SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
FOR FISCAL YEAR ENDED DECEMBER 31, 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 73-1468669
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
SUITE 960, THREE POST OAK CENTRAL
1990 POST OAK BOULEVARD
HOUSTON, TEXAS 77056
(Address of principal executive offices) (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.[ ]
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TABLE OF CONTENTS TO FORM 10-K
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PAGE
PART I
<S> <C> <C>
Item 1. Business ..................................................... 2
Risk Factors.................................................. 6
Item 2. Properties ................................................... 12
Item 3. Legal Proceedings ............................................ 20
Item 4. Submission of Matters to a Vote of Security Holders........... 20
PART II
Item 5. Market for Registrant's Common Equity and Related ............ 21
Item 6. Selected Financial Data ...................................... 21
Item 7. Management's Discussion and Analysis of Financial............. 22
Item 8. Financial Statements and Supplementary Data................... 26
Item 9. Changes in and Disagreements with Accountants on Accounting... 27
and Financial Disclosure
PART III
Item 10. Directors and Executive Officers of the Registrant .......... 28
Item 11. Executive Compensation....................................... 32
Item 12. Security Ownership of Certain Beneficial Owners and ......... 40
Management
Item 13. Certain Relationships and Related Transactions .............. 41
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K ......................................................... 42
Signatures ................................................... 46
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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 12,000 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
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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
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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 Bbls/d to 13,123 Bbls/d with an
average in excess of 7,079 barrels per day. The table below sets forth drilling
results to date on Emerald Mountain.
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MAXIMUM
ACTUAL
MAXIMUM ACTUAL GAS TEST
DATE VERTICAL DEPTH OIL TEST RATE RATE
WELL NAME COMPLETED (FEET) (BBS/D) (1) (MCF/D) DESCRIPTION
--------- --------- ------ ----------- ------- -----------
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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 north of ES 1-E; 1,168'
below ES 1-N
El Segundo 3-E (3) 8,021 (3) (3) Drilled 2.8 miles south of ES 1-E;
temporarily abandoned
Tres Pasos 1-E 10/97 6,200 13,123 6,000 Drilled 600' downdip to Northwest of ES 1-E
Tres Pasos 2-E 2/98 6,054 (4) (4) Drilled 5.6 miles to Northwest of ES 1-E
- ---------------
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(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 Bbls/d 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 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
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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 also is
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
Rosa Blanca 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.
During 1998, the Company expects to reprocess and evaluate 2-D seismic on the
Montecristo and Rosa Blanca 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
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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% 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
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received preliminary plans and engineering specifications for the construction
of pipelines and production facilities. 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 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 "Business-
Properties-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 6054 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
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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. ("Mohave") (10.205%), Doreal Energy (11.67%) and Heritage
Minerals Colombia ("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 BOPD in a short-term test, but was not
completed for production. Since the well was drilled and tested, additional oil
15
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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 market. 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%.
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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)................................... 32,160
Gas (MMcf).................................... -
Total (MBOE) ................................. 32,160
Net proved developed:
Oil (MBbls)................................... 11,494
Gas (MMcf).................................... -
Total (MBOE) ................................. 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
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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............ 14,459 94,579 8,343 54,572
Monte Cristo/Rosa Blanca. - 692,179 - 519,134
Tapir.................... - 232,613 - 27,623
Papua New Guinea........... - 1,200,000 - 1,200,000
Australia.................. - 2,394,546 - 429,978
- --------- - -------
Total.................... 14,459 4,613,917 8,343 2,231,307
======== ========= ===== =========
(1) Based on the Company's 57.7% working interest (before Colombian Government
participation).
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
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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 35 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. Due to
capacity limitations on the OAM pipeline, Phase I of the transportation plan is
expected to provide shipment of crude oil at a rate of approximately 50,000
barrels per day. 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.
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<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
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<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:
TOTAL
HIGH LOW VOLUME
---- --- ------
1996
First Quarter ............................... 6.75 0.55 8,402,885
Second Quarter .............................. 10.50 5.25 1,974,615
Third Quarter ............................... 20.00 7.00 6,655,958
Fourth Quarter .............................. 25.75 14.75 8,537,978
1997
First Quarter (through February 7,1997) ..... 19.00 15.00 3,018,441
First Quarter (since February 10, 1997) ..... 17.40 9.00 3,718,929
Second Quarter .............................. 13.10 8.25 3,200,200
Third Quarter ............................... 14.10 9.60 3,941,940
Fourth Quarter .............................. 20.05 11.80 7,541,766
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data should be read in conjunction with
the Consolidated Financial Statements and Notes thereto included herein.
