Document of The World Bank FOR OFFICIAL USE ONLY - t '- Y Report No.t- 3475-EGT STAFF APPRAISAL REPORT EGYPT ABU QIR GAS DEVELOPMENT PROJECT February 19, 1982 Energy-Department Petroleum Projects, Division I 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 Egyptian Pound (LE) LE 1.0 - US$1.45 LE 0.7 US$1.0 WEIGHTS AND MEASURES 1 Metric Ton = 1,000 kilogram (kg) 1 Ton (Metric) = 2,204 Pounds (lb) 1 Meter = 3.28 Feet (ft) 1 Kilometer (km)3 0.62 Miles 1 Cubic Meter (m ) 35.3 Cuic Feet (cft) 1 Barrel (Bbl) = 0.159 m 1 Ton of Oil (API 30) = 7.19 Bbls 1 Kilocalorie (kcal) 3.97 British Thermal Unit (Btu) 1 Ton Oil Equivalent (toe) 10 million kcal (39.7 million Btu) MMcf/d = Million cft per day Bpd = Bbls per day MW = Megawatt (1,000 kilowatts) GWh - Gigawatt hours (1 million kilowatt hours) TCF = Trillion cft PRINCIPAL ABBREVIATIONS AND ACRONYMS USED ARE = Arab Republic of Egypt EGPC = Egyptian General Petroleum Corporation WEPCO - Western Desert Operating Petroleum Company GUPCO = Gulf of Suez Petroleum Company EIB = European Investment Bank PETROGAS = Petroleum Gas Company LPG = Liquefied Petroleum Gas NGL = Natural Gas Liquids API = American Petroleum Institute FISCAL YEAR July 1 - June 30 This report was prepared by Messrs. V. Nayyar, J. Rochet, H. Schober and M. Wormser of Lhe Energy Department, on the basis of a field appraisal during Fetruary/March 1981. FOR OFFICIAL USE ONLY EGYPT ABU QIR GAS DEVELOPMENT PROJECT - STAFF APPRAISAL REPORT TABLE OF CONTENTS Page No. I. THE ENERGY SECTOR Introduction ......................................... 1 Energy Balance ....................................... 1 Resource Endowment ................................... 3 II. OIL AND GAS SECTOR Background ........................................... 5 Hydrocarbon Bearing Structures ....................... 5 Exploration Policy ................................... 6 Exploration Plan ..................................... 6 Current and Anticipated Level of Oil Production ..................................... 7 Demand for Petroleum Products ........................ 8 Refining, Transportation and Marketing .... ........... 10 Refining Capacity .................................... 10 Transportation and Marketing ......................... 11 Natural Gas .......................................... 11 Demand and Supply of Natural Gas ..................... 13 Gas Pipelines ........................................ 15 Foreign Exchange, Pricing and Fiscal Contribution of the Sector ......................... 15 Investment Plan for the Petroleum Sector .... ......... 17 Sector Issues and the Role of the Bank .... ........... 19 III. THE BENEFICIARY History ............ .................................. 24 Statutory Functions .................................. 24 Capital Structure .................................... 25 Organization and Management .......................... 25 Functional Structure ................................. 26 The Western Desert Petroleum Company ................. 26 Petrogas ............ ................................. 27 Accounting System and Management Information ........................................ 27 Audits ............. .................................. 28 Insurance ........... ................................. 28 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. TABLE OF CONTENTS (Continued) Page No. IV. THE PROJECT Background ................................ . 29 Gas Reserves, Production Potential and Field Development ...... ........................ 29 Project Design .............................. 31 Description of the Project ..........................o 33 Project Implementation .. 34 Project Costs .................... 35 Project Financing Plan . .............................. 37 Procurement and Disbursement and Advance Contracting ......................3......... 38 Project Risks ........................................ 39 Training ........................ 39 Ecology and Safety .................. ................. 40 V. FINANCIAL ANALYSIS Introduction .......................................... 41 Past Financial Performance ........................... 41 Current Income ................... ................... 43 EGPC's Future Position .. 44 Abu Qir Field ..................... ................... 46 Present Finances ............................ 46 Financial Viability of the Abu Qir Field ............. 47 Financing Plan .. ........... 47 Projected Financial Position ............ .. ........... 48 VI. ECONOMIC ANALYSIS Least Cost Solution .................. ................ 50 Cost Stream ...................... .................... 50 Direct Benefits .................... .................. 50 Rate of Return .. ..................................... 51 Gas Pricing .......................................... 51 Other Benefits ............................... . 51 VII. RECOMMENDATIONS 52 ANNEXES 2.01 Production-Sharing Agreements with Foreign Oil Companies. 2.02 List of New Discoveries. 2.03 Projected Average Demand for Natural Gas in Alexandria 2.04 Projected Average Demand for Natural Gas in Cairo 2.05 Projected Average Demand for Natural Gas in Suez and the Delta Area 2.06 Public Investment Program - Oil and Gas Sector 3.01 EGPC's Organization Structure. 3.02 Functional Structure of the Petroleum Sector. TABLE OF CONTENTS (Continued) ANNEXES (Cont-d) 4.01 Project Schedule. 4.02 Project Cost Estimate. 4.03 Estimated Schedule of Disbursement. 5.01 EGPC Unconsolidated Income Statements 1977-1979 5.02 EGPC Unconsolidated Balance Sheets 1973-1979 5.03 Abu Qir Field Project Sources and Applications of Funds 1981-1958 5.04 Forecast Income Statements for Abu Qir Fields 1981-1988 5.05 Forecast Balance Sheets for Abu Qir 1981-1988 5.06 Main Assumption for Financial Statements and Economic Analysis 6.01 Economic Analysis 7.01 Related Documents and Data in Project File MAPS IBRD 15795 - Project Area IBRD 15695 - Abu Qir Gas Development Project I. ENERGY SECTOR Introduction 1.01 Over the last five years the oil sector has acquired an increasingly dominant role in Egypt's economy and currently accounts for 75% of commercial energy used in Egypt. Oil output increased threefold during this period, and in 1980 export earnings from oil were of the order of $3 billion, constituting 67% of Egypt's merchandise exports. Inspite of extremely low domestic prices, the fiscal contribution of the sector is substantial and growing; as a propor- tion of total government revenues it increased from 10% in 1975 to about 35% in 1980. Nonetheless, on account of the rapidly depleting reserves, there was -oncern, about Egypt's capability to sustain its present production level. In this context, developments over the last 12 months have been encouraging. Oil companies efforts to maintain the production level in peaking fields have been successful, delineation drilling has led to the upward revision of presently known oil reserves and, most importantly, there has been a series of new, albeit, small discoveries. These developments will arrest production decline; as a matter of fact, a modest increase in production can be anticipated. Spurred by recent discoveries of oil in the Red Sea and gas in the Western Desert, there has been a resurgence of interest in Egypt's oil prospects and in the last one year Egypt has entered into 35 production-sharing agreements with foreign oil companies. Over the next five years, an annual expenditure of $600 million in exploration is anticipated, almost all of it is by foreign oil companies. This should allow Egypt to at least maintain and possibly improve upon the present production levels during the eighties. 