-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, NfuFSOJ5D/pEeb6RNv73Z7MeinaRIbji7E1BvxY64nNKF8PeoZM/2fqK+Enb206k J7xYQq9fqsaFSz8PP8vdzA== 0000890566-98-000541.txt : 19980402 0000890566-98-000541.hdr.sgml : 19980402 ACCESSION NUMBER: 0000890566-98-000541 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19971231 FILED AS OF DATE: 19980331 SROS: NONE FILER: COMPANY DATA: COMPANY CONFORMED NAME: SEVEN SEAS PETROLEUM INC CENTRAL INDEX KEY: 0000947156 STANDARD INDUSTRIAL CLASSIFICATION: OIL AND GAS FIELD EXPLORATION SERVICES [1382] IRS NUMBER: 731468669 FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-13771 FILM NUMBER: 98584500 BUSINESS ADDRESS: STREET 1: 1990 POST OAK BLVD SUITE 960 STREET 2: THIRD POST OAK CENTRAL CITY: HOUSTON STATE: TX ZIP: 77056 BUSINESS PHONE: 7136228218 MAIL ADDRESS: STREET 1: 1990 POST OAK BLVD SUITE 960 STREET 2: THIRD POST OAK CENTRAL CITY: HOUSTON STATE: TX ZIP: 77056 10-K 1 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.[ ] TABLE OF CONTENTS TO FORM 10-K

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 2 to an existing pipeline with approximately 50,000 barrels per day of available transportation capacity. The Company's 1998-1999 budgeted expenditures for these activities are $34.2 million for Phase I. The Company may utilize joint ventures and other arrangements to minimize its capital outlays for pipeline infrastructure and production facilities related to Emerald Mountain. BALANCING DEVELOPMENT ACTIVITIES WITH EXPLORATION PROGRAM. The Company seeks to balance its development drilling program with an exploration program focused on delineating and extending the reservoir limits of Emerald Mountain. The Company utilizes advanced technology, including 2-D and 3-D seismic techniques as well as other proven exploratory tools. CAPITALIZING ON FAVORABLE OPERATING ENVIRONMENT. The Company intends to capitalize on the relative advantages of the location and characteristics of Emerald Mountain, which it believes represent a more favorable operating environment than most other discoveries and producing fields in Colombia. These advantages include: o The productive Upper Cretaceous Cimarrona formation at Emerald Mountain is at relatively shallow vertical depth of between 6,000 to 7,500 feet and does not require the relatively more complicated and more expensive drilling methods required to reach the deeper formations that are found in many other areas of Colombia. o Emerald Mountain benefits from accessible terrain at an average of approximately 3,000 feet above sea level in a generally unforested area, which is served by a major highway and is located near the Oleoductos Alto Magdalena ("OAM") pipeline. o Emerald Mountain is located 60 miles northwest of Bogota in the capital state of Cundinamarca in central Colombia, which is characterized by greater civil and political stability and by a higher general population and military presence than more remote areas of Colombia. o Colombia is a relatively stable democracy with a long history of consistent GDP growth and an announced goal of aggressively expanding its oil exports. Colombia's sovereign U.S. dollar rating as of March 1998 was Baa3/BBB-. MITIGATING RISKS OF FOREIGN OPERATIONS. The Company seeks to mitigate operating and financial risks associated with operating in Colombia by: (i) building on its relationship with the Colombian government, which, through the Colombian national oil company ("Ecopetrol"), has the right to back-in to an initial 50% working interest in Emerald Mountain; (ii) continuing the high level of involvement of the Company's Colombian advisory board consisting of prominent business and government leaders, all of whom are shareholders of the Company, to provide advice and to facilitate operating in Colombia; (iii) building on existing favorable relationships with the local community by, among other initiatives, providing local employment as well as medical and educational assistance; (iv) employing local personnel with in-country oil and gas industry expertise; and (v) operating primarily in U.S. dollars with the right to expatriate profits from Colombia. EMERALD MOUNTAIN OVERVIEW. The Company's Colombian operations are focused on Emerald Mountain. The Emerald Mountain discovery is located on two adjoining concession areas in central Colombia, approximately 60 miles northwest of Bogota. The concession areas are defined by two association contracts, the Rio Seco Association Contract and the Dindal Association Contract. The Company owns a 57.7% working interest in Emerald Mountain before Colombian government participation. See "-The Association Contracts." As of December 31, 1997, estimated net proved reserves of Emerald Mountain were 32.2 MMBO with an SEC PV-10 of $144.9 million. The Emerald Mountain geological structure is a large anticline. The primary oil reservoir is the Upper Cretaceous Cimarrona formation, which comprises both limestone and sandstone and is relatively under pressured. The Emerald Mountain reserves are located at vertical depths of between 6,000 and 7,500 feet and are characterized by low sulfur content (less than 1%), low paraffin content and a medium gravity (18 degree to 20 degree API gravity). DRILLING ACTIVITY. The Company has enhanced its knowledge of the Cimarrona reservoir and of its potential productive capacity through the drilling of eight wells on the formation. Production tests of the wells have indicated a uniform and 3 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.

(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 4 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 5 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 6 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. 7 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 8 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. 9 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 10 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. 11 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. 12 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 13 analysis performed subsequent to the completion of drilling operations resulted in an indication of highly fractured and oil bearing formation similar to that found in the preceding five successful wells. In November 1997 drilling commenced for the El Segundo 3-E well located approximately 2.8 miles south of the surface location of the El Segundo 1-E well. This well was the eighth and most southern well to be drilled on Emerald Mountain and the sixth to be drilled on the Dindal Block. The drilling of the El Segundo 3-E was completed at a vertical depth of 8,021 feet in February 1998. The well encountered 292 feet of Cimarrona formation that exhibited similar characteristics in terms of lithology and fracturing as that exhibited in the previous seven wells. After the completion of drilling operations on the El Segundo 3-E, the Company encountered major mechanical problems while attempting to complete the well for production testing. Due to a failure to effectively install the lower portion of the well's casing, it was not possible to achieve sufficient communication with the Cimarrona formation to initiate production testing. The Company plans to temporarily abandon the El Segundo 3-E well and to move the drilling rig to the surface location for the drilling of the El Segundo 6-E well located approximately 5.3 miles south of the surface location of the El Segundo 1-E well. PROSPECT GEOLOGY. The Emerald Mountain structure is formed by a faulted anticlinal closure in the foot wall of the Bituima thrust fault system on the eastern side of the Magdalena river valley. The primary oil reservoir tested to date is the Upper Cretaceous Cimarrona formation which is comprised of both limestones and sandstones. These reservoir sequences are charged with oil generated from the immediately underlying Villeta (also called LaLuna) shale, which is considered the principal source rock for the oil accumulations throughout Colombia and Venezuela. The Cimarrona formation is seen in surface outcrop to the north and west of the structure, as well as in the Lasmo Madrigal #1 well, the AIPC Quina #1 well and the Company's five successful delineation wells completed as of March 1998. From this geologic control and completed well information, the Cimarrona is shown to be depositionally complex, with a high degree of fracturing consistent in directional orientation. Cimarrona formation is on average approximately 290 feet in thickness and contains limestones, calcareous sandstones, and siltstones. Evidence for the structural trap is found in both seismic data over the prospect and in surface geologic mapping. The trapping mechanism is believed to be formed by structural closure in three directions (north, south and west), and an imbricate fault within the Bituima Fault system to the east, which is evidenced in the Escuela 1 well which was drilled in 1994, prior to the acquisition of an interest in the block by the Company, and was determined to be a non-commercial well. The Escuela 1 well is located 2.5 miles southeast of the El Segundo 1-E discovery well location and encountered Tertiary and Cretaceous shales and siltstones from surface to total depth. This predominantly shale section, emplaced by thrust faulting adjacent to the Cimarrona reservoir section, is believed to form the eastern critical element of the trap for the prospect. TERMS OF ASSOCIATION CONTRACTS AND RELATED MATTERS The Association Contracts were issued by Ecopetrol in March 1993 and August 1995, respectively, and provide generally for a six-year exploration phase followed by a 22-year production period, with partial relinquishments of acreage, excluding commercial fields, required commencing at the end of the sixth year of each contract. Under the terms of the Association Contracts, Ecopetrol will receive a royalty equal to 20% of production (after transportation costs are deducted) on behalf of the Colombian government and, in the event a commercially feasible discovery is made, Ecopetrol will acquire a 50% interest in the remaining production, bear 50% of the development costs, and reimburse the joint venture, from Ecopetrol's share of future production, for 50% of the joint venture's costs of certain exploration activities. Upon acceptance of a field as commercial, Ecopetrol will acquire a 50% interest therein and the interests of the other parties to the contract, including the Company, will be reduced by 50%; all decisions regarding the development of a commercial field will be made by an Executive Committee consisting of representatives of the parties to the contract who will vote in proportion to their respective interests in such contract. Decisions of the Executive Committee will be made by the affirmative vote of the holders of over 50% of the interests in the contract. If any commercial field in the respective contract areas produces in excess of 60 million barrels, Ecopetrol's interest in production and costs for such contract area increases as follows: (i) under the terms of the Dindal Association Contract, such increases occur in 5% increments from 50% to 70% as accumulated production from any field increases in 30 million barrel increments from 60 million barrels to 150 million barrels; and (ii) under the terms of the Rio Seco Association Contract, Ecopetrol's interest increases from 50% to 75% as the ratio of the accumulated income attributable to the parties 14 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 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%. 16 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 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:

Since December 31, 1997, the Company has drilled 0 gross productive exploratory wells (0 net to the Company), 1 gross nonproductive exploratory well (.577 net to the Company), 0 gross productive development wells (0 net to the 18 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. 19 COMPETITION The Company encounters competition from other oil and gas companies in all areas of its operations, including the acquisition of producing properties. The Company's competitors in Colombia include major integrated oil and gas companies and independent oil and gas companies. Many of its competitors are large, well-established companies with substantially larger operating staffs and greater capital resources than the Company's and which, in many instances, have been engaged in the oil and gas business for a longer time than the Company. Such companies may be able to offer more attractive terms in obtaining concessions for exploratory prospects and secondary operations and to pay more for productive properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than the Company's financial or human resources permit. The Company's ability to acquire additional properties and to discover reserves in the future will be dependent upon its ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. EMPLOYEES At December 31, 1997 the Company had 33 full time employees, primarily professionals, including geologists, geophysicists, and engineers. ITEM 3. LEGAL PROCEEDINGS There are no material legal proceedings to which the Company is a party or to which any of its property is subject. ITEM 4. SUBMISSION OF MATTERS TO VOTE None 20 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 21 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 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 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 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 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

26 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 SUPPLEMENTARY FINANCIAL INFORMATION (unaudited) SELECTED QUARTERLY DATA. Results of development stage operations by quarter for the years ended December 31, 1997, and 1996 were:

ITEM 9. CHANGES AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None 27 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 SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES (A DEVELOPMENT STAGE ENTERPRISE) CONSOLIDATED BALANCE SHEETS

F-2 STATEMENTS OF CONSOLIDATED OPERATIONS AND ACCUMULATED DEFICIT

The accompanying notes are an integral part of these financial statements F-3 STATEMENT OF CONSOLIDATED STOCKHOLDERS' EQUITY FOR THE PERIOD FROM INCEPTION (FEBRUARY 3, 1995) THROUGH DECEMBER 31, 1997

The accompanying notes are an integral part of these financial statements F-4 STATEMENTS OF CONSOLIDATED CASH FLOWS

The accompanying notes are an integral part of these financial statements F-5 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 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 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 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 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 5. INCOME TAXES: The geographical sources of loss before income taxes and minority interest were as follows:

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 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 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:

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:

The effects of applying SFAS 123 in this proforma are not indicative of future amounts. F-13 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:

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 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 Costs incurred during the years ended December 31, 1997, 1996, and 1995, respectively, were as follows:

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 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:

F-17 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS The following table sets forth certain information regarding each director and executive officers the Company:

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 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 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 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 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

(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 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 -----------------------------------------------

(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 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.