PERIOD FROM
INCEPTION
FEBRUARY 3,
YEAR ENDED DECEMBER 31, 1995 TO
----------------------- DECEMBER 31,
1997 1996 1995
---- ---- ----
INCOME STATEMENT DATA: (in thousands, except per share amounts)
Revenues............................ $ 1,567 $ 575 $ 152
Net loss............................ (7,928) (2,195) (2,120)
Net loss per common share........... (0.24) (0.17) (0.23)
Weighted average shares outstanding. 32,505 12,972 9,247
BALANCE SHEET DATA (END OF PERIOD):
Cash and cash equivalents........... $ 18,067 $ 10,620 $ 3,366
Total assets........................ 291,914 235,501 4,170
Current liabilities................. 8,205 2,806 120
Minority interest................... 4,087 1,060 --
Stockholders' equity................ 184,163 167,667 4,050
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<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
MMBbls, 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. Final government approval of the agreement is pending. 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> <C>
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........................................... F-6
</TABLE>
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 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>
SUPPLEMENTARY FINANCIAL INFORMATION (unaudited)
SELECTED QUARTERLY DATA. Results of development stage operations by
quarter for the years ended December 31, 1997, and 1996 were:
<TABLE>
<CAPTION>
(in thousands, except per share amounts)
1997 QUARTER ENDED
-----------------------------------------------------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- ------- -------- -------
<S> <C> <C> <C> <C>
Operating revenues $ 434 $ 237 $ 308 $ 588
Less costs and expenses 1,194 2,408 1,340 4,847
(760) (2,171) (1,032) (4,259)
---------- --------- ------- ---------
Minority Interest 38 35 59 162
---------- --------- ------- ---------
Net loss $ (722) $ (2,137) $ (972) $(4,097)
========= ========= ======= =========
Net loss per share $(.03) $(.06) $ (.03) $(.12)
========= ========= ======= =========
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)
Minority Interest 64
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>
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, DECEMBER 31,
1997 1996
-------------- -------------
ASSETS
<S> <C> <C>
CURRENT
Cash and cash equivalents $ 18,067,189 $ 10,620,477
Marketable securities 43,795 43,795
Accounts receivable 3,865,180 1,241,430
Prepaids and other 118,447 -
------------ ------------
22,094,611 11,905,702
Note receivable from related party 200,000 -
Evaluated oil and gas interests, full-cost method 46,116,873 1,611,665
Unevaluated oil and gas interests, full-cost method 221,713,473 221,884,126
Fixed assets, net of accumulated depreciation of $42,716 at
December 31, 1997 and $12,194 at December 31, 1996 303,623 74,219
Other assets, net of accumulated amortization of $194,166
at December 31, 1997 and $76,622 at December 31, 1996 1,485,544 25,270
------------ ------------
TOTAL ASSETS $ 291,914,124 $ 235,500,982
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT
Accounts payable $ 6,885,573 $ 2,560,665
Accrued compensation 1,228,000 -
Other accrued liabilities 91,917 245,000
------- -------
8,205,490 2,805,665
Long-term debt 25,000,000 -
Deferred income taxes 70,458,512 63,967,775
Minority interest 4,087,022 1,060,433
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 196,405,889 6,781,616
Preferred share subscriptions - 5,002,972 shares at
December 31, 1996 - 45,652,120
Special warrant subscriptions - 14,274,171 warrants at
December 31, 1996 - 119,548,227
Deficit accumulated during development stage (12,242,557) (4,314,622)
Treasury stock, 29 shares held at December 31, 1997 and
December 31, 1996 (232) (232)
----- -----
Total Stockholders' Equity 184,163,100 167,667,109
-------------- -------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 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>
CUMULATIVE
TOTAL FROM INCEPTION TOTAL FROM INCEPTION
(FEBRUARY 3, 1995) (FEBRUARY 3, 1995)
YEAR ENDED DECEMBER 31, TO DECEMBER 31, TO DECEMBER 31,
----------------------- --------------- ---------------
1997 1996 1995 1997
---- ---- ---- ----
<S> <C> <C> <C> <C>
REVENUE
Crude oil sales $ 779,767 $ 233,682 $ - $ 1,013,449
Interest income 787,189 341,599 152,383 1,281,171
--------- ---------- --------- ----------
1,566,956 575,281 152,383 2,294,620
EXPENSES
General and administrative 8,714,333 2,454,884 1,070,765 12,239,982
Lease operating expenses 907,218 252,504 - 1,159,722
Depreciation and amortization 148,065 111,334 37,671 297,070
Dry hole and abandonment costs 16,952 4,910 1,122,806 1,144,668
Geological and geophysical 27,372 10,521 9,769 47,662
Other (income) expense (25,331) - - (25,331)
Loss on sale of resource properties - - 31,357 31,357
--------- ---------- --------- ----------
9,788,609 2,834,153 2,272,368 14,895,130
NET LOSS BEFORE MINORITY INTEREST (8,221,653) (2,258,872) (2,119,985) (12,600,510)
MINORITY INTEREST 293,718 64,235 - 357,953
--------- ---------- --------- ----------
NET LOSS $ (7,927,935) $ (2,194,637) $ (2,119,985) $ (12,242,557)
============= ============= ============= ==============
DEFICIT ACCUMULATED DURING THE
DEVELOPMENT STAGE , BEGINNING OF PERIOD (4,314,622) (2,119,985) - -
DEFICIT ACCUMULATED DURING THE
DEVELOPMENT STAGE , END OF PERIOD $ (12,242,557) $ (4,314,622) $ (2,119,985) $ (12,242,557)
============== ============= ============= ==============
BASIC AND DILUTED NET LOSS PER COMMON SHARE $ (0.24) $ (0.17) $ (0.23) $ (0.66)
======== ======== ======== ========
WEIGHTED AVERAGE
COMMON SHARES OUTSTANDING 32,504,872 12,971,871 9,247,101 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>
COMMON STOCK
-----------------------
