new or used. Disposal of major

excess materials, such as towers, tanks, engines, pumping units and piping will

be subject to Executive Committee approval. The Operator will, however, have the

right to reject damaged or unusable materials in any way.

20.2.5 All taxes accrued by reason of Joint Account materials or assets sale or

disposal shall be the responsibility of the Operator with charge to the Joint

Account.

CLAUSE 21 - INVENTORY

Upon request from ECOPETROL the Operator shall submit the necessary information

to analyze warehouse stock and the Parties shall agree upon joint participation

to control inventories. The Operator shall provide any facilities required by

ECOPETROL to take a fixed assets physical inventory at the Association

facilities, previous Financial Subcommittee agreement on the date, time and

number of persons designated to take said inventory.

21.1 Inventory and Audit

Subject to applicable regulations and no less than once every three (3) years

the Operator shall take all Joint Operation assets inventory.

21.2 The notice of intention to take an inventory shall be given by the Operator

in writing to the Parties one (1) month in advance to said inventory taking date

for the Parties to be represented. But if one of the Parties is not present the

inventory so taken by the Operator shall be no less valid.

21.3 The Operator shall provide the Parties copy of each inventory including

copy of the reconciliation and will submit results to the Association

Subcommittees which shall study the report and propose action to be taken on

the matter.

21.4 Excess and shortage inventory adjustments will be reported to the Executive

Committee for consideration and approval.

21.5 At midnight on the last day of the Exploration Period provided, the Parties

shall take an inventory of both material in the warehouse property of the Joint

Account and extracted products in the collection batteries and piping from

collection batteries to storage tanks or in storage tanks all within production

fields, and such inventories will be distributed to the Parties, after deducting

royalties, in the proportion provided under Contract Clause 13.

CLAUSE 22 - AUDIT

Subject to Clause 17 (section 17.4) hereof the Parties will have the right to

have their own Auditors or representatives examine and control Operator's

accounting books and records associated to properties and operation activities

thereof. However, with the purpose of facilitating Direct Exploration Costs

revision under this Agreement Clause 17 (section 17.2.1) as soon as the Operator

notifies the Parties any reimbursable Exploration Work initiation, the ASSOCIATE

or the Operator shall permit, previous due notice, ECOPETROL auditors to

periodically examine such Exploration Work accounts, for the mentioned revision

to have been performed under the best conditions and time when the Commercial

Field is declared. During audits herein provided representatives from the

General Accountant of the Republic will have the right to participate if such

body deems convenient. Such audit costs and expenses will be paid by the

interested Party.

22.1 After the audit report has been delivered, the ASSOCIATE or the Operator

will have a maximum six (6) months term to answer or sustain objections

submitted; upon said term expiration if the Operator has not answered,

objections will be deemed accepted and consequently the audit will proceed

accordingly. Audit notes or comments not resolved within the three (3) following

months will be resolved according to Contract clause 20.

CLAUSE 23 - FEES TABLE

23.1 Subject to limitations provided above, services provided the Joint

Operation by facilities exclusively owned by ECOPETROL or the ASSOCIATE will be

charged the respective fees with the purpose of recovering actual costs. Such

costs shall include normal work, salaries, fringe benefits, depreciation costs

and other operation expenses taking the following into account:

23.1.1 The transportation units fee usually calculated on the basis of operation

time shall include loading and unloading time, the time spent waiting for

loading and the time spent waiting to be unloaded. Transportation unit charges

assigned the operation shall include Sundays and holidays, except if out of

service for repairs.

23.1.2 In the event material required for the mentioned operations is

transported together with other material by fluvial or land carrier exclusively

owned by ECOPETROL or the ASSOCIATE the charge shall be based on transported

tons at rates which shall not exceed commercial rates.

23.2 Equipment and tools lease fees

The procedure to calculate equipment and tools property of the Parties leases,

excluding drilling equipment and major equipment which fees must be separately

calculated and approved by the Executive Committee, shall cover a depreciation

value in addition to a maintenance value and the procedure will be the

following:



23.2.1 Equipment description, model, number, purchase date and original cost.

23.2.2 Site where the equipment will be used, reasons for leasing and estimated

use period.