1.02 Stimulated partly by domestic prices which are a fraction (14%) of the international prices, domestic consumption of petroleum doubled during the last five years and the growth rate is not anticipated to decelerate in the near future. Such a buoyant growth rate could erode the exportable surplus of oil. If such a trend has to be retarded, it is important that Egypt increases the prices of petroleum products significantly, and at the same time, develop its natural gas resources. Egypt has large and relatively unexploited reserves of natural gas. Its currently known gas reserves are estimated at about 9.75 trillion cubic feet, equivalent to 225 million tons of oil; but presently natural gas provides only 10% of the commercial energy. By developing its gas fields and the concomitant infrastructural facilities, natural gas could release liquid hydrocarbons for export and become a major source of domestic energy during the eighties. Further, by optimizing the refinery program, so as to take note of fractions (essentially light and heavy ends) which natural gas could replace, Egypt could maximize its foreign exchange earnings from oil. This would require the development of a natural gas plan and mobilizing the necessary resources to fund it. Although Egypt has so far refrained from international commercial borrowing for financing its investment program, it may now be an opportune time for doing so, and the petroleum sector is likely to be specially attractive to the banking community. Energy Balance 1.03 Petroleum and hydroelectricity constitute the principal source of primary commercial energy in Egypt. Coal deposits have been discovered in the Western Desert and the Sinai Peninsula and are estimated at around -2- 100 million tons. As in other developing economies non-commercial fuels in the form of crop residue and animal waste are used extensively, and a recent study estimated energy produced by these sources at around 5 million tons of oil equivalent (toe). The table below estimates the commercial energy balance in oil equivalent for 1980 and 1985. Energy Balance (Thousand Tons of Oil Equivalent) 1980 1985-86 Production Crude Oil 29,400 1/ 34,800 Natural Gas 1,850 7,250 Hydroelectricity 2,800 3,100 Total Availability 34,050 45,150 Consumption 1. Petroleum Products 11,300 16,550 Industry & Commerce 3,190 3,480 Power 2,450 2,450 Transport 3,550 7,200 Agriculture 350 720 Domestic 1,760 2,700 2. Natural Gas 1,850 7,250 Industry & Commerce 1,309 4,150 Power 541 3,000 Domestic - 100 3. Refinery Losses 650 840 4. Hydroelectricity 2,800 3,100 5. Coal 1,000 1,200 Total Domestic Consumption 17,600 28,940 Exports (Net of Imports) 2/ Crude Oil 15,700 1/ 17,410 Petroleum Products 1,750 Coal (1,000) (1,200) Total Exports 16,450 16,210 1/ Of which foreign partners share 5.9 million tons. 2/ Includes stock change. -3- Resource Endowment 1.04 The major existing and potential sources of primary energy are indicated below: (a) Oil and Gas 1.05 Hydrocarbons are a predominant source of energy and presently account for 75% of the commercial energy consumed in Egypt. In 1980, against an estimated domestic consumption of about 11.3 million tons, the production level was around 30 million tons (600,000 barrels a day), and the recoverable reserves are estimated at around 400 million tons (3 billion barrels). In addition natural gas is rapidly growing into an important source of energy. Over the last ten years, seven gas fields have been discovered and after taking into account associated gas from the oil fields, the cumulative recoverable reserves are estimated at about 9.75 trillion cubic feet (TCF), equivalent to 225 million tons of oil. Current consumption amounts to 200 million cubic feet per day (MMcf/d); it is anticipated to grow fourfold over the next four years and will by 1985 account for 25% of the commercial energy consumed in Egypt. (b) Hydropower 1.06 Hydropower is the only other important source of primary energy available to Egypt and in 1980 accounted for 16% of commercial energy used domestically. The first step to tap hydropower potential was taken in 1960 when the old Aswan Dam was equipped with turbine generators having a cumula- tive capacity of 345 MW. The Aswan High Dam was completed between 1960 and 1970, seven miles upstream of the Aswan Dam, and equipped with the generating capacity of 2,100 MW. With this, of the total hydropower potential of about 12000 GWh, as much as 9000 GWh were harnessed. The least cost power develop- ment program calls for an early exploitation of the remaining hydropower potential. In June 1980, an IDA Credit (1052-EGT) was approved to help, inter alia, finance the installation of additional 270 MW capacity (1100 GWh) at the old Aswan Dam. The remaining 60-meter drop in the River Nile between Aswan and Cairo represents a generating potential of 460 MW, of which 190 MW could possibly be realized by adding generating facilities in three existing barrages: Esna (89 MW), Nag Hammadi (48 MW), and Assiut (53 MW). The Qattara depression represents the only other hydropower possibility in Egypt. It would, however, involve canalizing water from the Mediterranean Sea to the Qattara depression (which extends 135 meters below sea level) and using the descent to generate power. The economic viability of this project has yet to be determined. (c) Coal, Oil Shale and Nuclear Fuels 1.07 Coal deposits have been discovered in the Western Desert and in the Sinai Peninsula and are estimated at 100 million tons of which 35 million tons are considered exploitable. Amongst the various reserves identified, the deposits at Magahra in the Sinai Peninsula offer the highest potential for -4- development. These appear suitable for power generation and could possibly sustain a 600 MW coal-fired power plant for about 20 years. Oil shale deposits have also been located in the Sinai Peninsula and are 10-15 feet thick. The data indicate that the shale is of poor quality, has low hydrocarbon content and for the present cannot be considered as a possible energy source. No uranium or thorium is currently being produced in Egypt. Although geological conditions appear favorable to finding uranium deposits, airborne surveys and limited ground radiometric work have yielded no positive results. However, even if prospecting activities are accelerated, it appears doubtful if Egypt would be in a position to produce nuclear fuel during the eighties. (d) Solar Energy 1.08 Egypt has a vast potential for solar energy. Direct daily solar intensity is 350 calories/square centimeter in winter and 710 calories/square centimeter in summer. However, due to the high cost of this energy, current applications are limited to research. The main areas which are being explored are solar water heating, water desalination, dehydration plants, and photo- voltaic uses in deep well pumping and irrigation. This source of energy, although available in abundance, would have to await a series of technological breakthroughs before it can be considered for extensive application. (e) Geothermal Energy 1.09 A few geothermal sources have been identified in northern Egypt, in the Gulf of Suez, in the Sinai region and in southwestern Egypt. The Gulf of Suez appears the most promising with two hot springs located in the eastern shore of the Gulf with high flow rates in a tectonically active region. How- ever, their low temperatures (48 degrees centigrade and 75 degrees centigrade) limit the potential application to domestic and commercial requirements. There is no evidence to indicate the existence of a high temperature (greater than 200 degrees centigrade) vapor dominated system, and as such geothermal activity cannot be considered a potential source of energy for power genera- tion. (f) Wind Energy 1.10 Two areas, the Mersa Matruth region