DATE NUMBER AMOUNT
---- -------- ------
<S> <C> <C> <C>
Issuance of common share to founder February 3, 1995 1 $ -
Issuance of common shares to founder for cash February 27, 1995 999,999 1
Issuance of common shares in a private placement for cash
($0.25 per share) March 22, 1995 4,000,000 1,000,000
Issuance of common shares in private placements for cash
($0.75 per share): May 31, 1995 5,687,666 4,265,750
June 9, 1995 979,000 734,250
Issuance of common shares in settlement of agents' fees
($0.75 per share): May 31,1995 284,383 213,287
June 9, 1995 48,950 36,713
Less: Common share issuance cost May 31 - June 9, 1995 - (250,000)
Issuance of common shares in connection with the May 5, 1995
amalgamation agreement with Rusty Lake Resouces ($0.25 per share) June 29-30, 1995 680,464 170,116
Net loss - -
---------- ---------
BALANCE AT DECEMBER 31, 1995 12,680,463 6,170,117
Issuance of special warrants in a brokered private placement for cash
($2.75 per warrant) March 15, 1996 - -
Issuance of common shares to the Company's 401(k) plan
($7.875 per share) April 29,1996 10,000 78,750
Purchase Treasury Stock ($8.00 per share) June 26, 1996 - -
Exercise of stock options for cash ($.75 per share) Jan. - June 1996 305,000 228,750
Exercise of stock options for cash ($7.125 per share) April 29, 1996 10,000 71,250
Issuance of exchangeable preferred stock in connection with business
combination ( $9.125 per share) July 26, 1996 - -
Issuance of special warrants in connection with business combination
( $9.125 per warrant) July 26, 1996 - -
Issuance of convertible special warrants in a brokered private placement
for cash ($15.00 per warrant) October 16, 1996 - -
Exercise of stock options for cash ($.75 per share) July - December 1996 310,333 232,749
Net loss - -
---------- ---------
BALANCE AT DECEMBER 31, 1996 13,315,796 6,781,616
Conversion of special warrants issued in connection with the business
combination dated July 26, 1996 ($9.125 per share) February 7, 1997 11,774,171 107,439,309
Conversion of the preferred shares in connection with the business
combination dated July 26, 1996 ($9.125 per share) February 7, 1997 5,002,972 45,652,120
Conversion of privately placed special warrants ($15.00 per warrant) February 7, 1997 500,000 7,013,370
Conversion of privately placed special warrants ($2.75 per warrant) February 7, 1997 2,000,000 5,095,548
Issuance of common shares in connection with the business combination
($18.55 per share) March 5, 1997 1,000,000 18,550,000
Conversion of privately placed special warrants for cash
($3.50 per warrant) March 14, 1997 1,000,000 3,500,000
Exercise of stock options ($.75 - 10.90 per share) Jan.-December 1997 478,667 2,373,926
Net loss - -
--------------- -------------
BALANCE AT DECEMBER 31, 1997 35,071,606 $ 196,405,889
=============== =============
STATEMENT OF CONSOLIDATED STOCKHOLDERS' EQUITY
FOR THE PERIOD FROM INCEPTION (FEBRUARY 3, 1995) THROUGH DECEMBER 31, 1997
(Continued)
PREFERRED STOCK SPECIAL WARRANTS
-------------------- ---------------------
NUMBER AMOUNT NUMBER AMOUNT
------ ------ ------ ------
Issuance of common share to founder - $ - - $ -
Issuance of common shares to founder for cash - - - -
Issuance of common shares in a private placement for cash
($0.25 per share) - - - -
Issuance of common shares in private placements for cash
($0.75 per share): - - - -
- - - -
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) - - 2,000,000 5,095,548
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) 5,002,972 45,652,120 - -
Issuance of special warrants in connection with business combination
( $9.125 per warrant) - - 11,774,171 107,439,309
Issuance of convertible special warrants in a brokered private placement
for cash ($15.00 per warrant) - - 500,000 7,013,370
Exercise of stock options for cash ($.75 per share) - - - -
Net loss - - - -
BALANCE AT DECEMBER 31, 1996 5,002,972 45,652,120 14,274,171 119,548,227
Conversion of special warrants issued in connection with the business
combination dated July 26, 1996 ($9.125 per share) - - (11,774,171) (107,439,309)
Conversion of the preferred shares in connection with the business
combination dated July 26, 1996 ($9.125 per share) (5,002,972) (45,652,120) - -
Conversion of privately placed special warrants ($15.00 per warrant) - - (500,000) (7,013,370)
Conversion of privately placed special warrants ($2.75 per warrant) - - (2,000,000) (5,095,548)
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 - $ - - $ -
=========== =========== =========== ============
STATEMENT OF CONSOLIDATED STOCKHOLDERS' EQUITY
FOR THE PERIOD FROM INCEPTION (FEBRUARY 3, 1995) THROUGH DECEMBER 31, 1
(Continued)
DEFICIT
ACCUMULATED
TREASURY STOCK DURING
----------------- DEVELOPMENT
NUMBER AMOUNT PHASE TOTAL
------ ------ ----- -----
Issuance of common share to founder - $ - $ - $ -
Issuance of common shares to founder for cash - - - 1
Issuance of common shares in a private placement for cash
($0.25 per share) - - - 1,000,000
Issuance of common shares in private placements for cash
($0.75 per share): - - - 4,265,750
- - - 734,250
Issuance of common shares in settlement of agents' fees
($0.75 per share): - - - 213,287
- - - 36,713
Less: Common share issuance cost - - - (250,000)
Issuance of common shares in connection with the May 5, 1995
amalgamation agreement with Rusty Lake Resouces ($0.25 per share) - - - 170,116
Net loss - - (2,119,985) (2,119,985)
BALANCE AT DECEMBER 31, 1995 - - (2,119,985) 4,050,132
Issuance of special warrants in a brokered private placement for cash
($2.75 per warrant) - - - 5,095,548
Issuance of common shares to the Company's 401(k) plan
($7.875 per share) - - - 78,750
Purchase Treasury Stock ($8.00 per share) 29 (232) - (232)
Exercise of stock options for cash ($.75 per share) - - - 228,750