(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 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. 35 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 in the same proportion as used for determining the number of shares the holders of the Common Shares receive in any such exchange. Unless accelerated by the Compensation Committee, the vesting schedule set forth in the option agreement will continue to apply to such converted options. The Board of Directors of the Company may at any time suspend, amend, or terminate the Amended 1996 Stock Option Plan, but in the case of amendments to the plan, such amendments must be pre-cleared with The Toronto Stock Exchange. Any amendment to the Amended 1996 Stock Option Plan that increases the number of shares that may be issued under the plan, changes the designation of the participants or class of participants eligible for participation in the plan, or otherwise materially increases the benefits accruing to the participants under the plan, must be approved by the holders of a majority of the Company's outstanding voting shares, voting either in person or by proxy at a duly held shareholders meeting, within 12 months before or after any such amendment. 1997 STOCK OPTION PLAN The 1997 Stock Option Plan will give certain directors, officers, and employees of the Company, and its subsidiaries and affiliates an opportunity to develop a sense of proprietorship and personal involvement in the development and financial success of the Company, and to encourage them to remain with and devote their best efforts to the business of the Company, thereby advancing the interests of the Company and its shareholders. Accordingly, the Company may grant to certain directors, officers, and employees options to purchase up to an aggregate of 3,000,000 shares of the common stock of the Company ("Stock") pursuant to the 1997 Stock Option Plan. Such Stock may consist of authorized but unissued Stock or previously issued Stock reacquired by the Company. The 1997 Stock Option Plan is an amendment and restatement of the plan as previously adopted by the Board on September 9, 1997, and supersedes and replaces in its entirety such previously adopted plan. Effectiveness of the 1997 Stock Option Plan is subject to approval by the Company's shareholders at the annual meeting scheduled in June 1998. If the 1997 Stock Option Plan is not so approved by the shareholders, then all options granted thereunder will be void and of no further force and effect, and no additional options will be granted under the plan. All options granted under the 1997 Stock Option Plan are subject to, and contingent upon, such shareholder approval. Except with respect to options then outstanding, the 1997 Stock Option Plan, as amended and restated, will terminate upon and no further options will be granted thereunder after September 8, 2007. The 1997 Stock Option Plan will be administered by the Compensation Committee, which will have sole authority to select the optionees from among those individuals eligible under the plan and to establish the number of shares of Stock which may be issued under each option. The maximum number of shares of Stock that may be subject to options granted under the plan to an individual optionee may not exceed 5% of the Company's total Stock outstanding and during any calendar year may not exceed 1,000,000 (subject to adjustment under certain conditions described below). The Compensation Committee is authorized to interpret the 1997 Stock Option Plan and may from time to time adopt such rules and regulations, consistent with the provisions of the plan, as it may deem advisable to carry out the plan. All decisions made by the Compensation Committee in selecting optionees, in establishing the number of shares of Stock which may be issued under each option and in construing the provisions of the 1997 Stock Option Plan will be final. Options granted under the 1997 Stock Option Plan may be either incentive stock options, within the meaning of section 422 of the Internal Revenue Code of 1986, as amended (the "Code"), ("Incentive Stock Options") or options which do not constitute Incentive Stock Options ("Non-Qualified Stock Options"). Incentive Stock Options may be granted only to individuals who are employees (including officers and directors who are also employees) of the Company or any parent or subsidiary corporation (as defined in section 424 of the Code) of the Company at the time the option is granted. Non-Qualified Stock Options may be granted to individuals who are directors (but not also employees), officers and employees of the Company, any parent or subsidiary corporation of the Company, or any other affiliate of the Company. Options may be granted to the same individual on more than one occasion. No Incentive Stock Option will be granted to an individual if, at the time the option is granted, such individual owns stock possessing more than 10% of the total combined voting power of all classes of stock of the Company or of its parent or subsidiary corporation, within the meaning of section 422(b)(6) of the Code, unless at the time such option is granted the option price is at least 110% of the fair market value of Stock subject to the option and such option by its terms is not exercisable after the expiration of five years from the date of grant. Each option that is an Incentive Stock Option and all rights granted thereunder will not be transferable other than by will or the laws of descent and distribution or pursuant to a qualified domestic relations order as defined by the Code or Title 37 I of the Employee Retirement Income Security Act of 1974, as amended, or the rules thereunder, and will be exercisable during the optionee's lifetime only by the optionee or the optionee's guardian or legal representative. Each option that is a Non-Qualified Stock Option will bear the same transfer restrictions as an Incentive Stock Option except a Non-Qualified Stock Option may be assigned to a limited liability company or partnership if (i) the terms of such transfer are approved in advance by the Compensation Committee, (ii) 95% or more of all the member or partnership interests in such limited liability company or partnership are held by the holder of the option and members of his family, determined in accordance with section 318(a)(1) of the Code, or trusts for their benefit, (iii) such limited liability company or partnership is treated as a partnership for federal income tax purposes, and (iv) such limited liability company or partnership is controlled, directly or indirectly, as a fiduciary or otherwise, by the holder of the option. The purchase price of Stock issued under each option will be determined by the Compensation Committee, but such purchase price must not be less than the fair market value of Stock subject to the option on the date the option is granted. Each option must be evidenced by a written agreement between the Company and the optionee which shall contain such terms and conditions as may be approved by the Compensation Committee, provided that each such option must expire not later than 10 years after its date of grant. The terms and conditions of the respective option agreements need not be identical. An option agreement may provide for the surrender of the right to purchase shares of Stock under the option in return for a payment in cash or Stock equal in value to the excess of the fair market value of the shares of Stock with respect to which the right to purchase is surrendered over the option price therefor ("Stock Appreciation Rights"), on such terms and conditions as the Compensation Committee in its sole discretion may prescribe. The Compensation Committee will retain final authority (i) to determine whether an optionee will be permitted, or (ii) to approve an election by an optionee, to receive cash in full or partial settlement of such Stock Appreciation Rights. Moreover, an option agreement may provide for the payment of the option price, in whole or in part, by the delivery of a number of shares of Stock (plus cash if necessary) having a fair market value equal to such option price. Shares of Stock with respect to which options may be granted are shares of Stock as presently constituted, but if, and whenever, prior to the expiration of an option theretofore granted, the Company effects a subdivision or consolidation of Stock or the payment of a stock dividend on Stock without receipt of consideration by the Company, the number of shares of Stock with respect to which such option may thereafter be exercised (i) in the event of an increase in the number of outstanding shares will be proportionately increased, and the purchase price per share will be proportionately reduced, and (ii) in the event of a reduction in the number of outstanding shares will be proportionately reduced, and the purchase price per share will be proportionately increased. If the Company recapitalizes, reclassifies its capital stock, or otherwise changes its capital structure (a "recapitalization"), the number and class of shares of Stock covered by an option theretofore granted will be adjusted so that such option will thereafter cover the number and class of shares of Stock and securities to which the optionee would have been entitled pursuant to the terms of the recapitalization if, immediately prior to the recapitalization, the optionee had been the holder of record of the number of shares of Stock then covered by such option. If the Company declares an extraordinary dividend, which arises from any sale or exchange of assets, payable in cash or any other property, then the purchase price per share of Stock under any option theretofore granted shall be reduced by the amount of such extraordinary dividend payable on a share of Stock if paid in cash or the fair market value (as determined by the Compensation Committee) of any property distributable on a share of Stock if paid in kind. If in the event of any "Corporate Change", as defined in the 1997 Stock Option Plan, the Compensation Committee, acting in its sole discretion without the consent or approval of any optionee, will act to effect one or more of the following alternatives, which may vary among individual optionees and which may vary among options held by any individual optionee: (1) accelerate the time at which options then outstanding may be exercised so that such options may be exercised in full for a limited period of time on or before a specified date (before or after such Corporate Change) fixed by the Compensation Committee, after which specified date all unexercised options and all rights of optionees thereunder will terminate, (2) require the mandatory surrender to the Company by selected optionees of some or all of the outstanding options held by such optionees (irrespective of whether such options are then exercisable under the provisions of the plan) as of a date, before or after such Corporate Change, specified by the Compensation Committee, in which event the Compensation Committee will thereupon cancel such options and the Company will pay to each optionee an amount of cash per share of Stock according to a formula specified in the 1997 Stock Option Plan, (3) make any adjustments to options then outstanding as the Compensation Committee, in its sole discretion, deems appropriate to reflect such Corporate Change, or (4) provide that the number and class of shares of Stock covered by an option theretofore granted will be adjusted so that such option will thereafter cover the number and class of shares of Stock or securities or property (including, without limitation, cash) to which the optionee would have been entitled pursuant to the 38 terms of any Corporate Change if, immediately prior to such Corporate Change, the optionee had been the holder of record of the number of shares of Stock then covered by such option. The Board in its discretion may terminate the 1997 Stock Option Plan at any time with respect to Stock for which options have not theretofore been granted. The Board has the right to alter or amend the plan, or any part thereof from time to time. No change in any outstanding option will be made which would impair the rights of the optionee without the consent of such optionee. The Board may not make any alteration or amendment which would increase the aggregate number of shares which may be issued pursuant to the provisions of the 1997 Stock Option Plan or change the class of individuals eligible to receive options under the plan without the approval of the shareholders of the Company. 39 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. 40 (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 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 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 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 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 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 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 EX-10.B 2 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 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 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 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. 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. 