on the Mediterranean coast and the Harguda region on the Red Sea, have recorded an average wind speed high enough (around 20 kilometers per hour) to warrant further investigation. Research on the use of wind energy in Egypt is currently directed towards power generation, for lighting purposes and for pump irrigation. (g) Non-Commercial Energy 1.11 Although no data base exists for quantifying the extent of non- commercial energy use in Egypt, it is apparent that this form of energy constitutes a significant proportion of the total energy use, especially in the rural areas. However, Egypt is not well endowed in biomass, with only 2.7% of its territory under permanent or seasonal crops, the rest being desert, or areas covered with dry or extremely arid vegetation. Only a nominal area is under forests and, therefore, crop residues and animal -5- wastes are the main sources of non-commercial energy. According to a recent estimate, this form of energy currently caters to one-fourth of Egypt's total energy requirements. As in other developing countries, the level of utilization of animal and vegetable wastes is very high, although the end use efficiency is low - typically 10% to 15%. Considerable potential exists for upgrading the end use efficiency through improved appliances. II. OIL & GAS SECTOR OIL Background 2.01 Hydrocarbons are the major sources of commercial energy in Egypt and because of limited hydro potential they are likely to be relied upon increasingly to meet Egypt's incremental demand for energy. Although the first oil well was drilled in 1886, oil exploration was not done on a sys- tematic basis until the turn of the century. Commercial production began in 1913, but it was only after 1968 that oil production exceeded 10 million tons. As of March, 1981, 45 commercially exploitable oil and gas fields have been discovered. The 1980 production level is around 30 million tons per annum (600,000 barrels a day); of which about 20% represents the share of foreign partners, 40% is consumed domestically and the balance is exported. The recoverable reserves are currently estimated at around 400 million tons (3 billion barrels). Hydrocarbon Bearing Structures 2.02 There are three main hydrocarbon bearing zones in Egypt: The Gulf of Suez, the Western Desert, and the Nile Delta. Of these, the Gulf of Suez has been the most prolific producer and is considered to hold the highest potential. More than 300 exploratory wells have been drilled in this area, resulting in the delineation of 34 fields. Currently more than 90% of Egypt's oil is produced from the Gulf of Suez. The Western Desert has been extensively surveyed and more than 200 exploratory wells have been drilled. The success ratio of this extensive exploration has, however, been limited. So far only seven commercial discoveries have been made and the recoverable reserves are estimated at 30 million tons. Despite limited success, the hope of making a major strike persists, as giant fields have been discovered in similar structures in neighboring countries. Exploratory drilling has been carried out in the Nile Delta, the Red Sea, and the Nile Basin. In the Nile Delta, while more than 50 exploratory wells have been drilled, no oil has been discovered. However, four gas fields have been discovered of which two (Abu Madhi and Qantara) are considered commercially exploitable. Mobil has recently made two significant discoveries; for oil in the Red Sea near Harguda, and for gas in the offshore Nile Basin at Temsah. From preliminary production tests, oil reserves at Harguda are estimated at 300 million barrels and natural gas reserves from Temsah at 1 TCF. The Nile Delta is considered to be a very promising gas province, warranting further exploration (see para 2.14). : 6 Exploration Policy 2.03 For exploration, development and production of oil, Egypt has consistently followed an 'open-door policy' and almost all exploration and production work undertaken within the country has been through foreign oil companies. The exploration agreements have evolved from the 'concessions' of the pre-1960s to participation agreements which were subsequently converted into production-sharing agreements. Under the current production-sharing agreements, the cost of exploration and development is borne exclusively by foreign contractors and amortized, interest free, over a stipulated time period. After taking these costs into account, (as well as operating costs), Iprofit oil' 1/ is shared between the foreign contractor and EGPC generally in the ratio of 20:80, although in certain areas considered highly prospective, EGPC has negotiated its share of 'profit oil' up to 88%. In order to encourage foreign oil companies, EGPC has recently reduced the period for amortizing development costs from ten years to five years. Furthermore, in the Western Desert, EGPC permits a higher level of excess cost recovery which is subse- quently split on a negotiated basis between EGPC and the foreign company. Exploration Plan 2.04 The exploration policy as pursued by Egypt has served well its objective of maximizing oil production without bearing any risk of explora- tion or needing to divert public resources for financing development. Of the 1980 production level of about 30 million tons per annum, as much as 29 million tons are a result of these production-sharing agreements. Of late, there has been a tremendous resurgence of interest by foreign oil companies and in the last one year 35 new exploration agreements have been entered into with the foreign companies bringing the number of live agreements to 95, covering an area of about 200,000 square kilometers (Annex 2.01). At present the foreign contractors share oil with EGPC on an average, in the ratio of 1:4, and their share in 1980 amounted to an estimated 6 million tons valued at about $1.5 billion. The seismic work, exploratory drilling and development wells (both offshore and onshore), expected to be undertaken by oil companies in various structures, is indicated in the table below. It must be pointed out that the number and amount relating to exploratory wells represent only the contractual minimum under the production-sharing agreements; actual wells drilled (exploration and development) could be higher. 1/ "Profit oil" is the difference between oil productior and "cost oil". "Cost oil" consists of operating cost and amortized cost relating to exploration and development. -7- EGYPT'S EXPLORATION PLAN (In LE$ Million) Actual Estimate Total Nature of Work 1979-1980 1980-1981 1981-1982 1982-1983 1983-1984 1984-1985 80-81 -84-85 No. Value No. Value No. Value No. Value No. Value No. Value No. Value Seismic Work (party months) Offshore 12 9.6 15 12 23 18.4 24 19.2 21 16.8 17 13.6 1 100 80 Onshore 37.26 14.9 85 34 120 46.0 140 56.0 140 56.0 105 42.0 590 234 Exploration Wells Offshore 18 112 37 246 35 238 40 278 39 272 34 236 185 1270 Onshore 24 81 22 68 34 125 40 148 39 145 37 138 172 624 Developmnent Wells Offshore 29 145 24 120 32 157 42 205 42 210 40 200 180 892 Onshore 15 38 17 43.5 17 44.5 20 55 17 46.5 17 47 88 236.5 Total 400.5 523.5 628.9 761.2 746.3 676.6 3336.5 ~~~._.._. ..... , _ .._. " ...... ......