Exercise of stock options for cash ($7.125 per share) - - - 71,250
Issuance of exchangeable preferred stock in connection with business
combination ( $9.125 per share) - - - 45,652,120
Issuance of special warrants in connection with business combination
( $9.125 per warrant) - - - 107,439,309
Issuance of convertible special warrants in a brokered private placement
for cash ($15.00 per warrant) - - - 7,013,370
Exercise of stock options for cash ($.75 per share) - - - 232,749
Net loss - - (2,194,637) (2,194,637)
BALANCE AT DECEMBER 31, 1996 29 (232) (4,314,622) 167,667,109
Conversion of special warrants issued in connection with the business
combination dated July 26, 1996 ($9.125 per share) - - - -
Conversion of the preferred shares in connection with the business
combination dated July 26, 1996 ($9.125 per share) - - - -
Conversion of privately placed special warrants ($15.00 per warrant) - - - -
Conversion of privately placed special warrants ($2.75 per warrant) - - - -
Issuance of common shares in connection with the business combination
($18.55 per share) - - - 18,550,000
Conversion of privately placed special warrants for cash
($3.50 per warrant) - - - 3,500,000
Exercise of stock options ($.75 - 10.90 per share) - - - 2,373,926
Net loss - - (7,927,935) (7,927,935)
----- ------- ----------- -----------
BALANCE AT DECEMBER 31, 1997 29 $ (232) $ (12,242,557) $ 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>
TOTAL FROM CUMULATIVE TOTAL
INCEPTION FROM INCEPTION
(FEBRUARY 3, 1995) (FEBRUARY 3, 1995)
YEAR ENDED DECEMBER 31, TO DECEMBER 31, TO DECEMBER 31,
-----------------------
1997 1996 1995 1997
---- ---- ---- ----
<S> <C> <C> <C> <C>
OPERATING ACTIVITIES
Net loss $ (7,927,935) $ (2,194,637) $ (2,119,985) $ (12,242,557)
Add (subtract) items not requiring (providing) cash:
Compensation Expense 2,140,250 - - 2,140,250
Minority interest (293,718) (64,235) - (357,953)
Common stock contribution to 401(k) retirement plan - 78,750 - 78,750
Dry hole and abandonment costs 16,952 - 1,122,806 1,139,758
Loss on sale of resource properties - - 31,357 31,357
Depreciation and amortization 148,065 111,334 37,671 297,070
Changes in working capital excluding changes to
cash and cash equivalents:
Accounts receivable (2,082,750) (316,431) (43,642) (2,442,823)
Prepaids and other, net (118,447) 482 (482) (118,447)
Accounts payable 1,389,194 (17,472) 120,305 1,492,027
Other accrued liabilities (153,083) 245,000 - 91,917
------------ ----------- ----------- ------------
Cash Flow Used in Operating Activities (6,881,472) (2,157,209) (851,970) (9,890,651)
------------ ----------- ----------- ------------
INVESTING ACTIVITIES
Exploration of oil and gas properties (16,359,726) (4,309,446) (1,696,943) (22,366,115)
Proceeds from acquisition - 630,226 - 630,226
Proceeds from sale of property - - 84,336 84,336
Note Receivable from related party (200,000) - - (200,000)
Other asset additions (280,194) (64,135) (169,821) (514,150)
------------ ----------- ----------- ------------
Cash Flow Used in Investing Activities (16,839,920) (3,743,355) (1,782,428) (22,365,703)
------------ ----------- ----------- ------------
FINANCING ACTIVITIES
Proceeds from special warrants issued - 12,108,917 - 12,108,917
Proceeds from share capital issued 4,961,726 532,750 6,000,001 11,494,477
Proceeds from additional paid-in capital contributed - 999 - 999
Proceeds from issuance of special notes 25,000,000 - - 25,000,000
Costs of issuing special notes (1,572,929) - - (1,572,929)
Contributions by minority interest 2,779,307 513,004 - 3,292,311
Purchase of treasury stock - (232) - (232)
------------ ----------- ----------- ------------
Cash Flow Provided by Financing Activities 31,168,104 13,155,438 6,000,001 50,323,543
------------ ----------- ----------- ------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 7,446,712 7,254,874 3,365,603 18,067,189
Cash and cash equivalents, beginning of period 10,620,477 3,365,603 - -
------------ ----------- ----------- ------------
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 18,067,189 $ 10,620,477 $ 3,365,603 $ 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 participating 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 Bbls/d 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
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 $ 3,370
Goods and services tax receivable 3,099
Resource properties 115,693
Other assets (organization costs) 87,481
Accounts payable (39,527)
Share capital (680,464 shares) (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 DECEMBER 31, 1996
---------------- -----------------
Crude oil sales $ 291,049 $ 58,845
Joint interest billing 3,013,318 1,117,635
Advances 541,000 -
Other 19,813 64,950
------ ------
Total Accounts
Receivable $ 3,865,180 $ 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 DECEMBER 31, 1996
---------------- -----------------
Cash $ 2,156,973 $ 170,684
Short-term investments 15,910,216 10,449,793
---------- ----------
Total cash and cash
equivalents $ 18,067,189 $ 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 income taxes and minority
interest were as follows:
<TABLE>
<CAPTION>
PERIOD ENDED PERIOD ENDED PERIOD ENDED
DECEMBER 31,1997 DECEMBER 31, 1996 DECEMBER 31, 1995
---------------- ----------------- -----------------
<S> <C> <C>
United States $ (4,515,142) (277,456) -
Foreign (3,698,778) (1,979,078) (2,119,985)
----------- ------------ -----------
Loss before Minority $ (8,213,920) $ (2,256,534) $ (2,119,985)
interest
=============== ================ ==============
</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 DECEMBER 31, 1996
---------------- -----------------
Deferred Tax Liabilities $ 70,458,512 63,967,775