23.2.3 Annual equipment depreciation value, calculated on the basis of

depreciated book value and remaining useful life (minimum book value to be

considered will be ten percent (10%) original cost or the salvage value).

23.2.4 The annual maintenance value will be a percentage of the original cost

which will range from five percent (5%) for new equipment to fifteen percent

(15%) for depreciated equipment, depending on depreciation period, for instance:

Equipment A: (Five [5] years useful life)

Period (years) 1, 2, 3, 4, 5: one hundred percent (100%) depreciated equipment.

Maintenance: 5, 6, 7, 8, 9: 15%

Equipment B: (Ten [10] years useful life)

Period (years) 1, 2, 3, 4, 5, 6, 7, 8, 9, 10: one hundred percent (100%)

depreciated equipment.

Maintenance: 5, 6, 7, 8, 9, 10, 1,, 12, 13, 14, 15: 15%

Note: Useful life period and depreciation will be determined on the basis of

accounting practices applicable to oil operations.

23.2.5 Annual lease fee equals the value provided under Clause 23 (section

23.2.3) hereof plus the value specified in section 23.2.4 hereof.

23.2.6 Monthly or daily equipment lease fee will be as provided under Clause 23

(section 23.2.5) hereof divided into twelve (12) or three hundred and sixty five

365, as the case may be.

23.2.7 No "standby" fee will be charged but this fee will be charged in the

event of third parties.

23.2.8 The above lease fees do not include transportation, installation,

operation, lubricants and fuel costs which will be charged the operation

equipment is destined to.

23.2.9 The above lease fees will apply to eventual equipment and tools one

hundred percent (100%) property of the ASSOCIATE or the Operator and vice versa.

23.2.10 In each case, the Technical Subcommittee will recommend the Executive

Committee the need to use leased equipment and the Financial Subcommittee will

have the right to apply the fee system recommended herein.

23.2.11 Equipment lease fee will be calculated in US dollars but the respective

bill will be in pesos at the rate agreed by the Parties.

23.2.12 Warehouses and fixed assets lease fee.

For full or partial use of warehouses property of one of the Parties or the

Joint Operation lease fee calculation the procedure agreed by the Financial

Subcommittee will apply.

CLAUSE 24 - CONTRIBUTIONS IN KIND

ECOPETROL or the ASSOCIATE shall contribute in kind any materials deemed

convenient as agreed between the Parties.

PART III - ADMINISTRATIVE ISSUES AND SUNDRY PROVISIONS

Section One - The Executive Committee

CLAUSE 25 - OPERATING CONDITIONS

In development of its functions the Executive Committee shall comply with

conditions provided in Contract Clause 19, as follows:

25.1 The Executive Committee will be alternatively chaired by the Parties

starting with ECOPETROL.

25.2 The Executive Committee shall designate its Secretary alternating people

designated by ECOPETROL and the ASSOCIATE. The Chairman and the Secretary will

be members of the same Party.

25.3 The Executive Committee shall hold regular meetings during the months of

March, July and November, and shall hold extraordinary meetings any time the

Parties and/or the Operator deem necessary. At said meetings the production

program developed by the Operator, the development plan and immediate plans will

be discussed. This Executive Committee may be attended by each of the Parties

counselors as deemed convenient, being understood each of the companies shall

designate the less possible number of people.

25.4 In the event of Executive Committee regular meetings, the representative

chairing the coming meeting shall notify all other representatives (principal

and alternates) from the other Party and the Operator ten (10) calendar days in

advance indicating the meeting time and place and matters to be discussed

(agenda).

25.5 In development of Contract Clause 18 (section 18.3), during both regular

and extraordinary Executive Committee meetings, matters to be discussed and not



included in the agenda may be discussed during the meeting previous agreement of

the Parties representatives attending the Committee.