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 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 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 ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 1 0. - -------------------------------------------------------------------------------- numeral. To this end, the relinquishment may be made in one or two lots, comprising one or more adjoining cells and trying to conserve a single polygon, unless THE ASSOCIATE shows that this is either impossible or unsuitable, in such case approval must be obtained from ECOPETROL. Notwithstanding the requirement to relinquish areas referred to in Clause 8 (numeral 8.1). THE ASSOCIATE is not obliged to return areas under development or production, including the 2.5 km. wide belt surrounding said areas, unless development or production are suspended continuously for over a year without just cause and for reasons attributable to THE ASSOCIATE, in which case the areas will be returned to ECOPETROL, thus terminating the contract for said areas of part of the area. These stipulations are also applicable to development under the sole risk mode. 8.3 Retention Period: If THE ASSOCIATE has discovered a Gas Field and applied for commerciality thereof as set out in Clause 9 (numeral 9.1), he may simultaneously ask ECOPETROL for a Retention Period, giving reasons to fully justify this request. 8.3.1 THE ASSOCIATE must apply for the Retention Period, and ECOPETROL grant same, prior to the date for final relinquishment of areas referred to in numeral 8.1 hereof. 8.3.2 The Retention Period may not exceed four (4) years. If the initial term were to be insufficient, ECOPETROL may extend same following a written and justified application from THE ASSOCIATE, but the initial period plus any extension may not exceed four (4) years. CHAPTER III - EXPLOITATION CLAUSE 9 - TERMS AND CONDITIONS 9.1 To initiate the Joint Operation hereunder, it is considered that exploitation work starts on the date the Parties accept the existence of the first Commercial Field or upon compliance with the provisions of Clause 9 (numeral 9.5). THE ASSOCIATE shall prove the existence of a Commercial Field by drilling sufficient wells to reasonably define the hydrocarbon-producing area and the commerciality of the Field. In this case, THE ASSOCIATE will notify ECOPETROL in writing about such commercial discovery, furnishing the studies that have led to this conclusion. ECOPETROL must accept or reject the existence of such Commercial Field within ninety (90) calendar days from the date THE ASSOCIATE hands over all support information and makes the technical presentation. ECOPETROL may request any additional information it deems necessary within thirty (30) days following submittal of the initial support information. ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 11 - -------------------------------------------------------------------------------- 9.2.1 Should ECOPETROL accept the existence of a Commercial Field, it shall so advise THE ASSOCIATE within the ninety (90) day term referred to in Clause 9 (numeral 9.1) stipulating the area of the Commercial Field. Then it shall begin to participate in the development of the Commercial Field discovered by THE ASSOCIATE as set out in the terms of the Contract. 9.2.2 ECOPETROL shall reimburse fifty percent (50%) of the Direct Exploration Costs incurred by THE ASSOCIATE for its own risk and account in the Contract Area prior to the date when commerciality studies for the new commercial discovery were submitted, in keeping with numeral 9. 1. hereof. 9.2.3 The amount of such Direct Costs shall be established in dollars of the United States of America, the reference date being that when THE ASSOCIATE made such disbursements-, consequently, the costs incurred in Colombian pesos shall be liquidated at the market representative rate for such date as certified by the Banking Superintendency, or entity replacing same. Paragraph: Once the amount of Direct Exploration Costs to be reimbursed in United States Dollars has been established, such will be inflation-adjusted for each year or part thereof as of the disbursement date up to the date defined by the Ministry of Mines & Energy as the initiation of the exploitation period, using the international inflation rate for the respective year or, failing this, that for the previous year. The international inflation rate to be used shall be the annual percentage variation of the consumer price index for industrialized countries, taken from "International Financial Statistics" published by the International Monetary Fund (page S63 or replacement) or, failing this, the publication agreed by the Parties. 9.2.4 As soon as Operator puts the Field on-stream, ECOPETROL shall reimburse THE ASSOCIATE for Direct Exploration Costs according to Clause 9 (numeral 9.2.2) with the amount of dollars equivalent to fifty percent (50%) of its direct share in the total production of such Field, after deducting the royalty percentage. Paragraph-. For Commercial Gas Fields, ECOPETROL shall reimburse the ASSOCIATE with the amount of dollars equivalent to one hundred percent (100%) of its direct share in the total production of such Field, after deducting the royalty percentage, doing so as soon as Operator puts the Field on-stream. 9.3 If ECOPETROL rejects the existence of the Commercial Field referred to in Clause 9 (numeral 9.1), it may notify THE ASSOCIATE of additional work it ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 12. - -------------------------------------------------------------------------------- considers necessary to demonstrate such existence. The cost of this work may not exceed TWO MILLION DOLLARS (US$2,000,000) nor last for more than one (1) year, in which case the Exploration Period for the Contract Area will automatically be extended by the same period as that agreed by the Parties for the performance of the additional work requested by ECOPETROL in this Clause but without prejudice to the reduction of areas stipulated in Clause 8 (numeral 8.1). 9.4 If, upon completion of the additional work requested in Clause 9 (numeral 9.3), ECOPETROL accepts the existence of a Commercial Field as stipulated in Clause 9 (numeral 9.1), it will begin to participate in the development of said field as stipulated herein, and will reimburse THE ASSOCIATE as set forth in Clause 9 (numeral 9.2.3-9.2.4) for fifty percent (50%) of the cost of such additional work referred to in Clause 9 (numeral 9.3) and the work carried out will become Joint Account property. 9.5 If ECOPETROL continues to reject the existence of a Commercial Field after the additional work referred to in Clause 9 (numeral 9.3) has been carried out, THE ASSOCIATE may go ahead with the work it deems necessary to exploit such field and reimburse itself for two hundred percent (200%) of the total cost of the work performed at its own risk and account in the respective Field and up to fifty percent (50%) of the Direct Exploration Costs it incurred prior to submitting commerciality studies for such Field. For the purposes of this Clause, the reimbursement will be made with the value of Hydrocarbons produced, less the royalties established in Clause 13, deducting production, collection, transportation and sales costs. If THE ASSOCIATE avails itself of the sole risk modality, it is understood that the exploitation term begins on the date ECOPETROL notifies it that commerciality is rejected. The dollar equivalence of disbursements made in pesos will be calculated using the market representative rate certified by the Banking Superintendency, or entity replacing same, for the date THE ASSOCIATE made such disbursements. For the purposes of this clause, the value of each barrel of Hydrocarbon produced in said Field during a calendar month, shall be the average price per barrel received by THE ASSOCIATE for the sale of its share in the Hydrocarbons produced in the Contract area during the same month. The contents of the paragraph of Clause 9 (numeral 9.2.3.) shall apply to reimbursement of Direct Exploration Costs. Once THE ASSOCIATE has reimbursed itself with the percentage established herein, all wells drilled, the facilities and all property acquired by THE ASSOCIATE to exploit the field and paid as set forth in this Clause, shall become the property of the Joint Account free of any charge whatsoever, and after ECOPETROL agrees to participate in the development of such field. 9.6 At any time, ECOPETROL may start to participate in the operation of the ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 13. - -------------------------------------------------------------------------------- field discovered and developed by THE ASSOCIATE, subject to the latter's right to reimburse itself for investments made at its own expense as stipulated in Clause 9 (numeral 9.5). Once THE ASSOCIATE has repaid itself, ECOPETROL shall start to participate in the financial results of the wells developed at the exclusive expense of THE ASSOCIATE. 9.7 When defining the boundaries of a Commercial Field, consideration will be given to all geological/geophysical information on such field plus that of all wells drilled therein or related thereto. 9.8 If THE ASSOCIATE has drilled one or more Exploration Wells pointing to the possible existence of a Commercial Field by the end of the six-year (6) Exploration Period referred to in Clause 5 (numeral 5.2), it may ask ECOPETROL to extend the Exploration Period for the time necessary, but not to exceed one (1) year, to demonstrate the existence of said Commercial Field, without prejudice to the provisions of Clause 8. 9.9 If THE ASSOCIATE continues performing the exploration obligations agreed upon in Clause 5 after one or more fields have been declared commercial, it can simultaneously exploit such Fields before the end of the Exploration Period defined in Clause 4.26 but the 22-year Exploitation Period will run as of the expiry date of the Exploration Period. When ECOPETROL has granted a Retention Period for Gas Fields, the Exploitation Period for each Field will run from the expiry date of the respective Retention Period. 9.10 If THE ASSOCIATE shows that Exploration Wells drilled after the Field has been declared commercial contain additional Hydrocarbon accumulations associated to said field, it shall ask ECOPETROL to extend the area of the Commercial Field and its commerciality, following the procedures of Clause 9 (numerals 9.1 and 9.2.1). If ECOPETROL accepts the commerciality, it shall reimburse THE ASSOCIATE for fifty percent (50%) of the Direct Exploration Costs exclusively related to the extension of the Commercial Field, as set out in numerals 9.2.3 and 9.2.4. If ECOPETROL rejects the commerciality, THE ASSOCIATE may reimburse itself for up to two hundred percent (200%) of the total costs of work performed for, its own risk and account in exploiting the Exploration Wells that have become producers and up to fifty percent (50%) of the Direct Exploration Costs it incurred solely with regard to the commerciality application. Such reimbursement shall be made with production coming from the producing Exploration Wells, after deducting the royalty, and following the procedure of Clause 21 (numeral 21.2) until reaching the mentioned percentages. ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 14. - -------------------------------------------------------------------------------- CLAUSE 10 - TECHNICAL CONTROL OF THE OPERATIONS 10.1 The parties agree that THE ASSOCIATE is the Operator and as such shall control all operations and activities it deems necessary for an efficient, technical and economic development of Hydrocarbons existing within the Commercial Field, respecting the restrictions contained in this contract. 10.2 The Operator must follow standard industry practices in performing development/production work, using the technical methods and systems best suited to an economic and efficient Hydrocarbon production, and complying with pertinent legal and regulatory provisions on this matter. 10.3 The Operator shall be considered an entity distinct from the Parties hereto for all contract purposes, as well as for application of civil, labor and administrative law, and with regard to its employees as set out in Clause 32. 10.4 The Operator may resign as such by giving the Parties six-months (6) advance written notice of the effective date of such resignation. The Executive Committee shall then appoint a new Operator pursuant to Clause 19 (numeral 19.3.2) CLAUSE 11 - DEVELOPMENT PROGRAMS AND BUDGETS 11. 1 Within three (3) months following acceptance of a Commercial Field in the Contract Area, Operator shall present the Parties with a work program and a Budget for the rest of the calendar year together with a proposed development plan, to be agreed by the Executive Committee. If there are less than six and a half (6-1/2) months to run before the end of said year, Operator shall prepare and submit the Budget and programs for the following calendar year within a term of three (3) months. 11.1.1 Future Budgets and programs shall be submitted to the Parties in May each year, and Operator shall send its proposal to the Parties in the first ten (10) days of May. The Parties shall notify Operator in writing of any changes they wish to propose, doing so within twenty (20) days of receiving the Budgets and programs. When this occurs, Operator shall consider such proposals in preparing the Budget and programs to be submitted for final approval by the Executive Committee at its ordinary meeting held each July. Should the total Budget not be approved before July, the Executive Committee shall approve those items on which there is agreement, and the remainder shall be submitted to the Parties for subsequent review and final decision as provided for in Clause 20. 