Deferred Tax Asset 3,128,306 2,058,506
Valuation Allowance (3,128,306) (2,058,506)
----------- -----------
Total Deferred Tax
Liabilities $ 70,458,512 $ 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:
WEIGHTED AVERAGE
OPTION PRICE PER
COMMON SHARES SHARE
Granted 985,000 $ .75
------------------------------ ------------------------- ---------------------
DECEMBER 31, 1995 985,000 .75
Granted 805,000 12.86
Exercised (625,333) .85
------------------------------ ------------------------- ---------------------
DECEMBER 31, 1996 1,164,667 9.07
Granted 3,197,500 13.56
Exercised (478,667) 3.05
Revoked (5,000) 12.25
------------------------------ ------------------------- ---------------------
DECEMBER 31, 1997 3,878,500 $ 13.51
------------------------------ ------------------------- ---------------------
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> <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
----------------- ----------------- -----------------
<S> <C> <C> <C>
Pro Forma Net Loss ($32,426,733) ($5,938,372) ($2,309,940)
Pro Forma
Net Loss per Share ($1.00) ($.46) ($.25)
</TABLE>
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 UNITED STATES COLOMBIA OTHER FOREIGN AREAS TOTAL
<S> <C> <C> <C> <C> <C>
Year ended December 31, 1997
Revenues $ 753,433 $ 2,020 $ 810,077 $ 1,426 $ 1,566,956
Operating Loss (1,773,051) (4,515,142) (1,837,368) (88,359) (8,213,920)
Capital Expenditures - 57,572 19,050,432 471,046 19,579,050
Identifiable Assets 17,462,002 488,463 272,981,939 981,720 291,914,124
Depreciation and Amortization 110,695 20,708 16,662 - 148,065
CANADA UNITED STATES COLOMBIA OTHER FOREIGN AREAS TOTAL
Year ended December 31, 1996
Revenues $ 333,598 $ - $ 239,345 $ 2,338 $ 575,281
Operating Loss (1,399,866) (277,456) (438,948) (140,264) (2,256,534)
Capital Expenditures - - 4,335,166 271,405 4,606,571
Identifiable Assets 10,497,084 46,939 224,436,899 520,060 235,500,982
Depreciation and Amortization - 66,490 42,755 2,089 111,334
CANADA COLOMBIA ARGENTINA NORTH AFRICA OTHER FOREIGN AREAS TOTAL
Period from inception through December 31, 1995
Revenues $ 147,372 $ - $ - $ - $ 5,011 $ 152,383
Operating Loss (863,787) (3,147) (625,771) (509,878) (117,402) (2,119,985)
Capital Expenditures - 369,723 622,006 500,800 204,414 1,696,943
Identifiable Assets 3,565,647 385,999 - - 218,791 4,170,437
Depreciation and Amortization 36,875 297 - - 499 37,671
</TABLE>
10. 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: $83,683 for 1997; $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
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:
Colombia Others Total
------------ --------- -------------
As of December 31, 1997
Proved properties .................... $ 46,116,873 $ -- $ 46,116,873
============ ========= =============
Unproved properties .................. $220,771,518 $ 941,955 $ 221,713,473
Less: Dry Hole and Abandonment ....... -- -- --
------------ --------- -------------
Unproved properties, net ............. $220,771,518 $ 941,955 $ 221,713,473
============ ========= =============
As of December 31, 1996
Proved properties .................... $ 1,611,665 $ -- $ 1,611,665
============ ========= =============
Unproved properties .................. $221,413,217 $ 475,819 $ 221,889,036
Less: Dry Hole and Abandonment ....... -- (4,910) (4,910)
------------ --------- -------------
Unproved properties, net ............. $221,413,217 $ 470,909 $ 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> <C>
Year ended December 31, 1997
Development cost ..................$ 165,829 $ -- $ -- $ -- $ 165,829
Property acquisition cost:
Proved ........................ 5,454,064 -- -- -- 5,454,064
Unproved ...................... 26,072,373 -- -- -- 26,072,373
Exploration cost .................. 12,171,243 -- -- 471,046 12,642,289
Total cost incurred ...........$ 43,863,509 $ -- $ -- $471,046 $ 44,334,555
Year ended December 31, 1996
Property acquisition cost:
Proved ........................$ 1,554,041 $ -- $ -- $ -- $ 1,554,041
Unproved ...................... 215,536,257 -- -- 250,000 215,786,257
Exploration cost .................. 5,564,861 -- -- 21,405 5,586,266
Total cost incurred ...........$222,655,159 $ -- $ -- $271,405 $222,926,564
Year ended December 31, 1995
Property acquisition cost:
Proved ........................$ -- $ -- $ -- $ -- $ --
Unproved ...................... 106,383 75,000 500,800 6,073 688,256
Exploration cost .................. 263,340 547,006 -- 198,341 1,008,687
Total cost incurred ...........$ 369,723 $622,006 $500,800 $204,414 $ 1,696,943
</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
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):
1997 1996
----------- ----------
Beginning of year ................... 818,000 --
Extensions and discoveries .......... 31,342,245 818,000
End of year ......................... 32,160,245 818,000
Proved developed .................... 11,494,236 408,000
The following table presents the standardized measure of discounted
future net cash flows relating to proved oil reserves. Future cash
inflows and costs were computed using prices and costs in effect at the
end of the year without escalation less a gravity and transportation
adjustment of $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> <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>
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
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, Executive Vice
President, and Chief Operating
Officer
Herbert C. Williamson, III.................. 49 Director, Executive Vice
President, and Chief Financial
Officer
</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) $50,000 or (ii) 10% of individual
combined salary and bonus for the Named Executive Officers in that year.
