Document of The World Bank

e' . FOR OFFICIAL USE ONLY Public Disclosure Authorized Report No. 5084-CO Public Disclosure Authorized STAFF APPRAISAL REPORT

COLOMBIA

PETROLEUM PROJECT Public Disclosure Authorized

October 19, 1984 Public Disclosure Authorized

Energy Department

This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. CURRENCY EQUIVALENTS

Currency Unit = Colombian Peso (C$) C$ 1 = 100 centavos (ctv) C$ 106.46 = US$1.00 (Sept. 21, 1984) C$ 1 =US$0.094 (Sept. 21, 1984) C$ 1,000 = US$9.4 (Sept. 21, 1984)

AVERAGE EXCHANGE RATES USED (C$/US$1.00)

1980 1981 1982 1983 47.28 54.49 64.10 79.53

WEIGHTS AND MEASURES

I Metric Ton (m ton) = 1,000 Kilograms (kg) 1 Metric ton (m ton) = 2,204 Pounds (lb) 1 Meter (m) = 3.28 Feet (ft) 1 Kilometer (km) = 0.62 Miles (mi) 1 Cubic Meter (mi) = 35.3 Cubic Feet (cu ft) 1 Barrel (Bbl) = 0.159 Cubic Meter 1 Barrel (Bbl) = Barrels of 42 gallons 1 Metric Ton of Oil (API 30) = 7.19 Barrels 1 Kilocalorie (kcal) = 3.97 British thermal units (BTU) 1 Ton of Oil Equivalent (t.o.e.) 10 million kcal (39.7 million BTU)

GLOSSARY OF ABBREVIATIONS

"M" preceeding any unit indicates thousand "RM" preceeding any unit indicates million lt,"4II preceeding any unit indicates billion

BD = Barrels per day MBD Thousand barrels per day MMB = Million barrels gal CGallon kW = kilowatt MCF TThousand cubic feet TCF Trillion cubic feet MMCFD = Million cubic feet per day

MW - Megawatt GW = Gigawatt TOE = Ton of Oil Equivalent

CONPES - National Economic and Social Policy Council DNP - National Planning Department ECOPETROL - Empresa Colombiana de Petroleos ENE - National Energy Study EOR - Enhanced Oil Recovery FEN - National Electricity Development Bank FRG - Federal Republic of Germany COGC - Government of Colombia OAS - Organization of American States UNDP - United Nations Development Program

GOVERNMENT OF COLOMBIA AND ECOPETROL FISCAL YEAR January 1 to December 31 FOR OFFICIALUSE ONLY COLOMBIA PETROLEUM PROJECT STAFF APPRAISAL REPORT

Table of Contents

Page No. I. The Energy Sector ...... 1 Energy Resources and Policies @ .. . 1 National Energy Study ...... 2 Financing of the Energy Sector . . 3

II. The Hydrocarbon Sector ...... 5 Overview ...... 5 Institutional Aspects ...... 5 Petroleum Geology and Exploration . . 6 Contractual Aspects of Oil Exploration .. 6 Exploration and Production Strategy . . 8 Production and Consumption of Crude Oil ... i0 Refineries and Products Consumption . . 11 The Pipeline System ...... 11 Consumer Prices of Oil Products. . 12 Natural Gas . .13 Government Strategy and Role of the Bank .. 13

III. The Borrower ...... 16 Background and Scope of Activities .16 Organization, Management and Staff.16 Budgets, Procurement, Accounts, Audit and Insurance .17 Financial Performance .19 Past Performance .20 Sector Investment Strategy .22

IV. The Project .. 27 Project Objectives ...... 27 Project Description . . 27 Project Preparation . . 29 Project Implementation . . 30 Implementation Schedule...... 32 Cost Estimate . .32 Financing Plan . .33 Procurement . .34 Items Proposed for Bank Financing and Disbursements .35 Ecology and Safety.36 Project Risks .36 Reporting Requirements .37

This report was prepared following an appraisal mission to Colombia in February 1984, by Messrs. W. Schaefer, C. Khelil, R. Leiva, J. Ristorcelli, and M. Heitner (Consultant).

This documenthas a restricteddistribution and may be used by recipientsonly in the performanceof their official duties. Its contents may not otherwise be disclosed without World Bank authorization. Table of Contents (Continued)

V. Future Financial Performance ...... 38 ECOPETROL's Projected Financial Statements ...... 38 Assumptions ... 42 Major Features and Sensitivity of Financial Projections . . . 44 Financial Covenants ... 45 Financial Rate of Return . . 46

VI. Economic Justification General ...... 47 Casabe EOR Scheme ...... 47 Association Field Development Schemes ...... 48 ConcLusion ...... 48

VII. Agreements ...... 49

Text Tables

1.1 Estimated Energy Reserves and Consumption .... 1 2.1 Investments in Oil Exploration ...... 8 2.2 Crude Oil and Gas Reserves and Production .... 9 2.3 Volume of Production, Consumption, Imports and Exports...... 10 2.4 January 1984 Retail Prices of Oil Products ... 12 2.5 January 1984 Retail Gas Prices ...... 13 3.1 Income Statements ...... 20 3.2 Balance Sheet as of December 31, 1983.21 3.3 ECOPETROL's Past Investments .22 3.4 Petroleum Sector Investment Program 1984-1988.23 4.1 Summary of Project Cost Estimate .32 4.2 Financing Plan .33 4.3 Procurement and Disbursement .35 5.1 Forecast Income Statements .38 5.2 Balance Sheets.40 5.3 ECOPETROL's Cash Flow .41 5.4 Domestic Demand (MBD).42 5.5 Domestic Production, Exports & Imports.42 5.6 Net Imports.43 5.7 Volumes and Prices of Domestic Crude Oil and Gas Purchases .43 5.8 Inflation and Exchange Rate Variation .44 6.1 Sensitivity Analyses .47 6.2 Economics of Association Field Developments .49 List of Annexes

2.1 Geology of CoLombia 2.2 Petroleum Exploration as of December 31, 1982 2.3 Crude Oil and Gas Proven Reserves 2.4 Past and Forecast Production of Crude Oil 2.5 ECOPETROL's Exploration and Production Strategy 3.1 ECOPETROL's Principal Investments by Company at End of 1983 3.2 ECOPETROL's Organization Chart 3.3 ECOPETROL's Investment Program 4.1 Fields Development in Association with Private Oil Companies 4.2 Implementation Schedule 4.3 Detailed Cost Estimate 4.4 Estimated Disbursement of Bank Loan 5.1 Past and Forecast Income Statements 5.2 Assumptions Underlying the Financial Projections 5.3 Financial and Economic Analysis of Casabe EOR Scheme 6.1 Economic Analyses of Association Field Developments 6.2 Documents Available in Project File

IBRD Map No. 18402

COLOMBIA

PETROLEUM PROJECT

I. THE ENERGY SECTOR

Energy Resources and Policies

1.01 Colombia is rich in energy resources,particularly in hydroelectricityand coal. Its reserves of oil and natural gas are modest by internationalstandards, yet significantat the national level. Its recoverablecoal reserves are estimated at 10 billion tons (4,6oo MMTOE). Its hydropower potential is estimated at 100 GW which could yield some 440 TWh (equalingabout 110 MMTOE) per year or 5500 MMTOE over 50 years. Gas reserves of 4.07 TCF (121 MMTOE) representing30 years of present production,are small in comparison,as are the oil reserves of 734 million Bbl (102 MMTOE), representing 13 years of present production:

Table 1.1

lltimxted Reserves and Production

Reserves Prodaction Reserves/Prod ,-4MOE (%) 4M4E (r) (%) Ws)

IVroelectricity 5,500 53 4.6 24.7 Renew. Ccal a/ 4,600 45 2.3 12.4 2,000 NaturalGas a! 121 1 4.0 21.5 30.3 CnudePetroleum a/ 102 1 7.7 41.4 13.2 10,323 100 177 100.0 a/ Recoverable

The table shows that there is an imbalancebetween reserves and production for different sources of energy. For example, the huge reserves of hydroelectricityand coal contribute only 25% and 12% respectivelyto annual production while the rather modest gas and oil reserves contribute 22% and 41% respectivelyto annual production. Rational use of Colombia's energy resources would focus on a gradual, long-term shift of production demand from oil to coal and hydroelectricityand it is current governmentpolicy to emphasize further hydropower and coal developments. However, in the medium- and short-termthere is an urgent need to increase recovery rates of existing hydrocarbonreserves and discover new ones. The hydrocarbon sector is discussed in Chapter II.

1.02 Colombia's coal resources are very substantial even on international scale, with recoverable reserves estimated at some 10 billion tons, of which only about 20% can be classified as measured. At present rates of domestic utilization, reserves would last two thousand years. In view of the magnitude of reserves, it is the Government's policy to encourage domestic consumption of coal to substitute for natural gas and for fuel oil, and to promote coal exports, particularlyfrom those deposits located near the Atlantic Coast. Coal production grew at about 7% per annum on average over the 1970s to reach - 2 -

a Level of about 5 million tons in 1983. Production came from about 400 small and medium-scale mines, virtually all of which are non-mechanized, run by the private sector and located in Central Colombia. More than half the production and consumption of coal is concentrated in the highlands near Bogota. Sixty percent of all coal is consumed by industry, and most of the rest by the power sector. Residential consumption and exports represent only a small share of total output. A major coal development project under way in the north of the country and 150 km from the shore will increase the production capacity by 15 million tons of coal per annum at the end of this decade; the full output will be exported. 1/ Colombian coal is bituminous, of high calorific value (mostly over 6,000 kcal/kg) and with low sulphur content (mostly less than 1%). All of the coal consumed domestically by the cities in the center of the country is produced in Central Colombia. Some of this coal possesses coking properties. In 1983, domestic coal prices, which are freely set by market forces, typically ranged between US$25 and US$35 per ton delivered to the large consumers in the industrial centers of Bogota, Medellin or Cali. This is below international prices, but high internal transport costs imposed by distance to ports and difficult terrain all but rule out the export potential of coal from the interior of the country.

1.03 Colombia's hydroelectric potential, at about 100 GW, is amongst the largest in the world. The country has made strides in developing this potential (hydroelectric power generation grew at about 10% per annum during the 1970s), and total installed hydro-capacity at present is 4 GW. Hydroelectric plants currently represent about 70% of total electric power generation and 80% of the installed capacity, and thermal plants the balance. The largest part of the thermal capacity is located on the northern coast, where hydro potential is limited, but where there is abundant coal and natural gas. The rapid expansion of the hydro-system continues due to its low cost and plants now under construction will virtually double capacity by 1988. However, the optimal mix of hydro, coal and gas-fired plants needs to be determined in order to take advantage of the projected increased supply of coal and the existing availability of a natural gas surplus. This matter is curtently studied by the Government.

1.04 Other energy forms are geothermal energy, which has understandably received only little attention in view of all the other rich energy sources, and firewood which remains an important energy source as primary household fuel.

National Energy Study

1.05 To assemble relevant base material on the energy sector and to develop energy options, the Government has undertaken a major effort to improve sector knowledge through a National Energy Study (ENE), which

1/ The project is a joint venture of CARBOCOL, the national coal production company, and INTERCOR, an Exxon subsidiary. The project cost is currently estimated at US$3.2 billion. was carried out between 1979 and 1982 by the National Planning Department (DNP) with the help of local consultants and technical assistance from UNDP and the Federal Republic of Germany (FRG). The study came up with the following major energy options:

(a) a further increase in the proposed leveL of hydrocarbon exploration by private companies and ECOPETROL, and a pricing policy for petroleum products, which will allow ECOPETROL to finance from internal sources a larger share of its investment program;

(b) adoption of energy conservation policies, particularly in the transport sector, aimed at reducing growth in consumption of liquid fuels;

(c) selection of a variety of energy substitution programs and policies, especially in the residential and industrial sectors, and to a lesser extent in the transport sector, through use of hydroelectric power, coal, gas, and renewables in place of petroleum products;

(d) production of liquid fuels from gas, coal, and biomass resources;

(e) the undertaking of additional coal export projects and development and exports of uranium and natural gas derivatives (methanol and LNG);

(f) filling rural energy needs through renewables and expansion of rural electrification.

1.06 This study provides significant information needed for energy planning; it includes a preliminary evaluation of energy demand growth and of investments that could best serve such growth. However, much work remains to be done, particularly in the selection of alternative energy sources. The following studies related to the ENE are now about to commence, part of which will be financed by foreign technical assistance; particularly the Federal Republic of Germany will be providing assistance on modeling and data gathering, France on industrial energy savings, Italy on rural electrification, and the OAS on energy use in transportation. Several energy sector agencies and the Ministry of Public Works will provide counterpart staff and DNP will coordinate the external assistance.

Financing of the Energy Sector

1.07 Over the past five years, CoLombia has been reasonably successful in mobilizing external resources to finance energy development. This has been achieved through direct private foreign investments (in oil exploration and production and lately in coal) and external loans to the energy agencies, including power companies and the National Electricity Development Bank (FEN). However, the current large debt of Latin American countries makes it difficult for Colombia to mobilize additional external long-term funds. Local financing requirements are covered by internally generated resources and Government contributions, with the incipient local capital markets providing - 4- to date only a marginal share of the financing. In order to increase internal resource mobilization by the main agencies dealing in the energy sector, oil prices and electricity tariffs have been increased significantly in real terms; domestic prices of oil products are now broadly at the international level, which is adequate. In all, despite the recent achievements, mobilizing the financial resources required for the energy sector will require continuous; efforts by the Government; at the same time, energy sector investments offer excellent avenues at present to improve Colombia's balance of payment position in the medium and long-term.

Conclusions

1.08 The main issue in Colombia's energy sector is the investment priority, which will be addressed by the current studies being undertaken by the Government. Investments in coal and hydropower are priority, but long- term. Investments in gas are uncertain due to lack of a streng market. Investments in oil are priority in the short-term, in particular in exploration to increase reserves, and in production and refining to lower imports. Together with ECOPETROL, the private sector has strongly participated in the oil investments (exploration and production under association contracts) in the past and is expected to do so in the future. -5-

II. THE HYDROCARBON SECTOR

Overview

2.01 Colombia is a mature petroleum province which has been relatively well explored; it has exported considerable quantities of crude oil starting in the 1920's. However, policies pursued during the 1960s and the early 1970s contributed to a deteriorating oil situation. Prices to consumers and producers were kept artificially low, thus promoting consumption and dampening incentives for development of new reserves. Since 1976, the country has been a net importer of petroleum products, with adverse repercussions on the national balance of payments. Since then, the Government has gradually taken the steps required to (i) limit the domestic use of liquid fuels by increasing consumer prices to adequate levels (internal prices were increased by more than threefold in real terms between 1974 and 1980, and, lately, have fluctuated around the international prices); (ii) attract foreign investors to explore in Colombia by increasing the producer price to international levels for newly discovered oil; (iii) encourage the concession holding companies to pursue an aggressive drilling program by increasing the producer price for newly produced oil; (iv) mobilize the financing required for increased production from new fields and old fields by enhanced oil recovery schemes; and (v) encourage substitution of petroleum products by other forms of energy, where appropriate. These policies have yielded significant results. Consumption growth of petroleum products was only about half of GNP growth from 1979 to 1981, whereas it was higher than GNP growth from 1975 to 1977. Since 1979 accelerated exploration has increased recoverable reserves by about 343 million barrels, and production has increased by an average 7% p.a., from 123.4 MBD in 1979 to 152 MBD in 1983. Further pursuit of these policies may make Colombia self-sufficient in hydrocarbons in the 1990s.

Institutional Aspects

2.02 The central authority responsible for the development of petroleum resources in Colombia is the Ministry of Mines and Energy. The Ministry is in charge of all policy matters and of the overall organization and administration of the sector. The National Planning Department (DNP) reviews, and the interministerial committee CONPES approves major hydrocarbon investments which require foreign financing. The Empresa Colombiana de Petroleos (ECOPETROL), a state-owned company, was established in 1948, and started operations in 1951, by operating the concession fields and the refinery that reverted from an oil company to Colombia after the expiration of the concession. It plays an active role in exploration, production and refining (Chapter III). ECOPETROL is the main executing arm of the Government in the hydrocarbon sector.

2.03 In February 1984, as many as 42 exploration/production contracts with about 25 foreign and local oil companies were active in Colombia. Thirty two of these contracts involved exploration, six production, and five exploration and production. The companies include majors such as Exxon and Texaco; independents like Occidental and Houston Oil and Gas; a European company - Elf Aquitaine; many smaller companies such as Louisiana Land and Exploration and PETROCOL, a Colombian company which received assistance from IFC. - 6 -

2.04 The local service industry is reasonably well developed and ECOPETROL contracts it frequently in particular concerning detailed engineering design. drilling/workover services and assembling of certain oil field equipment in Colombia using foreign technology through joint foreign/local partnerships.

Petroleum Geology and Exploration

2.05 Colombia's prospective sedimentary areas cover 586,000 km2, and are divided into 12 basins of unequal size and prospectiveness (Annex 2.2). Eleven of these basins have recognized hydrocarbon source and reservoir rocks with adequate traps usually of the structural type (anticlines and/or faults). Jurassic and particularly cretaceous shales are usually considered to be source rocks of the oils trapped in overlying reservoirs. The Upper Rio Magdalena Valley, the Middle Magdalena Valley and the Llanos Orientales basins are considered the most prospective (see map IBRD 18402). Colombia's geology is described at Annex 2.1.

2.06 Colombia's history of petroleum activity dates back to the early 1900's. So far, nearly 900 exploratory wells have been drilled in 11 of the sedimentary basins (Annex 2.2). This resulted in the discovery of recoverable reserves of about 3 billion barrels of oil and 4 trillion cubic feet of gas of which 618 million barrels of oil and most of the gas remained to be produced as of December 1982 (Table 2.2 and Annex 2.3). Taking into account production during 1983, new discoveries (Elf, Occidental) and secondary recovery reserves from Casabe (70 million Bbl), total recoverable reserves at December 31, 1983 are estimated at 734 million barrels (Annex 2.3). On average, Colombia's exploratory efforts have resulted in a ratio of one commercial well discovery for nine dry wells or an overall success ratio of 10% which is favorable compared to many other countries. At the 1983 rate of production (150 MBD), the reserve/production ratio for oil is 13 years which is somewhat Low, but better than the 10.5 in 1979. The upper, middle and lower Magdalena valLey have been explored most as shown in Annex 2.2. However, there is scope for additional exploratory work, particularly in the Cauca, Sabana de Bogota, and Amazona basins. ECOPETROL is promoting these and all other basins actively to the!international oil industry (para. 2.14).

Contractual Aspects of Oil Exploration

2.07 Historically, the legal framework governing oil exploration in Colombia was of the concession type, where the exploration period was three years (with a possible 3-year extension), and the production period 30 years. The concessionaire was 100% owner of the oil produced, and had to pay royalties (initially 14.5% - later 20%) and income tax. In 1969, a new legal framework was introduced - the association contract - and since 1974, no new concession contracts have been entered into. There are still 16 concession contracts in effect which will expire, for the most part, in the 1990's.

2.08 The association contracts provide the Government, through ECOPETROL, with the possibility of a significant involvement in the venture, in the event of a commercial discovery, without the obligation to incur the necessarily rislkyexploration expenditures. The main features of the association contracts are: (i) an exploration period of up to 6 years, and a production period of 22 years; (ii) companies are allowed to choose areas without limitations as to the size, shape, or location, and to propose to ECOPETROL -7 - the terms and conditions regarding the mileage of seismic profiles to be run during the first year and the number of exploration wells to be drilled during the second and third years on which agreement needs to be reached; (iii) companies bear the exploration risk, but in the case of commercial discoveries, ECOPETROL reimburses the companies for 50% of the cost of the discovery well out of future production and pays in cash 50% of the subsequent development and operating costs; (iv) technical control of the operations is agreed to between the parties, and the operator may be either ECOPETROL or the partner, but is normally the partner; (v) during exploitation of the contract areas, the operator must deliver to GOC, through ECOPETROL, a royalty amounting to 20% of the liquid hydrocarbons and gas produced in the area; the rest of the oil and gas produced is owned by the partners on a 50/50 basis; (vi) exports are allowed only after domestic requirements are met; and (vii) apart from the 20% royalty and the sharing on a 50/50 basis of the balance of production, companies only pay taxes in accordance with the General Tax Code applicable to all companies who are not concession holders; such tax regulations allow amortization of intangible drilling costs (20% per annum) and depreciation of tangibles over the "useful Life" of the investment.

2.09 Since 1976, the Government has also increased producer crude oil prices to provide adequate incentives for exploration and production. Until 1975, crude oil was priced domestically at US$1.60/Bbl. Since 1976, however, association contracts provide that for "new" discoveries, ECOPETROL will purchase crude oil at the C.I.F. Cartagena price for similar crudes. In the case of fields that were under production at that time ("old" or "basic" oil), there is now a price for "base" crude (production following the normal decline of specific fields) and for "incremental" crude (production in addition to the normal decline). The price of base crude is about US$5-7/Bbl and adjusted annually wi,:h inflation indices, while the price of incremental crude is calculated according to a formula, reflecting the ratio of incremental over basic crude production and the international price, but cannot exceed 50% of the international price of crude oil. It is set to allow the firm to attain a discounted rate of return on the investment of about 20-25% (Ministerial resolution 058 of May 1980). The incremental price incentive system has helped reduce the natural decline in the production of those fields to 5-6% since 1976 compared to 6-9% from 1971 to 1976.

2.10 In 1975, The Government also revised the payment clauses which then resulted in sales of crude oil at exchange rates which were 20-35% below the official rates. Foreign companies continue to receive 25% of payments in local currency and 75% in US$ outside of Colombia, but these are now converted at official exchange rates. Moreover, the scope for profit remittances abroad (particularly those resulting from discoveries of natural gas) was improved. - g -

2.11 In all, the new financial/contractual framework has been successful ilnattracting private investors as the following table indicates (although exploration activity declined in 1983 in line with the world-wide trend):

Table 2.1

Investments in Oil Exploration

Private Companies Ecopetrol Total (No. of new contracts) (US$Mil) (US$Mil) (US$Mil)

1976 12 20 8 28 1980 18 153 29 182 1981 12 223 50 273 1982 8 231 51 282 1983 (est.) 21 110 50 160

Similarly, the annual average of exploratory wells drilled had declined sharply from about 34 during 1961-1969 to about 20 during 1970-1974 and further down to about 16 during 1975/76. However, a sharp increase in exploration has taken place since then, after price increases for association crude was announced (para. 2.09):

Number of Exploratory Wells Drilled

1977 1978 1979 1980 1981 1982 1983 Total Yearly Average 20 26 29 59 100 75 37 346 49

The decline in number of exploratory wells drilled from 100 in 1981 to 75 in 1982 is mainly due to the average higher cost per well in the Llanos area which was the main focus of exploration in 1982 when exploration expenditures increased slightly over those in 1981. The increased exploration activity since 1979 has resulted in an increase in recoverable reserves by about 343 million barrels (or nearly 53%) over the five-year period 1979-83. The recent discoveries in Apiay (operator ECOPETROL), Cano Limon (Occidental), Casanare (Elf), Cocorna (Texaco), and Castilla (Chevron) have also contributed to stir industry interest in exploring in Colombia.

Exploration and Production Strategy

2.12 Concerning accelerated promotion of exploration, the Government has turned to private international oil companies, while at the same time allowing ECOPETROL to explore in certain areas with its own resources (Annex 2.5). ECOPETROL's exploration program will concentrate on areas in the vicinity of its producing fields where the geology is reasonably well known. In addition, ECOPETROL is carrying out seismic surveys part of which it uses to promote acreage to private industry. As a result, ECOPETROL has accumulated large quantities of exploration data which are likely to stimulate additional exploration interest by private oil companies. Foreign companies are exploring the less known areas, which carry a higher exploration risk, but where the financial rewards will be competitive in relation to contractual/financial conditions elsewhere. In particular, the execution of the proposed Llanos pipelines (para. 2.22) is expected to spur industry interest in that area, given the considerable reduction in transport costs. - 9-

Moreover, ECOPETROL has recently embarked, for the first time, on an important promotional effort towards the oil industry. It has prepared an audio-visual program on Colombia's geology and its legal/fiscal framework for presentation to the oil industry in seminars in May 1984. ECOPETROL anticipates that foreign companies will invest some US$450 million in exploration in Colombia over the 1984-88 period, more than double its own budget of about US$200 million. These investments should result in the discovery of about 150 MMB recoverable reserves in the medium term. In conclusion, the exploration strategy is balanced and reasonable.

2.13 As of December 31, 1982 recoverable reserves were estimated at 618 MMB (Table 2.2). During 1983 averageproduction was 150 MBD. In 1983 ECOPETROLhad 46% of recoverablereserves of oil and also 46% of production. This compareswith 29% of reservesand 13% of productionfor associations which are relativelynew and where the fields are not yet fully developed,and 27% of reservesand 41% of productionfor concessionswhich representmuch older fields which are fully developed.