11.1.2 The development program shall become a guide for the technical, efficient and economic exploitation of each Field. It will describe work to be ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 15. - -------------------------------------------------------------------------------- carried out and estimated investments and expenses for the next five years, with details of the annual operating program and Budget for the next calendar year. 11.2 The parties may propose Budget additions or revisions to the Budget but not more often than every three (3) months except in emergencies. The Executive Committee shall decide on these proposed revisions or additions at a meeting to be scheduled within thirty (30) days following submittal thereof. 11.3 The programs and Budget are intended to- 11.3.1 Determine the operations to be carried out during the following calendar year, as well as expenditures and investments (Budget) the Operator is authorized to undertake. 11.3.2 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. ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 16. - -------------------------------------------------------------------------------- 11.7 The Operator is authorized to effect expenses chargeable to the Joint Account without prior authorization from the Executive Committee when it is a matter of taking emergency steps to safeguard persons or property of the Parties, emergency expenses originating in fire, floods, storms or other disasters; emergency expenses essential for the operation and maintenance of production facilities, including keeping wells at maximum production 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. ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 17. - -------------------------------------------------------------------------------- 12.5 Operator may use the Hydrocarbons consumed in production operations in the Contract Area, and such shall be exempt from the royalties referred to in Clause 13 (numerals 13.1 and 13.2). CLAUSE 13 - ROYALTIES 13.1 Liquid Hydrocarbons-. During exploitation of the Contract Area, and before distributing production among the Parties, Operator shall give ECOPETROL royalties corresponding to twenty percent (20%) of the certified production of liquid hydrocarbons coming from said area. ECOPETROL, for its own risk and account, shall take the royalty production in kind from the tanks belonging to the Joint Account. 13.2 Gaseous Hydrocarbons- Operator shall give ECOPETROL a royalty in the form of twenty percent (20%) of the production of gaseous Hydrocarbons reported at standard conditions. If such Hydrocarbons need to be treated at a gas plant, the twenty percent (20%) royalty production shall be established as the sum of dry gas produced at the plants plus the dry gas equivalent of liquid products produced, considering the conversion factors set out in current legislation. Regarding fields exploited under the sole risk mode, THE ASSOCIATE shall give ECOPETROL the royalty percentage of Hydrocarbons. 13.3 ECOPETROL shall use the royalty production to pay the entities legally appointed to receive the royalties due the State on the full production of the Commercial Field, doing so in the manner and respecting the time limits set out in law, and the ASSOCIATE shall in no case be liable for any payments to these entities. CLAUSE 14 - DISTRIBUTION AND AVAILABILITY OF HYDROCARBONS 14.1 The Hydrocarbons produced shall be transported to the jointly-owned tanks or to other measuring facilities agreed by the Parties, except for those used and inevitably consumed in operations hereunder. In the absence of an agreement, the measuring point for gaseous Hydrocarbons shall be- i. The gas line of each separator when they are not to be treated in gas plants, or ii) at the exit of the gas plants when such treatment is required. The Hydrocarbons shall be measured via accepted industry standards and such measurement shall be the basis for calculating the percentages of Clause 13. Thereafter, the remaining Hydrocarbons belong to each Party in the proportion specified in this Contract. 14.2 Production Distribution ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 18. - -------------------------------------------------------------------------------- 14.2.1 After deducting the royalty percentage, the remaining Hydrocarbons produced in each Commercial Field belong to the parties thus- Fifty percent (50%) for ECOPETROL and fifty percent (50%) for THE ASSOCIATE until cumulative production for each Commercial Field reaches 60 million barrels of liquid Hydrocarbons or 420 giga cubic feet of gaseous Hydrocarbons at standard conditions, whichever occurs first (1 cubic giga foot = 1 x 10 9- cubic feet) 14.2.2 Notwithstanding the fact that ECOPETROL has classified the Field as being commercial, when production at each Commercial Field (after deducting the royalty percentage) exceeds the limits of 14.2.1, distribution among the Parties will use the R factor as set out hereunder. 14.2..2.1 If liquid Hydrocarbons first reach the limit set out in numeral 14.2.1 hereof, the following table shall apply-. R FACTOR Production Distribution after Royalties (%) ASSOCIATE ECOPETROL 0.0 - 1.0 50 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- ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 19. - -------------------------------------------------------------------------------- 1A (The Associates Accrued Income)- is the valuation of income accrued by THE ASSOCIATE for hydrocarbons produced, after royalties, at the reference price agreed by the Parties, excluding hydrocarbons reinjected in Contract Area Fields, and those consumed in the operation and burnt gas. The parties shall jointly establish the average reference price for hydrocarbons. Accrued Income will be based on the Monthly Income which, in turn, will be obtained from multiplying the average monthly reference price by the monthly production in keeping with respective form issued by the Ministry of Mines & Energy. ID (Accrued Development Investment)-. Is fifty percent (50%) of the accrued development investment approved by the Association Executive Committee. Accrued Development Investment made prior to the exploitation start-up date of the Field as defined by the Ministry of Mines and Energy, shall be adjusted to such date in the same way as Direct Exploration Costs in the paragraph of Clause 9 (numeral 9.2.3). A. Direct Exploration Costs incurred by THE ASSOCIATE according to Clause o hereof and adjusted as set out in the paragraph of 9.2.3 . B. Accrued reimbursement of the afore-mentioned Direct Exploration Costs, in keeping with Clause 9 hereof. GO (Accrued Operating Expenses)-. accrued operating expenses approved by the Association Executive Committee, in the proportion corresponding to the ASSOCIATE plus the latter's accrued transportation costs. Transportation costs are investment and operating expenses for transporting hydrocarbons produced in the Commercial Fields within the Contract Area up to the exportation port or the place agreed for taking the price to be used in the IA calculation. Such transportation costs will be jointly determined by the parties once the Fields that ECOPETROL has declared to be commercial initiate the exploitation stage. Operating expenses include special levies or similar items directly applied to Hydrocarbon exploitation in the Contract Area. All values included in the R factor calculation following the exploitation start-up date established by the Ministry of Mines & Energy will be taken in current dollars. ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 20. - -------------------------------------------------------------------------------- To this end, expenses in pesos shall be converted to dollars at the Market Representative Rate certified by the Banking Superintendency, or entity replacing same, in force on the date the respective disbursements were made. 14.2.4 Calculation of the R Factor: Production distribution based on the R factor will be applied as of the first day of the third calendar month following that when the accrued production in the Contract Area reached 60 million barrels of liquid Hydrocarbons or 420 giga cubic feet of gaseous Hydrocarbons at standard conditions, in keeping with 14.2.1 The R Factor for calculation each Commercial Field will be based on the accounting closing for the calendar month when accrued production reached 60 million barrels of liquid Hydrocarbons or 420 giga cubic feet of gaseous Hydrocarbons at standard conditions, in keeping with 14.2.1 The resulting distribution will be applied until 30th June of the following year. Thereafter, R factor production distribution will be made for one-year periods (lst July to 30th June) for liquidation thereof based on accrued value at 31st December of the previous year as shown in the respective accounting closing. 14.3 In addition to the jointly owned tanks and other facilities, each Party may build its own production facilities in the Contract Area for its exclusive use and in keeping with legal regulations. When Hydrocarbons belonging to each Party are transported and delivered to pipelines and depots that are not jointly owned, this will be for the risk and cost of the Party receiving such Hydrocarbons. 14.4 When production sites are not connected to a pipeline, the Parties may agree to install pipelines up to a point connecting to the pipeline or where the Hydrocarbons can be sold, this work will be charged to the Joint Account. If the Parties agree to build such pipelines, they will enter into the contracts they deem suitable for this purpose and appoint the Operator pursuant to current legislation. 14.5 Each Party shall own the Hydrocarbons produced and stored as a result of the operation hereunder and made available to it pursuant to the provisions of this contract. Likewise, each Party must assume the expense of receiving such Hydrocarbons in kind or selling or disposing of them separately, as provided for in Clause 14 (numeral 14.3). 14.6 Should one Party, for any reason, be unable to separately dispose all or part of the Hydrocarbons to which it is entitled hereunder, or withdraw same from the Joint Account tanks, the following stipulations shall apply- 14.6.1 If ECOPETROL is the Party that is unable to fully or partially ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 21. - -------------------------------------------------------------------------------- withdraw its quota of Hydrocarbons (share plus royalty) pursuant to Clause 12 (numeral 12.3), Operator may continue producing the field and deliver to THE ASSOCIATE not only the quota to which the latter is entitled based on a hundred percent (100%) MER operation, but also all the Hydrocarbons that THE ASSOCIATE chooses and is able to withdraw up to a limit of one hundred percent (1 00%) of the MER, crediting ECOPETROL for subsequent delivery of the quota it did not withdraw. However, regarding the volumes not taken that correspond royalties for the month, ECOPETROL may ask THE ASSOCIATE to pay for the difference between the Hydrocarbon volume withdrawn and the volumes corresponding to royalties as set out in Clause 13.1 and 13.2, doing so in United States dollars. It is understood that any Hydrocarbons withdrawn by ECOPETROL shall first be used for payment in kind of the royalties, and thereafter, additional withdrawals will be credited to its share as set out in Clause 14 (numeral 14.2). 14.6.2 If THE ASSOCIATE is unable to fully or partially withdraw its quota under Clause 12 (numeral 12.3), the Operator shall deliver ECOPETROL not only its share based on a hundred percent (100%) MER operation, but all those Hydrocarbons that ECOPETROL is able to receive up to a limit of one hundred percent (100%) of the MER, crediting THE ASSOCIATE for subsequent delivery of the quota which it was unable to withdraw. 14.7 When both Parties are able to receive the Hydrocarbons allocated under Clause 12. (numeral 12.3), the Operator shall proceed as follows. When so requested by the Party previously unable to receive its quota, it shall deliver such Party its share in the operation plus at least ten percent (10%) a month of the monthly production corresponding to the other Party and by mutual agreement up to one hundred percent (100%) of the non-received quota, until such time when the total amounts credited to the non-receiving party are offset. 