____ Current and Anticipated Level of Oil Production 2.05 Production of oil in Egypt increased from 11.5 million tons in 1974 to 20.9 million tons in 1977. The growth in the petroleum sector slowed thereafter, and oil output grew by 17% (24.3 million tons) in 1978 and by an average of 10/% over the next two years to reach a level of 29.5 million tons in 1980. By early 1979, with production reserve ratio increasing, it was the general assessment that Egypt could not sustain this level of oil pro- duction and could conceivably become a net importer of petroleum products by late 1980s. However, developments over the last 12 months have qualitatively altered this assessment; resulting essentially from: (i) success attending oil companies efforts to increase reservoir pressure and, therefore, produc- tion in its peaking fields (July, Ramadan and El-Morgan); (ii) delineation drilling carried out by the Belayim Petroleum Company (Petrobel), Gulf of Suez Petroleum Company (GUPCO) and the General Petroleum Company (GPC) leading to a significant increase in the assessment of the recoverable reserves in the presently producing oil fields; and (iii) most importantly, a series of new, albeit, small discoveries made in the Gulf of Suez by Deminex, Total and Mobil. A list of new discoveries is in Annex 2.02. These developments will arrest production decline till 1985; as a matter of fact, a marginal increase can be expected. Thereafter, the production level would depend upon the rate of new discoveries but given the large investment program for exploration (over $600 million per year) it appears reasonable to assume that new discoveries will continue. However, large discoveries in the Gulf of Suez appears unlikely although the possibility of major finds in the Sinai, Red Sea, or the Western Desert area cannot be excluded. On the basis of the existing data, estimates of oil production up to 1985-86 are as under. FORECAST OF PETROLEUM PRODUCTION 1/ (In Million Tons) Actual Estimate Name of Company 1977 1980 1980/81 1981/82 1982/83 1983/84 1984/85 1985/86 GUPCO (GOS) 14.4 19.9 20.7 20.8 18.0 16.0 14.4 13.4 GUPCO (WD) 0.9 0.9 1.0 1.1 1.0 0.7 0.4 0.3 RUDUCO - - 0.5 0.3 0.3 0.2 0.2 0.2 TORSINA - 0.8 0.9 1.25 1.5 1.7 1.7 1.5 PETROBEL 3.5 5.3 5.25 5.9 5.8 5.6 5.5 6.0 GPC 1.5 1.3 1.1 1.1 1.2 1.4 1.5 1.5 WEPCO 0.6 1.1 0.3 0.25 0.2 0.1 0.5 - EPEDCO - 0.1 0.2 0.2 0.3 0.4 0.5 0.6 SUCO - 0.1 - 0.05 1.75 3.0 4.1 3.7 TOTAL - - 0.05 0.3 0.5 0.5 0.5 AGYPTCO - - - 0.05 0.1 0.1 0.1 0.1 New Discoveries - - - - 2.0 4.5 6.0 7.0 Total 20.90 29.50 29.95 31.05 32.45 34.20 35.40 34.80 Demand for Petroleum Products 2.06 Consumption of petroleum products has been rising rapidly and, inclusive of natural gas, is estimated at 13.2 million tons for 1980. This is against a consumption of 9.1 million tons in 1977 and 6.7 million tons in 1974. The overall annual growth rate has been of the order of 12%; with fuel oil/natural gas, gasoline, and gas oil recording the sharpest in- crease. At least over the next five years the growth rate is not anticipated to decelerate significantly. This results partly from the rapidly growing thermal power generation which is projected to rise from 8,600 GWh in 1980 to 23,000 GWh in 1985. Estimates of future consumption are as below. 1/ Includes production from the oil field regained from Israel, which is currently producing 20,000 bbl/day, 1 million tons per annum. EGYPT'S CONSUMPTION OF PETROLEUM PRODUCTS 1/ (in thousand tons) Annual Annual Growth Growth Rate Rate Product 1974 1977 1980 % 1981-82 1983-84 1985-86 % LPG 159 247 385 15.9 500 700 850 16.0 Gasoline 556 883 1,158 13.0 1,400 1,750 2,200 12.0 Naptha 24 18 52 13.7 50 50 60 - Kerosene 1,109 1,363 1,502 5.2 1,600 1,780 2,050 6.5 Turbine Fuel 119 101 280 15.3 450 525 650 10.0 Gas Oil 1,055 1,507 2,275 ) ) ) ) ) Diesel Oil 168 150 114 ) 11.8 ) 2,900 ) 3,600 ) 4,600 ) 12.0 Fuel Oil & NG Power 849 1,529 2,650 20.9 3,021 4,077 5,700 16.6 Others 2,471 3,031 4,390 10.0 4,829 5,843 7,000 10.0 Asphalt 64 142 210 21.9 220 320 400 16.0 Lube Oils 93 129 142 7.3 160 220 290 15.0 Total 6,667 9,100 13,158 12.0 15,130 18,865 23,800 12.0 Natural Gas (Fuel Oil Equivalent) 1,858 2,700 5,160 7,250 Demand for Liquid Hydrocarbons 11,300 12,430 13,705 16,550 2.07 The projected demand for hydrocarbons by 1985-86 is about 24 million tons. A qualitative change in the consumption pattern is, however, anticipated with natural gas replacing fuel oil. In the event Egypt takes measures to develop its known gas fields and the concomitant infrastructure, it would be possible to increase the consumption of natural gas from the present level of 200 MMcf/d (1.85 million toe) to 800 MMcf/d (7.25 million toe) by 1985-86 (see para. 2.19). This could contain the demand for liquid hydrocarbons to about 17 million tons. 1/ Consultants (PEIDA) commissioned to undertake a pricing study under the Gulf of Suez Project (Loan 1732-EGT) have recently finalized their study. The consultants used an elaborate model for projecting future demand for petroleum products. However, up to 1985-86 their results are not significantly different from the above projections. The consultants estimate of the consumption level for 1985 is 23.2 million tons against the above estimate of 23.8 million tons for 1985-86. - 10 - Refining, Transportation and Marketing 2.08 While for exploration and development Egypt has actively sought foreign assistance and participation, refining, transportation, and marketing of oil products is undertaken almost exclusively by state-owned entities. Refining Capacity 2.09 The first refinery in Egypt was built in 1913. Currently Egypt has 6 refineries located in Suez, Alexandria, El Ameria, Mastrot and Tanta. With the completion of the debottlenecking and balancing program, the refining capacity is about 16 million tons. The current refining throughput is of the order of 13 million tons. The present and anticipated product yield from Egypt's refineries is indicated in the table below. EGYPT'S PRODUCT YIELD OF REFINERIES (in thousand tons) Products 1975 1978 1979 1980 1981-82 1982-83 1983-84 1984-85 LPG 1/ 49 54 105 143 208 220 250 322 Gasoline/Naphtha 1,331 1,553 1,771 1,950 2,180 2,400 2,400 2,670 Kerosene 1,142 1,400 1,454 1,563 1,800 1,970 1,930 2,216 Turbine Fuel 152 220 183 160 300 340 390 500 Gas Oil 1,607 1,788 2,312 2,519 2,750 2,960 3,060 3,620 Fuel Oil 4,165 5,582 5,527 6,416 7,300 8,400 8,900 8,740 Asphalt 118. 235 202 273 220 270 300 310 Lube Oils 31 80 67 72 90 145 210 210 Others 19 69 26 35 30 33 39 40 Total 8,614 10,981 11,647 13,131 14,878 16,738 17,479 18,628 2.10 It can be seen from the table that the proportion of low value heavy ends like fuel oil and asphalt is fairly high (50%) while the output of high value middle distillates is relatively low (35%). With increased use of natural gas as feedstock for fertilizers and as replacement for fuel oil, there will be a growing imbalance between the consumption pattern and the product yield, requiring Egypt to export low value fuel oil and import high value gas oil. The refining program needs to be reviewed and optimized in the light of the anticipated consumption pattern and Egypt's objectives of replacing up to 7 million tons of liquid hydrocarbon (essentially fuel oil) by natural gas. Instead of merely expanding the refining capacity, as is currently being planned, Egypt should consider the possibility of investing in secondary processing. 1/ Includes LPG stripped from natural gas. - 11 - Transportation and Marketing 2.11 For internal transportation of petroleum products, EGPC uses a variety of modes including products pipelines, railways, river barges and road transportation. In 1980, it is estimated that 9 million tons of products were moved by pipelines, 7 million tons through trucks, and about a million tons through railroad and river barges. A pipeline network to carry 8 million tons of crude from Ras Shukeir to Suez is nearing completion. From Suez to Cairo, two pipelines having a capacity of 5 million tons already exist. Additionally, a product pipeline from Helwan to Tebbin with a capacity of 1.5 million tons is used for transporting products to Upper Egypt. Two other product pipelines, each having a capacity of 0.75 million tons, link Cairo to Mansura and Zagazig in Upper Egypt. In addition there is the Sumed pipeline consisting of two 42-inch pipelines and having a capacity of 80 million tons of crude which connects Ain El Soukhna on the Gulf of Suez to Sidikrier on the Mediterranean, and is being used for transporting Gulf crude to Europe. This 320-mile pipeline is owned jointly by Egypt (50%), Kuwait (15%), Saudi Arabia (15%), UAE (15%) and Qatar (5%). 