Table 2.2

CrudeOil ars Gas Reserves and Prox-ion

Rec,jerableReerves as B0O'iULShgre of Decenber31,198 Productionin 1983 (Incl.Rqalty Oil N1LturalGes Oil NEituralGas Capary inAssoc. contr.) % RF&T(VT%) (MD) M WM) 5)

EDPE]DL 100 2T8 16 164 4 68.9 46 13 3T

ASSOCIArlI0N 1.Colcitco 40 10 202 6.3 47 2. P-trocol 60 2 - 1.6 - 3.TerraResorces 20 1 - 0.7 - 4.Chevron 60 86 - 4.6 - 5.Texaco 60 54 - 3.4 - 6. ElfAquitaine 60 2T 6 0.7 - 7. Ixtercol 20 3 - 2.0 - 8. Temco 60 - _ 3,33 _ 86 Sub-TotalAssoiation @ 3,571 T 19.3 13 133 3

1.Texaro 0 62 17 13.2 2. Intercol 0 2 PP4 10.0 57 3.Hc stonOil 0 79 24 34.7 - 4.Chevron 0 4 1 3.0 5.ElfAcxLtaine 0 10 - .6 - 6. sanAndres 0 - 11 - 26 7.Antex 22 - 29 20 Sub-TotalAssoiatimn 157 25 3 8 _.s5 41 103 27

caWBY ToioL 618 100_~~~ 4 o01 lOO 1i4.7 100_ _ 372 _-100 - 10 -

2.14 To increase production, ECOPETROL has embarked on a program of increased recovery from existing fields through infill and step out drilling and application of enhanced oil recovery techniques (and the project would assist in these efforts). It has carried out an enhanced oil recovery scheme (EOR) in its La Cira fields and is planning to carry out the Casabe EOR scheme to be financed under the project. Texaco is carrying out an EOR scheme in Cocorna field under association contract, also to be financed under the project. However, there is an estimated additional potential for EOR of another 200 MMB from existing fields, half of which from ECOPETROL's own fields and the other half from fields under concessions. ECOPETROL and the private oil companies are studying the potential for EOR and at least one major concessionaire is actively considering implementation of an EOR scheme in its fields.

Production and Consumption of Crude Oil

2.15 Crude oil production declined throughout the 1970's, from 218.1 MBD in 1970 to 124.1 MBD in 1979, or an average decline of 6% per annum. Since 1980, however the trend has been reversed, in part because of the new policies introduced since 1975 regarding pricing (para. 2.09) and payment provisions, and production has increased from 124.4 MBD in 1980 to 152.0 MBD (taking account of 2 MBD apparent inventory drawdowns) in 1983, an average increase oi 7% per annum. Despite this turnaround, Colombia still remains a net importer of oil:

Table 2.3

Volume of Production, Consumption, Imports and Exports ('000 BD)

Actual Forecast 1970 1975 1980 1983 1988

Production 218.5 156.3 124.6 152.0 173.6 Imports - 4.0 52.3 57.9 64.0 218.5 160.3 176.9 209.9 237.6 Less Exports 112.8 30.5 30.7 43.5 55.9 Consumption 105.7 139.8 146.2 166.4 181.7

Self Sufficiency 207% 112% 85% 91% 96%

Source ECOPETROL. Only proven reserves are included in the production forecast.

The balance of payment impact of oil imports is considerabLy understated in the above table as Colombia imports high value products (essentially gasoline and crude oil), and exports a low value product (fuel oil). The net cost of imports reached US$350 million in 1981, and declined to US$210 million in 1983. Without the proposed project these imports could increase to about US$L billion. Even with the project, the net cost of oil imports could reach US$250 million by 1988, unless additional discoveries are made and quickly developed. These estimates are based on information available in early - 11 -

1984. Since then Occidental has had further successful exploration wells in the Llanos area, so that they estimate the reserves at Cano Limon as so significant that Colombia would definitely become a net exporter in petroleum in the next few years.

Refineries and Products Consumption

2.16 With increases in the demand for petroleum products, the refining capacity in the country has also expanded from 78 MBD in the 1960s to 176 MBD in 1979, and 220 MBD in 1984. At present, there are five refineries operating in Colombia. Two refineries, at Barranca Bermeja and Cartagena, account for the bulk (210 MBD) of refinery capacity. In February 1984 the refineries were operating at about 85% of capacity.

2.17 The Colombian market for oil products is characterized by a large share of gasoline (nearly 50% of products consumption), and a relatively small share of fuel oil (less than 7%). This is due to extensive use of hydropower in the central and southern part of the country and the use of coal and to a limited extent, natural gas, as a boiler feedstock for power generation and industry, mainly in the northern part of the country.

2.18 Despite heavy investments in recent years in cracking facilities, the output of Colombia's refineries does not match the pattern of demand, with light products being short and heavy products being in excess. As a result ECOPETROL imports crude and gasoline in proportions, which optimizes the use of its refineries, but also minimizes its losses since part of the imported crude is reexported after refining as fuel oil at a lower price (The price differential varied from US$10 per barrel in 1982 to US$3.5 per barrel in 1983.). A consultant (Bechtel, U.S.A.) has been appointed recently to carry out a master plan study for the refining sector in Colombia, which will examine the feasibility of further conversions and upgrading in the existing refineries, as well as the option of constructing a new refinery which would refine and crack mainly the heavier ends (Fondo Barril).

2.19 The Government has also taken measures to limit the growth of gasoline consumption by increasing the retail price of gasoline, so that gasoline consumption which grew by 5-6% annually in the 1970's, has been increasing by about 3% a year since 1980. The consumption of diesel oil increased at a similar rate as gasoline. The share of fuel oil (which includes that of a heavy crude being used directly as a fuel oil substitute), has been declining since 1980 and this is expected to continue, as fuel oil is being replaced by coal. The Government is also attempting to increase the efficiency of energy use in transport by encouraging mass transportation systems, in particular buses and cars with low fuel consumption.

The Pipeline System

2.20 The Colombian pipeline system comprises about 7,700 kilometers of pipelines of various sizes which run principally along the Magdalena River, beginning at Neiva, to Cartagena and passing through the refinery at Barranca Bermeja (Map IBRD 18402). The cities of Cali, Medellin, Bogota, Barranquilla, Bucaramanga, and Santa Marta are also linked by the pipeline system. Generally, crude oil flows northwords from the fields to the Barranca Bermeja refinery, and the refined products flow North and South from there. In - 12 -

addition there are two short pipelines which run from the oil fields at Orito to Tumaco, and from the oil fields in the Western Llanos to Yopal. Further there is a gas pipeline network which carries gas southward from the Guajira offshore fields, and northward from the Jobo/Tablon gas field, to Cartagena, BarranquilLa and Santa Marta. The pipeline sizes range from 4 to 16 inches and they traverse terrain which ranges from rugged mountains to swamp lands. ECOPETROL owns 65% of the national pipeline system, and the private foreign and local companies own the balance. One local pipeline company, PROMIGAS which owns a gas pipeline from Guajira to Cartagena received financial assistance from IFC.

2.21 The recent discoveries in the Western Llanos at Apiay, Cano Garza/Trinidad and Cano Limon by ECOPETROL, Elf and Occidental respectively could have the potential to produce a total of 70 MBD per day, according to preliminary estimates. The only existing means to transport this crude to the refineries at present is by tank-truck, which is three to five times more costly than by pipelines, in addition to the disadvantage of less reliability. The construction of pipelines to those fields has therefore become high priority; the design has been optimized from the point of view of the national economy and once commissioned, they will give a further impetus to the exploration activity in that province. A northern pipeline of about 290 km would move the Occidental association crude from Cano Limon to Rio Zulia where it would enter existing westward bound pipelines. A southern pipeline of about 480 km would transport the ECOPETROL Apiay crude and Ecopetrol/Elf Casanare crude westward to Velasquez where it would also enter an existing pipeline. Both projects are essential to bring the Llanos area fields to their full production level.

Consumer Prices of Oil Products

2.22 Up to 1975, retail prices for oil products in Colombia have been low, as the country was a producer. As gasoline imports grew, and the balance of payment impact of oil imports began to be felt, the Government gradually increased consumer prices in real terms so that they were on average within 10% of international levels since 1980. The prices were last increased in January 1984 basically to adjust with the domestic inflation, and are as follows:

Table 2.4

January 1984 Retail Prices of Oil Products

Domestic Price Border Price C$/Callon US$/Gallon US$/Gallon

Gasoline 77.5 0.87 0.82 Diesel Oil 77.5 0.87 0.88 Kerosene 77.5 0.87 0.73 Fue; oil 40.8 0.46 0.62

Thus the prices of gasoline and kerosene are above the CIF price, the price of diesel oil is practically at the border price level and that of fuel oil is some 25% below the FOB price. This is mainly because gasoline, diesel oil and kerosene are heavily taxed (about 30% of the retail price), while the tax on - 13 -

fuel oil, which is in surplus and being exported, is low (about 4%). Although the price of fuel oil is below international levels, it did not cause any demand distortions, given that fuel oil was partly substituted in the past couple of years by still cheaper coal and gas. In conclusion, Colombia's price level for petroleum products is satisfactory.

Natural Gas

2.23 Colombia has large natural gas reserves (about 4.05 TCF equivalent to some 700 million barrels of crude oil), which are presently considerably underutilized (at the present production rate of 370 MMCFD, reserves are sufficient for about 30 years). The main difficulties for utilization of natural gas are the location of the reserves (most of the reserves are in the Guajira province, in the Northeast, which lacks infrastructure, and is far from potential markets), and the lack of opportunity for fuel oil replacement, Colombia having already replaced much of the fuel oil consumed by cheaper coal. Therefore, even though prices for natural gas are particularly low, the market remains very limited in spite of the financial incentive.

Table 2.5

January 1984 Retail Gas Prices

C$/MCF US$IMCF % of Revenues

Electricity 44.25 0.50 52 Industry 120.00 1.35 ) ) 45 Petrochemical Industry 77.70 0.88 ) Residential 135.00 1.521 3 100

Power generation represents the main outlet, while industrial, petrochemical and refining industries account for the balance. The residential market is insignificant. Gas is being gradually phased out from power generation and being replaced by coal and hydroelectric power.

2.24 In the next five years, consumption of gas is not expected to increase significantly. The main economic applications of gas to be considered are fertilizers and petrochemicals, in addition to the production of methanol and compressed natural gas (CNG). The most obvious use of fuel oil substitution is not a viable proposal, since (i) the Castilla heavy crude, which is used as fuel oil, cannot be used elsewhere due to its high metal content and (ii) much of traditional fuel oil consumption has been substituted by coal. Under UNDP financing, a Japanese consulting company has carried out a study for potential use of gas in production of fertilizers, and petrochemicals. Moreover, ECOPETROL has embarked on a small pilot project for use of compressed natural gas (CNG) in a fleet of vehicles. As gas represents an important resource with potential in Colombia, DNP and ECOPETROL are carrying out a gas utilization study that would help the Government and ECOPETROL establish a strategy for gas use. - 14 -

Government Strategy and the Role of the Bank

2.25 The Government's long-term strategy in the energy sector is to develop its abundant coal and hydropower reserves and to substitute, where appropriate, demand for petroleum products. In following this strategy, the Bank's past involvement in Colombia's energy sector has essentially been in the power sector. The Bank has made 29 power loans totalling US$1,708.6 million. In March 1984, the last power loan was made to the Financiera Electrica Nacional, a financial intermediary which mobilizes financing for various electric utilities (Loan 2401-CO). A coal exploration loan was approved in October 1983 (Loan 2349-CO). However, in the short run there is an urgent need to develop existing oil reserves and discover new ones to couinterthe natural decline of existing fields and to increase domestic production. The proposed project would represent the Bank's first operation in Colombia's petroleum sector and would address this need.

2.26 The Colombian Government has developed a comprehensive framework of petroleum sector policies. Both producer and consumer prices for crude oil and petroleum products, respectively, have since 1980 closely followed world market prices fostering efficient supply and demand management. The legal and financial aspects of the contractual framework offered to private oil companies has led to the signature of 59 new exploration contracts between 1980 and 1983, and exploration and production investments by the private sector more than doubled compared to the previous 4 year period, so that the private sector share of production augmented from 43% to 54% of total production in the three years from 1980 to 1983.

2.27 In the light of these developments, the Bank reviewed ECOPETROL's five year investment program, which was subsequently reduced from US$2.8 biLLion to US$2.1 billion on the advice of the Bank. The investment program was structured in order to emphasize support for private sector activity and to concentrate on low risk investments. Of the overall petroleum sector investment of US$3.1 billion (para. 3.25) almost 70% are either private sector investment (31%) or in direct support of the private sector: exploration prom.otion (2.5%), contribution to association contracts (12%), pipeline infrastructure (11%), and refineries (12%). The two Llanos pipelines are designed with excess capacity on the advice of the Bank to accomodate procluctionfrom new fields in the Llanos. This would improve the attractiveness of the area by reducing transport cost and the time required to exploit new fields. Refining capacity would be expanded to process increased private sector production of crude.

2.26 ECOPETROL's own investment program is now almost exclusively focussed on fields and facilities that reverted to it under concession agreements with private oil companies, which include refineries. ECOPETROL's own efforts are furthermore concentrated on low risk activities leaving the high risk undertakings with high potential returns to the private sector, where it can make its most efficient contribution. ECOPETROL reduced its own exploration program to about US$200 million compared to US$450 million estimated to be invested by the private sector. The program (about 4% of total petroleum sector investments excluding the exploration promotion elements) is carried out in areas close to existing fields on well known structures. ECOPETROL will continue to develop its own fields and carry out the quick yielding enhanced recovery program in its Casabe field with private management - 15 - assistance (together about 20% of total sector investment). ECOPETROL's miscellaneous investments (including major maintenance) account for the remaining 8% of total sector investment. Yearly review of the investment program and financing plan would focus on high yielding projects and an adequate role of the private sector.

2.29 Bank financing is directed towards quick yielding, high return projects that have a large impact on Colombia's balance of payments and ECOPETROL's capital structure with the purpose of improving its prospects to raise long term funds from commercial banks. ECOPETROL's two lead banks have expressed reservations about additional long-term lending to ECOPETROL under present circumstances. These serious difficulties in obtaining long term financing at reasonable cost has adverse implications for the financing of ECOPETROL's share of the development of attractive new discoveries in association with private sector partners, and for the development of its own reserves, and enhanced oil recovery schemes. The two major investment components proposed for Bank financing, the Casabe enhanced recovery project and the association contract investments would lead to additional crude production, which by 1988 is forecast to amount to 20% of total crude production in Colombia. Apart from contributing to Colombia's balance of payments (about US$450 million in 1988) this would strengthen ECOPETROL's internal cash generation which would finance as much as 60% of its investments and improve its debt/equity ratio. By providing funds for these activities the Bank would ensure quick implementation and provide ECOPETROL with the necessary funds to finance its share under association contracts with its private partners. In financing a small amount of the Cano Limon-Rio Zulia pipeline the Bank would act as a catalyst to mobilize export credits.

2.30 Bank financing and the proposed financial covenants would improve ECOPETROL's creditworthiness and increase the potential for commercial lending. B-Loan arrangements would be pursued with the two lead banks of ECOPETROL, which have indicated interest in such an arrangement after the above described improvement of ECOPETROL's finances and an improvement of Colombia's economic outlook. Thus, Bank financing would allow ECOPETROL to mobilize commercial long term funds in the medium term and to take immediate advantage of high return investment opportunities.

2.31 Colombia has a large potential for secondary recovery programs (about 200 million barrels of crude oil). The implementation of such schemes is complex, since they require close monitoring of the water flows and their sweeping efficiency and prompt correcting measures if necessary. On the Bank's recommendation, ECOPETROL has recently set up a special unit for preparation of enhanced recovery projects. The proposed Bank Loan would finance technical assistance in the critical phase of the Casabe enhanced recovery project and for secondary recovery pilot projects. In particular, a competent team of specialists would be trained which would develop a comprehensive approach to future enhanced recovery programs, which possibly could be implemented with private sector participation. In addition, the proposed Bank project would help ECOPETROL establish adequate environmental protection policies. In preparation of the proposed project, the Bank has established sound relations with ECOPETROL, oil companies which are ECOPETROL's private partners, and cofinancing agencies. Bank operations with ECOPETROL could further deepen this dialogue and contribute to the efficient development of Colombia's petroleum sector, taking account of the role of the private sector. - 16 -

III. THE BORROWER

Backgroundand Scope of Activities

3.01 The Empresa Colombiana de Petroleos (ECOPETROL)was created in 1948 and began operations in 1951 when the De Mares concession and the Barranca Bermeja refinery reverted to the state from the Tropical Oil Company (Exxon) at the end of a 30-year concession. ECOPETROL's present statutes were published in January 1970 under Decree 062. It is a state-owned corporation, directly involved, or associated with private companies, in the exploration of some 6.8 million ha, and it has performed geological and geophysical studies over a further 20 million ha. In 1982, ECOPETROL's sales were about 5% of Colombia's GNP and the existing gasoline excise tax provided about 8% of total Government tax revenue.

3.02 ECOPETROL's fields account for about 46% of Colombia's overall production; in addition, ECOPETROL has a 60% share (including a Government share of 20%) in the association contracts which account for 13% of Colombia's production (para. 2.06). All domestic production from oil companies (under association and concession contracts) is sold to ECOPETROL as long as Colombia is a net importer. ECOPETROL controls all the country's refinery capacity of about 220,000 BD and about 65% of the total national oil and gas transportation system, which comprises about 7,700 km of pipelines. ECOPETROL is the sole exporter of hydrocarbon products from Colombia.

3.03 ECOPETROL has interests in a number of companies whose principal activities range from exploitation and development of oil fields to transportation and distribution of products and petrochemicals. ECOPETROL also owns interests in coal (49% of CARBOCOL)1/, electrical utilities and financial corporations. At present, the total amount of its subsidiary interests accounts for 12% of ECOPETROL's net worth. Annex 3.1 lists the principal companies.

Organization, Management and Staff

3.04 ECOPETROL is governed by a five-man board, chaired by the Minister of Mines and Energy, and appointed directly by the President of Colombia. The directors customarily are persons with experience in industry and commerce. The board meets every week and is kept well informed. The board has broad powers concerning all aspects of ECOPETROL's operation and has delegated adequately to ECOPETROL's chief executive.

3.05 Reporting to the board is ECOPETROL's chief executive (president), who is also appointed by the President of Colombia. Assisting him are five vice presidents, responsible for exploration, production and manufacturing, engineering and projects, finance, and administration. ECOPETROL's

1/ In FY1984, the Bank made a US$9.5 million loan to CARBOCOL for coal exploration and technical assistance (Loan No. 2349-CO of October 1983) (para. 2.25). - 17 -

organization chart appears in Annex 3.2. The current president of EGOPETROL, who was appointed to his post in August 1982, is a qualified and competent manager who has a chemical engineering background and previously was on the board of directors of several large enterprises in Colombia. His five vice presidents are all professional oilmen whose length of service with ECOPETROL is 16 years and above.

3.06 In general, the company is mature, competently staffed and organized. The fields, refineries and pipelines it inherited were delivered in good working order and with trained personnel to operate them. It is from this corps of engineers, geologists, accountants, and administrators that ECOPETROL has drawn most of its current senior management.

3.07 As of December 31, 1983, ECOPETROL's staff numbered 8,000 of whom 2,500 were technical supervisory staff. ECOPETROL has no difficulties recruiting competent professional and support staff, largely because overall salaries and benefits paid are considered to be among the best of public enterprises in Colombia. After 10 years of service, employees enjoy free education for their children right through university, medical treatment for all family members, interest free loans, subsidized food and an excellent retirement plan. Turnover of staff is low. Around 1980, when salaries in the oil industry abroad rose rapidly, ECOPETROL lost some qualified personnel, but at the present time salaries paid by ECOPETROL are competitive. Professional salaries are adjusted annually by a general and a merit increase and are approved by the president. Non-professional staff salaries are fixed by negotiations every two years with the union, which is strong and well organized, but with which ECOPETROL's management has been able to deal effectively.

3.08 ECOPETROL has a yearly training budget of about US$750,000 excluding the salaries of employees while in training; it also excludes the training provided by contractors and suppliers under construction contracts and equipment purchase orders. ECOPETROL has three kinds of staff training, within ECOPETROL, within Colombia and abroad; each one of its nine operational districts designs and implements its training program under the guidance of a company-wide training coordinator who resides in Bogota, and who is also directly in charge of training of personnel assigned to the Bogota area. Training activities cover technical, financial and managerial, personnel and skilled crafts. In 1983 each employee went on average on two training assignments of all types and durations; about 230 assignments were abroad.

Budgets, Procurement, Accounts, Audits and Insurance

3.09 General: ECOPETROL's budgeting, accounting and administration procedures are those used by the major oil companies whose concessions reverted to the state and have been modified only in the interest of standardization and to meet the needs of a state-owned company. In general, these procedures are adequate with the main weaknesses being in the arrangements for external audit (para. 3.15). rts financial records are well kept and up-to-date, and the costing/budgeting system reasonably well maintained. - 18 -

3.10 Budgets: ECOPETROL's planning department prepares, on an annual basis, five-year financial projections and work programs as well as each year's budget. Reports on operating investment budget performance are prepared by computer and are sent to all departments and operating units on a monthly and quarterly basis respectively. The budget is prepared in detail with explanations of the basic assumptions used. Of the 1980 to 1983 investment budgets only 80% was carried out due to delays and optimistic budgets. However, ECOPETROL has taken adequate steps to strengthen its planning and budgeting system.

3.11 Delegation: In spite of board approval of the annual budget, investments over C$30 million or US$450,000 must again be approved by the board and any company indebtedness above US$500,000 must be authorized by the Government. With the board meeting at least once a week and with GOC's recognition of the importance of ECOPETROL to the economy, it appears that there are no undue delays. Further, unforeseen capital expenditures, if sufficiently urgent, can be treated as "emergencies" and presented to the board after the fact. Adequate spending authority is delegated down to division chiefs (C$250,000 or US$5,000 in foreign exchange).

3.12 Procurement: ECOPETROL's procurement is generally done through bidding invitations sent to leading national and international companies (particularly those established in Colombia), and which have been prequalified and put on rosters. This is a practice inherited by ECOPETROL from the private oil companies. The procedures are well supervised and are quick and efficient.

3.13 Accounts: ECOPETROL's accounting system reflects the various systems used by the major foreign oil companies. Electronic data processing is widely used to monitor income and expenditures against budget. Balance sheets and income statements do not show individual "cost centers" but the income and costs from these centers can be retrieved from the computer when required, although this is not done systematically. The accounts and material coding systems are good and handled proficiently.

3.14 Internal Audit: There are no internal audit procedures in ECOPETROL which can be considered truly "independent". However, there is an "internal control" group of 50 accountants who report directly to the vice president, Finance. This group has a yearly work program which is kept secret and includes reviews of its management systems and procedures.

3.15 External Audit: By law, the external audit of ECOPETROL's accounts is carried out through the Office of the Comptroller General of the Republic of Colombia by means of a Special Fiscal Auditing Team assigned to ECOPETROL. Although the scope of this audit is thorough and detailed, the focus is more on compliance with the law than the certification that ECOPETROL's financial statements accurately reflect its financial performance. To supplement this Government audit, agreement has been reached that ECOPETROL's financial statements and the project accounts will be audited in accordance with appropriate auditing principles consistently applied, by independent auditors acceptable to the Bank and ECOPETROL and that the audited statements would be submitted to IBRD within four months after the end of each fiscal year. - 19 -

3.16 Insurance: ECOPETROL carries adequate insurance on its major facilities and equipment in operation against all major hazards, such as fire, destruction, etc. Insurance against hazards of transportation, and delivery of goods is regularly arranged.

Financial Performance

3.17 ECOPETROL's finances are complex essentially because of ECOPETROL's varied scope of activities, and the existing legal/contractual framework governing petroleum exploration and production in Colombia. ECOPETROL's revenues originate from the domestic sale of oil products and natural gas, and the export of fuel oil and middle distillates. On the expenses side, ECOPETROL purchases the full output of oil and gas produced in Colombia by private oil companies. In addition, ECOPETROL imports crude oil (to make up for the shortfall in domestic crude production) and gasoline (to optimize its financial returns). Lastly, ECOPETROL produces natural gas and crude oil, which is processed together with the domestically-purchased and the imported crude in its two major refineries.

3.18 The prices and volumes of ECOPETROL's operations which are heavily affecting its financial performance are largely determined by forces external to ECOPETROL. The prices at which ECOPETROL sells oil products and natural gas are Government-regulated. The prices at which it purchases domestic crude oil and natural gas from the foreign companies are based on the concession and association agreements, where a distinction is made between old or basic oil, incremental oil and new oil, and an adjustment is made for crude quality. 1/ The prices at which it exports fuel oil, and imports crude oil and gasoline are fixed by the international market. The volume of domestic sales are determined by market forces and the volume of imports is a function of the domestic sales and domestic production, which is to some extent determined by foreign operators within the framework of the association and concession contracts.

3.19 Within this framework, ECOPETROL operates in a financially and economically responsible manner, as all investment decisions are taken following a careful economic assessment of all alternatives. ECOPETROL is financially autonomous, although it received in 1980 a US$100 million equity contribution from the Government. In subsequent years, prices received by ECOPETROL were sufficient to cover operating costs and a reasonable part of investment costs. ECOPETROL is virtually exempt from income taxes. However, through sales taxes on gasoline products, the Government collected in 1982 C$15.7 billion (US$240 million), or about 8% of total Government tax revenue. ECOPETROL is a net user of foreign exchange due to (i) net imports of petroleum, (ii) payment of 75% of local purchases of oil in foreign exchange, and (iii) imports of capital goods, equal to about 60% of ECOPETROL's investments.