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
LONG TERM COMPENSATION
-------------------------
ANNUAL COMPENSATION AWARDS PAYOUTS
------------------- ------ -------
OTHER SECURITIES ALL
ANNUAL RESTRICTED UNDERLYING LTIP OTHER
NAME AND COMPEN- STOCK OPTIONS/SARS PAYOUTS COMPEN-
PRINCIPLE POSITION YEAR SALARY($) BONUS($) SATION($) AWARDS($) (#) ($) SATION($)
- ------------ ---- --------- -------- --------- --------- --- --- ---------
<S> <C> <C> <C> <C> <C> <C>
Robert A. Hefner III ................ 1997 -0- -0- -0- -0- 450,000 -0- -0-
Chairman, Chief 1996 -0- -0- -0- -0- 50,000(7) -0- -0-
Executive Officer and
Managing Director
Malcolm Butler (4)................... 1997 13,301 -0- -0- -0- 200,000 -0- 250,000
Chief Executive
Officer
Albert E Whitehead (4)............... 1997 77,308 -0- -0- -0- 50,000 -0- 125,000(4)
Chairman and Chief 1996 150,000 -0- -0- -0- 185,000 -0- 14,634(3)
Executive Office 1995 125,000 -0- -0- -0- 200,000 -0- -0-
Timothy T Stephens (4)............... 1997 67,644 -0- -0- -0- 50,000 -0- 525,000(4)
President 1996 135,000 93,840 -0- -0- 172,000(5) -0- 13,170(3)
1995 106,875 -0- -0- -0- 250,000 -0- -0-
Larry A. Ray (2)..................... 1997 139,062 -0- -0- -0- 550,000 -0- 33,330(3)
Executive Vice-
President, Chief
Operating Officer, and
Director
John P. Dorrier (6) ................. 1997 107,981 -0- -0- -0- 40,000 -0- 392,019
Executive Vice- 1996 120,000 83,520 -0- -0- 151,000 -0- 11,707(3)
President 1995 80,000 -0- -0- -0- 125,000 -0- -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 $18.75 for his participation as a member of the Board of Directors.
32
<PAGE>
OPTION/SAR GRANTS DURING 1997
The following table sets forth information regarding individual grants of
Options by the Company during the fiscal year ended December 31, 1997 to each of
the Named Executive Officers, and their potential realizable values.
INDIVIDUAL GRANTS
-----------------------------------------------
<TABLE>
<CAPTION>
POTENTIAL
REALIZABLE VALUE
NUMBER OF AT ASSUMED ANNUAL
SHARES EXERCISE RATES OF SHARE
UNDERLYING OR PRICE APPRECIATION
OPTIONS/SARS % OF TOTAL BASE FOR OPTION TERM(1)
GRANTED OPTIONS/SARS PRICE EXPIRATION --------------------
NAME (#) GRANTED ($/SH) DATE 5% 10%
- ---- --- ------- ------ ---- -- ---
<S> <C> <C> <C> <C> <C> <C> <C>
Robert A. Hefner III .................. 300,000 9.4% $10.70 07/17/2007 2,018,752 5,115,913
150,000(2) 4.7% 18.55 11/24/2007 1,749,899 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 6.3% $10.70 06/12/2007 1,345,835 3,410,609
200,000(3) 6.3% 13.23 09/08/2007 1,664,835 4,217,043
150,000(2) 4.7% 18.55 11/24/2007 1,749,899 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% $10.90 04/30/2002 120,459 266,182
</TABLE>
(1) The assumed rates of annual appreciation are calculated from the date of
grant through the assumed expiration date. Actual gains, if any, on stock
option exercises and Common Share holdings are dependent on the future
performance of the Common Shares and overall stock market conditions. There
can be no assurance that the value reflected in the table will be achieved.
(2) Subject to shareholder approval at the 1998 annual meeting.
(3) 105,000 of the options granted to Mr. Ray on September 9, 1997 are subject
to shareholder approval at the 1998 annual meeting.
33
<PAGE>
OPTION EXERCISES DURING 1997 AND FISCAL YEAR END OPTION VALUES
The following table provides information related to Options exercised by the
Named Officers during 1997 and the number and value of unexercised Options held
by the Named Executive Officers at year-end. The Company does not have any
outstanding stock appreciation rights.
<TABLE>
<CAPTION>
SHARES VALUE OF UNEXERCISED
ACQUIRED NUMBER OF UNEXERCISED IN-THE-MONEY
ON VALUE OPTIONS, WARRANTS/SARS AT OPTIONS, WARRANTS/SARS
EXERCISE REALIZED FISCAL YEAR-END (#)(1) AT FISCAL YEAR-END ($)(2)
-------- -------- ----------------------------- ----------------------------
(#) ($)(1) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
--- ------ ----------- ------------- ----------- -------------
<S> <C> <C> <C> <C> <C> <C>
NAME
- ----
Robert A. Hefner III ............... -0- -0- 150,000 350,000 685,000 1,370,000
Malcolm Butler ..................... -0- -0- 200,000 -0- 1,330,000 -0-
Albert E. Whitehead ................ -0- -0- 235,000 -0- 1,375,000 -0-
Larry A. Ray ....................... -0- -0- 66,666 483,334 456,662 1,777,338
Timothy T. Stephens ................ 21,667 282,420 222,000 -0- 1,270,750 -0-
John P. Dorrier .................... 131,000 1,883,089 135,000 -0- 576,600 -0-
</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),
(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.