Section Two - Subcommittees

CLAUSE 26 - SUBCOMMITTEES ORGANIZATION

In development of the function provided under Contract Clause 19 (section

19.3.8), the Executive Committee will have the right to designate any advisory

subcommittees deemed necessary. In any case the Executive Committee shall

designate a Technical Subcommittee and a Financial Subcommittee.

The above subcommittees will be the organizations in charge of controlling and

defining Contract technical, financial and legal recommendations to the

Executive Committee and shall be governed by the Contract and this Agreement.

Each subcommittee shall issue its own internal regulations to be approved by the

Executive Committee.

Section Three - Operator

CLAUSE 27 - RIGHTS AND OBLIGATIONS

27.1 Pursuant to Contract Clause 30, the Operator has the right to conduct Joint

Operations by itself or retaining subcontractors subject to general Executive

Committee direction. In any case, the Operator will be responsible of the Joint

Operation according to Contract provisions.

27.2 Some of the Operator's obligations are the following, among other:

27.2.1 To prepare, submit and implement the development plan, expenses budgets

and exploration/ production programs as well as expenses approval.

27.2.2 To direct and control all operation expenses statistical and accounting

services.

27.2.3 To plan and obtain all services and materials required for good Joint

Operation development.

27.2.4 To provide all techniques and assistance required for good Joint

Operation development.

27.2.5 To plan tax effects and to comply with all tax obligations derived from

operations developed and to provide a timely report to the Parties in their

respective proportion.

27.3 The Operator shall not have the right to constitute any lien on Joint

Operation properties.

27.4 Operator resignation will be without prejudice of any right, obligation or

responsibility acquired during the time the Operator acted in such condition; if

the Operator resigns or is removed before obligations provided under the

Contract have been satisfied, the Joint Account shall not be charged any

expenses incurred by such change. But if the Executive Committee approves, these

costs and expenses may be charged to the Joint Account.

27.5 If the Operator has been removed or if its resignation has been accepted,

for obligations transfer purposes ECOPETROL will audit the Joint Account and

take an inventory of all Joint Operation properties. Said inventory will be used

for devolution and accounting purposes as regards said obligations transfer

procedures. All costs and expenses incurred with respect to inventory taking and

audit shall be charged to the Joint Account.

27.6 The Operator shall not be responsible for any loss or damage caused by

Joint Operation except if such losses or damage are imputable to:

27.6.1 The Operator's fault

27.6.2 The Operator's default to take and maintain any of the insurance required

under Contract Clause 33, except if the Operator has made every possible effort

to obtain and maintain such insurance with fruitless results, which case shall

be timely notified to the Parties.

Section Four - Contracting Procedures

CLAUSE 28 - SUPPLIERS REGISTER AND LIST OF PROPONENTS

28.1 The Operator will be responsible of keeping an updated suppliers register,

classified according to the different activities required by the operation and

shall determine qualification criteria applicable to companies to be included in

the list of proponents. The Technical Subcommittee will have the right to review

criteria before approving the list of proponents.

28.2 ECOPETROL will have the right to review the Operator suppliers register on

an annual basis and will have the right to have the Technical Subcommittee

suggest including or excluding suppliers from the record. The above

notwithstanding, ECOPETROL will have the right, any time, by duly motivated

petition, to require individuals or entities to be removed from the record.

28.3 In any cases implying invitations to bid for contracting purposes the

suppliers register shall be consulted placing the act on record in the

respective document.

28.4 Individuals or entities listed in the suppliers register shall evidence

technical, moral and economic solvency in addition to experience not only

regarding the company but also its partners and technicians working for such

companies on a steady basis.



28.5 On the basis of the above parameters, the Operator shall keep a qualified

suppliers register, which shall be periodically updated according to their

performance.

CLAUSE 29 - TENDER PROCEDURE

29.1 Responsibility. The Operator will be responsible of preparing duly in

advance the invitation to bid and will submit it to the Technical Subcommittee

for consideration.