1/ Old oil: oil discovered before 1976, and originating from the natural depletion of the fields (1983 price: US$5-7/bbl). Incremental oil: Oil discovered before 1976, and originating from additional investments in the fields (1983 price: US$15-17/Bbl). New oil: oil discovered after 1976 (1983 price: US$25-30/Bbl) (para. 2.09). - 20 -

Past Performance

3.20 The financial results (Annex 5.1 page 1) for the last four years can be summarized as follows: 1/

Table 3.1

Income Statements

(US$ million)

Year 1980 1981 1982 1983

Revenues Domestic Sales 922 1,173 1,390 1,368 Export Sales 313 334 347 440 Total Revenues 1,235 1,507 1,737 1,808

Expenses Domestic Purchases 218 289 444 536 Imports 713 679 712 601 Direct Expenses 56 a/ 280 333 346 fDepreciation 84 79 88 118 Total Expenses 1,071 1,327 1,577 1,601

Gross Income 164 180 160 207 Interest 88 93 77 60 Exchange Losses 81 77 93 137 Net Income (5) 10 (10) 10

Exchange rate (mid-year) 47.46 55.00 64.68 79.53 i7-_Net of a Government subsidy of US$167 million.

As the above table indicates, ECOPETROL made small losses in two out of the past four years and small profits in the other two years. In 1983 for example, ECOPETROL made an overall profit of US$10 million. ECOPETROL generated profits from (i) the purchase of domestically produced oil at an average of US$11.7/Bbl compared to average revenues from domestic sales of products of US$21.9/Bbl 2/; (ii) its 50% share in association contracts with foreign partners, and its own production, where cost vary from field to field and are of the order of US$5-15/Bbl; and (iii) 8% of the 20% royalty on

1/ ECOPETROL's official accounts overstate revenues, as those include rebates given to electric utilities purchasing natural gas; the rebates are included in the operating expenses. ECOPETROL's revenues and expenses in this report have been stated net of rebates.

2/ ECOPETROL receives only about 70% of the retail price of gasoline and 90% of that of fuel oil, the balance being basically taxes. - 21 - association contracts, which it retains. However ECOPETROL makes losses on imports of crude and gasoline for which it pays international prices, but for which it receives only about 70% of those prices, the other 30% being essentially excise taxes.

3.21 The low profitability of ECOPETROL is partly due to foreign exchange losses on foreign debt which are expensed through the income statement in each year. As foreign exchange losses do not represent immediate outlays but are only paid when the loans fall due, ECOPETROL's cash flow is strong. Over 1980-83, it was able to finance from internal sources about half of its investment program of approximately US$1.0 billion.

3.22 ECOPETROL's balance sheet as of December 31, 1983 can be summarized as follows:

TabLe 3.2

Balance Sheet as of December 31, 1983

C$ billion US$ million a/ %

Assets Current Assets 35.3 398 27 Fixed Assets 76.6 863 59 Other Assets 17.6 197 14 Total Assets 129.5 1,458 100

Liabilities and Equity Current Liabilities 50.1 564 39 Pension Fund 19.9 224 15 Long Term Debt 30.1 340 23 Equity 29.4 330 23 Total Liabilities & Equity 129.5 1,458 100

Current Ratio 0.7 Debt:Equity 65:35 a! At the exchange rate US$1.0=C$88.77

It shows that the current ratio was rather low at 0.7 in December 1983. ECOPETROL's main difficulty in the last two years has been the unavailability of long-term financing, with the consequent resort to short-term borrowings. In recent years, ECOPETROL was only able to get two long-term loans, one syndicated by Chemical Bank (US$200 million in 1979) and the other by Manufacturer's Hanover Trust (US$100 million in 1980). Since 1980, ECOPETROL has been financing its investment program by internal funds and short-term borrowings. The amount of short-term borrowings peaked at US$365 million at end-1982, and as of end-1983, the outstanding amount of short-term borrowings was US$200 million. Had ECOPETROL obtained long-term rather than short-term financing, its current ratio at end-1983 could have been an acceptable 1.1 rather than 0.7. One of the purposes of the Bank loan is to help ECOPETROL to improve its financial structure and enable it to have access to commercial long-term lending. As part of the project ECOPETROL has agreed to improve its - 22 -

current ratio to 1.1 by 1986 and to review its investment and financing plan on an annual basis with the Bank.

3.23 At end-1983 ECOPETROL's debt:equity ratio 1/ was 65:35. This ratio is calculated on a very conservative basis, because it is based on unrevalued assets while long-term Liabilities are revalued. In accordance with Colombian law, ECOPETROL revalues only partly the assets in its books. For instance, at end-1983, for insurance purposes ECOPETROL's operating assets (excluding pipelines) were estimated at US$1.9 billion, against a book value of US$0.75 billion; therefore, had ECOPETROL revalued its assets on the basis of replacement costs, its debt:equity ratio at end-1983 would have been 33:67 rather than 65:35.

Sector Investment Strategy

3.24 A breakdown of ECOPETROL's past investments from 1980 to 1982 shows that ECOPETROL doubled its annual investment program from US$156 million to US$339 million:

Table 3.3

ECOPETROL's Past Investments

1980 1981 1982 Total US$ MM % US$ MM % US$MM % US$ MM %

Exploration 29 19 50 24 51 15 130 19 Development 37 23 46 22 97 29 180 25 Refineries & FPetrochemicals 42 27 40 19 56 16 138 20 Pipelines 25 16 44 22 108 32 177 25 Reg. Investments 23 15 25 13 27 8 75 11 TOTAL 156 100 205 100 339 100 700 100

The past investment program shows a relative balance between exploration (which accounted for 19% of the program), development (25%), refineries (20%), pipeline (25%), and regular investments (11%). Over the three years it shows a decline of refinery investments in relative terms, but a rapid increase in development and pipeline expenditures, reflecting ECOPETROL's preoccupation with rapid yielding productive investments and the fact that ECOPETROL had completed before 1980 all major expansion and optimization in the Barranca Bermeja refinery. The refinery investments during 1980 to 1982 constitute mainly the expansion of the Cartagena refinery.

3.25 ECOPETROL's investment plan for 1984-1988 was originally US$2.8 billion. After discussion with the Bank and taking into account ECOPETROL's project implementation capability and the financial constraints, ECOPETROL reduced its program to a realistic US$2.1 billion (Annex 3.3). The petroleum

1/ A large pension obligation which ECOPETROL has to its staff is included in the debt. - 23 - sector investment program below shows an adequate balance between private and public sector investments, between exploration, development, pipelines and refineries and has a size which is tailored to (i) the urgent needs of increased production, (ii) financial capabilities (para. 5.04), and (iii) implementation capacity, since it would result in an increase of ECOPETROL's annual investment budget of only 6% p.a. (para. 3.33):

rible 3.4

Petroleum Sector Investxent Progm 1984-1988 a/ (Current IB4)

ECOMMiR)L Private Sector Total (US) (;3S)(3wFT%) %)

Explormtion Seismic 78 3.7 100 178 5.8 Drilling 125 5.9 350 475 15.4 203 97 4750 653 21.2

Association fieLds 379 17.8 379 758 24.6 CasabeEDR 375 17.7 - 3(5 12.2 EflHPE]R:L'sfields 225 10.6 - 2 7.3 Pilot BOR 11 .5 - 11 3 990 7.6 379 l3 4. Pplineso and Stora6p CR5uFe',an.oLiIn - Rio Zulia) 49 2.3 123 b/ 172 5.6 Crade (AAay - YoLp-veJasque) 145 6.8 - 145 4.7 Fael Oil (CavenCaTtagena) 47 2.2 - 47 1.5 Wkite R-odacts (SebastoPol-Yunbo) 58 2.7 - 58 1.9 Other 24 1.1 24 .8 323 15.2 123 v1T 143 Refineries and Petrodhenicals Fcndo Barril Refinery 252 11.9 - 252 8.2 Otber 106 5.0 _ 106 7.4 vF8 ; - 358 11.6

MLscellaneoas (incl. invest. in other canpanies) 250 11.8 _ 250 8.1 MEAL 2,T 100.0 952 36 100.0 a/ Totals nm not add dneto ra=nding. bI AlthlniBDPE2L wculdhave a 50%s1are in the pipeline campary, related lcans nW not appear on EBOEXFL's balance sheet.

The table 3.4 shows that the private sector activity would be strongest in risky exploration and development of new fields, whereas ECOPETROLwould concentrate its efforts on development of fields, which reverted to it after expiration of concessions, as well as infrastructure (pipelines and refineries) that is complementary to private sector activities. - 24 -

3.26 The table 3.4 shows that ECOPETROL will keep its investments in risky oil exploration at US$40 million per year, with the expectation that the private sector will invest about double that amount. With its exploration budget, ECOPETROL intends to shoot 14,800 km of seismic at an average cost of US$5,300 per km, which is adequate given some difficult terrain in the Llanos. ECOPETROL would drill 46 exploration wells at an average cost per well of US$2.7 million, which is reasonable.

3.27 ECOPETROL's investments in field development of US$990 million represents the bulk of its investment program and reflects the high priority it attaches to increasing production. The largest part of ECOPETROL's development program is its 50% share in field developments (US$379 million) under association contracts with private oil companies which would pay the other 50% share. The next largest part is ECOPETROL's investment in EOR of the Casabe field. Both investments (including the pilot EOR) are of very hig3h priority and are part of the proposed project and discussed in detail in Chapter IV. In addition, ECOPETROL plans to spend US$225 million to continue development drilling in its own fields (13 old and one new): Lisama, Tesoro, Peroles, Llannito, Nutria, Galan and Cristalina in the central district; Orito, Churuyaco, Acae and La Hormiga in the southern district; Rio de Oro and Tibu in the northern district; and Apiay in the Llanos Orientales. The cost estimate is based on on-going operations and therefore very realistic. This investment is of highest priority since it will help ECOPETROL maintain at least the production level achieved in 1983 in its fields which would experience an overall yearly production decline of about 8% without additional drilling and surface production facilities. The additional production oi 20,000 BD in 1988 is valued at US$300 million, indicating a very high rate of return on investment.

3.28 ECOPETROL's 1984-88 investment program for pipelines comprises 11 projects totalling an investment of about US$323 million. A large part of the investment (US$145 million) consists of the Apiay-Yopal-Velasquez pipeline which will handle the recent finds made in Los Llanos by Ecopetrol (Apiay) and Elf (Casanare). Another project totalling US$172 million includes in the Canc Limon - Rio Zulia pipeline scheme and changes to the Velasquez-Barranca Bermeja and Zulia-Ayacucho pipeline systems to permit transporting to the refinery the finds made by Occidental in Los Llanos (Cano Limon).

3.29 The Apiay-Yopal-Velasquez pipeline based on industry norms, would have a mean cost of US$127 million which compares with ECOPETROL's estimate of US$145 million. Given the uncertainties of pipeline construction in mountainous areas, ECOPETROL's estimate is reasonably conservative. For an investment of US$167 million, 1/ ECOPETROL and its partner Elf would ultimately derive a yearly saving of transport cost of approximately US$100 million (based on a production of 30,000 BD from Apiay and Casanare). For the Cano Limon - Rio Zulia pipeline which ECOPETROL is undertaking with Occidental, the benefits to be derived are of the same order of magnitude as those envisaged for the Apiay-Yopal-Velasquez/Barranca Bermeja pipeline systems discussed above.

1/ which includes modifications to the Velasquez - Barranca Bermeja pipeline system. - 25 -

3.30 Two additional investment program items, each costing a little under US$50 million, are the Combustoleoducto from Barranca Bermeja to Cartagena which will permit transporting excess residual fuel to the coast for export or for hydrocracking at Cartagena, and the expansion of the Poliducto Sebastopol- Medellin which will provide a product transport capacity of 50,000 BD to southwestern Colombia and will also provide diversity of transport risk by establishing a separate pipeline route to the southwest. These projects are presently under construction and would be completed in 1985 and 1986 respectively.

3.31 Two pipeline terminals, La Sabana and Medellin are also included in the investment program. The second phase of the La Sabana terminal costing about US$15 million has been included in the program to handle the increased requirements of the Bogota region and to permit abandoning the old terminal for Bogota which is extremely congested and presents a hazard to safety. This will permit gradually phasing out the old terminal and moving all products terminals to La Sabana. The expansion of the Medellin terminal will cost about US$10 million and is needed to acconodate the growth in that area. Finally the program contains also five small projects aggregating just under US$8 million.

3.32 In refineries ECOPETROL's major proposed investment is a new refinery unit which would mainly use the heavier ends of petroleum, of which Colombia presently has an oversupply, for cracking and refining into lighter products, of which there is a shortage (para. 2.18). Refinery configuration, its location, technology, cost and overall justification compared to increased gasoline imports is still under study for at least another two years. Therefore, there is provision for studies of US$1 million in 1984 and 1985, after which a decision can be taken. Allocation of US$252 million is spread over the outer years from 1986 to 1988. Other investments are for energy conservation and pollution control for the Catagena refinery and for rehabilitation and balancing in the Barranca Bermeja refinery totaling US$106 million. There is an obvious need for further investments, but their costs and justification still need to be studied in detail.

3.33 In conclusion, the ECOPETROL's investment program of US$2.1 billion is well balanced concerning its size and its different components. It would be supplemented by US$1. billion of private investments. In terms of management of the investment program, the private sector is responsible for about half, since it would manage its own program plus ECOPETROL's share of US$.4 billion in associations field developments. ECOPETROL's investments in 1988 would be about US$460 in current prices and constitute a 6% increase p.a. over actual investments of US$350 million in 1983. It reflects ECOPETROL's commitment to (i) participate in the development of new discoveries under association contracts with Elf Aquitaine, Occidental Petroleum and other oil companies which make successful discoveries so as to increase production rapidly, (ii) increase productivity of old fields through EOR methods, and (iii) further develop existing fields. Moreover, the investment program would - 26 -

permit ECOPETROL to possibly increase reserves through explorationand to maintain and enlarge the transport infrastructureand refineries to adequately supply the domestic market. In addition, the program leaves considerable investments in exploration, production and pipelines to the private sector to benefit from their expertise and financial resources. ECOPETROL has agreed to an annual review of its five year financial projections (para. 5.13) by the Bank, and such review would include the size and composition of ECOPETROL's investment program. Moreover, ECOPETROL has agreed, that it would initiate new investments only if they do not adversely affect its capabilities to implement the proposed project. - 27 -

IV. THE PROJECT

Project Objectives

4.01 The main objectives of the project are to increase the production of oil in Colombia through enhanced recovery methods, and to contribute to the development of oil fields (discovered by private oil companies) in joint ventures between private companies and ECOPETROL thus improving Colombia's balance of payments and ECOPETROL's finances by reducing imports. In addition, the project would strengthen ECOPETROL's capabilities in enhanced oil recovery technology and environmental protection and would provide transport infrastructure to allow production increases and to spur further exploration. The project is of high priority given that enhanced oil recovery for older fields and development of newer fields under association contracts is the most economic approach to increase oil production in the medium-term. It represents some 30% of ECOPETROL's investment program over 1984-88 (para. 3.25). The project would have a major impact on reduction of Colombia's dependence on imported oil. Its increase of production would be 36 MBD in 1988, or 9% of Colombia's projected imports in 1988 in value equivalent.

Project Description

4.02 The project contains four main components: (i) Casabe enhanced oil recovery; (ii) field developments under association contracts; (iii) the Cano Limon - Rio Zulia pipeline, and (iv) technical assistance and training.

(a) Casabe Enhanced Oil Recovery

The primary recoverable reserves of the field are estimated at 252 million Bbls out of which 210 million Bbls have already been produced as of 'December 31, 1982. The field produced about 5000 BD in February 1984. An estimated 70 million barrels of additional oil can be recovered from the existing Casabe field (owned and operated by ECOPETROL) through water injection of about 243,000 barrels of water per day over 1985- 2004. At a cost of some US$336 million before contingencies, it will produce an additional 20MBD (of an annual value of about US$300 million) when the enhanced oil recovery program is completed in 1988. The project includes: (i) the drilling of about 500 wells to inject water in 4 overlapping reservoirs (Al, A2, Bl and B2) of the Colorado and Mugrosa formations of tertiary age at a depth varying between 3,000 and 5,000 feet; (ii) the drilling of 53 new oil well producers and the working over of 324 existing oil well producers to allow oil production from the 4 above mentioned reservoirs; (iii) the design and construction of expanded surface facilities for the gathering of fluids from the producing wells and for the handling of increased production of fluids, separation of crude oil from water, crude oil storage and transfer to the main pumping station at Barranca Bermeja; (iv) the drilling of 14 shallow water producing wells (800 feet), construction of water gathering lines and the design and construction of water storage facilities and an injection station as well as injection flow lines; and (v) facilities for treating residual - 28 -

water after initial separation from oil to remove any pollutants before disposing of the water into the nearby Magdalena River. Successful execution of this project component would require resolution of difficult technical problems which may emerge as the project implementation advances. To assist in handling them, provisions would be made under the proposed loan for consultant and engineering services for the detailed design, execution and monitoring of the execution; the Bank would also maintain close supervision.

(b) Field Developments under Association Contracts

In accordance with the association contract in effect in Colombia, ECOPETROL shares 50% of the development cost of discoveries made by foreign oil companies (para 2.09). Companies such as Occidental Petroleum (U.S.), Elf Aquitaine (France) and Chevron (U.S.) have made recent discoveries in the Llanos Orientales basin (Cano Limon, Casanare and Castilla respectively). Texaco has started enhanced recovery programs in an old field, by steam injection in Cocorna. At a total cost of US$329 million before contingencies, these developments will produce an additional 16.5 MBD, with an annual value of about US$250 million, in 1988 (Annex 4.1). ECOPETROL participates for 50% of the cost of the above projects and will receive directly 40% (US$100 million) of the production with the Government receiving another 20% (US$50 million) in royalty. These developments require large expenditures in drilling, pumping, steam injection, surface processing and separation facilities, gathering lines and pipelines. Unless ECOPETROL can finance its share, delays are likely to take place. It is therefore proposed to provide under the project, financing for part of ECOPETROL's share in these ventures.

(c) Cano Limon - Rio Zulia Pipeline

The association company, of which ECOPETROL and Occidental Petroleum own 50% each, will own and operate a pipeline from Cano Limon to Rio Zulia to transport the Cano Limon crude to Rio Zulia where it would enter an existing pipeline to the Barranca Bermeja refinery. The pipeline will be approximately 290 km long and will have diameters of 18/20 inches with an ultimate capacity of 180,000 BD; initially the system would have three pump stations with the addition of a future fourth station in order to attain the ultimate capacity and thus be able to handle the production from potential future discoveries. The investment of about US$140 million, compares to yearly savings of about US$40 to 50 million at 30,000 BD uLtimate production, showing a maximum payout period of four years, which is favorable. Since the peak production is likely to be higher, the payout period wouLd likely be less. - 29 -

(d) TechnicalAssistance, Training and Studies

This component includes (a) technicalassistance, training, and pilot studies for EOR, and (b) study to monitor present pollutionand to establish standardsof environmental protection. ECOPETROL presently operates about 40 oil fields directly,while private companies exploit under association and concessioncontracts respectively19 and 17 fields. Out of a total oil originally in place of about 13 billion barrels, it was recently estimated that only about 3.0 billion barrels, or 22,5% could be recovered ultimately using the existing productiontechniques. Using enhanced recovery techniques, an additional 100 million barrels could be recovered from ECOPETROL'sfields (excluding Casabe). It is therefore proposed to include in the project (i) technical assistance to Ecopetrol'sEnhanced Oil Recovery Unit for design and supervisionof studies, planning and evaluation of pilot tests; (ii) specializedanalyses of cores and fluids in foreign laboratoriesequipped for enhanced oil recovery studies; (iii) reservoir simulation studies (in 18 fields operated by ECOPETROL and foreign companies); (iv) four field pilot enhanced oil recovery tests iacluding drilling, workover and specializedcompletion services for about 25 wells; and (v) training of ECOPETROL'spersonnel in enhanced oil recovery methods and techniques (overseas training of 5 professional staff of ECOPETROL). This will enable ECOPETROL and its consultantsto: (a) identify high priority fields with enhanced oil recovery potential; (b) define an implementation program to economicallyrecover additional oil from the existing fields; and (c) carry out field pilot tests to confirm the feasibilityof enhanced oil recovery projects in specific producing fields and evaluate institutional/ contractualarrangements for future EOR projects. Lastly, it is proposed to provide for a specializedstudy to establish a policy framework for environmentalprotection.

Project Preparation

4.03 Preliminaryfeasibility studies of the Casabe secondary oil recovery component were completed by ECOPETROL in 1977 with the help of DeGolyer and McNaughton (U.S. consultants). Since then ECOPETROL carried out three pilot water injection tests in different reservoirs to test the validity of the results of the preliminarystudies. The tests gave positive results as the ratios of water injected to oil production varied between 12 and 15 1/. Thus, the field pilot results confirmed the forecast made by the engineering studies. The enhanced recovery program in Casabe has been drawn up and basic engineeringwork on designs and equipment specificationshave been completed by ECOPETROLwith the help of Williams Brothers Engineering

1/ This compares favorably to the ratio of 13.3 reported in a study of 86 waterfloods in similar fields in the U.S.A. - 30 -

(U.S. consultant). ECOPETROL started implementation of secondary recovery investments in the field in 1982, and drilled about 150 injection wells until February 1984, using four contracted rigs and one ECOPETROL rig. ECOPETROL is in the process of installing surface facilities. The proposed project includes the continuation of the secondary recovery investments.

4.04 Concerning the four field developments under association contracts proposed to be financed under the project, preparation of field development programs is the responsibility of the private oil companies which are the operators of these fields, i.e. Chevron, Elf Aquitaine, Occidental Petroleum and Texaco. Over the years 1981 to 1984, ECOPETROL declared the discoveries of Chevron, Elf Aquitaine and Occidental Petroleum commercial and approved the EOR project of Texaco, based on feasibility studies carried out by the private operators. ECOPETROL normally approves the commerciality of the discoveries within three months of submission, the last approval having been given in Januiary1984 for the latest Elf Aquitaine discovery. After submission of the feasibility study the operator submits to ECOPETROL an annual development program for review and approval.

4.05 The Cano Limon - Rio Zulia pipeline has been studied by ECOPETROL and Occidental Petroleum in detail. One regional optimization study analyzed five different alternatives for evacuation of the Llanos crude and established that the proposed pipeline is part of the optimal solution. Other optimization stucliesconcerning the detailed routing and the optimum combination of pipeline diameter and pumping horsepower have also been carried out.

Project Implementation

4.06 The Production Projects Division of the Production Department is in charge of the implementation of all aspects of the Casabe enhanced oil recovery project. The Production Department is headed by an Assistant Vice President, who reports to the Vice President - Operations .

4.07 The Production Projects Division is headed by a competent and experienced engineer, whose staff consists of ten qualified engineers in all the relevant engineering disciplines (civil, electrical, mechanical, petroleum etc.). The division has commissioned William Brothers (U.S. consultant firm) for all aspects of basic design, procurement, evaluation and construction of surface facilities. It also receives support from the drilling division at heaquarters for all aspects of drilling contracts awards and from the Superintendent of Casabe field for supervision on drilling operations. During implementation important coordination problems are resolved by a committee headed by the Assistant Vice President, Production; the committee is composed of the head of the Production Projects Division, the Manager of El Centro District (where Casabe is located), the superintendent of the Casabe field, and the heads of the driLling divisions at headquarters and at Casabe. This committee meets on a monthly basis. The division staffing and organizational arrangements for making important decisions are satisfactory, and ECOPETROL has agreed to maintain satisfactory staffing and organizational arrangements for the implementation of that part of the project. - 31 -

4.08 The injection wells are to be drilled by four contracted and one ECOPETROL drilling rigs. For workovers of old producers, and for well completion, seven service rigs are to be contracted for. Specialized services such as logging, perforating and cementing would be performed by contractors. Surface facilities, such as pumping equipment to handle the increase in oil production, would be acquired directly and installed by contractors under ECOPETROL's supervision.

4.09 Regarding the field development, the private oil companies are in charge of developing the reserves, once ECOPETROL has given its approval to the initial development plan and its annual review. This arrangement is satisfactory. Preliminary development plans which are submitted prior to declaration of commerciality were reviewed by the Bank and are reasonable. The Bank also reviewed the reserves evaluation studies and detailed one-year development plans for such reserves which were satisfactory. For subsequent years ECOPETROL has agreed to submit to the Bank for its approval the annual development plan for the fields to be financed by the Bank, not later than November 15 of each year.

4.10 Concerning the Cano Limon - Rio Zulia pipeline, Occidental has issued tender documents in June 1984 and a contract has been signed for turnkey works with Mannesmann (Germany) in August 1984 under which the general contractor will do the detailed design, supply the materials and construct and commission the pipeline system. Inspection during construction will be carried out jointly by Occidental and ECOPETROL assisted by consultants. Occidental would be operator of che pipeline under the association contract. A condition for disbursements on this component would be contractual arrangements between ECOPETROL and Occidental Petroleum, satisfactory to the Bank, for construction of the pipeline according to a feasibility study and financing plan, satisfactory to the Bank.