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<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
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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
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<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.
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<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.
NUMBER OF
COMMON PERCENT
BENEFICIAL OWNER SHARES (1) OF CLASS
- ---------------- ---------- --------
Robert A. Hefner III............................ 6,565,300(2) 19%
c/o Seven Seas Petroleum Inc.
Suite 960, Three Post Oak Central
1990 Post Oak Boulevard
Houston, Texas 77056
Breene M. Kerr.................................. 3,048,417(3) 9%
c/o Brookside Company
115 Bay Street
Easton, Maryland 21601
George Soros and Stanley F. Drunkenmiller....... 3,058,000 9%
888 Seventh Avenue, 33rd Floor
New York, NY 10106
Robert W. Moore................................. 2,184,900 6%
MTV Investments Limited Partnership
3600 West Main Street, Suite 150
Norman, Oklahoma 73072
Brian Egolf..................................... 126,386(4) *
Sir Mark Thomson Bt............................. 452,566(5) 1%
Robert B. Panero................................ 17,445(6) *
Gary F. Fuller.................................. 27,000(7) *
James D. Scarlett............................... 25,000(7) *
Herbert C. Williamson, III 150,256(8) *
Timothy T. Stephens............................. 353,500(9)(15) 1%
Albert E. Whitehead............................. 1,246,758(10)(15) 4%
Malcom Butler................................... 200,000 *
Larry A. Ray.................................... 193,887(11) *
John P. Dorrier................................. 277,486(13)(15) *
All executive officers and directors as a group 12,684,001
(13 persons).................................... (14) 36%
- -----------------
* Less than 1%
(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.
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<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.
(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 of more than
6% of the Company and owner of the minority interest in Cimarrona LLC, a
consolidated subsidiary of the Company. Resulting from cash calls to fund oil
and gas exploration activities, an account receivable of $541,000 was due from
MTV at December 31, 1997.
41
<PAGE>
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 dated as of
July 26, 1996 by and between the Company and
certain individuals
*(I) Shareholders' Voting Support Agreement dated as
of July 26, 1996 by and between Seven Seas
Petroleum Inc. and Messrs. Hefner, Kerr,
Whitehead, Plewes and Stephens
*(J) Management Services Agreement by and among GHK
Company Colombia, the Company and The GHK Company LLC
*(K) The Escrow Agreement for a Natural Resources Company by
and among Montreal Trust Company as trustee, the Company
and certain individuals and entities
*(L) The Escrow Agreement for a Natural Resources
Company by and among Montreal Trust Company, as
trustee, the Company and Albert E. Whitehead
*(M) Amended 1996 Stock Option Plan
*(N) Form of Incentive Stock Option Agreement
*(O) Form of Directors' Stock Option Agreement
*(P) Form of Employment Agreement between the Company
and each of Messrs. Stephens, Dorrier and DeCort
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 Agreement between the Company
and Larry A. Ray
*(S) Settlement Agreement between the Company and
Mr. Whitehead dated May 20, 1997
*(T) Petrolinson S.A. Share Purchase Agreement dated
February 14, 1997, between Hazel Ventures LTD., Seven Seas
Petroleum Colombia Inc. and Seven Seas Petroleum Inc.
*(U) Pledge Agreement dated March 5, 1997 among Hazel
Ventures LTD., Seven Seas Petroleum Inc., Seven Seas
Petroleum Colombia Inc., and Integro Trust (BVI Limited)
*(V) Shareholder Voting Support Agreement made as of March
5, 1997 between Seven Seas Petroleum Inc. and Hazel
Ventures LTD.
*(W) Purchase Warrant Indenture made as of August 7, 1997
between Seven Seas Petroleum Inc. and Montreal Trust
Company of Canada
*(X) Indenture made as of August 7, 1997 between Seven Seas
Petroleum Inc. and Montreal Trust Company of Canada
*(Y) Limited Recourse Guarantee, Security and Pledge
Agreement made as of August 7, 1997 between Seven Seas
Petroleum Holdings Inc. and Montreal Trust Company of
Canada
*(Z) Limited Recourse Guarantee, Security and Pledge
Agreement made as of August 7, 1997 between Seven Seas
Petroleum Colombia Inc. and Montreal Trust Company of
Canada
*(AA) Private Placement Subscription Agreement made as of
August 7, 1997 between Seven Seas Petroleum Inc. and
Jasopt Pty Limited
*(BB) 1997 Stock Option Plan
(11.1) Not Applicable
(12) Not Applicable
(13) Not Applicable
(16) Not Applicable
(18) Not Applicable
(21) Not Applicable
*(22) Subsidiaries of the Registrant
(23) Consent of experts and counsel
*(A) Consent of Jerry L. Williams, Independent Public
Accountants
*(B) Consent of Arthur Andersen LLP
44
<PAGE>
NO. EXHIBIT DOCUMENT
- --- ----------------
(24) Not Applicable
*(27) Financial Data Schedule
(28) Not Applicable
(29) 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 31st day of March, 1998 by the following
persons in their capacity as officers of the Registrant.
SEVEN SEAS PETROLEUM INC.
By: /s/ ROBERT A. HEFNER III By: /s/ HERBERT C. WILLIAMSON,III
Robert A. Hefner III Herbert C. Williamson, III
Chief Executive Officer 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 31st day of March, 1998 by the following
persons in their capacity as directors of the Registrant.