29.2 The list of entities invited to bid will be prepared on the basis of

Suppliers Register information.

29.3 If the estimated contract value subject to bidding exceeds US$40,000, the

Operator shall invite no less than three (3) companies. If this would not be

possible, justification will be placed on record in the recommendation report to

the Technical Subcommittee.

29.4 The Operator shall endeavor to invite no more than 6 companies to bid with

the purpose of preventing excessive tender evaluation costs and also to give

participant companies a better opportunity to be awarded the respective

contract.

29.5 Being all other factors equivalent, the priority order to have the right to

be included in the list of proponents will be: Companies organized and domiciled

in the Department or Departments where the Commercial Field or Fields is or are

located - Colombian companies domiciled outside the Department or Departments

where the Commercial Field or Fields is or are located, but having a branch in

the Department - Colombian companies with their main domicile outside the

Department or Departments where the Commercial Field or Fields is or are located

not having a branch in said Department - Foreign companies with a branch

organized in Colombia - Foreign companies without a branch in Colombia.

29.6 Companies invited to bid list will also take into account companies

technically and commercially qualified which have not been provided the

opportunity to participate in similar tenders in the past.

29.7 The Operator shall prepare the tender Reference Terms and will submit them

to the Technical Subcommittee for consideration, duly in advance.

29.8 Tender Reference Terms shall clearly specify that:

29.8.1 Costs will be one of the criteria to be taken into account for contract

award and management:

29.8.2 All tenders exceeding such activity actual cost will be disqualified.

29.8.3 Tender evaluation will take into consideration factors other than costs,

which factors will be included in the Reference Terms

29.8.4 Offers shall be submitted according to invitation to bid Reference Terms

and if this requirement is not complied with the offer may be considered

invalid.

29.8.5 The invitation to bid will include a detailed price table to be filled

out by proponents to facilitate proposals evaluation.

29.9 The list of proponents will be reviewed and approved by the Technical

Subcommittee before delivering to parties invited.

29.10 As soon as the Reference Terms have been distributed, the following rules

will apply:

29.10.1 Any original Reference Terms information, amendment or clarification

will be delivered all proponents. The Operator Purchases and Supplies Unit will

be responsible of such changes. Changes must be duly justified by written

document.

29.10.2 No proponents shall be added or removed from the proponent list

originally approved by the Technical Subcommittee.

29.10.3 Every proponent who does not comply with tender procedures and rules, or

who violates the Operator business ethics code will be forthwith disqualified.

29.11 All invitation to bid contents and form shall meet "Documentation

Submitted to the Technical Subcommittee Form" procedure requirements and shall

be submitted to the Technical Subcommittee for consideration.

29.12 Internal approvals required by the Operator and ECOPETROL will depend on

contract estimated value on the basis of their respective internal procedures.

CLAUSE 30 - CONTRACT AWARDING AND PURCHASE ORDERS

30.1 The Operator will be responsible of awarding contracts and purchase orders.

For this purpose the Operator shall submit its recommendation to the Technical

Subcommittee which is the body in charge of approving and will be ratified by

the Executive Committee if awarded value equals or exceeds US$40,000.

30.2 Value: Awarding will be based on the best global value. The lowest price is

not always the best, because value will also take into consideration proponents

programming and quality, experience, reputation, and Colombian contents. In the

event the contract is not awarded to the lower value offer, such decision shall

be justified.

30.3 Written justification. The Operator shall submit a written recommendation

to the Technical Subcommittee justifying each contract and purchase order

awarded if the value equals or exceeds US$40,000. Such justification shall



include a summary of proposals submitted commercial and technical evaluation and

the basis for Operator recommendation.

30.4 Direct contracting: Direct contracting shall be supported and submitted in

writing to the respective Subcommittees clearly stating justification. The

Operator will have the right to contract directly with no need for tender in any

of the following events:

30.4.1 In the event only one supplier is available within the term required to

meet project schedule;

30.4.2 In the event there is no equivalent or satisfactory substitute for the

item or service previously directly contracted .