4.11 One part of the technical assistance will cover the enhanced oil recovery pilot studies for fields other than Casabe, and will be carried out by consultants to be selected according to Bank guidelines and to be appointed by ECOPETROL. These consultants will also be in charge of training ECOPETROL personnel in the techniques of enhanced oil recovery. ECOPETROL has recently set up a special unit in the Production Projects Division specifically in charge of EOR. The role of this unit will be to gather reservoir information on all Colombian fields and develop a program to implement enhanced oil recovery projects. This program would: (i) define the training needs of the staff of the project unit; (ii) identify specialized technical assistance needs to help the unit develop the enhanced oil recovery program and supervise its implementation; (iii) hire specialized consultants to review and evaluate field prospects (about 18) for enhanced oil recovery; (iv) arrange for specialized analyses in overseas laboratories on oil and core data from candidate reservoirs; and (v) design and implement field pilot tests. A qualified engineer has already been appointed to head that unit, and agreement has been reached that another two staff members will be appointed before December 31, 1984.

4.12 Another part of the technical assistance consists of a study to monitor present pollution and to establish standards of environmental protection for the oil industry in Colombia. Such a study would be carried out by external consultants, who would be selected according to Bank guidelines. - 32 -

Implementation Schedule

4.13 Implementation of the works necessary for water injection in the northern part of Casabe (122,000 BD of water) started in 1982, and is expected to be completed by February 1985. The second phase involving implementation of works in the southern part of the field includes the drilling of about 250 injection wells, and working over 190 oil producers, equipping them, and connecting them to the injection station and the field battery of separators. Implementation would begin in the second half of 1984, and cornmissioning would take place at end-1987. The detailed impLementation schedule appears at Annex 4.2.

4.14 With regard to the associations' field development component, contracts would be let after preparation by the oil companies and approval by ECOPETROL of the detailed one-year development plan and its annual review and approval by the Bank.

4.1.5 Contractor mobilization for the construction of the Cano Limon - Rio Zulia pipeline would take place during the fourth quarter of 1984 with completion of the pipeline scheduled for January 1986.

4.16 The different consultants for the technical assistance component involving enhanced oil recovery (other than Casabe), and environmental studies are expected to be appointed in early 1985.

Cost Estimates

4.17 The detailed cost estimate of the project appears at Annex 4.3. It is summarized below:

Table 4.1

Summary of Project Cost Estimate a/ US $ million

Local Foreign Total

Casabe Enhanced Oil Recovery 166 209 375 Field Developments 132 221 353 Cano Limon - Rio Zulia Pipeline 73 67 140 Technical Assistance 2 8 10 Subtotal 373 505 878

Contingencies: Physical 26 35 62 Price -10 b/ 51 40 Subtotal 16 86 102

Total Project Cost 389 591 980 a/ Totals may not add due to rounding b/ Negative price contigency on locaL currency expressed in US$ is due to domestic inflation assumed to be lower than the devaluation of the Colombian Peso. - 33 -

The cost estimate is expressed mid-1984 prices. Physical contingencies are at 7%, which is considered adequate given the advanced stage of project preparation. Price contingencies are provided at 8% in 1985 and 9% over 1986- 1988 for foreign cost and 20% in 1985 and 1986 and 18% in 1987 and 1988 for local cost. The Colombian currency is projected to devalue by 28% in 1984, 23% in 1985, 13% in 1986, 10% in 1987, and 9% in 1988. The technical assistance component provides for 280 man-months of consulting services.

Financing Plan

4.18 The financing plan for the project would be as follows:

Table4.2

FinancingPlan

Ls$ Million Cot P:ropsed Financirg Foreign Private BXOPEMR)L Exhargelocal Total Operators Cash Gen. Ecp. Cr. Can. B. IfD

Casabe EBR 2C9 166 375 - 240o 25 40 70 Assodation Field Develcpmnt 221 132 353 176.5 78.5 18 4o 4o Cano laimn - Rio Zulia Pipeline 67 73 140 70.0 5.0 55.0 - 10 Studies and T.A. 8 2 10 - 2.0 - - 8 Ccntirgences 86 16 102 27.5 64.o 8.5 - 2 Total 591 9 __ 395 X(40 _m 130

Peroent 60 4o lOO1 40 121 8 13

ECOPETROLwould finapee US$390 million or 40% of the total project cost from its internal cash generation, which would be equal to the local currency cost. ECOPETROL's contribution to the cost of the project is equivalent to 26% of its internal cash generation available for investments during the period under review (para. 5.05). The private oil companies would finance US$274 million or 28% of total project cost, representing half of the association field developments and of the pipeline including contingencies. The private oil companies, being all subsidiaries of large international oil companies would have no particular difficulties in mobilizing their share. Cofinancing of US$187 million would represent 19% of total project cost of which 11% would come from export credits and 8% from commercial bank loans. The export credits would be for tubular goods (well casing and tubing) and wellheads; and line pipe and pumping stations. The proposed Bank loan of US$130 million would be 13% of total project cost.

4.19 The distribution of financing between the four components would be as follows: of the Casabe EOR scheme, ECOPETROLwould finance 64%, cofinancing 17%, and the Bank 19%. Of the field developments under association contracts, the private operators would pay 50%1of expenditures from their own financial sources as equity; ECOPETROLwould finance 22% from internal cash generation, and cofinancing and the Bank loan would account for 16% and 11% respectively, - 34 - all of which would be accounted as ECOPETROL's equity in the association as its contractual obligation. The private operator would finance 50% of the pipeline, ECOPETROL 4%, the Bank 7%, and cofinancing would account for the balance all of which would be considered equity. Concerning the Technical Assistance component, ECOPETROL would finance from cash generation the local currency portion and the Bank loan would finance the foreign exchange.

4.20 ECOPETROL has reviewed, together with the Bank, those contracts which would lend themselves to export credits, and will attempt in the future to mobilize such credit. Moreover, ECOPETROL is in the process of identifying additional sources of commercial financing, which could be further encouraged through a potential B-loan from the Bank which would be required by the first half of 1985. If some of the envisaged cofinancing would not materialize ECOPETROL could curtail the Casabe secondary recovery and the association field developments without compromising the projects viability. Concerning the pipeline, sufficient cofinancing has been mobilized and the pipelines' sponsor (Occidental Petroleum) has committed himself in addition to raise the necessary financing to fill any shortfalls. ECOPETROL has prepared a financing plan which would be reviewed annually by the Bank together with ECO)PETROL's investment program (para. 5.13).

4.21 The proposed Bank loan would be at the standard variable interest rate for 14 years including four years grace. The favorable cash-flow projections of the project and ECOPETROL would allow terms which are more stringent than the usual country terms (17 years). One of the objectives of a possible B-loan would also be to lengthen the maturities of potential commercial bank loans (para. 4.20). The proposed terms of the financing package would enable ECOPETROL to improve its current ratio from .7 in 1983 to at least 1.1 in 1986 and thereafter and to maintain a satisfactory debt service coverage ratio of at least 1.4. ECOPETROL would pay to the Government a guarantee fee equal to 10% of the standard Bank rate and rounded to the next highest tenth of a percentage point.

Procurement

4.22 Goods and services for the project components financed from the proposed loan and to be procured under international competitive bidding procedures in accordance with Bank guidelines, would include (a) drilling and (b) pumps for both Casabe and pilot enhanced oil recovery projects and (c) some pipeline equipment including tanks, cathodic protection and telecommunications 1/. Other specialized services such as cementing, logging and perforating needed during completion of wells would be procured by requesting bids from all firms known to supply these services since there is only a small number of companies worldwide which offer these services. Consultants would be selected in accordance with World Bank guidelines.

1/ Although the pipeline would be built under a turnkey contract, ECOPETROL has agreed that a condition of contract award be that the turnkey contractor procure as an agent of the association of ECOPETROL/Occidental Petroleum at least US$10 million of equipment and services for the pipeline under the Bank guidelines. - 35 -

4.23 Procurement arrangements for the project components to be financed from the proposed loan are summarized below:

Table4.3

Procurenmntand Disbuirsennt

ProjectElement Procureient Method TotalCost Disbursenents (U.$Mio) (% of total ccst)(IB$Mio)

1. Drilling Services ICB 116 50 58

2. Cemntirg, Lcggirg and Bids fran all Perforatirg Services knownsuppliers 34 90 31

3. MecanicalRmps mB 24 100 24

4. PipelineEquipment ICBand LIB 10 100 10

5. CoorultingServices -Bank Guidelines 7 100 7

TOMA 191 130

Procurement for items to be financed from other than World Bank sources would follow acceptable oil industry practice, which would result in competitive prices in line with the cost estimates. The associationpartners, who are the operators for the associationfield developments,would procure the drilling services and selected specializedservices (which representabout 50% of total foreign exchange cost of these developmentsand is equal to ECOPETROL'sshare) according to Bank procurementguidelines, thus allowing disbursementsagainst these contracts. The association partners would carry out all other procurement accordingto industry practice.

Items Proposed for Bank Financingand Disbursements

4.24 The proposed Bank loan would finance:

(a) 50% of total expenditures representing 100%6 of the foreign exchange component for drilling services for Casabe, the other four field developments,and enhanced oil recovery field pilot tests;

(b) 90% of total expenditures representing 100% of the foreign exchange component of specialized services (logging, perforating and cementing) for Casabe, field developmentsand enhanced oil recovery field pilot tests;

(C) 100% of the foreign expenditures for pumping units for Casabe, for the enhanced oil recovery field pilot tests and for pipeline equipment comprising crude oil storage tanks, cathodic protection and telecommunications; - 36 -

(d) 100% of the foreign expenditures for enhanced oil recovery studies, technical assistance, training and laboratory tests.

4.25 Annex 4.4 provides a schedule of disbursements, which essentially conforms with the statistical profile as of February 1984 for Energy Projects. Loan proceeds would be disbursed into a dollar- denominated special account in Banco de la Republica, to be established by ECOPETROL solely for the purposes of the project. Upon ECOPETROL's request, the Bank would make an initial deposit into the account of up to US$20 million. Disbursements from the special account would be made for eligible expenditures under the Loan. Replenishment of the dollar equivalent amount of disbursements from that account would be made upon receipt of withdrawal applications from ECOPETROL. After disbursement from the loan account of a total of US$65 million, the Bank would begin to recuperate the initial deposit. In addition to the external auditing of ECOPETROL the revoLving fund account would be audited annually by independent auditors acceptable to the Bank. All disbursements would ultimately be documented by a certified statement of expenditures.

Ecology and Safety

4.26 No major environmental risks are likely to result from the Project. So far, ECOPETROL has had an excellent safety record and its pollution and fire prevention practices, which are standard for the petroleum industry, are satisfactory. Oil spills resulting from pipeline failures and blowouts are always possible, but ECOPETROL is experienced and takes precautionary measures. With respect to the Casabe component, Williams Bros (US) in association with Techniavance Ingenieros (Colombia) were awarded a contract in April 1983 to carry out the complete design of the gathering, processing and handling system of produced crude oil and associated residual waters. The basic engineering design report was finalized after review by ECOPETROL's Procluction Projects Department in December 1983. Upon completion in 1985 the system would have the capacity to desalinate and strip all traces of residual oil from up to 240,000 BD of residual waters containing up to 120 tons/day of salt. Since fresh water will be injected, this is ample desalinacion capacity. Thus, the processed water will not pollute the Magdalena river into which it would be discharged. Maximum modification of the salinity of the river waters in the immediate vicinity of the project area would be I PPM. equivalent salt, which is fully acceptable. The Cano Limon - Rio Zulia pipeline will be beneficial to the environment since it will replace road tanks transport which is hazardous, noisy, environmentally dirty and less fuel-efficent. Furthermore, under the Project, ECOPETROL is to appoint consultants to carry out a specialized study to establish a policy framework for environmental protection (para. 4.02).

Project Risks

4.27 The risks associated with the project are those inherent in the petroleum industry. With respect to the enhanced oil recovery component, all information already available on the Casabe field established it as an excellent candidate for secondary recovery by water injection. ECOPETROL has already taken steps both during the preparation of the project and initiation of implementation of the first phase of this component to ensure an efficient - 37 -

and careful execution. The key factor has been thorough organizational arrangements of the project unit and technical assistance from a well known and reputable foreign engineering firm.

4.28 The risks associated with the field development component have been minimized as the operators, who contribute 50% of all development investments, will all be well known and experienced oil companies. In all, the risks have been carefully evaluated, and considering the potential benefits of the project to the Colombian economy, are worth taking.

4.29 The risks associated with the Cano Limon - Rio Zulia pipeline are minimal, since the feasibility study has established that there are sufficient reserves for adequate utilization of the pipeline. A qualified and experienced contractor would be in charge of construction, thus minimizing any possible delays. Occidental Petroleum would have adequate incentive to properly operate and maintain the pipeline, to allow production from the Cano Limon field.

Reporting Requirements

4.30 In order to allow the Bank to reach an informed judgement on the progress of the project, agreement has been reached that ECOPETROL will provide the Bank with quarterly progress reports covering technical progress of the Casabe enhanced oil recovery scheme, the association field developments, the Cano Limon - Rio Zulia pipeline, the studies on enhanced oil recovery, and environmental protection, procurement status and funds committed/spent. A completion report will be submitted at the end of the Project. - 38 -

V. FUTUREFINANCIAL PERFORMANCE

ECOPETROL's Projected Financial Statements

5..01 ECOPETROL's financial projections for the 1984-88 period, based on historical trends and a detailed analysis of the underlying volumetric and price structure, are in Annex 5.1 and are summarized below. The projections were made in current Colombian Pesos (C$) to permit (i) a realistic analysis of the effects of real exchange rate variations, and of variations in domestic and international prices, (ii) a comparison with ECOPETROL's own financial projections, which are made in C$, and (iii) close monitoring of actual results during project implementation. Below is a summary of ECOPETROL's projected income statements, balance sheets and cash-flow, expressed in US$ at projected exchange rates to give the reader a feeling of the orders of magnitude and to eliminate the effects of domestic inflation, which is projected to be about double the international inflation after 1984.

5.02 The summarized income statements below show that ECOPETROLwould continue to make profits from 1984 to 1988, which however would not exceed 9.7% of sales (in 1987):

Table 5.1 ECOPETROL FoRECAST 1NCO ME STATENEMTS

(=N)

-mnues 1984 1985 1986 1987 19B

DwosticSales 1362 1383 1529 1755 2057 EWrtSales 449 482 589 7

SalesRPes 1,811 1,865 2,118 2,494 2,845

30mesticPurchases 50 534 616 693 129 lports 456 493 504 720 1,012 (prating Evenses 461 442 467 513 574 oepreciatiam 118 128 153 182 214

TotalEwpfises 1,543 1,597 1,740 2,108 2,529

keratingIncue 268 68 378 385 317 NM ratingInco 50 48 49 52 56 Less:Interest 86 99 107 103 100 Exchange 164 171 110 85 71 Otter 7 6 b 7 7

et Ince 62 40 204 243 194

Operating Ratio (Z) 86Z 86a 83Z 85Z 89?

MidYear ExdciM Rate 101.2 126.7 148.8 165.8 181.1 - 39 -

Export sales of fuel oil would continue t.o represent about 25% of total sales, and imports of crude oil and gasoline wo,ild increase from 29% of operating costs in 1984 to 40% in 1988. The operating ratio would remain reasonable at 90% and below.

5.03 The above analysis is based on a presentation of accounts in line with ECOPETROL's present practice, which however does not adequately take into account inflation. For compari.son, the! income statement was adjusted concerning two aspects, which are partly offsetting: (a) annual depreciation based on revalued assets rather than historical values, as in ECOPETRCL's firiancial statements; and (b) the exchange losses were tak,en into account only for the portion repayable in each year., rather than the exchange loss on the total foreign exchange outsta.nding as in ECOPETROL's financial statements. As a result, depreciation would be atbout double and exchange losses would decrease about one tenth:

1984 1985 1986 1987 1988 ...... US$ Million ..

Increase in Depreciation 160 178 210 234 289 Decrease in Foreign Exchange Losses 150 160 103 76 58 Adjustment -10 -18 -107 -158 -231

Adjusted Net Income 38 7 84 73 -47

The adjusted net income would still be positive, except for 1988, when the depreciation adjustment would havE! an overproportional impact due to compounded local inflation rates ighich would exceed by 15% compounded devaluation rates. During supervision of the proposed project, the Bank would discuss with ECOPETROL the possitbility of adequate inflation accounting. - 40 -

5.04 The summarizedbalance sheets below show that the current liabilities are projected to drop in 1985 and 1936 below the 1984 level due to repayment of short-termdebt which is replaced by long-termdebt, so that the current ratio improves over that period from 0.8 to 1.1, in compliance with the proposed covenant (para. 5.13).

Tabte 5.2 ECOPETROL ktal FORECAST BALANCE SHEETS Balae

ASSETS 1903 194 19E 1986 1987 1900

a)IrentAssets 398 4JO 444 500 583 662 NotOWatiNg Asets 756 29 795 915 1,0 1,158 wkrkinProges 107 73 189 197 210 221 Invtumtsin Subidiaries 165 IT 200 233 214 199 OtherAssets 32 31 34 37

T0TAL ASSETS 1,458 1,552 1,658 1,877 2,000 2,277

L I A B.AND E 0 U I T Y

CurentLiailities 54 569 477 454 524 52 NtLmgTeruDbt 33 473 70 784 716 67 PmsiuiFund 224 210 205 217 213 254 fiauatin uplus 109 85 69 61 5 51 Paidin Equity 227 i 144 7 116 107 Rsens -5 8 55 a2 434 578

T 0 TA L LIM.ANDEEWT 1,458 1,552 1,658i1,877 2,00 2,277 ::====: ::== :==. , =: =:== :==

CurrentRatio 0.7 0. 0.3t 1.1 1.1 1.1 Debt:lebt&EEuity() 65 71Z d? 72l 65? 60Z Debt:Debt& Eq.after R (7dl(Z) 33 36 422 3 3i 30% DebtService Cvragm Ratio 2.9 2.7 3.1 2.9 2.1

YearEnd Exchi Rate 8.8 113.6 13.8 157.9 173.7 100.5

a) The reserves do not tally with the profits of Table 5.1, since the effects of exchange rate losses properly accounted fot,in the statementsexpressed in C$ in Annex 5.1, get blurred in the conversion into US$. -41

The equity and reserves would triple from 1984 tc) 1988, while the long-term debt including pension fund would increase only b y 66Z. As a result, the debt/equity ratio would improve to 60:40 based.on historical values, and even 30:70 based on revalued assets. The revaluation o f assets for these projections are based on a value, which a reputablh! external consultant firm, Marsh-McLennon (USA) established for ECOPETROL's as sets in 1982 for insurance purposes, after a detailed desk and field sti.dy. The revaluation of assets would be carried out for the calculation of the debt,/equityratio, but not be recorded in ECOPETROL's books. The debt service cov erage ratio would be fully satisfactory at above 2.0 until 1988.

5.05 The summarized cash flow from 1984 to 1988 b elow shows that the net operating income before depreciation over this period provides US$2.4 billion equal to 115% of the proposed investment program of US $2.1 billion. Additional cash generation comes from the increase in l-he pension fund (9%) and from non-operating income (10%). However, inte7.est and principal payments of long and short term debt during the period are eciual to 53%, increase in working capital and other assets 11%, and investmenl:sir. subsidiaries another 7%, leaving 61% for internal financing of ECOPETROL s in vestment program. Thus ECOPETROL intends to borrow about 40Z of its irivestnientprogram or US$880 million.

Table 5.3. ECOPETROL Cash Flow FiveYeans $many

(1aRwR) Perent 3 ,illia Cilin ofWIn. Pro.

'(rating incou 230,911 1,561 7U4 Dweciatik i27,M3 849 411

)bitotal 38,275 2,410 112

DebtService nterest 72,313 495 231 Principal 62,979 402 20% increasein WorkingCapital 32,55 241 102

Lncrease in otherAssets 4,045 28 iZ lot TermDebt eiaymt 32,624 2M3 ioZ

utota1 204,512 1,39 662

Additicms increasein Pensio Fud 27,940 193 9% 4et n-fperating Incru 32,459 223 102

FImdsAvailable For [nwstwet 214,161 1,426 o92

Capitallovestmt Progran 310,710 2,124 IOOZ investbts In 9sidiaries 22,828 180

Fincing Gap 119,376 878 3ZZ

-inancedby Borrowings: angloere 122,805 M 4M0 Shrt rera 3,256 32 i7 - 42 -

The proposed World Bank loan of JS$130 million would represent some 6% of ECOPETROL's overall investmer ts cver 1984-88, and about 14.6% of ECOPETROL's overall long-term borrowings of US$890 million in the period under review. ECOPETROL would in future re ly to the extent possible on supplier's credits (US$300 million) to finance part of the equipment required for its investments. Moreover, ECO'?ETROL is in the process of identifying possible long-term financing from it s lead 'anks, which could be encouraged further by a possible B-loan. These L,nd other loans, including the proposed World Bank loan would finance about U'$590 million. Finally, ECOPETROL expects the private sector to match EC OPETROL's investment program with the provision of another US$1.0 billion ov'3r the five-year period.

Assumptions

5.06 The supporting voliinmetricand pricing assumptions for the above financial statements are- in Annex 5.2 and are summarized below:

Table 5.4

Domestic Demand (MBD)

1984 1985 1986 1987 1988

Fuel Oil 19 18 19 19 20 Gasoline 81 84 87 90 93 Other Products 65 65 67 70 73 TOTAL 165 167 173 179 186

Fuel oil demand is projectecd to remain static, due to satisfaction of increased demand b y coal. Demand for gasoline and other products is projected to increase at 3.5% per anniim, except for other products in 1985.

Table 5.5

Domestic Production, Exports and Imports

(MBD)

1984 1985 1986 1987 1988

Crude Producti oll 171 169 183 183 174 Minus Crude u sect as Fuel O'U 8 8 8 10 10 Plus Crude Iu,iports 35 37 34 44 46 Condens ate 4 4 3 3 3 Refinery Thr oughput 202 202 212 220 213 Production of Fuel Oil 56 55 59 62 60 Gasoline 72 76 80 82 76 Other Products 69 70 72 75 78 Export of Fuel Oil 45 45 49 54 50 Other Products 4 5 5 5 6 Import of- Gasoline 9 9 8 8 18 - 43 -

The aggregate domestic crude production was projected after detailed field by field analysis. After deduction of crude which is used directly as fuel oil and addition of imported crude, the production of fuel oil, gasoline and other products was projected as percentages of refinery throughput. Of the fuel oil production, part is used for ECOPETROL's internal consumption, part for domestic sales and the bulk is exported. The difference between gasoline demand and production is imported ranging at about 10% of demand. Of other products, the excess of production over demand is exported, ranging at about 8% of production of other products.

5.07 The cost of crude and gasoline imports, and fuel oil and products exports are based on latest Bank's price projections. Colombia would become a net exporter in 1986 and 1987 but return net importer in 1988.

Table 5.6

Net Imports

1984 1985 1986 1987 1988 Value of Net Imports (US$MM) 7 11 (85) (19) 223

5.08 The domestic crude oil purchases by ECOPETROL are projected according to association contracts (basic, incremental and new crude) and concession contracts (basic and incremental crude) and by applying the price formulae agreed for their purchase. In a similar way the cost of gas purchases was determined.

Table 5.7

Volumes and Prices of Domestic Crude Oil and Gas Purchases

1984 1985 1986 1987 1988 Volumes of Purchases Association Crude (MBD) 17.4 19.5 24.0 27.6 27.2 Concession Crude (MBD) 64.0 57.1 49.3 41.0 34.7 Gas (MMCFD) 205 205 208 206 206

Average Prices Association Crude (US$/B) 21 23 28 33 37 Concession Crude (US$/B) 11 11 13 14 15 Gas (US$/MCF) 1.09 1.19 1.30 1.49 1.68

Cost of Purchases Association Crude (US$MM) 130 164 242 327 363 Concession Crude (US$MM) 248 234 226 207 195 Gas (US$MM) 82 89 99 112 126 - 44 -

5.9 The following macroeconomic assumptions were used:

Table 5.8

Inflation and Exchange Rate Variation

1984 1985 1986 1987 1988 Local Inflation 1.20 1.20 1.20 1.18 1.18 Foreign Inflation 1.04 1.08 1.09 1.09 1.09 Current Exchange Rate Variation 1.28 1.23 1.13 1.10 1.09 Real Exchange Rate Variation 1.10 1.11 1.03 1.02 1.00

Local inflation is projected at about 20% p.a., whereas international in.Elationwould increase from 4% in 1984 to 9% in 1988. Annual devaluation of the C$ vs US$ would be 28% in 1984 tapering off to 9% in 1988. This implies a real devaluation of the C$ in each year, cumulating to 28% until 1988.

5.10 Under the above assumptions, the Government and ECOPETROL would have to increase consumer prices in C$ by 5% annually over the domestic inflation rate to maintain ECOPETROL in a sound financial situation, thus meeting the proposed financial covenants. With this increase and the assumptions used for foreign and domestic inflation, future exchange rates, and future oil prices, domestic prices expressed in US$ would increase broadly at the same pace as current international oil prices (Annex 5.2, Page 9, Coefficient 8).