14.8 Subject to legal provisions on this matter, each Party is free at all times to sell or export is share of Hydrocarbons, in keeping with this contract, or to dispose thereof in anyway. CLAUSE 15 - USE OF ASSOCIATE NATURAL GAS When one or more fields with Associate Natural Gas are discovered, Operator shall submit a project for using this gas for the benefit of the Joint Account, this must be done within two (2) years following the starting date for field exploitation as established by the Ministry of Mines and Energy. The Executive Committee shall approve the project and establish a schedule for performance thereof. If Operator fails to submit a project within the two-year period, or fails to perform ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 22. - -------------------------------------------------------------------------------- same within the time limits established by the Executive Committee, ECOPETROL may take all the Associate Natural Gas coming from the Reservoirs being exploited and not needed for efficient field production, without having to pay for same. CLAUSE 16 - UNIFICATION When an economically exploitable reservoir extends continuously into another area or areas located outside the Contract Area, the Operator, ECOPETROL and other interested parties should agree on a unified development program. Such program should respect engineering techniques for Hydrocarbon production and be approved by the Ministry of Mines and Energy. CLAUSE 17 - INFORMATION SUPPLY AND INSPECTION DURING EXPLOITATION 17.1 The Operator shall give the Parties reproducible originals (sepias) and copies of the electric, radioactive and sonic logs for the wells drilled, histories, core analyses, cores, production tests, reservoir studies and other pertinent technical data, as well as any routine reports made or received in connection with the operations and activities carried out in the Contract Area, doing so as these become available. 17.2 Each Party shall be entitled to inspect the wells and facilities in the Contract Area and related activities, doing so at its own cost, expense and risk and through authorized representatives. Such representatives shall have the right to examine cores, samples, maps, drilling logs, surveys, books and any other source of information connected with the performance of this contract. 17.3 Operator shall prepare all reports called for by the Colombian government and hand them over to ECOPETROL so the latter may comply with the provisions of Clause 29, 17.4 Information and data connected with exploitation operations shall be treated as confidential, under the same terms as those of Clause 6 (numeral 6.3) hereof. CHAPTER IV - EXECUTIVE COMMITTEE CLAUSE 18 - CONSTITUTION 18.1 Within thirty (30) days following acceptance of the first Commercial Field, each Party should appoint a representative and his first and second alternates to the Executive Committee, and notify the other Party in writing of the names and ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 23. - -------------------------------------------------------------------------------- addresses of such persons. The Parties may change the representative or alternates at any time, but should so notify the other Party in writing. The vote or decision of each Party representative is binding on said Party. If the main representative of either Party is unable to attend a Committee meeting, he will be replaced by the first or second alternate, in that order, and such shall have the same authority as the principal. 18.2 The Executive Committee will hold ordinary meetings in March, July and November to review the development program being carried out by Operator, the development plan and other immediate plans. In the July meeting every year, the Operator shall submit an annual operating program and the investment and expenditure Budget for the next calendar year. 18.3 The Parties and Operator may ask that special Executive Committee meetings be convened to study specific operating conditions. The representative of the interested party shall give ten (10) calendar days advance written notice of the data and agenda for such meeting. The meeting may address any matter not included in the agenda, provided the Party representatives agree. 18.4 For all matters discussed in the Executive Committee, the Party representatives shall have a vote equal to the percentage held by the respective party in the Joint Operation. Any decision or resolution taken by the Executive Committee will only be valid if approved by over fifty percent (50%) of the total Interest. In keeping with the mentioned procedure, decisions taken by the Executive Committee shall be compulsory and final for the Parties and for Operator. CLAUSE 19 - FUNCTIONS 19.1 The Party representatives shall constitute the Executive Committee which has full authority and responsibility to establish and adopt production, development and operations schedules and Budgets for this contract. Operator shall send a representative to Executive Committee meetings. 19.2 The Executive Committee shall appoint a Secretary to keep complete and detailed records and minutes of all matters discussed and decisions taken by the Committee. Party representatives should sign and approve the Minutes within the ten (10) business days following adjournment of the meeting, otherwise they will not be valid. Minutes should be delivered to the Parties as soon as possible. 19.3 The Executive Committee has the following duties, among others-. 19.3.1 Adopt its own regulations ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 24. - -------------------------------------------------------------------------------- 19.3.2 Appoint the Operator in the event of resignation or removal, and issue regulations to be met by Operator when such is a third party, setting out all causes for removal. 19.3.3 Appoint an External Auditor for the Joint Account 19.3.4 Approve or reject the annual operations program and expenditure Budget, any modification or revision thereof, and approve extraordinary expenses. 19.3.5 Establish expenditure policies and norms 19.3.6 Approve or reject expenditure recommended by Operator (not included in the approved Budget) when such expenditure exceeds forty thousand dollars of the United States of America (US$40,000) or the equivalent in Colombian currency. 19.3.7 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 ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 25. - -------------------------------------------------------------------------------- is resident in Colombia, in order that they may reach a joint decision. If the Parties reach an agreement or decision on the matter in question within sixty (60) calendar days after such referral, they shall so notify the Executive Committee Secretary who should call a meeting within the fifteen (1 5) calendar days following receipt of the notice and committee members must ratify the agreement or decision in said meeting. 20.2 If the Parties fail to reach agreement within the sixty (60) calendar days following the consultation, operations may go ahead pursuant to Clause 21. CLAUSE 21 - SOLE RISK OPERATIONS 21.1 If, at any time, one Party wishes to drill an Exploitation Well that has not been approved in the operating schedule, it shall so notify the other Party at least thirty (30) calendar days prior to the next meeting of the Executive Committee, together with data on location, drilling recommendation, depth and estimated costs. The Operator shall include this proposal in the Agenda for the next committee meeting. If the Committee approves the proposal, said well shall be drilled for the Joint Account- otherwise the Party wishing to drill the well, hereinafter the participating Party, shall be entitled to drill, complete, produce or abandon such well at its own risk and for its account. The Party not wishing to participate in the afore-mentioned operation shall be referred to as nonparticipating Party. The participating Party should spud the well within one hundred eighty (180) days following rejection by the Executive Committee. If drilling does not start within this period, it must be re-submitted to the Executive Committee. When requested by the participating Party, Operator shall drill the afore-mentioned well for the risk and account of said Party, provided Operator considers that such operation will not interfere with normal Field operations, and that it has received the sums it considers necessary from the participating Party. If Operator is unable to drill the mentioned well, the participating Party may drill it directly or via a competent service company and, in such case, the participating Party will be responsible for the operation, without interfering in normal Field operations. 21.2 If the well referred to in Clause 21 (numeral 21.1) is completed as a producer, it shall be administered by Operator and its production, after deducting the royalty referred to in Clause 13, will belong to the participating Party. This Party will assume all operating costs for the well until net production value, after deducting costs of production, gathering, storage, transport and similar, and sales costs, reaches two hundred percent (200%) of drilling and completion costs. Thereafter, and for all contract purposes, the well shall belong to the Joint Account as if it had been drilled with the approval of the Executive Committee and for the ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 26. - -------------------------------------------------------------------------------- account of the Parties. For purposes of this Clause, the value of each barrel of Hydrocarbon produced in the well during a calendar month and prior to deducting the afore-mentioned costs, shall be the average price per barrel received by the participating Party for sales of its share of Hydrocarbons produced in the Contract Area during the same month. 21.3 If one Party at any time wishes to recondition or deepen a well to Production Targets, or plug a dry hole or a non-commercial producer drilled for the Joint Account, and such operations have not been included in the program approved by the Executive Committee, such Party shall notify the other Party of its intention to recondition, deepen or plug said well. If equipment is not available at the location, the procedure of Clause 21 (numerals 21.1 and 21.2) shall apply. If suitable equipment is available at the well site, the Party wishing to carry out such operation shall notify the other Party which must reply in a period of forty-eight (48) hours following receipt of such notice, if no reply is received in this lapse, it shall be understood that the operation is performed for the risk and account of the Joint Account. If the proposed work is performed for the sole risk and account of the participating Party, the well shall be administered in keeping with Clause 21 (numeral 21.2). 21.4 If, at any time, one Party wishes to build new facilities to extract liquid from the gaseous hydrocarbons and to transport/export Hydrocarbon production, these will be referred to as additional facilities and such Party shall notify the other in writing as 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. ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 27. - -------------------------------------------------------------------------------- CHAPTER V - JOINT ACCOUNT CLAUSE 22 - MANAGEMENT 22.1 Subject to other provisions set out herein, Exploration expenses shall be for the risk and account of THE ASSOCIATE. 22.2 Once the Parties accept the existence of a Commercial Field, and subject to the provisions of Clauses 5 (numerals 5.2) and 13 (numerals 13.1 and 13.2), the rights or Interest in Contract Area Operation shall be owned thus ECOPETROL fifty percent (50%) and THE ASSOCIATE fifty percent (50%). Thereafter, all expenses, payments, investments, costs and liabilities made and contracted for operations hereunder and Direct Exploration Costs made by the ASSOCIATE prior to acceptance of each Commercial Field and extensions thereto, in keeping with Clause 9 (numeral 9.10), shall be charged to the Joint Account. Except as set out in Clauses 14 (numeral 14.3) and 21, all assets acquired or used thereafter for operating the Commercial Field shall be owned and paid for by the Parties as set out in this clause. 22.3 The Parties shall pay Operator their share of budget requirements, doing so in the currency in which expenditure is to be disbursed, that is Colombian pesos or United States dollars as called for by Operator in keeping with programs and Budgets approved by the Executive Committee. This payment shall be made in the first five (5) days of each month and at the bank chosen by Operator. When THE ASSOCIATE lacks sufficient Colombian pesos to cover its pesos share, ECOPETROL may supply these funds and have them credited to its dollar obligation, using the market representative rate certified by the Banking Superintendency, or the entity acting in this capacity, on the day that ECOPETROL should make the respective payment, provided such transaction is legally acceptable. 22.4 The Operator shall give the Parties a monthly statement showing the funds advanced, expenses incurred, outstanding liabilities and a report on all debits and credits made to the Joint Account, this report should follow Appendix B hereto. The statement and report should be submitted monthly within the fifteen (15) calendar days following the end of each month. If the payments mentioned under Clause 22 (numeral 22.3) are not made within stipulated term and Operator chooses to pay same, the delinquent Party shall pay commercial interest in the same currency for the time of such delay. 