30.4.3 In the event the service or work derives from previous service or work or

in the event of and addition to a contract or purchase order opened within the

past ninety (90) days and if commercial conditions have not been modified or

when a recent tender evidences justify awarding with no need for tender.

30.4.4 In the event the Operator has standardized a specific item or service for

all applications within its operations area and there is only one known supplier

for such item or service.

30.4.5 In the event only one item or service is deemed meeting Operator's

requirements within the specified delivery term.

30.4.6 In the event an item or service is obtained for testing or evaluation.

30.4.7 In the event of an emergency. The Operator shall notify ECOPETROL at the

Technical Subcommittee immediately following such emergency.

30.5 Partial awards: A tender may be partially awarded two or more bidders,

provided the following conditions are fully satisfied:

30.5.1 The possibility to partially award is clearly specified in the Invitation

to Bid

30.5.2 Favored bidders have met Invitation to Bid requirements

30.5.3 Partial award reflects the best items or services to be obtained value

30.5.4 Any work scope change or awarding criteria shall be clearly communicated

all proponents before partial award.

30.6 Rejected offers: The Operator will have the right to declare the tender

void when the Technical Subcommittee finds motives justifying such decision

and/or if offers are distant from actual costs.

30.7 Notice to non favored bidders: Awarding results will be notified all

participants in writing.

30.8 Clarification: During the evaluation period, the Operator will have the

right to require clarifications from proponents. The Technical Subcommittee

shall approve significant commercial clarifications. No new approval from the

Technical Subcommittee will be required in the event of technical

clarifications. Clarifications capable of affecting the tender shall be notified

all proponents in writing.

CLAUSE 31 - CONTRACT MANAGEMENT AND PURCHASE ORDERS

31.1 The Operator will be responsible of managing contracts and purchase orders

and of execution thereof.

31.2 Contracts or purchase orders management basis will consist in execution

thereof, which shall include agreed costs, schedules and quality requirements.

31.3 The operator shall keep written record of all original contract amendments,

Each contract costs change impact will be evaluated by the Operator and

negotiated with the supplier or contractor before changing contract price.

31.4 If the proposed change exceeds US$40,000 or 10% originally approved value

not to exceed the US$40,000 limit the change will have to be submitted to the

Technical Subcommittee for consideration.

31.5 The Operator shall be responsible of Costs Control.

31.6 Any additional work or item within contract terms shall be authorized by

the Operator Project or Operations Manager, who shall consult with the Purchase

and Logistics Department or substituting units before amending the contract in

any way. This double responsibility ensures change process integrity. In the

event changes imply amending the contract text, such changes will be subject to

the Operator Legal Department approval.

31.7 Quality control will be managed subject to the QA/QC ("Quality Assurance

and Quality Control) process which shall include independent work inspection and

monitoring at the right time during work development.

31.8 Procedures applied by the Operator to control costs are described in a

Costs Control procedure.

31.9 The Parties will be delivered a monthly report on work progress accompanied

of costs documentation and schedules including major contracts and purchase

orders originally agreed budget variations analysis.

31.10 After major contracts and purchase orders have been completed a detailed

analysis will be conducted to evaluate experiences learned and applicable to

similar contracts or purchase orders to improve their control.



CLAUSE 32 - INSURANCE

For the purposes of Contract Clause 33, as regards insurance, the Operator shall

deliver to ECOPETROL the following information for ECOPETROL to insure fifty

percent (50%) Commercial Field assets:

32.1 Assets description, separated as far as possible in the following way:

31.1.1 Offices, camps and other non industrial assets.

31.1.2 Collection stations specifying tanks (quantity and capacity) and other

equipment

31.1.3 Sundry warehouses and other facilities

NOTE: External pipelines and wells are not covered by the fire policy because in

such case ECOPETROL directly assumes the risk.

32.2 Assets value indicating only the portion property of ECOPETROL value and

indicating the full value percentage it represents.