Major Features and Sensitivity of Financial Projections

5.11 The above financial projections are relatively conservative. They are based on domestic production levels, which do not include production from potential new discoveries, so that domestic production actually declines in 1988. The projections also show that the increasing share of high priced association crude would rapidly increase ECOPETROL's costs. Association crude will increase from 13% 38% of Colombia's production in 1983, to $389 in 1988, while the share of concession crude (at a price of about half the one of association crude) would decline from 41% to 20%. As a result, the average cost of purchases by ECOPETROL would more than double in current terms from US$11.71/Bbl in 1983 to US$26.71/Bbl in 1988.

5.12 Moreover, ECOPETROL's financial projections are highly sensitive to many of the basic assumptions used, partly because (i) ECOPETROL is involved in exports and imports, (ii) its purchases of domestic crude are denominated partly in US$ whereas its sales are in C$, and (iii) its operation is relatively large. With the annual sales volume of US$1.8 billion in 1983, even small variations in volume or price of, say, 5% have a major impact on sales and profits (about US$100 million). The financial projections show that the continued financial soundness of ECOPETROL will depend on a large number of factors, but in particular on the three below:

(a) Domestic Increase in Demand and Crude Oil Production: At present ECOPETROL has to import the shortfall between domestic consumption and production. In 1983 ECOPETROL imported crude at an average price of US$28/Bbl while it purchased domestically produced crude at an average price of US$11.71/Bbl. Thus a decrease in production or an increase of consumption over projected levels would worsen - 45 -

ECOPETROL's finances considerably. The assumptions result in an increase of imports volume of gasoline and crude from 44 MBD in 1984 to 64 MBD in 1988.

(b) Price Levels and Exchange Rate: About 60% of ECOPETROL's operating and investment costs are at prices which are related to international prices. Thus an increase of the international petroleum price or of international inflation would increase ECOPETROL's costs accordingly. In addition, a higher real devaluation of the C$ than projected levels would also worsen ECOPETROL's financial situation, given that about 75% of ECOPETROL's revenues, but only about 40% of its expenditures are in C$, the balance being in foreign exchange. Finally, domestic inflation at higher levels than projected would worsen ECOPETROL's finances, unless domestic prices of petroleum products are adjusted accordingly.

(c) The Investment Program: Obviously, the magnitude of ECOPETROL's investments, together with ECOPETROL's ability to mobilize long-term financing will have an important impact on its financial performance. ECOPETROL's investment program of US$2.1 billion contains only high yielding projects with fast production increases (para. 3.25). ECOPETROL is unable to reduce its investment program any further, without reducing the projected production under (a), thus damaging its financial performance. The projections show that, on average, ECOPETROL would be able to finance from internal sources some 60% of its investment program, after investments in other companies.

Financial Covenants

5.13 To ensure that ECOPETROL's financial performance will remain satisfactory, the following assurances have been obtained during negotiations:

(a) ECOPETROL's operating income, before depreciation and debt service charges, for each full fiscal year shall be equivalent at all times to at least 1.4 times the aggregated debt service requirements, for the respective year;

(b) ECOPETROL's long-term debt to equity ratio shall not be greater than 60:40, based on revaluated assets according to a method to be agreed by the Bank; ECOPETROL shall complete the revaluation of assets for the calculation of this covenant not later than March 31, 1985;

(c) ECOPETROL's current ratio shall be at all times at least 0.8 in 1984, 0.9 in 1985 and 1.1 thereafter;

(d) ECOPETROL will submit to the Bank on an annual basis, not later than February 28 of each year, detailed five-year financial projections, including ECOPETROL's five-year investment program with particular details on investments in the following year, - 46 -

and financing plan for short-term and long-term borrowing, and discuss with the Bank measures to be taken if such projections show that ECOPETROL will not be able to meet one or more of the financial covenants.

The above assurances constitute in effect a proxy for pricing covenants, as they will ensure that the prices to ECOPETROL are maintained at adequate levels; in view of the financial impact of both crude imports, and domestic crude purchases, domestic prices will have to be maintained close to the international level.

Financial Rate of Return

5.14 A financial rate of return for the Casabe Enhanced Oil Recovery Project was calculated conservatively on the basis of the average prices ECOPETROL is expected to receive for product sales. The calculation appears at Annex 5.3. The financial rate of return for ECOPETROL is 18.9%, which is satisfactory. The financial rate of return for the field developments is identical to the economic return, given that the operators receive international prices for crude, and that ECOPETROL would have to import crude in the absence of these field developments. - 47 -

VI. - ECONOMIC JUSTIFICATION

General

6.01 The proposed project constitutes about one third of ECOPETROL's investment program from 1984 to 1988 and focuses on the production of crude oil with quick yielding returns. However, ECOPETROL's other planned investments in exploration, pipelines, and refineries are also of highest priority to enable ECOPETROL to satisfy adequately domestic demand (para. 3.25). By 1988, the Casabe EOR scheme and the association field developments would provide an additional production of 36MBD or 20% of Colombia's projected demand. The annual economic value of this production in 1988, based on the current replacement cost of imported oil in 1988, would be about US$540 million, or 9% of Colombia's projected imports in 1988. Columbia's share would be US$450 million and the companies' share would be US$90 million. Total oil recovery from Casabe EOR scheme and association field developments over the 20 years life of the project will be 140 million barrels. Concerning the Cano Limon - Rio Zulia pipeline, for an approximate investment of US$157 million, the yearly saving would be about US$40-50 million based on an ultimate production of 30MBD from Cano Limon, thus showing a maximum pay-out period of four years,which is favorable. The estimated rate of return would be at least 18%. Since the peak production is likely to be higher the benefits are also likely to be higher.

Casabe EOR Scheme

6.02 The Casabe Enhanced Oil Recovery project will permit the recovery of an additional 70 million barrels, for an investment (in 1983 prices) of US$354.3 million. By 1988, additional production will be 20 MBD, equivalent to annual import savings of US$300 million at 1988 current prices, or 5% of Colombia's imports. The base economic rate of return was calculated at prices expressed in constant 1984 dollars and is very favorable at 42.7% (Annex 5.3). The following sensitivity analysis was performed:

Table 6.1 Sensitivity Analysis

Rate of Return (%)

Base Case 42.7% Production Down 25% 32.5% Production Down 50% 20.0% Investments Up 25% 34.8% Investments Up 25%, Production Down 50% 14.4% Project Completion Two Years Delayed 27.6% Price of Crude Oil Down 25% 30.0%

As the above table indicates the project remains viable even under the most pessimistic scenario of an increase of investment cost by 25%, coupled with a decrease of production by 50%, which is extremely unlikely. - 48 -

Association Field Development Schemes

6.03 The associations proposed to be included in the project are those between ECOPETROL and Chevron, Elf Aquitaine, Occidental Petroleum, and Texaco. For all of these ventures, the economic rates of return are a favorable 23% or higher (Annex 6.1) as the benefits of the investments would ma-terialize early.

lbl-e6.2 Fxcncics of Association Field12veLopents

CumLated Production Investnznts ERR Production in 1988 over 20 Field Oerator ) T ) (UMat 1988 Q) cureretprices)

Castilla Chevron 5.5 64.2 1.3 19 6.o Casnare Elf-Aquitaine 92.9 34.3 5.2 77 22.8 Cano Lirnn Occidntal Petr. 1C5.4 32.3 5.0 75 20.6 Cocorma Texaco 149.8 22.8 5.0 75 22.6 9nTAL 353.6 17 21; 70.0

The total production from the four field developments would be 16.5 MBD in 1988 with an annual value of US$246 million at 1988 current prices of which 60% (or us$144 million equal to 2.5% of Colombia's imports) would accrue to Colombia, the balance being the share of the private operators. Total production over 20 years would be 70 million barrels.

Conclusion

6.o4 The project would provide significant benefits to the Colombian economy. It would provide for 20% of Colombia's domestic sales in 1988, it would replace alternative imports valued at about US$540 million in that year, thus relieving Colombia's balance of payments and bring Colombia close to self sufficiency in 1988. In addition, the project would strengthen ECOPETROL's financial situation, since it would avoid costly imports, and thus generate sufficient funds to allow further increases in production and reserves. Moreover, the project would strengthen ECOPETROL's capabilities in the techniques of enhanced oil recovery, and permit the preparation of additional EOR projects whose economic benefits can be expected to be important. Lastly,the environmental component would help ECOPETROL monitor any negative effects on the environment and develop appropriate guidelines for the petroleum industry so that the accelerated production program does not cause enviLronmental damage. - 49 -

VII - AGREEMENTS

7.01 The following agreements have been reached:

(a) that ECOPETROL would initiate new investments only if they do not adversely affect its capabilities to implement the proposed project (para. 3.33);

(b) that ECOPETROL's financial statements would be audited by independent auditors acceptable to IBRD, and that audited financial statements as well as audited project accounts will be submitted to IBRD within four months after the end of each fiscal year (para 3.15);

(c) that ECOPETROL will continue to maintain satisfactory staffing and organisational arrangements for the implementation of the Casabe EOR project (para.4.07);

(d) ECOPETROL shall submit to the Bank for its approval the annual development plans for the association fields to be financed from the proposed Bank loan before November 15 of each year (para. 4.09);

(e) that ECOPETROL will employ at least three staff members in its unit of preparation of EOR projects not later than December 31, 1984 (para. 4.11);

(f) ECOPETROL will provide the Bank with quarterly progress reports covering technical progress of the Casabe enhanced oil recovery scheme, the association field developments, the studies on enhanced oil recovery, environmental protection and others, procurement status and funds committed/spent (para. 4.30).

(g) ECOPETROL's operating income (before depreciation, and debt service charges) for each full fiscal year shall be equivalent at all times to at least 1.4 times the aggregated projected debt service requirements (para. 5.13).

(h) ECOPETROL's long-term debt to equity ratio shall not be greater than 60:40, based on revalued assets agreed by the Bank; ECOPETROL shall complete the revaluation of assets not later than March 31, 1985 (para. 5.13);

(i) ECOPETROL's current ratio shall be at least 0.8 in 1984, 0.9 in 1985 and 1.1 thereafter (para 5.13); and - 50 -

(j) ECOPETROL will submit to the Bank on an annual basis, not later than February 28 of each year, detailed five-year financial projections,including ECOPETROL's five-year investment program, with particular details on investmentsin the followingyear, and financingplan for short-termand long-term borrowing,and discuss with the Bank measures to be taken if such projections show that ECOPETROLwill not be able to meet one or more of the financial covenants (para. 5.13).

7.02 A condition of disbursementfor the Cano Limon - Rio Zulia pipeline would be contractualarrangements between ECOPETROLand the Occidental Petroleum,satisfactory to the Bank, for constructionof the pipeline accordingto a feasibilitystudy and financingplan, satisfactoryto the Bank (para.4.10).

7.03 The proposed project would constitutea suitable basis for a Bank loan of US$130 million to ECOPETROL,with the guarantee of the Government. The loan would be for a period of 14 years, including a grace period of four years. It would be guaranteed by the Government at a fee equal to 10% of the IBYD standard variable interest rate and rounded to the next highest tenth of a percentage point. - 51 - Annex 2.1 Page 1 of 3

GEOLOGY OF COLOMBIA

General

1. Colombia's geology is relatively well known, as exploration started as early as 1916. Colombia's backbone is the northern part of the Andes Mountains. This mountain system is divided into the Eastern, Central and Western Cordilleras. The structural grain in the southern part of Colombia is north-northeast; in the northern part, Eastern Cordillera, and northwest, Western Cordillera; the Central Cordillera dies in the plains bordering the Caribbean Sea.

2. Geomorphostructural subdivisions around the Andean backbone's of Colombia are from East to West:

(a) The Guyana Shield made out of igneous and metamorphic rocks;

(b) The Oriente Plains with a thick sedimentary pile wedging out toward the shield;

(c) The Eastern Cordillera composed mainly of sedimentary rocks with patches of basement; it branches out into the Perija Mountains along the Colombo-Venezuelan border to the east of Lake Maracaibo, and the WSW-ENE trending Merida Andes of Venezuela;

(d) The Upper and Middle Rio Magdalena River, a down-faulted sedimentary area with thick Creataceous formations that have sourced ample hydrocarbons;

(e) The Central Cordillera and its resurgent, up-faulted block, the Santa Marta Mountain made out mostly of igneous and metamorphic rocks; snow capped dormant volcanoes highlight this chain;

(f) The Cauca Valley which exposes intermontane sedimentary sections, so far devoid of commercial hydrocarbon finds;

(g) The Western Cordillera which also contains mainly igneous and high and low grade metamorphic rocks; and

(h) The Pacific Coast Range with thick Tertiary sediments often resting on ultra-basic rocks within an otherwise undetermined section.

3. The stratigraphic sequence extends from Paleozoic rocks (in the Eastern Cordillera) to Late Tertiary (particularly along the Caribbean and Pacific Coast basins), through Triassic, Jurassic and Cretaceous formations, the latest ones being particularly extensively developed in central Colombia.

4. Orogenic events occurred several times during the long geological history of Colombia; they finally resulted in the present day geomorphic subdivisions. The main oroganic phases are reported from the end of the Paleozoic, Early Jurassic, Late Cretaceous and Late Tertiary periods. - 52 -

Annex 2.1 Page 2 of 3

Petroleum Geology

5. The prospective sedimentary basins of Colombia including the offshore cover an area of about 746,000 km2. These are generally distributed into 12 basins of unequal size and prospectiveness. With the exceptions of the Pacific Coastal and Cauca Basins, they all have recognized hydrocarbon source and reservoir rocks with adequate trapping usually of the structural type (ariticlinesand/or faults). Jurassic and particularly Cretaceous shales are generally considered to be source rocks for the oils trapped in overlying reservoirs (mostly sands of variable quality, rarely carbonates).

6. The petroleum basins of Colombia are as follows:

(a) The Upper Rio Magdalena Valley, commonly referred to as the "Upper Mag" with a 1982 production of about 40.5 million Bbls in the Cabrera, Dina, Ortega, Tello and Tetuan fields. The overall exploration success ratio is 0.16.1!

(b) The Middle Magdalena Valley or Mid-Mag, from Honda to El Banco; this remains the most prolific producer in Colombia with the La Cira, Infantas, Casabe, Velasquez fields. The 1982 production was about 67.8 million Bbls. The overall success ratio is 0.22.

(c) The Lower Magdalena Valley or Lower Mag which encompasses all the Caribbean Coast from the Gulf of Uraba in the west to the Santa Marta massif in the east. Producing fields are: Cicuco, El Dificil, Jobo- Tablon. The overall success ratio is 0.15. The 1982 production was about 5.8 million Bbls. So far only minor production in the order of 50 to 100 BD has been established in the Caribbean Coast sub-province where large mud volcanoes or diapirs are reported along the coast. These features are similar to those of the Trinidad environment where abundant oil was discovered.

(d) The Catatumbo Basin corresponds to the western part of the Maracaibo basin of Venezuela. Well known fields, now essentially depleted, are Rio de Oro, Petrolea, Rio Zulia, and Tibu. 1982 production was about 2.6 million bbl. The overall success ratio is 0.22.

(e) The Putumayo Region or Oriente Sur bordering with Ecuador, has several almost depleted fields: Burdine, Churuyaco, Orito, Nancy, Sucio, Temblon. The 1982 production was 18.2 million bbl. The success ratio in the Putumayo is 0.24.

(f) The Guajira Peninsula Basin is separated from the Santa Marta Massif and the Cesar-Rio Rancheria Basin by the Oca fault, a major regional strike-slip fault. So far only dry gas was discovered (initial

1/ The success ratio is taken to be the number of discoveries (whether commercial or not) divided by the number of wildcat wells drilled since the beginning of oil exploration. - 53 - Annex 2.1 Page 3 of 3

reserves are around 3.5 TCF) near Rio Acha and current production is 220 MMCFD. The success ratio is 0.19.

(g) The Llanos Orientales Basin situated east-northeastof the Andes is a deep basin at the foot of the mountains. Great thicknesses,possibly repeated by faulting, of Tertiary sands and shales overlie a Cretaceous that contains several shales rich and mature. The shales are usually considered as the source for the oil accumulated in Lower Tertiary and uppermost Cretaceous reservoir beds. 1982 productionwas about 6.4 million bbl. The success ratio in 1982 was about 0.29.

(h) The Cesar-RioRancheria Basin corresponds to an eastwards extension toward Venezuela of the Lower Mag basin. The same rock sequence exists; structuraland combination traps are reported. So far exploration efforts have not been successful- 12 dry holes have been drilled.

(i) The Cauca Basin is an intermontanebasin with mainly continental sediments often of volcanic origin. The prospectivenessof the basin is rather low and only one exploratorywell, a dry hole, was drilled.

() The Pacific Coast - Atrato Basin is a large basin extending from the Guayaquil area in the south to the Panama Darien in the north in which hostile environmentprevails: rugged topography,lack of communicationnetwork, sparse population and high rainfalls. Tertiary sediments are reported to be very thick (several thousand meters), but no good source rock or potential reservoirshave been detected so far. The Paleocene and Upper Cretaceousformations seem to lie at great depths except along the edges of the basin where formations wedge-out against and/or onlap thick basaltic traps of Late Cretaceous age. Except for a minor gas discovery,no commercialdiscovery has been made. However, taking into account the size of the basin, and the limited amount of explorationundertaken so far, the prospectivenessof this basin remains to be established.

(k) The Sabana de Bogota Basin correspondsto the plateau about half way between the CordilleraOriental and the Rio MagdalenaValley. The geology consists of folded and faulted Cretaceous sediments with extremely thick (several thousands of meters) Cretaceous shales which are often consideredto be the source rocks for the Mag Valley production. Obviously in the Sabana, the prospects if any lie at greater stratigraphicdepths, perhaps Triassic or Upper Paleozoic. So far four dry holes were drilled.

(1) The Amazonas Basin which consists of the eastern Putumayo and the Colombian panhandle or trapeze southwardsto the Amazon river, has been little explored due to its remotenessand lack of obvious petroleum attractiveness. The northern part, along the edge of the Guyana Shield, might contain heavy oils since it might constitutean extension of Venezuela'sOrinoco tar belt. Explorationwould take off if some interestingresults were to be obtained across the border in Brazil or Peru. ODILBIA

PETROLEU!FXPWRATIXON AS OF DE(CERER31, 1982

Exploration Drilling Remining Surface Wildcats Coniircial Density Contracts Recoverable Geological 2 Basins In Km Wells Discovery Km2/Well Concession Association Total Reserves

1. Upper Magdalena 16,000 69 5 232 2 9 11 99.8 2. Middle Magdalena 30,000 251 34 119 7 7 14 341.4 3. Lower Mbgdalena 87,000 175 13 497 5 5 10 0.7 4. Catatunbo 9,000 41 8 219 1 1 2 21.8 5. Putumyo 48,000 66 11 727 - 1 1 28.7 6. Guajira 31,000 27 4 1,148 - 3 3 - 7. Llanos Orientales 190,000 62 15 306 1 25 26 98.0 8. Cesar-Rancheria 9,000 12 - 750 - - - - 9. Caua 9,000 1 - 9,000 - - - - 10. Pacific-Atrato 70,000 9 - 7,000 - 2 2 - 11. Sbana De Bogota 9,000 5 - 2,250 - 1 1 - 12. Amazonas 108,000 ------Total 586,000 718 90 684 16 54 70 610.0

Source: Ecopetrol: Estadisticas de la Industria Petrolera Colombiana, 1982. Ecopetrol: Plan Quinquenal de Inversiones 1984-1988 - February 9, 1984 -55-

kmex 2.3

MaDE OIL ANDGAS PREN RNER 1 AS OF DECEMBER31, 1982

Natural Eoopetrol Share Oil Gas Number (Incl. Royalty MilUcx Bil7 xi ComPany Pegixn of Fields for Associations) Barrels Cublc Feet (7.)

ECOPEIROL

El Centro 12 100 90.94 53.75 COndor 6 100 114.92 26.25 Distrito Norte 12 100 18.97 26.47 Distrito Sur 8 100 28.19 53.63 Apiay y Ortega 2 100 25.40 4.48 Sub-Total Eapetrol 40 278.42 164.58

ASSOCIATION

1. kUlcitco P*yoa y Otros 4 40 10.29 202.10 2. Petrocol Andalucia 1 60 1.92 - 3. Terra ResoLwces Burdine y Otros 3 20 0.59 - 4. Cbeavron Castilla 1 60 85.64 - 5. Texas Cocorna Nare 2 60 53.71 - 6. Elf Aquitaine Casanare 5 60 27.30 6.50 7. Intercol Araica 1 60 3.10 - 8. Texas GQajira 3 60 - 3363.02 9. Provincia San Jorge 1 60 - - 10. Webb 2 60 0.2 - Sub-Total Association 23 182.75 3578.21

O=ION

1. Texas Melasquez y Otros 5 0 61.10 16.90 2. Intercol Provincia y Otros 3 0 1.99 223.60 3. Houston Oil (Hocol) Dina Tello y Otros 3 0 79.47 23.60 4. Chevron 751uia 1 0 3.50 1.16 5. Elf Aquitaine Yalea 1 0 10.00 - 6. San Andres Jobo 2 0 - 11.20 7. Aitex El Dificll 1 22 - 29.30 Sub-Total CGbcession 16 16 156.56 305.76

CWJN1r MIDAL 79 617.73Y! 4048.55

Souroe: Ecopetrol

1/ Occidental has ane field with 37 million barrels estimated proven reserves.

2/ Taking into acxcunt production during 1983, new discoveries (Elf, Occidental) and secondary recovery reserves from Casabe (70 mi.on barrels), reserves at December 31, 1983 could be estimted at alout 734 mlIon barrels. - 56 - C O L 0 B I A ANNEX2.4 Pastand ForecastProduction of CrudeOil

(HBO) ACTUAL FORECAST 1980 1981 1982 1983 1984 1985 1986 1987 1988 ECOPETROL ------_ El Centro 25.80 25.80 26.7 26.7 26.80 26.00 24.00 227,0 20.40 Condor 15.31 16.31 15,41 15.32 14.60 16.50 30.80 31.60 33.40 Distrito Norte 9,00 8.00 7,4 6,9 6.70 6.60 6.10 5.60 5,20 Distrito Sur 20.10 18.60 1746 16.2 15.30 13.00 10.80 8.90 7.20 Apiav 0.5 3.8 7.40 7.10 6.40 5,70 5.20 Palaqua 3.00 2.70 ------____ -______-___-____-____--_- Total Ecopetrol 70.21 68.71 67.61 68.84 70.80 69.20 78.10 77.00 74.1) ASSOCIATION Pavoa- Colcito (38.51) Basic n634 4.91 3.34 2.35 2.00 1.60 1.50 1.29 1.08 Incresental 0.61 2.33 3.49 3.95 4.50 4.60 4.30 3,71 3.12 Subtotal 6,95 7.24 6.83 6.30 6.50 6,20 5.80 5.00 4.20 Chevron- Castilla (60%) Basic 2.64 3.62 3.32 3.39 3.50 3.50 3.50 3.50 3.50 Incresertal 0.00 0.004 1.18 4.50 4.50 4.50 6.50 6.50 Subtotal 2.64 3.62 3,33 4.57 8.00 8.00 8.00 10.00 10.00 Terra Resources- Burdine(20Z) 1.16 0,89 0.97 0.73 0.70 0.60 0.50 0.40 0,30 Occidental- CanoLimon (601) 0.00 0.00 0.00 0.04 2.00 2.00 7.00 10.00 10,00 Elf- Casanare(60%) 0.00 0.00 000 0.71 6.20 9.00 14.20 16,10 15.00 Petrocol - Arndalucia(60Z) 0.00 1.63 2.25 1.61 1.40 1.20 1.00 0"l0 0,?0 Ir,tercol - Arauca(20%) 0.00 0.00 0,00 2.00 2.70 1,90 1.20 0.70 0.60 Te,xaco- CocornaNare (60%) 0.00 0.02 1.47 3.35 9.00 14.10 17.50 20470 24,00 TOTALASSOCIATION PRODUCTION 10.75 13,40 14.85 19.32 36.50 43.00 55.20 65.10 64.80 CONCESSION Texaco- Velasquez easic 12.67 12.92 8.0 6.9 6.1 5.1 4.9 3.2- 3.1 Incremental 6,1 6.3 7.4 3.1 7.9 5.2 4.,° Subtotal 12.67 12.92 14.03 13.24 13.50 13.20 12.80 8.40 8.00

Intercol - Frovincis Basic 8.43 7.71 6.23 5.26 4.40 3.70 2.55 2.5 1.74 Incresental 1.31 1.61 3.03 4.69 5.40 5.00 3.45 3.05 2,36 Subtotal 9.74 9.32 9.25 9.95 9,80 8.70 6.00 5.30 4.10 HoustanOil - Dina Tello IBsc 16.98 24,96 10.50 9.48 8.50) 7.50 6.41 5.21 4234 Increoental ^20.9625.26 27.10 22.90 19.59 15.89 13,26 ------~~~~~~~~~~------Subtotal 16.98 24.96 31.46 34.73 35.60 30.40 26.00 21,10 17,60 Chevron- Zulia Basic 2.63 2.56 2.09 1.52 1.10 0.80 0.67 0.53 0.44 Incremental 1.41 1.47 1.29 1.52 1.40 1.00 0.83 0.67 0,56 Subtotal 4.04 4.03 3.38 3.04 2.50 1.80 1.50 1.20 1.00 Elf- Jales/Trinidad 0.64 2.60 3.00 3.00 5.00 4,00 TOTALCONCESSIONS PRODUCTION 43.43 51.2Z3 58.12 61.60 64.00 57.10 49.30 41.00 34.70

TOTALPRODUCTION i0Q) 124.40 133.34 140.58 149.76 171.30 169.30 182.60 183.10 173.60 ------TOTALPRODUCTION (MNBbl) 45.40 48.67 51.31 54.66 62.52 61.79 66.65 66,83 63.36 1/PeivcentaQes indicate Ecopetrol's share, 05-Apr-84 - 57 -

Annex 2.5 Page 1 of 2

ECOPETROL'SEXPLORATION AND PRODUCTIONSTRATEGY

Objectives

1. ECOPETROL'sprincipal objectives in explorationand production consist of increasingthe hydrocarbon resource base of the country and promoting a rapid increase in production so as to achieve self sufficiency in the near term.