2.12 Marketing of petroleum products is largely undertaken by two subsidiaries of EGPC, namely the Cooperative Petroleum Company and the Misr Petroleum Company. Mobil and Esso are also marketing products, but share less than 25% of the market. NATURAL GAS 2.13 Egypt has a large and relatively unexploited reserve of natural gas. Its currently recoverable gas reserves are estimated at about 9.75 TCF equiva- lent to 225 million tons of oil, that is, almost half of Egypt's recoverable oil reserves. The Gas Utilization Study, recently completed by Consultants (PEIDA) estimate the probable gas reserves at 15 TCF. This estimate too could prove to be conservative as exploration has just commenced in the gas prone Nile Delta and the Northern Sinai Province. Egypt also is a substantial consumer of fuel oil and its consumption is anticipated to grow significantly over the next ten years. By developing natural gas fields and the ancillary infrastructural facilities, natural gas could replace liquid hydrocarbons and become a major source of energy during the eighties. Further, by optimizing the refinery program so as to take note of the fractions (essentially light and heavy ends) which the natural gas would replace, Egypt could maximize its foreign exchange earnings through the export of oil. Non-Associated Gas 2.14 Non-associated gas on a commercially exploitable scale has been discovered over the last ten years in the Western Desert (Abu Gharadig and T-Structure), in the Gulf of Suez (Amal) and in the Nile Delta (Abu Madhi and Abu Qir). Egypt has so far developed three non-associated gas fields with a cumulative supply potential of 300 MMcf/d. Geologically, the Nile Delta is considered the most promising gas province; an assumption which has been reinforced by a large offshore discovery at Temsah made - 12 - recently by Mobil. The proven recoverable gas reserves of non-associated gas are presently estimated at 7.75 TCF. Associated Gas 2.15 The current production level of associated gas in Egypt is around 140 MMcf/d and, except for a nominal amount (20 MMcf/d) which is being used for meeting oil field needs, the rest is being flared. Most of the associated gas comes from the oil fields in the Gulf of Suez. The Bank, through Loan 1732-EGT, is financing a project for gathering, processing, and transporting this gas to Suez and Cairo. Recent discoveries made by GUPCO, Deminex, Mobil and Petrobel will add significantly to the availability of associated gas. Currently, cumulative reserves of associated gas in the Gulf of Suez area are being estimated at 2 TCF. As the new discoveries are developed and after taking into account gas required for infield use (40 MMcf/d), associated gas to the extent of 200 MMcf/d would become available. Existing facilities are inadequate for gathering and transporting this gas. So as to avoid flaring this gas, action to create gathering facilities and to augment the existing processing facilities and pipeline, would need to be initiated immediately. Gas Fields of Egypt Associated Gas Non Associated Gas Total Gulf of Abu Abu Abu Abu New Discoveries 1/ Name of Field Suez Gharadig Madhi Qir Qir (N) Qantara Amal T Structure Temsah Recoverable Reserves (TCF) 2.0 0.6 1.9 1.9 1.0 0.35 0.5 0.5 1.0 9.75 Production 1980 (MMcf/d) - 87.0 67 50.0 - - - - - 204.0 Exploration Policy 2.16 Egypt has not been successful in eliciting the interest of the foreign oil companies in areas known to hold potential for gas. In fact, whenever a foreign oil company in search of oil discovered gas in commercial quantity, the concession was relinquished and the gas field was developed by EGPC, the national oil company. This was on account of the fact that export of gas through liquefaction was not attractive, except for a very large gas field, and the domestic market was neither well developed nor financially rewarding. Rapidly rising prices of liquid hydrocarbons over the past few years have made the export of gas a more remunerative proposition. Further, as the domestic absorptive capacity for natural gas increases, it 1/ Extremely tentative estimates and will need to be firmed up through delineation drilling. - 13 - is in Egypt's interest to rapidly identify and develop new gas reserves. In order to attract foreign oil companies to explore for gas, EGPC is currently evolving a new package of incentives. It will permit the export of gas once the national reserve requirement of 12 TCF has been established. Further, under this package foreign companies which assist in the establishment of commercial discoveries will be reimbursed for the cost of exploration; com- panies which assist in the establishment of the reserves beyond 0.25 TCF will, in addition, be paid commercial interest on its cost for the period between the establishment of the reserves and the development of the gas discovery. For discoveries above a stipulated level the companies would receive an additional bonus which would be as negotiated in each production sharing contract. Once the national gas reserves of 12 TCF have been established, the oil companies would be permitted to export gas in liquified form. However, in such an export arrangement, the oil companies which helped in the buildup of reserves up to 12 TCF, would have a share in proportion to the magnitude of their respective discoveries. Foreign companies have not been excluded from the domestic market and can develop the discovered gas fields for internal use on mutually agreed upon terms and conditions. While a large number of companies have evinced interest in the new package of incentives, no agreement has so far been concluded. Demand and Supply of Natural Gas 2.17 Over the past few years Egypt has made significant efforts to develop its gas potential. Presently the production capacity of natural gas, approximately 300 MMcf/d, is greater than the current demand of 200 MMcf/d. This situation is anticipated to reverse rapidly and by 1985 the potential gas demand is expected to be far in excess of potential gas supply, especially in the areas of Alexandria and Cairo. 2.18 If efforts are not initiated to augment gas supply in Alexandria and Cairo, by 1985 Egypt would have to divert annually about 4.5 million tons of liquid hydrocarbons valued at US$1 billion in current prices, from the export to the domestic market. It is with the objective of attenuating this shortage that the Bank on December 9, 1980, approved a loan of US$25 million for assisting Egypt in exploring for hydrocarbons in the Abu Gharadig area of the Western Desert. Similarly, the proposed Abu Qir offshore gas development project aims at bridging the anticipated shortfalls in gas supply in the Alexandria area to the extent of about 100 MMcf/d. Even after the development of Abu Qir, potential demand will exceed supply by a significant margin. Steps would, therefore, need to be initiated almost simultaneously to develop fully the Abu Madhi gas field and the new discovery in Abu Gharadig. 