32.3 Geographical location

32.4 Reception date from the time the risk is transferred to the Joint

Operation.

CLAUSE 33 - FORCE MAJEURE OR ACTS OF GOD

Contract Clause 34 only suspends compliance with specific obligation of the

Parties if development thereof is impossible due to events of force majeure or

acts of God. Additionally, obligations associated to goods, properties,

production facilities etc. are only suspended if affected by such circumstances.

The affected Party shall notify force majeure termination detailing damages

magnitude and corrective actions affecting the system.

CLAUSE 34 - OPERATION AGREEMENT REVISION

This Operation Agreement may be revised when the Parties deem convenient, upon

request from either of them; the Executive Committee is fully empowered to

review and amend this Agreement. This Operation Agreement will be in force until

one of the following events occurs:

34.1 Contractor termination

34.2 Written agreement of the Parties

34.3 Entering into a new Agreement

<PAGE>

In witness the Parties sign this Operation Agreement in ECOPETROL contract paper

on the 30th (30) day of the month of December; 1997.

EMPRESA COLOMBIANA DE PETROLEOS "ECOPETROL"

Enrique Amorocho Cortes

President

SEVEN SEAS PETROLEUM COLOMBIA INC.

Gustavo Vasco Munoz

Legal Representative

Witnesses

</TEXT>

</DOCUMENT>

<DOCUMENT>

<TYPE>EX-27

<SEQUENCE>4

<TEXT>

<TABLE> <S> <C>

<ARTICLE> 5

<LEGEND>

THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE

CONSOLIDATED BALANCE SHEETS AND STATEMENTS OF CONSOLIDATED OPERATIONS AND

ACCUMULATED DEFICIT ON PAGES F-2 AND F-3 OF THE COMPANY'S FORM 10-K FOR

THE YEAR ENDED DECEMBER 31, 1997, AND IS QUALIFIED IN ENTIRETY BY REFERENCE

TO SUCH FINANCIAL STATEMENTS.

</LEGEND>

<S>

<PERIOD-TYPE>

<FISCAL-YEAR-END>

<PERIOD-END>

<CASH>

<SECURITIES>

<RECEIVABLES>

<ALLOWANCES>

<INVENTORY>

<CURRENT-ASSETS>

<PP&E>

<DEPRECIATION>

<TOTAL-ASSETS>

<CURRENT-LIABILITIES>

<BONDS>



<C>

YEAR

DEC-31-1997

DEC-31-1997

18,067

44

3,865

0

0

22,095

251,984

43

291,914

8,205

25,000



<PREFERRED-MANDATORY>

<PREFERRED>

<COMMON>

<OTHER-SE>

<TOTAL-LIABILITY-AND-EQUITY>

<SALES>

<TOTAL-REVENUES>

<CGS>

<TOTAL-COSTS>

<OTHER-EXPENSES>

<LOSS-PROVISION>

<INTEREST-EXPENSE>

<INCOME-PRETAX>

<INCOME-TAX>

<INCOME-CONTINUING>

<DISCONTINUED>

<EXTRAORDINARY>

<CHANGES>

<NET-INCOME>

<EPS-PRIMARY>

<EPS-DILUTED>



0

0

196,406

0

291,914

780

1,567

907

9,789

0

0

0

(7,928)

0

(7,928)

0

0

0

(7,928)

(.24)

(.24)



</TABLE>

</TEXT>

</DOCUMENT>

<DOCUMENT>

<TYPE>EX-23

<SEQUENCE>5

<TEXT>

EXHIBIT 23

CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS



As independent public accountants, we hereby consent to the incorporation of our

reports included in this Form 10-K, into the Company's previously filed

Registration Statement on Form S-8 File No. 333-46749.



ARTHUR ANDERSEN LLP

Houston, Texas

March 31, 1998

</TEXT>

</DOCUMENT>

</SEC-DOCUMENT>

-----END PRIVACY-ENHANCED MESSAGE----