22.5 If one Party fails to pay the Joint Account on the due date, it shall be considered thereafter as the delinquent Party and the other as the Prompt party. If ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 28. - -------------------------------------------------------------------------------- the Prompt party were to pay both its own share and that of the delinquent Party, after sixty (60) days of delay, it shall be shall be entitled to receive from Operator the full share of the delinquent Party in the Contract Area (excluding royalty percentage). This will continue until production provides the prompt Party with a net income from sales equal to the sum not paid by the delinquent Party, plus annual interest at the Commercial rate as of the sixtieth (60) day following the delinquency date. Net income is understood as the difference between the sales price of the Hydrocarbons taken by the prompt Party, less the cost of transport, storage, loading and other reasonable expenses disbursed by such Party in selling such production. The prompt Party may exercise this right at any time after thirty (30) calendar days of having notified the delinquent Party in writing of its intention to take part or all such Party's production. 22.6.1 All Direct Expenses of the Joint Operation will be charged to the Parties in the same proportion as for production distribution after royalties. 22.6.2 Indirect Expenses will be charged to the Parties in the same proportion as for Direct Expenses set out in 22.6.1 hereof. These expenses shall be the result of applying the equation a+m (X-b) to the total annual amount for investment and direct expenditures (excluding technical and administrative overhead). Where: x Is total annual investments and expenditures "a", "m", and "b" are constants whose values are set out in the table hereunder depending on the amount of annual investment and expenditures INVESTMENTS AND EXPENDITURE - CONSTANT VALUES x (US$) a(US$) m(fract) "b"(US$) 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 ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 29. - -------------------------------------------------------------------------------- corrected or questioned items and the reasons therefor. Any account that has not been corrected or questioned in this period, shall be considered as final and correct. 22.8 The Operator shall keep accounting books, vouchers and reports for the Joint Account, in Colombian pesos and according to Colombian law. Any credit or debit to the Joint Account shall follow the accounting procedure set out in Appendix B which is a part hereof. In the event of any discrepancy between said accounting procedure and the terms of the contract, the latter shall prevail. 22.9 Operator may sell material or equipment during the first twenty (20) years of the Exploitation Period, or the first twenty eight (28) years in the case of a Gas Field, crediting the proceeds to the Joint Account when the amount does not exceed five thousand dollars of the United States of America (US$5,000) or the equivalent in Colombian currency. In any calendar year, operations of this type may not exceed fifty thousand dollars of the United States of America (US$50,000) or the equivalent in Colombian currency. The Executive Committee must approve sales of real estate or those exceeding the afore-mentioned amounts. These materials or equipment shall be sold at a reasonable price considering their condition. 22.10 All machinery, equipment or other assets or chattels purchased by Operator for contract performance and charged to the Joint Account shall belong to the Parties in equal shares. However, if one Party decides to terminate its interest in the contract during the first seventeen (1 7) years of the Exploitation Period, except as set out in Clause 25th, said Party must sell all or part of its share in said items to the other Party at a reasonable commercial price or at book value, whichever is lower. If the other Party is not interested in purchasing them within ninety (90) days following the formal sales offer, the withdrawing Party shall be entitled to assign its interest in said machinery, equipment, and items to a third party. If THE ASSOCIATE wishes to withdraw after seventeen (17) years of the Production Period have elapsed, its rights in the Joint Operation shall pass to ECOPETROL free of charge, once the latter has accepted. CHAPTER VI - CONTRACT DURATION CLAUSE 23 - MAXIMUM DURATION This contract shall last for a maximum period of twenty eight (28) years running from the Effective Date and broken down thus: up to six (6) years for the Exploration Period in keeping with Clause 5 and subject to Clause 9 (numerals 9.3 and 9.8); and twenty-two years for the Exploitation Period counted from the ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 30. - -------------------------------------------------------------------------------- termination date of the Exploration Period. It is understood that when the Exploration Period is extended as provided for in this contract, this shall never signify an extension to the total twenty-eight (28) year term, except as stipulated in paragraph I hereunder. Paragraph 1: The Exploitation Period for Gas Fields discovered in the Contract Area shall have a maximum duration of thirty (30) years counted from the expiry date of the Exploration Period, or of the Retention Period. In any case, the total contract term for such Fields cannot exceed forty (40) years counted from the Effective Date. Paragraph 2: Notwithstanding the above, at least five (5) years prior to the expiry of the Exploitation Period for each Field, ECOPETROL and THE ASSOCIATE will study conditions for continuing exploitation beyond the term stipulated in this Clause. If the Parties agree to continue with such exploitation, they will define the terms and conditions therefor. CLAUSE 24 - TERMINATION This contract shall terminate in the following cases: 24.1 Upon expiry of the Exploration Period if THE ASSOCIATE has not discovered a Commercial Field, except as set out in Clauses 9 (numerals 9.5 and 9.8) and 34. 24.2 Upon expiry of contract duration, as stipulated in Clause 23. 24.3 At any date when THE ASSOCIATE so wishes and provided it has met its obligations stipulated in Clause 5th, and all others contracted hereunder. 24.4 For the special causes set out in Clause 25th. CLAUSE 25 - CAUSES FOR UNILATERAL TERMINATION 25.1 ECOPETROL may unilaterally declare this contract terminated at any time prior to expiry of the period agreed to in Clause 23, in the following cases. 25.1.1 Death or dissolution of THE ASSOCIATE or its assignees. 25.1.2 If THE ASSOCIATE or its assignees were to transfer this contract, fully or partially, without giving compliance to the provisions of Clause 27. ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 31. - -------------------------------------------------------------------------------- 25.1.3 For financial incapacity of THE ASSOCIATE and its assignees which shall be assumed when bankruptcy proceedings are filed. 25.1.4 When THE ASSOCIATE defaults on its obligations contracted under this contract. Upon expiry of each period defined for exploratory work, THE ASSOCIATE shall submit a written report showing performance of the obligations for the respective period. If such have not been performed, THE ASSOCIATE shall be given sixty (60) calendar days to diligently perform same in keeping with good petroleum practices. If such period is insufficient, the Parties may mutually agree to establish a longer period for performance. If the agreed work has still not been performed at the end of this new extension, there will be default and consequently ECOPETROL may proceed as set out in clause 25.3 25.2 When unilateral termination is declared, the rights of THE ASSOCIATE set out in this contract will lapse, both as interested Party and as Operator, if at such time the ASSOCIATE is acting in both capacities. 25.3 ECOPETROL may only declare unilateral termination of this contract when it has given the ASSOCIATE or its assignees sixty (60) calendar days advance written notice thereof, clearing stating the reasons for such decision, and when THE ASSOCIATE has failed to provide ECOPETROL with satisfactory explanations or to correct the default in contract performance. This does prevent THE ASSOCIATE from filing any appeal it considers to be in order. CLAUSE 26 - OBLIGATIONS IN EVENT OF TERMINATION 26.1 When the contract is terminated under Clause 24th during the Exploration, Retention or Exploitation Periods, THE ASSOCIATE shall hand over the buildings, pipelines, transfer lines and other movable items belonging to the Joint Account (located in the Contract Area), leaving any producing wells in production, and all of this will pass to ECOPETROL free-of-charge together with the rights-of-way and assets acquired for the contract, even though these may be located outside the Contract Area. 26.2 If this contract is terminated for any reason after the first seventeen (17) years of the Production Period, all interest of THE ASSOCIATE in the machinery, equipment or other assets or movables used or purchased by THE ASSOCIATE or the OPERATOR for contract performance, shall pass to ECOPETROL free-of charge. ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 32. - -------------------------------------------------------------------------------- 26.3 If this contract terminates in the first seventeen (17) years of the Exploitation Period, the terms of Clause 22 (numeral 22.10) shall apply. 26.4 If this contract is terminated unilaterally at any time, all chattels and real estate acquired exclusively for the Joint Account shall pass to ECOPETROL free-of-charge. 26.5 Upon contract termination at any time and for any reason, the Parties commit to give satisfactory compliance to their legal obligations both among themselves and with third parties, as well as those contracted hereunder. CHAPTER VII - MISCELLANEOUS PROVISIONS CLAUSE 27 - ASSIGNMENT RIGHTS 27.1 THE ASSOCIATE is entitled to fully or partially cede or transfer its rights, interests, and obligations in the Association Contract to another person, company or group, with the consent of the Minister of Mines & Energy and the President of ECOPETROL Consequently, THE ASSOCIATE must notify the Ministry of Mines & Energy and the President of ECOPETROL via a certified document of any project that implies total/partial assignment or transfer of its interest, rights and obligations hereunder, indicating essential points of the transaction such as possible assignee, price, interest, rights and obligations to be assigned, scope of the operation etc. The Minister of Mines & Energy and President of the Empresa Colombiana de Petroleos - ECOPETROL shall have thirty (30) business days to exercise their discretionary powers and appraise the possible assignees, and subsequently take a decision without being obliged to give reasons therefor. In any case, the criterion of the Minister of Mines & Energy shall prevail. 27.2 If the ASSOCIATE has not received a reply thirty (30) business after submitting the application to the Minister of Mines & Energy, it will be understood for all purposes that such has been approved. 27.3 Assignments made during the Exploration Period among companies legally established in Colombia shall not be subject to the above mentioned procedure, they shall be formalized by written authorization from ECOPETROL and signing the respective document. 27.4 Any change in the contractual relations between THE ASSOCIATE and ECOPETROL resulting from direct, total or partial transactions of the interest, ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 33. - -------------------------------------------------------------------------------- quotas or stock of the former must also be approved by the Minister of Mines and Energy and President of ECOPETROL. 27.5 However, such changes shall not require authorization from the Minister of Mines and Energy and Ecopetrol in the following cases-. 27.5.1 When the transactions are made in an open stock exchange. 27.5.2 When the transfer/cession is the result of matters beyond the control of the ASSOCIATE or the companies that control or direct same, such as governmental decisions, judicial sentences, division and award of assets and auctions. 27.5.3 When the negotiations take place between companies that control or direct THE ASSOCIATE, or their subsidiaries or affiliates, or between companies making up a single economic group, it suffices to notify the Minister of Mines & Energy and ECOPETROL of such assignment or cession in a timely way. 27.6 Except for the above cases, any cession, transfer, negotiation, transaction or operation referred to in this Clause that is made without approval or consent of the Minister of Mines & Energy and the President of ECOPETROL, when called for, shall give rise to the application of Clause 25th of the Association Contract. 27.7 If the operations carried out under this Clause give rise to taxes under Colombian law, such shall be paid. CLAUSE 28 - DISAGREEMENT 28.1 Whenever there is a discrepancy or contradiction in interpreting the clauses hereunder as compared to those of Appendix B known as the Operating Agreement, the former shall prevail. 28.2 Disagreements of a legal nature arising among the Parties with regard to contract interpretation and performance and that cannot be resolved in a friendly way, shall be referred to the decision of the jurisdictional branch of Colombian public power. 