2.19 The table overleaf indicates the demand forecast for gas in Alexandria, Cairo, Suez and the Delta areas against possible supplies based on the assumption that timely and adequate investment is made on these gas fields. Detailed market projections for Alexandria, Cairo, Suez and the Delta area are in Annexes 2.03, 2.04 and 2.05. - 14 - EGYPT DEMAND AND SUPPLY PROJECTIONS FOR NATURAL GAS ----------- Million Cubic Feet Per Day -------… - ---------------Estimate----------------- 1980 81-82 82-83 83-84 84-85 85-86 86-87 Alexandria Abu Qir (Phase I) 100 100 100 100 100 100 100 Abu Qir (Phase II) - - - 50 100 100 100 Abu Qir (North) - -- - - - 100 Total Potential Supply 100 100 100 150 200 200 300 Total Potential Demand 50 140 215 265 370 380 390 Short Fall (50) 40 115 115 170 180 90 Cairo Abu Gharadig 87 87 100 100 100 100 100 T-Structure - - - 50 50 50 50 Total Potential Supply 87 87 100 150 150 150 150 Total Potential Demand 75 160 200 200 230 300 350 Short Fall (12) 73 100 50 80 150 200 Suez AG from Gulf of Suez - - 50 110 120 120 120 New Discoveries - - - - 30 80 80 Total Potential Supply 13 1/ 13 1/ 50 110 150 200 200 Total Potential Demand 13 13 50 110 200 230 230 Short Fall - - - - 50 30 30 Delta Area Abu Madhi 100 100 100 100 100 100 100 Abu Madhi (Phase II) - - - 50 100 100 100 Qantara - - _ - 50 50 50 Total Potential Supply 100 100 100 150 250 250 250 Total Potential Demand 67 100 115 115 115 115 115 Short Fall 33 - 15 (35) (135) (135) (135) Total Potential Supply 2/ 300 300 350 560 750 800 900 Total Potential Demand 205 413 580 690 915 1025 1085 Total Shortfall (95) 113 230 130 165 225 185 1/ Supplied from Abu Gharadig field. T/ Assumes that it would be feasible to shift gas from surplus field to deficit markets. - 15 - 2.20 In the event the potential of the known gas fields is fully developed, Egypt would be able to replace 7 million tons of liquid hydro- carbons ($1.7 billion, present prices) by 1985 and 8.5 million tons by 1987. Gas Pipelines 2 21 Presently Cairo is linked with the Abu Gharadig gas field through a 24-inch gas pipeline, 370 km in length. Similarly a 57 km pipeline connects Abu Qir gas field with the major consumers in the Alexandria area, namely, the Abu Qir fertilizer plant and the power stations in Kafr El-Dawar and Damanhur. Separately the Abu Madhi gas field is linked to the consumers in Talkha and El Mahala. Under the Gulf of Suez Project, a 16-inch pipeline having a maximum capacity of 120 MMcf/d, is being constructed to link Ras Sukheir with Suez. An existing 10-inch white product pipeline can transport gas up to 30 MMcf/d from Suez to Cairo. The present system essentially links individual gas fields to specific markets that are not interlinked with one another. Not only is this network inadequate for handling the projected increase in sup- plies, it is incapable of transporting surplus from one field to meet the deficits in other markets. Further, in the absence of interfield linkages, gas-based industries would become extremely vulnerable to production problems in individual gas fields. In order to protect the industry against this risk, economic justification and phasing for establishing a national grid for gas pipelines and load dispatch stations along with necessary telecontrol and telemetry facilities would need to be studied (See para. 2.32). Foreign Exchange Earnings, Pricing and Fiscal Contribution of the Sector Foreign Exchange Earnings 2.22 Egypt-s export earnings from oil rose from $0.7 billion in 1977 to $1.8 billion in 1979 and were of the order of $3 billion in 1980, con- stituting 67% of merchandise exports. Impressive increases in the production of oil coupled with rapidly rising prices has been responsible for such a significant jump in foreign exchange earnings. On account of rising domestic consumption, growth of net exports in volume terms has slowed since 1978, but has been more than offset by the sharp increase in prices. Further, the minimum cost recovery factor in almost all production-sharing agreements is stipulated at 20% and in case the cost of producing oil falls below this level, the difference reverts to EGPC. On account of this provision, the rapidly rising price of oil since 1979 has resulted in a higher proportion of the cost recovery crude reverting back to EGPC. - 16 - PETROLEUM EXPORTS AND IMPORTS (Q = Quantity in Million Tons) (V Value in US$ Millions) 1977 1979 1980-81 Q V Q V Q V Total Petroleum Exports 9.3 1,012 12.8 2,695 18.0 4,510 Egypt 6.0 720 8.4 1,770 12.1 3,070 Foreign Oil Companies 3.3 292 4.4 925 5.9 1,440 Petroleum Imports 0.3 135 0.5 243 0.7 340 Net Transfer Abroad by Foreign Oil Companies 219 893 1,340 Net Foreign Exchange Earnings 658 1,559 2,830 Prices 2.23 Domestic prices of refined products in Egypt are established by a governmental decree and, but for a few adjustments made last year, have remained virtually unaltered over the last twenty years. This has resulted in a significant and a growing gap between domestic and international prices. The table below indicates the domestic product prices and the present international prices. PETROLEUM PRODUCT PRICES Product Domestic Prices 1/ World Prices 2/ Domestic Prices L.E./Ton US$/Ton US$/Ton (As % of World Prices) LPG 52 62 400 (cif) 16 Premium Gasoline 180 214 345 (fob) 62 Regular Gasoline 151 180 320 (fob) 56 Kerosene 39 46 300 (fob) 15 Gas Oil 36 43 300 (cif) 14 Diesel Oil 30 36 300 (cif) 20 Fuel Oil 7.5 9 160 (fob) 6 Natural Gas 7.5 9 160 (fob) 6 (0.17/Mcf) (0.20/Mcf) (4.0/Mcf) 2.24 As Egypt trades in all petroleum products, world prices (fob) represent border prices for Egypt, except for gas oil and LPG where cif prices have to be taken since Egypt has to import these products to supplement its domestic production. Natural gas is not traded, but to the extent it is used 1/ Exchange rate of LE 0.84 = US$1. 2/ Prices as reported in Italy in December 1981. - 17 - in the domestic economy, it releases liquid hydrocarbons, essentially fuel oil for exports. At least till such time as the supply of gas does not exceed demand, the opportunity cost of gas can be taken as the fob export price of fuel oil. The current weighted domestic price of petroleum products is about 14% of its opportunity cost. 2.25 Currently two categories of subsidies can be identified in the petroleum pricing structure. The first is the financial subsidy which results from petroleum products being sold at less than the domestic cost of production (fuel oil, natural gas, kerosene and gas oil) or below the cost of imports (LPG). The second is the economic subsidy which represents the difference between the domestic price and the price at which the product can be exported, but does not impose on the state a direct financial burden. The financial subsidy for 1980 has been estimated at about $250 million and the economic subsidy at $2,000 million. Further, unless deliberate measures are taken to increase domestic prices, the magnitude of the financial and economic subsidy is likely to grow even larger. (For fuller discussion please see para. 2.35). Fiscal Contribution of the Sector 2.26 In 1980 Egypt secured a netback of about US$4.5 per barrel from domestic sales. This is against an average price of $35 per barrel which it received from the export of oil. The value of aggregate gross output, and the fiscal contribution of the petroleum sector is extremely sensitive to the relative weights of domestic consumption and export in overall output. Despite relatively low domestic prices and rapidly growing domestic consump- tion, the fiscal contribution of the petroleum sector is significant and growing rapidly; and as a proportion of the total public revenues, it grew from 10% (LE 158 million) in 1975 to 35% (LE 1460 million) in 1980. Fiscal contribution from the sector in 1980-81 is estimated at LE 2200 million. Investment Plan for the Petroleum Sector 2.27 An investment of about US$7.3 billion is planned for the sector during 1980/81 - 1984/85 period. The major part of this investment ($4.8 billion) would be for exploration and