Exploration Strategy

2. In order to achieve an increase in the hydrocarbonresource base of the country, ECOPETROLhas 42 ongoing association contractswith private oil companies. These are making a considerableeffort in exploration (83 and 63 wells drilled respectivelyin 1981 and 1982). In addition ECOPETROL is carrying out a large effort in seismic works (about 14,000 km over 1984-1987) to help attract additional companies in the most promising basins and drill on its own about nine exploratorywells annually during the period 1984-1987. While ECOPETROL's role in exploration is small, it is an important catalyst for continued effort on the part of companies. On the other hand ECOPETROL has achieved the same rate of success (about 10%) as the oil companies. ECOPETROL's strategy has been highly successful in the past and continued effort at the same level in the future should result in the discovery of additional reserves of about 150 MMBBLS in the medium term.

ECOPETROL's ExplorationPriorities

3. ECOPETROLwill concentrate its drilling efforts in areas of lesser risk and greater potentialwhile at the same time carrying out seismic works in the other areas of greater risk where it will attempt to attract private oil companies. ECOPETROL defined the following order or priority in its efforts of exploration:

Priority Order from high to low SedimentaryBasins (km2)

1 Llanos Orientales (192,000) 2 Valle Medio de Magdalena (24,000) 3 Putumayo (50,000) 4 Catatumbo (8,000) 5 Valle Superior de Magdalena (15,000)

While ECOPETROLwill concentrate its efforts in above five sedimentary basins, it will continue to rely on the very attractive terms of the associationcontracts to promote exploration to the private oil sector in the other sedimentarybasins as follows: Valle Inferior de Magdalena (62,000 km2 ), Guajira (11,000km 2), Pacifica y Valle del Atraco includingthe offshore platform (90,000kn 2), Sabana de Bogota (9,000 km2), and Amazonia (108,000 kin2 ). The effort made by ECOPETROL in explorationpromotion however may not be sufficient and the Bank is discussing with ECOPETROL the possibility of an - 58 - Annex 2.5 Page 2 of 2 explorationpromotion project in these sedimentarybasins which might consist of additional seismic surveys and reinterpretationof seismic data in order to make them more attractiveto the oil companies.

Production Strategy

4, ECOPETROLhas concentratedits developmentefforts as follows: First on its own high productivitydiscoveries in the Llanos Orientalessuch as Apiay, second on infill and step out wells in its older fields and third on carrying out secondary recovery and enhanced oil recovery projects in the most promising fields.

ProductionPriorities

5. ECOPETROL is developingApiay field as the highest priority. The reserves are estimatedat about 20 MMBBLS while the targeted production by end 1984 is about 7,000 BD. Total investments in wells and production facilities are about US$13MM. Operating costs are estimated at US$3.0/BBL.

6. ECOPETROL has also made a consistent and successful effort in the past in the continuous developmentof its old fields through infill and step out wells. As a result production decline has been arrested in certain fields. This effort will continue in the period 1984-1987 through the drilling of about 40 wells a year in 13 fields located in 3 operating districts. The total investmentwould be about US$225MM with a gain of production of about 20,000 BD by early 1988. Economic rate of return would be in excess of 100%.

7. In the areas of secondary and enhanced oil recovery,ECOPETROL is injectingabout 100,000 BD of water in the field of La Cira that results in a production of 10,000 BD of oil. Injection of carbon dioxide has also given some positive results in the Galan field but further tests need to be conducted.

8. In associationwith Texaco, ECOPETROL has entered into a steam injectionprogram in the field of Cocorna. The additionalreserves are estimatedat 52 MMBBLS with an expected total production of about 22,000 BD by 1987. The correspondinginvestments amount to US$140MM excludingphysical and price contingency.

9. Finally ECOPETROL is embarking upon a water injectionprogram in Casabe that would yield 70 MMBBLS additional reserves and an incremental production of 20,000 BD by 1987 for a total investment of US$329MM excluding physical and price contingency.

10. ECOPETROL has also agreed with the Bank to set up a special enhanced oil recovery unit to promote further secondary and enhanced oil recovery projects in Colombia and carry out pilot test programs in the near term. About 200 MMBBLS of additionaloil could possibly be recovered in the medium term, half of which would come from ECOPETROL's own fields and another half from concessionairesfields. ECOPETROL's special enhanced oil recovery unit will carry out the necessary studies with the help of consultantsto define a program for recoveringadditional oil from older fields in Colombia. This program would be financed under the project. - 59 -

Akrex 3.1 Page 1 of 2

(OOLCIBIA

ECCPfOL'S PRIPAL INVESfES BYOXtIPANY ATEND OF 1983

Investment Percentage Conpany (C$ 000) (mership Pearrks

Carboaes de Colombia 7,352,987 49.2 Involvedtin the development of coal production, specificaly in El Cerrejon.

Promigas 205,834 37.4 Operates 245 mile gas pipeline between La Guajira and Barranquilla and Cartagena.

Explotaciones Condor 79,550 90.0 Exploitation of oil fields in the Medio e3gdalena area.

MDnomerosColombo- Veenezolanos 112,222 14.0 Colombian,Venezueln and Dutch aoi3ay which produces caprolactuan and various fertilizers.

Poliolefinas Colomianas 83,191 89.0 Cowpanyinvolved in the production of low density polyethylene.

Terpeles 327,782 49.0 Sale and distribution of hydrocarbons in the cities of Bucaramanga,Manizales and MedeUTn.

Colgas 5,726 21.3 Distributes bottled gas to residential areas and nenufactures gas stoves.

Petroquimca del Atlantico 23,000 20.2 Production and transportation of natural gas and Ught crude oil in the lower Magdalenaarea.

Others 203,662 Includes: Development of uranitun production in the tile axmtry. Sale and distribution of gas and electrical generation for the Sentender area. Production of various fertilizers.

Source: EC)PEI13OL,February 1984 - 60 -

Annex 3.1 Page 2 of 2

ECOPETROL'S FINANCIAL INTERESTS BY SECTOR (1983)

Investment Sector (C$ 000)

Energy 7,507,779

Petrochemicals 243,546

Transport and distribution of products 547,507

Electrical Utilities 67,085

Financial Institutions 18,999

Other 7,238

TOTAL 8,392,154

Source: ECOPETROL ECOt'EROL Orgniaonk Chacrt jLne 3.2

[~~~~~~a&v sa l aaet l lac

va l_ri 1 1 UNP~~~~~~~~~~~~~~~G to t 1 atG 1t,

0~~~~~~~~~c ta, GI W.c.r R m ONO I rOtt L

A + S ~~~~~~~~~~~~~~Ot0 POtto DototOo I otetato toOO,

___ tat?t J | _ |

Ott- H. < 4_

_-

1 1 f 1 + 93Goae

X~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~Wl l0 07 - 62 -

Anriex 3. 3

OOU1IBIA

EOflFETROL

Investment Program 1) (US$ Mllion)

1984 1985 1986 1987 1988 TOTAL

Explcraticn Seismic (line-km) 600 2,000 3,210 4,000 5,000 14,810 Drilling (wlls) 6 10 10 10 10 46

Seismic ($) 9 14 16 18 21 78 Drilling ($) 17 18 20 30 40 125 Total 26 32 36 48 61 203

IevelopmEnt No. of Wels 40 40 40 40 40 200

tDvelopment Cost 44 44 45 46 46 225 Association Contracts 70 73 75 78 83 379 Casabe Enhancenent Oil Fecovery 63 90 74 94 54 375 Pilot Erian*cet Recovery 0 2 3 3 3 11 Total 177 209 197 221 186 990

Pipelines and Stcrage Crude Cano Llon - Rio Zulia 0 0 0 49 0 49 Cude Apiay-Yopel-Velasquez 19 52 74 0 0 145 Fuel Oil Carven-Cartagena 31 16 - - - 47 White Products Sebast.-Yumbo 24 25 9 - - 58 0die 14 9 1 - _ 24 Total 88 102 84 49 0 323

Refineries and Petrodm Fondo Barril - 1 40 50 161 252 1) Other 16 26 26 29 9 106 Total 16 27 66 79 170 358

Maintenance Projects and Envirornetal Protectimn 81 48 35 43 43 250

TOTAL 388 418 418 440 460 2124 investnt Program (C$ Million) 39,265 52,957 62,217 72,963 83,308 310,710 Investnnt in Subsidiaries (C$ mllio) 6,000 7,320 8,784 337 387 22,828

1) Total project cost is more than US$500 million. The balance will be applied in 1989 and 1990. - 63 -

Annex 4.1 Page 1 of 3

COLOMBIA PETROLEUMPROJECT FIELDS DEVELOPMENT IN ASSOCIATIONWITH PRIVATE OIL COMPANIES

Summary

1. The associated operating companies (Elf, Oxy, Texaco and Chevron) estimated the total additional oil reserves to be recovered from their fields at about 70 MMBBLSduring the next 20-year period. Total investments required during the period 1984-1987 for drilling new wells, constructing new production facilities and infrastructure amount to 329.0 MMUS$ excluding physical and price contingencies. Incremental production is about 16,500 BD by 1988 with operating costs varying between 3JS$/BBL for Oxy and Elf to about 6.2US$/BBL for Texaco steam injection project. These operating costs represent costs of labor, transport, fuel, consumables and management overhead, 30 percent of which represent fixed costs and the rest varies with the level of production. Future oil prices shown in Annex 6.2 represent the equivalent FOB international oil prices at Cartagena. It is assumed that a pipeline will be operational to transport Oxy and Elf crude in 1987 and 1988 respectively.

Elf Association

2. Elf is developing six fields: Barquerena, Tocaria, Cano Garza, Cano Garza Norte, Gravo Sur, and Gloria norte with a drilling program of 12 wells over 1984-1986 for a total of 20 producing wells by 1987.

3. Elf has installed production manifolds, separators, treaters, storage tanks and pumping stations in each of Cano Garza, Barquerena and Tocari fields in 1983 and is planning both their expansion and new surface facilities in Gravo Sur and Gloria Norte fields by end 1984 to achieve surface production facilities capacity of about 20000 BD.

4. Elf estimates total reserves at about 38 MMBBLS. While total production from these fields may reach 16000 BD, incremental production due to investments during the period 1984-1987 (86.8 MMUS$) excluding physical and price contingencies) is estimated at about 5200 BD by 1988. This production level would be maintained for about 4 years before declining at about 8X per year (Annex 6.2). Operating costs would average 3.0 US$/BBL representing about the same costs Elf has experienced in Trinidad field in the same area. During the period 1984-1987 production from the Casanere fields will be trucked to the refinery at Barranca Bermeja at a cost of 12.0 US$/BBL. Starting in 1988 production will be shipped via pipeline at a cost of 6.0 US$/BBL. - 64 -

Annex 4.1 Page 2 of3

Oxy Association

5. Oxy declared the field of Cano Limon commercial in December 1983. Reserves are estimated at 37 MMBBLS.l/During 1984-1985 the development program calls for the drilling of 6 wells in addition to the two discovery wells that will be converted into producers. In addition Oxy will construct production facilities including production manifold/flowlines, separation equipment, crude oil storage and pumping station as well as facilities for the personel (camp, office), warehouses and an air strip. Total investments over the period 1984-1987 amount to about 98 MM US$ excluding physical and price contingencies while operating costs are estimated at 3.0 US$/BBL for an incremental production of 5000 BD by 1988. This incremental production would be maintained for about 2 years before onset of decline at about 8% per year afterwards. Operating costs are in line with those experienced by Elf in the same area and for the same type of fields. During the period 1984-1986 production will be trucked to the refinery in Barranca Bermeja at a cost of 10.0 US$/BBL while starting in 1987 it will be shipped via a pipeline at a cost of 5.0 US$/BBL

Texaco Association

6. Texaco is developing the fields of Cocorna and Nare and starting an enhanced oil recovery program consisting of huff and puff steam injection in a reservoir about 2000 foot deep. Estimates of recoverable reserves amount to 52 MMBBLs. Over 1982-1983 Texaco has already drilled 80 wells, is finishing construction of steam injection facilities with a capacity of 10000 BD, built a 20 inch oil line, a storage tank and pumping station with 20,000 BD capacity.

7. During 1984-1987 Texaco plans to drill 64 additional wells, build 2 additional steam injection units each having a capacity of production of 5000 BD.

8. Total investments during the period 1984-1987 amount to about 140 MM US$ for an incremental production of about 5000 BD by 1988. This rate would be maintained for about 4 years before an onset of 8% annual decline afterwards. Texaco estimates operating costs at 6.20 US$ which would include labor, transport, fuel, consumables and management overhead. Production from Cocorna is transported via pipeline to the refinery in Barranca Bermeja at a cost of 0.50 US$/BBL.

Chevron Association

9. Chevron drilled 3 wells in Castilla field in 1983 for a total fluid production of 10000 BD, and built a second storage and heating/treating station to achieve a capacity of dehydration of 15000 BD of total fluid. The crude produced in Castilla contains high level of metals and is not suitable for refining. It is sold directly to industries in the Bogota area that use it as fuel. Chevron estimates reserves at about 25 MMBBLS.

10. Chevron plans to drill one additional well and improve the dehydration facilities of the first storage and heating/treating station in

1/ This information is based on data vailable in early 1984. Meanwhile, further exploration wells were successful and Oxy estimates reserves as significantly larzer. - 65 -

Annex 4.1 Page 3 of 3

1984 for a total investmentof 5.0 MM US$ excluding physical and price contingencies. Incremental production is estimatedat 1300 BD by 1988 to be maintained for about 4 years before decliningat about 8% per year. Chevron estimates operating costs at about 5 US$/BBL representingthe costs of labor, transport, fuel, consumables and management overhead. Production from Castilla is trucked to Bogota at a cost of 12.0 US$/BBL. - 66 -

Annex 4.3 Page 1 of 3

COLOMBIA PETROLEUM PROJECT Detailed Cost Estimate (US$ Million)

Local Foreign Total

I. Casabe Enhanced Oil Recovery

. Drilling of Wells 111.46 140.2 251.66 . Workover of Wells 33.13 40.3 73.43 GatheringStorage and Crude Trans. 6.55 9.0 15.55 . Processingof Produced Fluids 2.03 2.8 4.83 , Water Wells, Lines and Water Inj. Plant 3.12 4.2 7.32 InjectionLines 2.64 3.5 6.14 PPower Interconnection 0.97 1.3 2.27 * Processingof Residual Water 6.19 7.8 13.99 Subtotal Casabe 166.09 209.1 375.19

[I. Fields Development 131.52 221.1 352.62

III. Cano Limon - Zulia Pipeline

. Pump Stations 7.30 6.7 14.00 . Pipeline 59.07 53.3 112.37 . Crude Oil Storage 7.30 6.7 14.00 Subtotal Pipeline 73.67 66.7 140.37

IV. TechnicalAssistance and Studies

. Enhanced Oil Recovery 0.50 2.11 2.61 EnvironmentalStudies 0.05 0.07 0.12 TechnicalAssistance 0.23 0.80 1.03 Training of ECOPETROL staff 0.16 0.70 0.86 LaboratoryTests 0.13 0.70 0.83 Pilot Tests 0.69 3.60 4.29 Subtotal Technical Assistance 1.76 7.96 9.72

Total Base Cost 373.04 504.86 877.90

Contingencies: Physical 26.19 35.40 61.59 Price -10.38 50.60 40.22

Total Project Cost 388.85 590.76 979.61 - 67 -

Arkex 4.3 Page 2 of 3

OOU4BIA PETROLEUM PROJECT

Ehasing of Expenditures local Currency Pcrtim (US$ Million)

1984 1985 1986 1987 Total

I. Casabe Eohanced Oil Recovery

. 1lilling of Wells 15.70 41.31 42.65 11.80 111.46 1rkover of Wells 3.30 9.01 9.85 10.97 33.13 Gaterring Stcrage and rude Thansfer 3.30 3.25 - - 6.55 PIocessing of Produced Fluids 0.90 1.13 - - 2.03 . Water Wells, Lines and Water Injection Plant 1.20 1.63 0.29 - 3.12 Injection Lines 1.10 1.25 0.29 - 2.64 P Pw Intercamection 0.60 0.37 - - 0.97 Pfrocessing of ResidualWater 1.00 1.75 2.79 0.65 6.19 Subtotal Casabe 27.10 59.70 55.87 23.42 166.09

II. Fields DevelopiEnt 45.30 38.30 38.09 9.83 131.52

III. Cano Linrn - Zulia Pipeline

• Pun Staticns 2.10 3.88 1.32 - 7.30 , Pipeline 17.40 30.79 10.88 - 59.07 , (ixle Oil Stcrage 2.10 3.88 1.32 - 7.30 Subtotal Pipeline 21.60 38.55 13.52 - 73.67

IV. Techical Assistance & Studies

Ehanced Oil Recovery 0.10 0.12 0.15 0.13 0.50 . EnvircnmitalStudies 0.01 0.01 0.01 0.02 0.05 . Technical Assistance 0.05 0.04 0.04 0.04 0.17 . Ttaining of ECPExfDL's staff 0.CB 0.04 0.04 0.05 0.16 . laboatary Tests 0.03 0.04 0.03 0.03 0.13 . Pilot Tests 0.15 0.16 0.18 0.20 0.69 Subtotal Techn. Assist. 0.42 0.4 0.51 5

Total Base Cost 94.37 136.96 107.93 33.72 372.88

Contingencies: Thysical 6.60 9.63 7.50 2.46 26.19 Price - -9.31 -2.41 1.34 -10.38 Total Project Cost 100.97 137.28 113.02 37.52 388.69

Fhysical 0.07 0.07 0.07 0.07 Price Escalatimn in Peso - 0.20 0.20 0.19 - 68 _

Annex 4.2

COLOMBIA PETROLEUMPROJECT Time Schedule fbr Planning and implementation of Water Injection Scheme (Casobe Oil Reld)

YEAR 978 979 1980 1981 1982 1983 4984 1986 1986 1987 988 19 RIE 2 1134 34112f10 2314 121341X 234 -

1SjbrjIfac Strde (Competed)[ 2 AI.Ige ProlectLoda I i DrChono DI Bendedi- 3 NMc Test(2 DlltretIDenerIcoF A-, [ [r) & Reseve,) A. l.....w ...... 4.Select We4lLoctlls Ai,At2. Ei1.E2 ords. (Competed) 5. FqectDegn & ]mpientatflbo Progtom 6 Injctin & PFoducngIWells (520 elcto. 53 ftductioc)

12 90 t20 120 , i 1i t l Ij2078WelI DrFling & Completr (lgs) Fg

7. Wets Wets I

Dtltng & Cotepleten if Want,Gotneeng em F Dqsign

DAssign

t Fled Eleetifol Wkrt

12. Wkrroe Esiting PReanengWARt

Reg Contrac (3 Corhbtn& 4 Wrke) e |1 L |2

13. PsMingleg qopnet (WllsT)

141t,saioslToif

Conenuenoton 15. feensroftWduetten Gottierng Syste I T t } t 1 11|[ i Design

Conemeteond t6. WaterDlngeso System

Mes-gn Servees~ ~ ~ ~ ~ ~ Lged

17. TechetlalAseistae(DetIadiDeegt Contract Evla3tiorsssemsJon ofconewtrsets) MWeet&eehmr Englneestrg) 18. Watel3ectto CetetijiePen ocinceanncPeh

Geoleglet fleas (B=ecs) [IV

G-a,phiod Noew 0 19 li?PrdrietWan (SD) 0O 7- C556 ~~~~~~~~~CB Ptrescwh 2500 EID In t98 na'mcltl 1r9 bR''einn .i 3,o

A PReoar Detatee DesIgn. Mateifs SbGeesteatontendets Aarate Conftant El MateralsDeilteey InField t St AC"ttlt Serelees LaggIng,CorratentIg. Pesfaatht

ICasabes todrvetlcn coud reeel 2002208Cc19889 toFITani tt-esrgF 19926Mote aeel n rg at 20%Ot netterate - 69 -

miex 4.3 Page 3 of 3

PETROLEUMPROJECT

Phasirng of Expaiditures Foreign Qirrency P1rtim (UlS$ Million)

1984 1985 1986 1987 Total

I. Casabe Enhanced Oil Pecovey

Dilling of Wlls 22.5 53.9 50.9 12.8 140.1 Wrkove of WeJs 4.7 11.8 11.8 12.0 40.3 Gathering Stcage and Crude Transfer 4.8 4.2 0.0 0.0 9.0 Processing of Produced Fluids 1.4 1.4 0.0 0.0 2.8 Water wlls, lines and Water Injecticn Plat 1.8 2.1 0.3 0.0 4.2 Injection Lines 1.5 1.5 0.4 0.0 3.4 Power Intercnnection 0.9 0.4 0.0 0.0 1.3 Processing of residal water 1.5 2.4 3.4 0.6 7.9

Subtotal Casabe 39.1 77.7 66.8 25.4 209.0

II. Fields Development 84.1 64.6 58.8 13.7 221.2

III. Cano Limon - ZuAia Pipeline

P3p Stations 2.0 3.5 1.2 - 6.7 Pipeline 16.0 27.7 9.6 - 53.3 Crde Oil Strage 2.0 3.5 1.2 - 6.7

Subtotal Pipeline 20.0 34.7 12.0 - 66.7

IV. Tecnical Assistance and Studies

Fnhanced Oil Recovey 0.53 0.53 0.53 0.53 2.12 Envirnmental Studies 0.02 0.02 0.02 0.02 0.08 Tedical Assistance 0.20 0.20 0.20 0.20 0.80 fraining of EODPEMOL'sStaff 0.18 0.18 0.18 0.18 0.72 Laboratcry Tests 0.18 0.18 0.18 0.18 0.72 Pilot Tests 0.90 0.90 0.90 0.90 3.60

Total 2.01 2.01 2.01 2.01 8.04

Total Base Cost 145.21 179.01 139.61 41.11 504.94

Ccntingencies: RPysical 10.2 12.5 9.8 2.9 35.4 : Price 0.0 14.3 24.7 11.6 50.6

IuTALPEU= OIST 155.41 205.81 174.11 55,61 90.94

Ehysical: 7.00% 7.00% 7.00% 7.00% Price 1.00 1.08 1.09 1.09 - 70 -

Annex 4.4

COLOMBIA

Petroleum Project

Estimated Disbursementof Bank Loan 1/ (US$ MM)

IBRD Amount Cumulative Fiscal Year Quarter Disbursed Amount Percentage

1985 II 6.o 6.o 5 III 8.0 14.0 12 IV 10.0 24.o 18

1986 I 12.0 36.0 28 II 16.o 52.0 4o III 20.0 72.0 55 IV 14.0 86.o 66

1987 I 9.0 95.0 73 II 8.0 103.0 79 III 8.0 111.0 85 IV 7.0 118.0 90

1988 I 7.0 125.0 96 II 5.0 130.0 100

May 29, 1984

1/ This disbursementprofile essentiallyconforms with the statistical prof'ileas of February 1984 for 72 Bank/IDA Energy Projects, etc. but excluding Power Projects approved from FY 73 to FY 83. - 71 - CQLOMB I A ANNEX5.1

ECOPETROL Pagelof3

Past andForecast Income Statements

(C$million)

ACTUAL FORECAST

1980 1981 1982 1983 1984 1985 1986 1987 1988

Revenues

DomesticSales 43,744 64,509 894,872108,838 137,795 175,231 227,542 291,016372,461 ExportSales 14,863 18,388 22,467 34,963 45,479 61,056 87,740 122,484 142,809

SalesRevenues 58,60782,897 112,339143,801 183,274 236,287 315,283 413,501 515,270

Expenses

mestic Purchases 10,337 15,80728,712 42,637 51,447 67,715 91,700 114,984 131,984 Imports Cr,@Oil 17,80025,504 21,553 31,584 35,305 49,177 59,655 98,506126,331 Gasoline 16,052 11,830 24,525 16,245 10,86613,298 15,421 20,913 56,857 Price Stabilization (7,917) (995) OperatingExpenses 11,641 17,745 24,294 31,218 46,634 55,977 69,551 85,025 103,993 Depreciation 3,978 4,386 5,718 9,406 13,375 17,89024,111 31,622 40,366