28.3 Any difference of a technical nature arising among the parties with regard to contract interpretation and performance and that cannot be resolved in a friendly way shall be referred to the final decision of experts appointed thus: one by each Party and a third chosen by the first two. If the latter are unable to reach agreement on such third expert, either Party may ask the Board of Directors of the Colombian Society of Engineers - SCI - having its head office in Santafe de ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 34. - -------------------------------------------------------------------------------- Bogota to appoint same. 28.4 Any difference of an accounting nature arising among the parties with regard to contract interpretation and performance and that cannot be resolved in a friendly way shall be referred to the final decision of experts who should be public accountants appointed thus- one by each Party and a third chosen by the first two. If the latter are unable to reach agreement on such third expert, either Party may ask the Central Board of Accountants of Bogota to appoint same. 28.5 Both Parties declare that the decision of the experts shall have the force of a settlement among themselves, and consequently shall be final. 28.6 If the Parties fail to agree on whether the controversy is of a legal, technical or accounting nature, such shall be considered legal and subject to Clause 28th (numeral 28.2). CLAUSE 29 - LEGAL REPRESENTATION Without impairing the legal rights of the ASSOCIATE as set out in law or in this Contract, ECOPETROL shall represent the Parties with Colombian authorities in matters regarding the development of the Contract Area, whenever such is called for, furnishing government offices and entities with all information and reports they may legally require. Operator must prepare the respective reports and hand them over to ECOPETROL. Any expenses incurred by ECOPETROL to attend matters referred to in this Clause shall be charged to the Joint Account. When such expenses exceed five thousand dollars of the United States of America (US$5,000) or the equivalent in Colombian currency, the Operator must first approve same. Regarding any relations with third parties, the Parties represent that neither the provisions of this or any other Clause in the contract, implies granting a general power-of-attorney, nor that the Parties have set up a civil or commercial association or any other relationship whereby either Party may be held jointly liable for the acts or failure to act of the other Party, or have authority or mandate to commit the other Party with regard to any obligation. This contract refers to operations within the Republic of Colombia and while ECOPETROL is an industrial and commercial company belonging to the Colombian State, the Parties agree that THE ASSOCIATE, if such were the case, may choose to be excluded from the provisions of sub-chapter K entitled Partners and Partnerships of the Internal Income Code of the United States of America. The ASSOCIATE may make such choice in a suitable way. CLAUSE 30 - RESPONSIBILITIES ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 35. - -------------------------------------------------------------------------------- 30.1 The Operator shall perform operations hereunder in a manner that is diligent, responsible, efficient, economically and technically sound and in keeping with internationally accepted industry practices for this type of operation, it being understood that at no time shall it be liable for errors of judgment, or loss or damage that is not directly attributable to it. 30.2 Liabilities contracted by ECOPETROL and THE ASSOCIATE hereunder with third parties shall not be joint, therefore each Party is individually liable for its share in the expenses, investments and obligations resulting therefrom. 30.3 Operator alone shall be liable with third parties for expenses incurred and contracts entered into for amounts exceeding forty thousand United States dollars (US$40,000) or the equivalent in Colombian currency when such have not been duly authorized by the Executive Committee, except as ruled in Clause 1 1 (numeral 11.7) and therefore it shall assume the full cost thereof. When the Executive Committee accepts such expenditure, it will pay Operator for the work, study or purchase in keeping with the guidelines it has set out in this respect. If the Executive Committee rejects the expense or asset, Operator if possible should withdraw same and reimburse the partners for any expense incurred in such withdrawal. When Operator is unable or refuses to withdraw the assets, the resulting equity increase or profit from such expenditure or contract shall belong to the Parties in proportion to their share in the Operation. 30.4 Ecological Control. In performing work hereunder, THE ASSOCIATE should comply with the provisions of the National Code for Renewable Natural Resources and Environmental Protection and other legal provisions on this matter. THE ASSOCIATE undertakes to carry out a permanent prevention plan to guarantee conservation and restoration of natural resources within the zones where it carries out Exploration, development and transport hereunder. THE ASSOCIATE should make these plans and programs known to the communities and to national and regional entities involved in this matter. Likewise, specific contingency plans should be established to deal with emergencies and take pertinent remedial action. To this end, THE ASSOCIATE should coordinate plans and action with the authorized entities. THE ASSOCIATE must prepare the respective Budgets and programs as set out in the pertinent clauses of this contract. All costs incurred shall be assumed by THE ASSOCIATE in the Exploration Period and in sole risk operations during the Exploitation Period. During the Exploitation Period these costs will be charged to the Joint Account and shared by both Parties. ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 36. - -------------------------------------------------------------------------------- CLAUSE 31 - TAXES, LEVIES AND OTHERS Taxes and levies related to Hydrocarbon production, caused after the Joint Account has been set up but before the Parties receive their production share, shall be charged to the Joint Account. Each Party shall be exclusively liable for its own taxes on income, capital and similar. CLAUSE 32 - PERSONAL 32.1 When THE ASSOCIATE is Operator, it should consult ECOPETROL before appointing the Manager for Operator. 32.2 According to the terms hereof, and subject to norms to be established, Operator shall be free to appoint the personnel needed for operations hereunder, and may fix salary, duties, categories and conditions thereof. Operator shall be diligent in training Colombian personnel needed to replace the foreign personnel that it considers necessary for operations hereunder. In any case, Operator shall comply with legal provisions on the proportion of local and foreign personnel. 32.3 Transfer of Technology: THE ASSOCIATE commits to assume the cost of a program to train ECOPETROL professionals in areas related to contract performance. In the Exploration Period, this obligation could be met by training in- geology, geophysics and related areas, reserve appraisal, reservoir characterization, drilling and production, among others. Supervised training should take place throughout the initial exploration period and its extension by integrating the ECOPETROL professionals to the work group THE ASSOCIATE sets up for either the Contract Area or other similar activities. If THE ASSOCIATE wishes to resign as set out in Clause 5, it must have first given compliance to these training programs. The Association Executive Committee shall establish the scope, duration, place, participants, conditions and other aspects of training during the Exploitation Period. THE ASSOCIATE shall assume all costs of supervised training during the Exploration Period, except for labor costs of the professionals attending same. During the Exploitation Period both parties shall assume these costs via the Joint Account. ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 37. - -------------------------------------------------------------------------------- PARAGRAPH: To comply with Technology Transfer called for hereunder, THE ASSOCIATE commits to run annual supervised training programs for Ecopetrol professionals for each of the first three years of the Exploration Period, in an amount of fifty thousand (US$50,000) United States dollars per year. ECOPETROL and THE ASSOCIATE shall first agree on the subject and type of training. If the Exploration Period is extended, the supervised training will be similar to that set out here. 32.4 During the Exploitation Period, Operator may perform any work through contractors, subject to the Executive Committee approval when the amount of the contract exceeds forty thousand dollars of the United States of America (US$40,000) or the equivalent n Colombian currency. CLAUSE 33 - INSURANCE The Operator shall take all insurance called for under Colombia law. Likewise, it shall require any contractor engaged in work hereunder to obtain such insurance as the Operator considers necessary and keep same in force. Likewise, Operator shall take such additional insurance as the Executive Committee deems suitable. CLAUSE 34 - FORCE MAJEURE or FORTUITOUS CIRCUMSTANCES The obligations referred to hereunder shall be suspended for such time as either Party is unable to fully or partially perform same because of unforeseen events that constitute force majeure or fortuitous circumstances, such as strikes, shutouts, wars, earthquakes, floods or other catastrophes, laws, decrees or government regulations that prevent procurement of essential materials and, in general, any non-financial reason that effectively impedes work, even when not listed above, but that affects the Parties and is outside their control. If force majeure or fortuitous circumstances prevent one Party from performing its duties hereunder, it should immediately notify the other Party, setting out the causes of 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. ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 39. - -------------------------------------------------------------------------------- 38.2 Differences arising in the application of this Clause shall be settled via the means set out in this Contract. CLAUSE 40 - DELEGATION AND ADMINISTRATION In keeping with ECOPETROL regulations, its President delegates the administration of this contract to the Vice President for Exploration and Production, with power to take all action pertinent to contract performance. The Vice-President of Exploration and Production may exercise this delegation via the Assistant Vice President for Joint Operations. CLAUSE 41 -VALIDITY This contract must be approved by the Ministry of Mines & Energy in order to be valid (and the incorporation and approval of the Colombian branch, if pertinent). In witness whereof, the parties sign in the presence of witnesses in Santa Fe de Bogota, on the 30th day of the month of December nineteen hundred and ninety-seven (1997) EMPRESA COLOMBIANA DE PETROLEOS ECOPETROL ENRIQUE AMOROCHO CORTEZ President SEVEN SEAS PETROLEUM COLOMBIA INC. GUSTAVO VASCO MUNOZ Legal Representative Witnesses ROSABLANCA ASSOCIATION CONTRACT - with Gas Incentives Page 40. - -------------------------------------------------------------------------------- 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 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 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 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. 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 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. 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 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 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 (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. 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 Are investments 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 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 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 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. 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 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. 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 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: 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. 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. 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 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: 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 (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. 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 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. 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 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 EX-10.C 3 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

POLYGONAL AREA: 151,933 HECTARES, 5,950 M2 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 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 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 EX-27 4
5 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. YEAR DEC-31-1997 DEC-31-1997 18,067 44 3,865 0 0 22,095 251,984 43 291,914 8,205 25,000 0 0 196,406 0 291,914 780 1,567 907 9,789 0 0 0 (7,928) 0 (7,928) 0 0 0 (7,928) (.24) (.24)

EX-23 5 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 ~~-----END PRIVACY-ENHANCED MESSAGE-----~~