development, and the balance would be for petrochemicals, refining, processing, marketing and distribution. A breakdown of the planned investment is presented below. It should be noted that the expenditure planned for production and exploration will largely dependent upon the success of the exploratory efforts. - 18 - INVESTMENT PLAN FOR THE PETROLEUM SECTOR (1980/81 - 84/85) (in Million Egyptian Pounds) Foreign Total Exchange Component Production and Exploration Public Investment EGPC 311 219 GPC 309 272 Foreign Contractors Exploration 1800 1440 Production and Development 916 730 Subtotal 3336 2661 Refining and Processing EGPC (Petrochemicals) 505 353 Alexandria Petroleum Co. 126 91 Suez Oil Processing Co. 89 62 El Nasr Petroleum Co. 247 169 Subtotal 967 675 Marketing and Distribution EGPC 414 270 Misr Petroleum Co. 54 29 Coop. Petroleum Co. 56 31 Petroleum Pipelines Co. 18 8 Mobil 1 1 Esso 1 1 Petrogas 227 137 Subtotal 771 477 Total Investment 5074 (US$7306) 3813 (US$5490) Public Investment 2355 (US$3391) 1641 (US$2362) Private Investment 2719 (US$3915) 2172 (US$3128) - 19 - 2.28 According to the current plan, private oil companies would be responsible for undertaking the major proportion of the investment in explora- tion and development (81%). Investments in refining, processing, marketing and distribution would be undertaken almost exclusively by public sector companies. However, the amounts which have been slated for public expenditures in development and exploration appear largely insufficient to sustain the required program for the development of gas reserves. In fact, the projects currently covered by the investment plan do not include the develoment of Abu Madhi, as well as the development of Abu Qir North and Abu Qir Phase 11 (see para. 2.31). The total cost of a comprehensive program for gas develop- ment is estimated at $1 billion, which is more than twice the requirements taken into account in the five-year plan for EGPC and GPC development/explora- tion efforts related to gas. The public investment program proposed for FY81-FY83 is in Annex 2.06. Sector Issues and the Role of the Bank Bank Group Participation in the Sector 2.29 The proposed loan would be the fourth loan for Egypt-s hydrocarbon sector. The first loan was made to EGPC for the Gulf of Suez Project (Loan 1732-EGT) in June 1979. The objective of this Loan was to gather, process, and transport associated gas, which would otherwise be flared, from the Gulf of Suez oil fields to Suez and Cairo. The Project also included financing for several important sector studies covering prices of petroleum products, oil/gas reserve assessment and the optimal utilization of gas. The project is in an advanced stage of implementation, and its first phase is likely to be commissioned by April 1982 (four months behind the original schedule). For the second project, an IDA credit of $50 million (Credit 1024-EGT) was made in May 1980 to support domestic gas distribution project in four Cairo suburbs. The objective of the project was to upgrade the use of natural gas from being a replacement for fuel oil to substitute for high value products, namely, LPG and gas oil. This project is under implementation, the high pressure pipeline along with the distribution network for one suburb (Helwan) has been completed, the distribution network for the second suburb (Heliopolis) is under construction and 13,000 households have been converted to gas. The third loan of $25 million was approved in December 1980. The objective of this loan was to support exploration in eight identified struc- tures in the Western Desert. The second and the third exploratory well drilled in the T and Y structures have resulted in two separate discoveries. Natural Gas has been discovered in the T structure and preliminary estimates place the recoverable reserves at 0.4 TCF. Oil has been discovered in the Y structure; further tests on the existing well and additional delineation drilling would need to be undertaken to determine the size of the discovery. The progress of all Bank Group financed projects in the sector is satisfactory; demonstrating EGPC's capacity to implement projects with speed and competence. Sector Issues 2.30 The search for new sources of primary energy and its development continues to be a critical aspect of Egypt's developmental effort. The - 20 - Bank through its lending operations has attempted to support these efforts while encouraging efficient use through an appropriate pricing policy. Our involvement in the sector over the last two years has provided us with an opportunity to review sector issues; a few of the important ones are considered below. (i) Development of Natural Gas Resources 2.31 To maintain its status as an exporter of oil during the eighties, Egypt would need to rapidly develop its known gas reserves and also increase the economy's capability to use gas. Egypt has the reserves to step up gas use from 2 million toe in 1980 to seven million toe by 1985, and possibly 10 million toe by 1990. To do so would require early and substantial investment in the development of gas reserves and assiduous efforts to increase the absorptive capacity of the economy through the development of an appropriate infrastructure, specifically: (a) augmenting the processing and gathering capacity for associated gas from the Gulf of Suez to potential users. The capacity created under the Gulf of Suez project is inadequate to transport associated gas from the new Gulf discoveries. The capacity of the Ras Shukeir-Suez pipeline would have to be increased through compression from 80 MMcf/d to 120 MMcf/d. Furthermore, after the gathering and processing facilities have been completed for the new discoveries, the capability of this pipeline would have to be stepped up further, possibly through looping, to 200 MMcf/d. Alternatively, the option of linking Cairo directly with Ras Shukeir would have to be considered. A feasibility study for this purpose is proposed to be financed under the project, which would be completed by March 31, 1983 and its findings reviewed with the Bank; (b) in view of the latest reservoir estimate of the Abu Madhi gas field, its production potential can be doubled. Development plan which includes means for transferring surplus gas to deficit areas would need to be prepared, funded and implemented; (c) separately, the Qantara gas field should be developed after the problem of removing and transporting condensates has been studied and resolved; (d) new discoveries need to be rapidly delineated and developed. Abu Qir (North) should be developed as soon as delineation is completed (1982), because even after taking account of the gas becoming available under Abu Qir Phase II (proposed project), the. demand in Alexandria will continue to be in excess of supply. To meet the requirements of Cairo, the new discovery in the Western Desert should be accorded priority; the existing infrastructure including a pipeline with excess capacity would assist in the rapid deployment of this gas; - 21 - (e) even after the above gas fields have been fully developed, the demand for gas would be in excess of supply, a gap which would need to be bridged by diverting liquid hydrocarbons from the export to the domestic market. So as to encourage foreign oil companies to explore in areas known to hold potential, largely for gas, EGPC has prepared a fresh package of incentives. In the event these measures fail to secure the desired response, EGPC may need to undertake exploration through its subsidiaries, especially in the Nile Delta, presently considered the most promising gas province. (ii) Natural Gas Pipeline Grid 2.32 Gas demand and supply projections indicate that Alexandria and