TotalExpenses 51,89174,357 104,802 131,090157,627 204,057 260,438 351,051 459,531

OperatingIncome 6,716 8,540 7,537 12,711 25,647 32,230 54,845 62,450 55,739

NonOperating Income 1,177 1,611 3,250 4,233 5,080 6,096 7,315 8,631 10,185

Less: Interest 4,170 5,108 4,961 4,732 8,689 12,564 15,856 17,043 18,162 ExchangeLosses 3,847 4,221 6,0 10,83916,572 21,59116,425 14,104 12,865 Other 129 290 461 550 660 792 950 1,121 1,323

Net Income (253) 532 (663) 823 4,806 3,379 28,928 38,81233,574

OperationRatio (Z) 89 90% 93% 91% 86% 86Z 83% 85% 89%

18-S 4 - 72 - COLOMB I A Annex5.1

ECQPETROL Page2of3

Sourcesand Application of Funids

(Csaillion)

F O RE C A S T Five-YearsSumary

1984 1985 1986 1987 1988 CSmillion US$Million Percent

(peratingIncome 25,64732,230 54,845 62,450 55,739 230,911 1,561 741 Depreciation 13,375 17,80 24,111 31,622 40,366 127,363 849 41%

Subtotal 39,021 50,120 78,95794,072 96,105 358,275 2,410 115%

Deductions DebtService Interest 8,68912,564 15,856 17,043 18,162 72,313 495 23% Principal 4,756 6,081 9,377 15,789 26,975 62,979 402 20% Increasein WorkingCapital 9,995 3,224 5,970 6,520 6,842 32,550 241 10% Increasein OtherAssets 575 690 829 895 1056 4,045 28 12 ShortTerm Debt Repayment 0 14,442 13,130 5,052 0 32,624 233 10%

Subtotal 24,015 37,00245,161 45,299 53,035 204,512 1.399 66%

Additions Increasein PensionFund 3974 4769 5723 6181 7293 27,940 193 9% NetNon-operating Income 4420 5304 6364 7510 8862 32,459 223 10%

FundsAvailable For Investment 23,400 23,191 45,882 62,464 59,224 214,161 1,426 69%

CapitalInvestment Program 39,265 52,957 62,217 72,963 83,308 310,710 2,124 100% InvestmentsIn Subsidiaries 6,000 7,320 8,784 337 387 22,828 180 7%

FinancingGap 21,865 37,087 25,118 10,8 24,470 119,376 878 38

Financedby Borrowings: LongTerm 18,999 37,555 25,681 13,673 26,898 122,805 m8 40% ShortTerm 3,256 0 0 0 0 3,256 32 1%

Increase(decrease) in Cash 390 469 562 2,837 2,428 6,685 42 2% CumulatedCash 2,342 2,811 3,373 6,210 8,637

DebtService Coverage 2.9 2.7 3.1 2.9 2.1

(*)not includingincrease in cash 18-Sep-84 - 73 - COLOMB I A ANEX5.J

ECOPETROL Page3of3

Pastand Forecast Balance Sheets

(CSmillion)

ACTUAL FORECAST

December31 1980 1981 1982 1093 1904 1985 1986 1987 1988

ASSETS

CurrentAssets Cash 1,399 1,301 1,508 1,952 2,342 2,811 3,373 6,210 8,637 AccountsReceivable 6,802 6,794 8,638 8,274 11,685 15,053 20,055 26,265 32,778 Inventories 9,537 17,540 24,053 25,076 35,726 44,180 55,555 68,872 83,456

Subtotal 17,738 25,635 34,199 35,302 49,754 b2,044 78,902 101,346124,872

GrossAssets 39,776 50,745 61,647 96,887 126,024172,135 229,723 297,312 375,448 Less:Acc. Depreciation 12,0D0 16,218 21,09b 29,783 43,158 bl,047 05,159 116,781157.146

NetOperating Assets 27,776 34,527 39,751 67,10482,867 111,088144,564 180,532 218,301

Workin Progress 2,540 4,903 13,455 9,505 19,632 26,479 31,190 36,481 41,654

Investmentsin Subsidiaries 5,795 7,811 10,185 14,674 20,674 27,994 3b,778 37,115 37,502

OtherAssets 1,494 1,916 2,860 2,877 3,452 4,143 4,971 5,866 6,922

T O T AL A S SE T 5 55,343 74,792 100,450129,462 176,379 231,748 296,404 361,341 429,251

L I A B. ANDEU I T Y

CurrentLiabilities AccountsPayable 11,113 15,043 18,484 24,249 27,248 34,724 44,351 56,690 70,302 ShortTerm Debt 15,754 8,711 20,746 17,798 2b,430 16,587 4,812 0 0 CurrentPortion of LTDebt 4,243 6,081 9,377 15,789 26,975 32,856 Other 1,392 2,068 2,820 3,811 4,878 6,000 6,780 7,458 8,092

S;ubtotal 28,259 25,822 42,050 50,101 64,b45 b6,688 71,731 91,114 111,250

LongTerm Debt 13,595 19,718 25,711 34,367 59,798 108,272139,646 151,393 164,181 Less:Current Portion 0 0 0 4,243 6,O81 9,377 15,789 26,975 32,056

NetLong Term Debt 13,595 19,718 25,711 30,124 53,717 98,895 123,857124,418 131,32b

PensionFund 7,029 10,398 14,498 19,871 23,845 28,614 34,337 40,518 47,811

RevaluationSurplus 9,703 9,703 9,703 9,703 9,703 9,703 Paidin Equity 7,622 19,484 19,484 20,134 20,134 20,134 20,134 20,134 20,134 Reserves (1,162) (630) (1,293) (471) 4,335 7,714 36,b42 75,454 109,020

Subtotal 6,460 18,854 18,191 29,366 34,172 37,551 66,479 105,291138,865

T QT A L LIAB.AND EQUITY 55,343 74,792 100,450129,462 176,379 231,748 296,404 361,341 429,251

CurrentRatio 0.6 1.0 0.8 0.7 1.0 J.9 1.1 1.1 1.1 Debt:Debt& Equity (Z) 761 b61 69Z 651 71l 78l 72 651 W0I Debt:Debt& Eq. after Reval(Z) . 33? 361 42l 38% 33% 30%

Revaluationof assets GrossAssets 223,073299,739 410,409 555,836 729,560 946,048 Accum.Depreciation 74,276103,843 144,291 199,671 270,080 362,b93

NetAssets 148,797195,895 266,118 356,165 459,479 583,355

RevaluationSurplus 81,693 113,029155,030 211,601 270,948 365,053

10-Sep-84 - 74 -

Annex 5.2 Page 1 of 13

COLOMBIA

PETROLEUM PROJECT

ASSUMPTIONSUNDERLYING THE FINANCIAL PROJECTION

General

The financial projectionsare expressed in current pesos (C$). The main coefficientsused for domestic and foreign inflation, exchange rates, and real domestic and internationaloil prices are on page 9 of this annex.

I. Income Statements

a. Revenues

The breakdown of oil revenues appears on page 10 of this Annex. The sales volume is derived from the sales forecast for gasoline, fuel oil and the products.

The domestic prices to ECOPETROL for 1984 were announced in January 1984, and are as follows:

Product C$/Gal US$/Bbl

Gasoline 48.17 20.44 Middle Distillates(average) 50.00 21.07 Fuel Oil 40.14 17.03

For future years, the prices were escalated in accordancewith the assumed rates of domestic inflation, and domestic real price increases. Regarding exports of fuel oil and middle distillate,the average prices received in 1983 were respectivelyUS$24.17/Bbl and US$42.20/Bbl. In future years, the export prices were escalated in accordancewith the anticipated internationalinflation and internationalreal crude oil price increases.

With regard to natural gas, four different prices are in effect, as follows:

Gas Prices (in effect, January 1984) C$/MCF US$/MCF ElectricityL 44.25 0.45 Petrochemicals 77.7 0.78 Industry and Commerce 120.0 1.21 Residential 135.0 1.36

1/ Rate excludes subsidy paid by ECOPETROL to power companieswhich reduce the effective price paid by utilities further. ECOPETROL has been asked to provide details. - 75 -

Annex 5.2 Page 2 of 13

The first three are sales prices to customers. The price of residential gas is somewhat higher, as the distribution companies (Barranquilla, Cartagena mostly) charge an additional distribution margin.

In future years, it was assumed that the price of gas would increase at the same pace as domestic inflation.

Page 12 of this annex shows the breakdown of gas sales by year, and the corresponding revenues.

b. Expenses

(i) Purchases

ECOPETROL purchases crude oil from the companies operating in Colombia, and imports crude oil and gasoline. The concession and association contracts in effect provide for two categories of crude oil, i.e. basic crude and incremental crude for discoveries made until 1976. The price of basic crudes, which reflects, inter alia, their qualities, is indexed in accordance with the following formula:

F = 1 + [0.75 ( A/100 + 0.25 (B/C - 1)] where A is the annual percentage variation of the international price index, B is the domestic price index variation, C is the exchange rate variation. Incremental crude is indexed as follows:

P = Pi (0.3R + 0.2) where Pi is the c.i.f. import price, and R is the ratio of incremental and basic productions. The price of incremental crude cannot exceed 50% of the international price.

In the case of crude oil discovered after 1976, ECOPETROL buys the crude at the international price. For the purpose of the forecast, the price of basic crude was assumed to increase at the same pace as international inflation; the price of incremental crude was escalated in accordance with the international oil price, taking into account the 50% limit of the c.i.f. price of imported crude; the price of new crude was assumed to increase in line with the international oil price. In addition, ECOPETROL buys condensate (on average 3.1 MBD at US$3.2/Bbl) and pays transportation charge for domestic crude (estimated at C$76/Bbl in 1984).

Page 12 of this Annex shows the purchases of natural gas. ECOPETROL buys natural gas from three producing companies. The price of Guajira gas (US$1.59/MCF in 1984), is linked to the fuel oil price; the prices of El Dificil, Payoa and Provincia gas (respectively US$0.95, US$0.67 and US$0.57/MCF) are linked to international inflation; the price of Jobo Sucre gas (US$0.70/MCF) is constant. In the forecast, the purchase price of gas was projected in accordance with the contractual arrangements. - 76 -

Annex 5.2 Page 3 of 13

The quantities of imported oil were derived from the difference between the demand, and the domestic production (excluding crude used directly as fuel oil), and the price of imported crude oil was based on US$27.56/Bbl in 1983, and escalated in parallel with the international oil price.

The quantities of gasoline imports were derived from the difference between domestic production and demand. The future price of gasoline imports was derived from the actual price paid in 1983 (US$32.71/Bbl), and escalated in parallel with international crude oil prices.

(ii) Operating Expenses

Direct operating expenses were taken to be C$46.6 billion in 1984 (budget) and escalated in accordance with domestic inflation, and the growth rate in domestic sales volume.

(iii) Depreciation

With regard to exploration expenditures, including seismic, and unsuccessful drilling, these are amortized over five years. Development expenditures are amortized over 10 years. The forecast assumes that the annual depreciation expense would be equivalent to 12% of the average gross assets in operation during the year.

(iv) Interest

Interest expense includes the interest on the long term debt (whose annual breakdown in US$ appears at Page 13), and interest on the short term debt (assumed to be 15%).

(v) Exchange losses

The amount of exchange losses was calculated by averaging (in US$) the debt outstanding during the year, and calculating the increase in the value of that average due to the difference in exchange rates at the year's beginning and at year end.

(vi) Taxes

As ECOPETROL receives a credit towards income tax equivalent to its full investment program, it will not have income tax obligations during the forecast period.

(vii) Other

Non operating income and other, non operating expenses, were assumed to increase at the same rate as inflation. - 77 - Annex 5.2 Page 4 of 13

II. Balance Sheets

a. Balance Sheet Items

Cash was assumed to be escalating, at the minimum, in accordance with local inflation.

Accounts receivable were assumed to be 6.5% of domestic sales and 6% of export sales.

Inventories were assumed to be 8% of total sales, plus 70% of 1983 actual inventories, escalated in accordance with local inflation.

The investment program (in US$) appears in Annex 3.3. Work in progress was assumed to be 50% of the annual investment program.

Other assets include mostly ECOPETROL's investments in its subsidiaries, particularly Carbocol. They were assumed to increase in accordance with ECOPETROL's obligations as follows:

Year 1984 1985 1986 1987 1988

Investment (C$ million) 6,000 7,320 8,784 337 387

Accounts payable were assumed to be 19% of overall purchases, plus 7% of crude and gasoline imports, plus 4% of domestic sales (Fondo Vial), plus 30% of actual 1983 accounts payable escalated in accordance with domestic inflation.

The amount of short term debt is based on ECOPETROL's requirements to maintain an adequate level of cash.

Other liabilities were assumed to increase at the same pace as domestic inflation.

No increase in paid-in capital was assumed troughout the forecast.

b. Ratios

(i) current ratio = current assets/current liabilities including current portion of long-term debt

(ii) long-term debt/equity ratio = (long-term debt 1/ + pension fund)/(equity + long-term debt 1/ + pension fund)

(iii) long-term debt/equity ratio after revaluation of assets = (long-term debt 1/ + pension fund)/(equity + long-term debt 1/ + pension fund + revaluation surplus)

1/ Excluding current portion of long-term debt - 78 -

Annex 5.2 Page 5 of 13

(iv) debt service coverage ratio = (operating income + depreciation)/(debt service) where debt service is interest for short-term and long-term debt and principal for long-term debt and reduction, if any, of short-term debt during the year.

c. Revaluation of Assets

Balance Sheet Figures 1983 Revalued Figures 1983

C$MM C$MM Gross Assets 96,887 Gross Assets 223,073 Acc. Depreciat. 29,783 Acc. Depreciat. 74,276 Net Assets 67,104 Net Assets 148,797

Revaluation Surplus: C$MM 81,693

For 1984 and subsequent years, assets were revalued with local inflation:

(i) (revalued gross assets), = (revalued gross assets) x (local inflation)t + (increase in gross assets)t x [I + (local inftation- 1)t/2]

(ii) (accumulated depreciation)t = (revalued acc. dep)t-i x (local inflation)t + (new depreciationt x [1 + (local inflation- 1) t/21

(iii) (net revalued assets)t = (revalued gross assets)t - (revalued accumulated depreciation)t

(iv) (revaluation surplus)t = (net revalued assets)t - (net assets)t

III. Volumetric and Production Data (page 10 of this Annex)

a. Crude Production

This is the total domestic crude production; it includes ECOPETROL's production and that from association and concession contracts (based on a field by field analysis).

b. Crude Used as Fuel Oil

Due to heavy metal content, some crude does not lend itself for refining and is therefore used as fuel oiL. This use is estimated at 8 MBD from 1984 to 1986 and to increase to 10 MBD thereafter. - 79 -

Annex 5.2 Page 6 of 13

c. Total Throughput

This is a function of domestic demand and the relative import price of crude and gasoline. The total throughput is projected to be 10% below refinery capacity in 1984 and reaching 100% in 1987.

d. Imports of Crude

Necessary to provide sufficient crude for the refinery throughput. Import = total throughput - crude production + crude used as fuel oil - 3.1 MBD.

This 3.1 MBD is condensate produced in the gas fields and is bought by ECOPETROL.

e. Fuel Oil, Gasoline and Other Products Production and Demand

The domestic demand is given below:

Domestic Demand (MBD)

1984 1985 1986 1987 1988 Fuel Oil 19 18 19 19 20 Gasoline 81 84 87 90 93 Other Products 65 65 67 70 73 TOTAL 165 167 173 179 186

Fuel oil demand is projected to remain static, due to satisfaction of increased demand by coal and gas. Demand for gasoline and other products is projected to increase at 3.5% per annum, except for other products in 1985.

The production is projected as a percentage of the total throughput. The average percentages are:

Fuel oil- 25.7% Gasoline 36.8% Other Products 34.8% TOTAL 97.3%

Over the years these percentages vary to reflect changing import price relations of crude and gasoline.

f. Domestic Prices for Petroleum Products

The prices are those received by ECOPETROL in 1983 compounded by the inflation and real price increase indexes (7) given in page 9.

g. Export Prices for Petroleum Products

These prices are the international prices in 1983 and adjusted for subsequent years in line with Latest projections of the commodities division, according to the index (6) in page 9. - 80 -

Annex 5.2 Page 7 of 13

h. Prices for Domestic Purchase of Crude Oil

These price projections for purchase of crude oil are explained in page 2 of this annex.

IV. Gas Production, Sales and Purchases

a. Production

The production of two fields, i.e. Guajira and Payoa, are expected to increase by about 4.5% and 3.5% annually. The production of two fields, i.e. Provincia and Lisarna are expected to stay at the existing levels, whereas the production of the two fields of El Difficil and Jobo Sucre are projected to decline rapidly by about 15% and 19% respectively.

b. Purchase Prices

Are explained in page 2 of this annex.

c. Sales

(i) Quantities

Industry demand is projected to increase by an annual average of 8.9%, with an exceptionnally large increase of 28% in 1985 and a smaller rate than average in subsequent years. Electricity demand is projected to remain at about the 1983 level, due to new electric power generated by coal. Residential demand is projected to remain at about 1% of total demand.

(ii) Prices

The prices are those obtained by ECOPETROL in 1983 adjusted for local inflation every year. V. Debt Schedule

a. Chemical Loan: The loan of MMUS$ 200 was made in 1979 for ten years including five years of grace at LIBOR + 3/4%. Thus first repayments are due in 1984, totaLing MMUS$ 36 annually. Interest was assumed at 14.5% p.a.

b. Manufacturers Hanover Trust: The loan of MMUS$ 100 was made in 1980 for ten years including five years grace at LIBOR + 5/8%. Thus first repayments are due in 1986, totaling MMUS$ 18 annually. Interest was assumed at 14% p.a.

c. Other: Opening balance 1984: MMUS$ 74 Average interest: 7.3% Last repayment: 1991 - 81 - Annex 5.2 Page 8 of 13 d. World Bank Proposed Loan: An amount of MMUS$ 130 is to be made in 1984 for 14 years including four years grace at 11.5%. First repaymentwill be due in 1988, totaling MMUS$ 13 annually. e. New Borrowings This is commercialborrowing to supplementWB borrowing in financing the investment program. Assumed to be made for 8 years including 2 years grace at 11.5%. - 82-

C O L Q M B I A ANNEX5.2

E C , P E T R , L Page9 of 13

MairnCoefficients Used

1980 1981 1982 1983 1984 1985 1986 1987 1988 Coefficients (la)Local Inflation 1.20 1.20 1.20 1.18 1.18 (lb)Cuaulated Local Inflation 1.00 1.20 1.44 1.73 2.04 2.41 (2a)Foreign Inflation 1.04 1.08 1.09 1.09 1,09 (2b)Cumulated Foreign Inflation 1.00 1.04 1.12 1.22 1.33 1.45 (3a)Current Exchanrge Rate Variation 1.28 1.23 1.13 1.10 1.09 (3b)Cumulated Current Exchange Rate Variation 1.00 1.28 1.57 1.78 1.96 2.12 (4a)Real Exchange Rate Variation 1.10 1.11 103 1.02 1.00 (4b)Cueulated Real Exchange Rate Variation 1.00 1,10 1.22 1.25 1.27 1.28 (5a)Year End Exchange Rate 50.92 59.07 70.29 88.77 113.63 139.76 157.93 173.72 188.49 (5b)Mid Year Exchange Rate 47.46 55.00 64468 79.53 101.20 126.69 148.84 165,82 181.10 (6a)Int. Oil Price Increase in currentterms 0.98 1.05 1.13 1.15 1.11 (6b)Cusulated Int. Oil Price Increase in currentterms 1,00 0.98 1.03 1.17 1.34 1.49 (7a)Domestic Real Price Increase for Petroleum Products 1.05 1.05 1.05 1.05 1.05 (7b)Cua. Domestic Real Price Increase for Petroleum Products 1.00 1.05 1.10 1.16 1.22 1.28 (8a)Daoestic Price Index for Petroleum Products 100 98 101 112 127 145 (8b)International Price Index for Oil Prices 100 98 103 117 134 149

I/ TheCumulated Real Exchanle Rate Variatior, (4b) is calculated as follows: (4b)= 2b)x (3b)I (lb) i.e.real exchanqe rate index multiplied by localinflation indexequals exchange rate index multiplied by international inflationindex. 2/ TheDomestic Price Index is multipliedby thefollowing factor (7a)x (la)I (3a) i.e.domestic real price increase multiplied by localinflation anddivided by theexchange rate variation 3/ TheInternational Price Index is basedon projectionsof the commoditiesdivision. iL-May--84 - 83 -

C O L Q Me I A ANNEX5.2 EC OPE T ROL Page10 of 13 Volumetricand Production Data

A C T U A L F O R E C A S T 1980 1981 1982 1983 1984 1985 1986 1987 1988 CrudeOil CrudeProduction (HBD) 124.40 133.34 140.58 149.76 171.30 169.30 182.60 183.10 173.60 Add:Apparent Inmv drawdowns 0.20 0.46 1.12 2.24 TotalProduction (MBD) 124.60 133.80 141.70 152.00 171.30 169.30 182.60 183.10 173.60 LessCrude Used as Fuel Oil (MBD) 4.00 4.30 3.70 4,80 8.00 8.00 8.00 10.00 10.00 TotalThrou hput (MBD) 152.10 165.40 161.90 187.50 201.50 201.50 211.70 220.10 213.00 Imports of Crude (H8D) 31.50 35.'90 23.90 40.30 35.10 37.10 34.00 43.90 46,30 Priceof crude(US$/Bbl) 31.05 34.87 34418 27.71 27.23 28.66 32.30 37.07 41.28 FuelOil FuelOil Production (MBD) 41.50 44,70 50.00 52.70 55.70 54.50 59.10 62.00 59.80 Fuel Oil Demand(MBD) 19.30 20.59 21.10 17.60 18.50 17.90 18.50 18.50 19.40 LessInternal Cons. IHfD) 3.10 9.20 6.40 0.50 2.70 4.80 4.90 4.60 5.00 FuelOil Domestic Sales (MBD) 16.20 11.39 14.70 17.10 15.80 13.10 13.60 13.90 14.40 DomesticFuel Oil Pricey (US$/Bbl) l4.26 14.33 15.06 14.93 14.78 14.88 15.96 17.75 20.13 FuelOil Exports (MBD) 26.20 28.41 32.60 39.90 45'20 44.60 48.60 53.50 50.40 FuelOil Export Price (USt/Ebl) 25.19 25.64 23.85 24.17 23,75 25.00 28.17 32.34 36.00 Gasolir,e GasolineProduction (NBO) 49.80 56,80 53.30 62.50 72.20 75.70 79,70 82.30 75.70 GasolineDomestic Sales (MED) 70.60 72.00 78.90 80.10 81.35 84.20 87.1S 90.20 93.35 GasolineDomestic Price (US$/Bbl) 17.54 20.31 22.31 21.87 21.65 21.79 23.37 25.99 29.49 Gasoline Imports (MBD) 20.80 15.20 25.60 17.60 9.15 8.50 7.45 7.90 17.65 GasolineImport Price (US5/Pbl) 38.46 40.27 37.94 32.71 32.15 33,84 38.12 43.76 48.73 OtherProducts OtherProdLucts Production 1M8D) 51.70 55.80 56.50 66.90 68.90 69.70 72.30 75.20 78.20 LessExports (NBD) 4,70 4.20 3.70 3.60 3.80 4.70 5.00 5.20 5.50 OtherProducts Dom. Sales (MBD) 47.00 51.60 52.80 63.30 65.10 65.00 67.30 70.00 72.70 OtherProduct Price (US$/Bbl) 21.28 22.35 26.52 23.76 23.53 23.68 25.40 28.25 32.05 ExportPrice (US$/Bbl) 39.94 43.20 42.91 42.20 41.47 43.66 49.18 56.46 62.86 Productionas a Percentageof Throughput Fuel oil 25.2% 21.5% 26.9% 27.8% 26.3% 24,7% 25.6% 26.1% 25.7% Gasoline 32.72 34.3% 32.9% 33.3X 35.8X 37.6% 37.6% 37.41 35.51 Products 34.0% 33.7% 34.9X 35.7% 34.2% 34.6% 34.2% 34.2% 36.7% Total 92,0% 89.5% 94.7% 96.9% 96.3% 96.8% 97.4% 97.6% 98.0X TotalVolume of DomesticSales (M8D) 133,80 134.99 146.40 160.50 162.25 162.30 168.05 174.10 180,45 TotalVolume of Imports(NeD) 52,30 51.10 49.50 57.90 44.25 45.60 41.45 51.80 63495 TotalVolume of Exports(MBD) 30.90 32.61 36.30 43.50 49.00 49,30 53,60 58.70 55.90 NetVolume of Imports(MeD) 21,40 18.49 13.20 14.40 -4.75 -3.70 -12.15 -6.90 8.05 USSMillion Costof GasolineImports 291.99 223.42 354.51 210,13 107.37 104.96 103,60 126.12 313.95 Costof CrudeImports 357.02 456.91 298.12 407.56 348.87 388.16 400,79 594.04 697.56 TotalCost of Imports 649.00 680.32 652.63 617.68 456.25 493.12 504.39 720,15 1011.51 Vlalueof FuelOil Exports 240.89 265.88 283,79 352.00 391.8B 407.03 499.72 631.48 662.35 Valueof OtherExports 68.52 66.23 57.95 55.45 57.52 74.89 89.76 107.16 126.20 TotalValue of Exports 309.41 332.10 341.74 407.45 449.40 481.92 589448 738.64 788.55 NetImports 339.59 348.22 310.89 210.23 6.84 11.20 -85.09 -18.48 222.96 25-Mav-84 - 84 -