/s/ ROBERT A. HEFNER III /s/ HERBERT C. WILLIAMSON, III
Robert A. Hefner III Herbert C. Williamson, III
/s/ BREENE M. KERR /s/ JAMES D. SCARLETT
Breene M. Kerr James D. Scarlett
/s/ SIR MARK THOMSON Bt. /s/ LARRY A. RAY
Sir Mark Thomson Bt. Larry A. Ray
/s/ BRIAN EGOLF /s/ GARY F. FULLER
Brian Egolf Gary F. Fuller
/s/ ROBERT B. PANERO
Robert B. Panero
46
<PAGE>
Principal sources of changes in the standardized measure of discounted
future net cash flows during 1997:
Beginning of year .......................... $ 3,801,000
Net change in production costs ............. (1,741,552)
Extensions, discoveries, and additions,
less related costs ......................... 141,402,293
Net change in future development costs ..... (1,611,820)
Net change in income taxes ................. (41,969,044)
Accretion of discount ...................... 736,100
End of year ................................ $ 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
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 Clauses-
CHAPTER 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 are-
N-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
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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 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
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
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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
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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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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
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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
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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.
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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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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 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. 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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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 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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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
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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 50
1.0 - 2.0 50/R 100-50/R
2.0 or more 25 75
14.2..2.2 If gaseous 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 - 2.0 50 50
2.0 - 3.0 50/(R-1) 100-[50/(R-1)]
2.0 or more 25 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-
IA
R -------------------
ID + A - B + GO
Where-
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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.
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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 apply-
14.6.1 If ECOPETROL is the Party that is unable to fully or
partially
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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
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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
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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
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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
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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
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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 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. 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.
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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
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Page 28.
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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$) m(fract) "b"(US$)
1 0 25,000,000 0 0.10 0
2 25,000,001 50,000,000 2,500,000 0.08 25,000,000
3 50,000,001 100,000,000 4,500,000 0.07 50,000,000
4 100,000,001 200,000,000 8,000,000 0.06 100,000,000
5 200,000,001 300,000,000 14,000,000 0.04 200,000,000
6 300,000,001 400,000,000 18,000,000 0.02 300,000,000
7 400,000,001 onwards 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
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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
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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.
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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.
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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,
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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
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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
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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.
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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.
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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 Bogota,
Colombia
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.
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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.
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EMPRESA COLOMBIANA DE PETROLEOS
Calculation of area, direction and distances using Gauss coordinates,
origin
Santafe de Bogota.
Data and results of ROSABLANCA sector
Point Norte East Distance Dif. N. Dif. E Direction
A 1,402,900 1,020,000 27,100 27,100 0.00 North
B 1,430,000 1,020,000 10,000 0.0 10,000 East
c 1,430,000 1,030,000 30,000 30,000 0.00 North
D 1,460,000 1,030,000 30,000 0.00 30,000 East
E 1,460,000 1,060,000 35,000 -35,000 0.00 South
F 1,425,000 1,060,000 8,000 0.00 - 8,000 West
G 1,425,000 1,052,000 15,478 0.00 -15,478 West
H 1,425,000 1,036,522 4,001.57 -4,000 -112 Si 36.13.0.906w
I 1,421,000 1,036,410 10,000 0.00 -10,000 West
J 1,421,000 1,026,410 18,100 -18,100 0.00 South
K 1,402,900 1,026,410 6,410 0.00 -6,41 0.00 West
A 1,402,900 1,020,000
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.
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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
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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.
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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
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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. 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 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.
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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
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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 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
<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.
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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
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
Clauses-
CHAPTER 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, the terms listed below shall have the meaning set
out hereunder-
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
0.0 - 1.0 50 50
1.0 - 2.0 50/R 100-50/R
2.0 or more 25 75
14.2.2.2 lf gaseous 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 50
1.0 - 2.0 50/R 100-50/R
2.0 or more 25 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:
IA
R = -------------------
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 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 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).
Where-
x 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
INVESTMENTS AND EXPENDITURE - CONSTANT VALUES
X (US$) "A"(US$) M(FRACT) "B"$ (US$)
1 0 25,000,000 0 0.10 0
2 25,000,001 50,000,000 2,500,000 0.08 25,000,000
3 50,000,001 100,000,000 4,500,000 0.07 50,000,000
4 100,000,001200,000,000 8,000,000 0.06 100,000,000
5 200,000,001300,000,000 14,000,000 0.04 200,000,000
6 300,000,001400,000,000 18,000,000 0.02 300,000,000
7 400,000,001onwards 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 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 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 de Bogota,
Colombia
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> <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 32
PART III - ADMINISTRATIVE ASPECTS AND SUNDRY PROVISIONS
Section One - The Executive Committee 32
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 "MONECRISTO" SECTOR
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
<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> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<CASH> 18,067
<SECURITIES> 44
<RECEIVABLES> 3,865
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 22,095
<PP&E> 251,984
<DEPRECIATION> 43
<TOTAL-ASSETS> 291,914
<CURRENT-LIABILITIES> 8,205
<BONDS> 25,000
0
0
<COMMON> 196,406
<OTHER-SE> 0
<TOTAL-LIABILITY-AND-EQUITY> 291,914
<SALES> 780
<TOTAL-REVENUES> 1,567
<CGS> 907
<TOTAL-COSTS> 9,789
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> (7,928)
<INCOME-TAX> 0
<INCOME-CONTINUING> (7,928)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (7,928)
<EPS-PRIMARY> (.24)
<EPS-DILUTED> (.24)
</TABLE>
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