ANNEX5.2 C O L OM B I A ------T------Page11 of 13 E C O P E T R O L DomesticCrude Oil Purchases

ACTUAL FORECAST 1980 1981 1982 1983 1984 19B5 1986 1987 1'?88 Volljumesof Purchases(MBD) ------Associations Basic' 5.9 5.2 4.2 3.4 3.2 2?9 2.7 2.5 2.3 Incresental 0.4 1.4 2.1 2.9 4.6 4,6 4.4 4.9 4,5 New 0.0 0.7 1.5 3.9 9.6 12.0 16.8 20,2 20,4 TotalAssociations Purchases 6.3 7.3 7.8 10.2 17.4 19,5 24.0 27.6 27.2 Concessions Basic 77.4 74.0 38.8 34.4 22.7 20.1 17.6 16.2 13.6 Incremtental 8.2 4.0 34.8 42.5 41.3 37.0 31.7 24.8 21,1 Total Volumeof Conrcession Purchases 85.5 78.1 73.5 76.9 64.0 57.1 49,3 41.0 34,7

TOTALVOLUME OF PURCHASES 91,2 85,3 81.3 87.1 81,4 76.6 73.3 68,6 61t9

CruideOil Prices (US$!Bbl) AssociationsOil Basic 5.66 7.31 6.35 6,52 6,74 7.28 7.94 8.65 9,413 Incremental 5,35 7.61 16.92 15.71 13,62 14.33 16.15 18.54 20.64 New 0,00 36.62 30.25 29.04 28.54 30,04 33.85 38,86 43.26 AveragePrice of AssociationsOil 5,64 10.03 13.82 17.74 20,61 22.98 27.64 32.50 36.63 ConcessionsOil Basic 3.90 6,68 4.57 4.97 5.14 5.55 6.05 6.60 7.19 Incremental 3,43 5t95 15.20 15.72 13.62 14.33 16.15 18.54 20.64 AveragePrice of ConcessionsOil 3.85 6.64 9.60 10.91 10,61 11.24 12,55 13481 15.36 Overall Averageof Price of Purchases 3,97 6.93 10.00 11.71 14.37 15.92 19,31 23.24 26.71

Cost of Purchases(MMUS$) AssociationsCrude Basic 12.15 13.82 9,64 8.06 7.85 7.61 7.88 7.94 7.94 Incremental 0,74 3.98 13.27 16,63 22,70 24.22 26.21 33403 34.02 New 0,00 8a84 16.43 41,22 100.01 132,04 208.07 285,93 321.52 Total Associations 12,89 26.63 39.34 65.91 130.57 163.86 242.16 326.90 363,40 Corncessions Basic 110,02 180.38 64.70 62.37 42.59 40,73 38.83 39.08 35.73 Ircretental 10,24 8.80 192t92 243,94 205.25 193.56 186.95 167.55 158.82 TotalConcessions 120.25 189.18 257.62 306,31 247,84 234.28 225,78 206.64 194t55; Condensate 3.62 3.62 3.62 3.62 3.62 TransportatiornCost 44,76 43.44 45,23 44,27 41.57 TOTALCOST OF CRUDE PURCHASES 133,14 215.80 296.96 372.21 426.79 445.21 516.78 581.43 603,22

25-May-84 - 85 -

ANNEX5.2 COLOMBIA ------Page12 of 13 ECOPETROL Pjlot GasProduction Sales and Purchases

A CT U A L F5 R E C AS T 1982 1983 1984 1985 1986 1987 1988 GasProduction (MMCFO) Ecopetrol- Guajira 117.00 130.00 143+00 156.00 154.00 156.00 160.00 Guajira- Texas 78.00 86,00 95.00 104.00 102.00 104.00 107,00 Petroquimica- El Dificil 6.00 20.00 12.00 10.00 10.00 6.00 5.00 Intercol- Jobo Sucre 40.00 26.00 15.00 ao8.00 8.00 300 1.00 Subtotal 241.00 262.00 265.00 278.00 274.00 269.00 273.00 EcopetrolShare - Payoa 18.00 19.00 22.00 22.00 22.00 Cities- Pavoa 27.00 28.00 33.00 33.00 33.00 33.00 33.00 Intercol- Provincia 51,00 57.00 50.00 50.00 55.00 60.00 60.00 Ecopetrol- Lisarna 4.00 6.00 5.00 5.00 5.00 5.00 5.00 Subtotal 100.00 110.00 110.00 110.00 115.00 120.00 120.00 Total 341.00 372.00 375,00 388.00 389.00 389.00 393.00 GasSales (MMCFD) Quantities(MtCFD) Industry 85,00 83.00 90.00 115.00 117.00 118.00 120.00 Electricity 167.00 197,00 210.00 208.00 200.00 200.00 201.00 Domestic 1.00 2.00 4.00 2.00 3.00 3.00 3.00 Total 253.00 282.00 304.00 325.00 320.00 321.00 324.00 GasPrices PricesC$/MCF Industrv 82.00 103.00 120.00 144.00 172.80 203.90 240.61 Electricity 54.00 44,00 44.00 52.80 63.36 74.76 88.22 Residential 93.00 116.00 135.00 162.00 194.40 229.39 270.68 Revenues(C$ million) Industry 2,544 3,120 3,942 6,044 7i379 8,782 10539 Electribity 3,292 3.164 3,373 4,009 4,625 5,458 6.472 Residential 34 85 197 118 213 251 296 TOTALGAS REVENUE 5,870 6,369 7.512 10.171 12,218 14,491 17,307 Costof GasPurchases Prices($/MCF) Guajira 1.81 1.58 1.59 1.67 1.89 2.16 2.41 ElDificil 0.63 0.79 0.95 1.03 1.12 1.22 1.33 JoboSucre 0,70 0.70 0.70 0,70 0.70 0.70 0.70 Payoa 0.43 0.63 0.67 0.72 0,79 0.86 0.94 Provincia 0,43 0.59 0.57 0.62 0.67 0.73 0.80 TotalCost (NNUS$) Guailra 51.53 49.60 55,13 63.53 70.20 82,17 94.13 ElDificil 1.38 5.77 4.16 3.74 4.08 2.67 2.42 JoboSucre 10.22 6.64 3.83 2.04 2.04 0.77 0.26 Payoa 4,24 6.44 8.07 8.72 9450 10.36 11.29 Prvincia 8.00 12.27 10.40 11.23 13,47 16.02 17.46 TOTALCOST OF GASPURCHASES 75.37 80.72 81.60 89.27 99,30 111.98 125.55

25-May-84 -86 - AbIX5.2 COL0MBIA ------Page13 of 13 ECOPEIROL

DebtSchedule

(U5$Million)

1984 1985 1986 1987 1988

Cheeical

OpeningBalance 200 164 127 91 54 Drawings a 0 a 0 0 Principal 36 37 36 37 36 Interest 29 20 15 10 5 Closing 164 127 91 54 18

M.H.T.

OpeningBalance 100 100 100 82 64 Drawings 0 0 0 0 0 Principal 18 18 18 Interest 14 14 13 10 8 Closing 100 100 82 64 46

Other

OpeningBalance 74 63 52 43 35 Drawings Principal 11 11 9 8 8 Interest 6 5 4 3 3 Closing 63 52 43 35 27

WorldBank

OpeningBalance 6 52 103 130 Drawings 6 46 51 27 4 Principal 13 Interest(10.0%) 0 3 8 12 13 Closing 6 52 103 130 121

NewBorrowings

OpeningBalance 193 444 565 588 Drawings 193 250 122 55 145 Principal 32 74 Interest(11.5%) 11 37 58 66 72 Closing 193 444 565 588 659

SARY

OpeningBalance 374 526 775 884 871 Drawings 199 296 173 82 149 Principal 47 48 63 95 149 Interest 60 79 98 101 100 Closing 526 775 884 871 871

DebtSchedile (CS)

BalanceYear End 59798 108272139646 151393 164181 BalanceBeginning 33200 59798 108272139646 151393 Withdrawals 20166 37555 25681 13673 26898 Repayments 4756 6081 9377 15789 26975 Exchangelosses 1118d 17000 15070 13864 12865 Interest 6114 9949 14552 16746 18162

.L8-56a4 - 87 -

Annex 5.3 Page 1 of 3

COLOMBIA

Petroleum Project

Assumptionsfor Financial and Economic Analysis of Casabe EOR Scheme

The investmentcosts in constant 1984 prices of US$354.3 million, which includes physical contingenciesbut excludes price contingencies,are distributedover the implementationperiod from 1984 to 1987. Incremental production starts in 1985 at 3.85 MBD from the wells already completed by then and increases to 20 MBD by 1988, when all investmentsare completed. Full production capacity is sustained for five years, up to 1992, when the field experiencesa 20% annual decline in production until the year 2003. In the financialanalysis, the price of oil, which ECOPETROLreceives was assumed to be the domestic price of gasoline from 1984 to 1988, expressed in constant 1984 US dollars, minus US$4/Bbl for refining cost. (This conservative assumption presupposesthat in the absence of the scheme other domestic productionwould be available and ECOPETROL would not have to import the equivalent volume at internationalprices). From 1989 on, the price increase would be 2% p.a. In the economic rate of return, the price of oil was assumed to be the internationalprice of crude from 1984 to 1988 as assumed in the financial projections,but expressed in constant 1984 dollars, and increased by 2% p.a. thereafter. Thus the total analysis was done in constant 1984 dollars. The operating costs after production at plateau level are calculated as follows:

fixed = 30% of operating cost at plateau level

variable cost _ 70% of operating cost at plateau level x production production at plateau level

The operating costs are calculatedin the same way for the other fields. - 88 -

C OL O MBI A ANNEX5.3 Page2 of 3 FinancialAnalysis ofCasabe E 0 R Project

Year 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 Investeents(US$Ml) 70.8 134.1 112.1 42.5 OperatingExpenses (US$MM) 3.65 18.25 27.38 36.50 36.50 36.50 36.50 36.50 31.39 27.30 AdditionalProduction (M8D) 2.0 10.0 15.0 20.0 20.0 20.0 20.0 20.0 16.0 12.8 CumulatedProduction (lMB) 0.7 4.4 9.9 17.2 24.5 31.8 39,1 46.4 5242 56.9 FutureOil Price (US$/BbD) 16,44 15.8 16.0 16.4 16.9 17.3 17.7 18.1 18.6 19.0 19.5 AdditionalRevenues (US$MM) 11.5 58.4 90.0 123.2 126.2 129.3 132.5 135.7 111,2 91.1 NetCash Flow (US$M1) (70,8)(126.2) (72.0) 20.1 86.7 89.7 92.8 96.0 99.2 79,8 63.8

Year 1995 1996 1997 1998 1999 2000 2001 2002 2003 InvestmentsWUSSHH) OperatingExpenses (US$MM) 24.03 21.42 19.32 17.65 16.31 15.24 14.38 13,69 13,14 AdditionalProduction (MBD) 10,2 8.2 6.6 5*2 4.2 3.4 2.7 2.1 1*7 CumulatedProduction (lNB) 60.6 63.6 66.0 67.9 69.4 70.7 71.6 72.4 73.0 FutureOil Price (US$/Bbl) 20,0 20.5 20.9 21.4 21.9 22.5 23.0 23.5 24.1 AdditionalRevenues (US$MM) 74.7 61.2 50.1 41.0 33.6 27.5 22.5 18.4 15.1 NetCash Flow (US$MM) 50.6 39.7 30.8 23.4 17.3 12.3 8.2 4.8 2.0 FinancialRate of Return 18.9X

09-May-84 - 89 -

C O LO MB I A ANNEX5.3

EconosicAnalysis ofCasabe E 0 R Project Page3 of3

Year 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 Investments(US$MM) 70.8 134.1 112.1 42.5 OperatingExpenses (USS$MM) 3.65 18.25 27.38 36.50 36.50 36.50 36,50 36.50 31.39 27.30 AdditionalProduction (HBO) 2.0 10.0 15.0 20 20.0 20.0 20.0 20.0 16.0 12.8 CumulatedProduction (1MB) 0.7 4.4 9.9 17.2 24,5 31.8 39.1 46.4 52.2 56.9 FutureOil Price (USM/Bbl) 27.2 26,5 27.4 28.9 29.5 30,1 30.7 31.3 31.9 32.6 33,2 AdditionalRevenues WUS$WH) 19.4 100.1 158.2 215.4 219,7 224.1 228.6 233.2 190.3 155$3 NetCash Flow (US$SH) (70,8)(118,4) (30,2) 88.3 178.9 183.2 187.6 192.1 196.7 158,9 128,0

Year 1995 1996 1997 1998 1999 2000 2001 2002 2003 Investments(US$SM) OperatingExpenses (USW1) 24.0 21.4 19.3 17.6 16.3 15.2 14.4 13.7 13.1 AdditionalProduction (BD) 10.2 8.2 6.6 5.2 4.2 3.4 2.7 2.1 1.7 CumulatedProduction (11B) 60.6 63.6 66.0 67.9 69.4 70.7 71.6 72.4 73.0 FutureOil Price (US$/BbD) 33,9 34.6 35.3 36.0 36.7 37.4 38.2 38.9 39.7 AdditionalRevenues (USW1) 126.7 103.4 84,4 68.8 56.2 45.8 37,4 30.5 24.9 NetCash Flow (US$SH) 102.7 82.0 65.0 51.2 39,9 30.6 23.0 16.8 11.8 Rateof Return 42,7%

09-May-84 - 90 -

C G L O HB IA ANNEX6.1 Page1 of4 EconomicAnalysis of CastillaProject (Chevron) I/

Year 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 InvestmentsWUSSHH) 3.2 2.3 OperatingExpenses (USWNN) 0.0 1.8 1.8 2.3 2.3 2.3 2.3 2.2 2.0 1.9 1.8 AdditionalProduction (MBD) 0.0 1.0 1.0 1.3 1.3 1.3 1.3 1.2 1.1 1.0 0.9 CumulatedProduction (MNB) 0.0 0.4 0.7 1.2 1.6 2.1 2.6 3.0 3.4 3.7 4.0 FutureOil Price (lUS$/bl) 2/ 23.75 23.15 23.93 25+20 25.74 26.25 26.78 27.32 27,86 28.42 28.99 TransportationCosts (US*18b1) 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 AdditioralRevenues (USWNN) 0.0 4.1 4.4 6.0 6.3 6.5 6.7 6.4 6.1 5+8 5.6 NetCash Flow (US$WH) (3.2) (0+1) 2.5 3.7 4.0 4.2 4.5 4.3 4.1 3.9 3.7

Year 1995 1996 1997 1998 1999 2000 2001 2002 2003 Investments(US$NN) OperatingExpenses (USSMH) 1.74 1.65 1+58 1.50 1,44 1,38 1.32 1.27 1,22 AdditiDnalProduction (MBD) 0.8 0.8 0,7 0.6 0.6 0.5 0,5 0.5 0.4 CumulatedProduction (MNB) 4.3 4.6 4.9 5.1 5.3 5.5 5.7 5,9 6.0 FutureOil Price (US$/BblD 2/ 29.6 30.2 30.8 31.4 32,0 32.6 33.3 34.0 34.6 TransportationCosts (US$/Bbl) 12.0 12,0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 AdditionalRevenues (US$SH) 5.3 5+0 4.8 4.5 4.3 4.1 3.9 3.7 3.5 NetCash Flow WUSWHH) 3.5 3.4 3.2 3.0 2.9 2.7 2.6 2.4 2,3 Rateof Return 64.2Z

1/Major Assumptions arein Annex 4,1 2/Sirice the crude from this field cannot be refinedi due to its hish metalcontent, it isused exclusivelv asfuel oil. Therefore theexport price for fuel oil was used from 1984 to 1988.expressed in1984 dollars. and then increased by 2% p.e.

09-Htay-84 - 91 -

CO L O H B I A ANNEX6.1

Paqe2 of 4

EconosicAnalysis of CasanareProject (ELF) I/

Year 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 ____ ------__ Investments(USWHH) 36.4 17.3 26.6 12.6 OperatingExpenses (US$Mi) 1.53 4.38 5.69 5.69 5.69 5.69 5.39 5.08 4.74 AdditionalProduction (MBD) 1.4 4.0 5,2 5.2 5.2 5.2 4.8 4.4 4.0 CukulatedProduction (MMB) 0Q5 2.0 3.9 5.8 7.7 9.6 11.3 12.9 14.4 FutureOil Price(US$/Bbl) 2/ 27.2 26.5 27,4 28.9 29.5 30.1 30.7 31.3 31.9 32.6 TransportationCosts (US$/8bb) 12.0 12.0 12.0 6.0 6.0 640 6.0 6.0 6.0 AdditionalRevenues (USSHH) 7,4 22.5 32.1 44.6 45.7 46.9 44.4 41.7 38.4 Net CashFlow (US$WH) (36.4)(11.4) (8.5) 13.8 38.9 40.0 41.2 39.0 36.6 33.7

Year 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 Investments(US$MM) OperatingExpenses (USWHM) 4.4 4.2 3,9 3.7 3.5 3.3 3.2 3.0 2.9 2.8 AdditionalProduction (NBD) 3.6 3.2 2.9 2.6 2.3 2.1 1.9 1.7 1.5 1.4 CumulatedProduction (HHB) 15.7 16.8 17.9 18.8 19.7 20.5 21.2 21.8 22.3 22.8 FutureOil Price (US$/Bbl) 2/ 33.2 33,9 34.6 35.3 36.0 36,7 37.4 38.2 38.9 39.7 TransportationCosts (US$/Bbl) 6.0 6.0 6.0 6.0 6.0 6.0 6.0 6.0 6.0 6.0 AdditionalRevenues (US$WH) 35.4 32.7 30,1 27.8 25.6 23.6 21.7 20.0 18.4 17.0 Net CashFlow (US$WI) 31.0 28,5 26.2 24.1 22.1 20.3 18,6 17.0 15.6 14.2 Rateof Return 34.3X

1/ MaiorAssumptions are in Annex4.1 2/ Internationalprice for crudeas projectedby the bank's commoditydivision (see Annex 5.2 p.9)up to 1988!expressed in 1984dollars. Thereafter the price was increasedby 2X p.a. - 92 -

ANNEX6.1 C O L O H B I ------Page3 of 4

EconomicAnalysis ofCano Linon Project (OXY) 1/

Year 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 Investments(USWH1) 28.9 41.5 33.1 1,9 OperatingExpenses (USSMM) 1.1 1.1 3.8 5.5 5.5 5.2 4.9 4.6 4+4 4.2 4.0 AdditionalProduction (IBD) 1.0 1.0 3.5 5.0 5.0 4.6 4+2 3.9 3.6 3.3 3.0 CumulatedProduction (M?8) 0.4 0.7 2.0 3.8 5.7 7.3 8.9 10.3 11.6 12.8 13.9 FutureOil Price (USS/bl) 2/ 27.2 26.5 27.4 28.9 29,5 30.1 30.7 31.3 31.9 32.6 33.2 TransportationCosts (US$/Bbl) 10.0 10.0 10.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 AdditionalRevenues (US$SM) 6+3 6.0 22.3 43.6 44,7 42.1 39.7 37.4 35.2 33.2 31.2 NetCash Flow (USSMM) (23.7)(36+6) (14.7) 36.2 39.3 37.0 34.8 32,8 30.8 29.0 27.3

Year 1995 1996 1997 1998 1999 2000 2001 2002 2003 Investments(USWHH) OperatingExpenses (US$HM) 3.78 3.61 3.45 3.31 3.17 3.05 2,94 2.84 2,74- AdditionalProduction (MBD) 2.8 2.6 2.4 2.2 2.0 1.8 1.7 1.6 1.4 CumulatedProduction (MMB) 14.9 15.9 16.7 17.5 18.3 18.9 19.5 20.1 20.6 FutureOil Price (US$/Bbl) 2/ 33.9 34.6 35.3 36.0 36.7 37.4 382 38.9 39,7 TransportationCosts (US$/Bbl) 5.0 5.0 5.0 5.0 5+0 5.0 540 5,0 5.0 AdditionalRevenues (US$iM) 29.4 27.7 26.1 24.6 23.1 21.8 20.5 19,3 18.1 NetCash Flow (USSMM) 25,6 24.1 22.6 21+2 19.9 18.7 17.5 16.4 15,4 Rateof Return 32.3%

1/Maior Assumptions arein Annex 4.1 2/International price for crude as projected bythe bank's commoditydivision (see Annex 5.2 p.9) up to1988t expressed in 1984dollars. Thereafter theprice was increased by2% p.a.

09-May-84 - 93 -

ANNEX6.1 C O L O HB I A ------Paqe4 of 4

EconomicAnalvsis of CocornaProiect (TEXACO) 1!

Year 1984 1985 1986 1?87 1?88 1989 1990 1991 1992 1993 1994 Investments(USSMM) 70 40.8 30.9 8.1 OperatinqExpenses (US$WN) 0.0 2.4 6.2 11.3 11.3 11.3 11.3 10.7 10.1 9.6 9.1 AdditionalProduction (MBD) 0.0 1.1 2.8 5.0 5.0 5.0 5.0 4.6 4.3 3.9 3.6 CumulatedProduction (MMB) 0.0 0.4 1.4 3.2 5.0 6.9 8.7 10.4 11.9 13.3 14.7 FutureOil Price (US$/Bbl) 2! 27.2 26.5 27.4 28,9 29.5 30.1 30.7 31.3 31.9 32.6 33.2 TransportationCosts (US$/Bbl) 0.5 0.5 0.5 0.5 0.5 0.5 0,5 0,5 0.5 0.5 0.5 AdditionalRevenues (USSMH) 0.0 10.0 27.0 51.8 52.9 54.0 55.1 51.7 48.8 45.7 42,9 NetCash Flow (US$MM) (7040)(3342) (10.1) 3244 41.6 42.7 43.8 41.1 38.6 36.1 33.8

Year 1995 1996 1997 1998 1999 2000 2001 2002 2003 Investments(USSHM) OperatingExpenses WUSSHH) 8.62 8.21 7.82 7.47 7.14 6.84 6.57 6.31 6.08 AdditionalProduction (MBD) 3.3 3.0 2.8 2.6 2.4 2.2 2.0 1.8 1.7 CunulatedProduction (MMB) 15.9 17.0 18.0 18.9 19.8 20.6 21.3 22.0 22.6 FutureOil Price (US$/Bbl) 2/ 33.9 34.6 35.3 36.0 36.7 37.4 38.2 38.9 39.7 TransportationCosts (US$/Bbl) 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0,5 0.5 AdditionalRevenues WUSWMM) 40.2 37.8 35.5 33.3 31,2 29.3 27.5 25.8 24.2

NetCash Flow (US$MM) 31.6 29.6 27.6 25.8 24.1 22.5 21.0 19.5 18.2 Rateof Return 22.8Z

1/ MaiorAssueptions are in Annex4.1 Li Internationalprice for crude as projectedbv thebank's commoditydivision (see Annex 5.2 p.9) up to 1?88texpressed in 1984dollars, Thereafter the price was increased by 2% p.a.

09-Mav-84 - 94 -

Annex 6.2 Page 1 of 2

COLOMBIA

Petroleum Project

Documents in Project File

Re. Casabe

Desarrollo Secundario de Casabe Mediante Inundacion con Agua (December 21, 1981)

Evaluacion de tres Ensayos Pilotos de Inyeccion de Agua de Campo Casabe (Aug. 1983)

Re. Association Contracts

Contrato Modelo de Association

Contratos de Association con Chevron, Elf, Occidental y Texaco

Re. Chevron: Castilla

Evaluacion Economica y de Reservas de la Concession Cubarral (May 1974)

Re. Elf: Casanare

Commercialidad del Campo Cano Garza (March 12, 1980)

Commercialidad Campos Tocaria y Barquarena (August 1982)

Commercialidad Campo Cravo Sur No.1 (July 2, 1983)

Commercialidad Campo Cano Garza Norte 1 (July 21, 1983)

Commercialidad Campo la Floria Norte (October, 1983) - 95 -

Annex 6.2 Page 2 of 2 Re. Occidental: Canao Limon

Estudio de Commercialidad, Campo Cano Limon (October 1983)

Notificacion de Commercialidad, October 1983

Re. Texaco: Cocorna

Memoria Technica del Area Norte del Contrato de Associacion Cocorna (April 27, 1981)

Estudio de Commercialidad del Campo de Cocorna (July 14, 1981)

Re. Cano Limon - Rio Zulia Pipeline

Information Memorandum June 1984

Proposal Documents (Tender) Volume I to IV June 1984

Amendments to Proposal Document

Re. ECOPETROL

Annual Reports 1977 through 1982

Information Memorandum for a US$100 million loan syndicated by Manufacturers Hanover of August 1980

Plan Quinquenal de Inversiones, ECOPETROL 35 Anos

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