Cairo would be deficit in gas, while Suez and the Delta area would be surplus in gas. The gas network would need to be designed to transfer gas from surplus areas to deficit areas. Furthermore, to reduce the vulnerability of gas-based industries to production difficulties in individual gas fields, the economic viability and phasing of a pipeline grid which would make it possible to transfer gas from one field to the other would need to be evaluated. The proposed loan contains financial provisions to undertake such a study. The study is expected to be completed by March 31, 1983 and EGPC will review the findings of the study with the Bank. (iii) Gas System for Upper Egypt 2.33 Upper Egypt is a significant user of energy. The requirement of fuel oil for power, sugar and cement plants is anticipated to grow to 1 million tons by 1985. In addition the Kima fertilizer plant, (which relies on the obsolescent technology of manufacturing fertilizer through electrolysis) consumes 15% of the total power currently generated in Egypt and represents an uneconomic use of energy. Provision of natural gas for Upper Egypt would not only replace about 1 million tons of oil but also release over 220 MW of power for lower Egypt. The loan contains financial provisions to undertake a study to examine the feasibility of setting up a gas system for upper Egypt by using surplus gas from the Gulf of Suez and from the newly discovered oil/gas fields in the Red Sea. EGPC has agreed to complete this study by March 31, 1983 and review the findings with the Bank. (iv) Commercial Borrowings 2.34 The investment requirement for developing gas resources and establish- ing a gas pipeline grid would require resources in excess of $1 billion over the next four years. The present investment plan does not contain provisions for developing natural gas resources in this magnitude. Similarly there are other areas, including secondary processing and petrochemicals, where invest- ment has not been made for want of resources. So far, EGPC has refrained from international commercial borrowings to finance its investment requirements. It is felt that financing such development within Egypt could prove attractive to the international banking community, more so as it would have the direct effect of increasing EGPC's foreign exchange earnings by augmenting its export capability. However, this would require familiarization: (a) of the banking community with EGPC's existing and proposed programs; and (b) of EGPC with - 22 - financing sources and techniques available. During negotiations possibilities in this regard were discussed with EGPC. As a first step EGPC has asked an international commercial bank to identify, negotiate and finalize a package of credits for the proposed and possibly other projects. (v) Pricing Policy and Efficiency of Energy Use 2.35 Movement towards an appropriate energy pricing policy has been the principal ingredient of the Bank's policy dialogue in this sector. In order to assist Egypt in this area, a pricing study was financed under the Gulf of Suez project (Loan No. 1732-EGT) which has since been completed. This study, inter alia, aimed at evaluating the effect of discrete increases in the price of petroleum products on various goods and services, evolving policy options and spelling out the fiscal and other implications of the proposed measures and their impact on demand, consumption and income distribution. This study along with the Gas Utilization Study has considerably enhanced our ability to evaluate and formulate specific policy recommendations. The major findings of the study are: (a) Current energy price levels and related energy consumption growth are unsustainable without impairing Egypt's growth objectives. The model used by the consultants treats economic growth as exogenous, and uses as its assumption the Bank's projections from its DRM model for Egypt. If energy prices and consumption paths are not changed, achieving the target GNP growth rate would mean that by 1990 Egypt's balance of payments deficit would be over $8 billion and its budgetary deficit would be in excess of $7 billion. The country would become a net oil importer by 1995. To reverse these gloomy projections will require a comprehensive energy policy and investment strategy both for expanded energy production and for increasing the efificiency of energy use. (b) The inflationary impact of adjusting energy prices to attain world price levels by 1990, implying an average adjustment in these prices in the order of 35-45% p.a., is significant in that it would add a 6% p.a. to the wholesale price index and about a 3.3% p.a. to the consumer price index. The inflationary impact is markedly different for different major users of energy. Lower income groups in the population, and particularly those in rural areas, would suffer only margin- ally while the CPI for the urban upper income groups would increase by something less than 4.0% p.a., assuming all price increases were fully passed on. Those groups which are most seriously affected are basically a few large industrial users of fuel oil and gas, most of which are in the public sector. Moreover, in industry the 6% p.a. average impact is heavily influenced by four major energy using industries (aluminum, cement, fertilizer and electricity), where the impacts range between 7% and 17% p.a. - 23 - (c) There are major inefficiencies in energy use by the largest consumers in Egypt. The scope for energy savings is large; but the studies bring out an important qualification to this finding. Increases in energy prices are neither a necessary nor a sufficient condition to improve the energy efficiency of these large users. They are nearly all public sector firms, many are chronic loss-makers, in some cases their technology is outmoded, they are all subject to price controls on their output; in short, they are unlikely (indeed, unable) to be very responsive even to major changes in the prices of their energy inputs. While in some cases, major investments in energy technology or retrofitting for fuel substitution would be justified, it may be more economic to phase out production at certain plants. A cost benefit analysis needs to be initiated to assess the viability of the current operation of the Naq Hammadi aluminium plant, and the benefits of a major investment which would permit the Kima fertilizer complex to switch its feedstock from power to natural gas (see para. 2.33). Both these units currently consume almost 30% of the power generated in Egypt. They pay less than one- fifth of the long-run marginal cost of power, yet operate at a loss. (d) As a long term objective, Egypt should endeavour to eliminate the "economic subsidy" on petroleum products by increasing the weighted average price of all petroleum products to the weighted average of their border prices. Within this weighted average, there may be justification for cross-subsidies based on Egypt's broader socioeconomic objectives. However, a necessary con- dition for attaining this objective is restructuring the prices of a wide range of products within the Egyptian economy. Special attention would need to be paid to tariffs/controlled prices relating to power, cement, steel and fertilizer - major consumers of hydrocarbons which by government directives are obliged to price their products at a fraction of the long run marginal cost. However, it would not do to underestimate the complexities involved in such a fundamental restructuring or the social, economic and political costs it would entail. 2.36 Based on the results of the above studies, Bank proposes to undertake a wide ranging discussion with GOE which would focus not only on the question of petroleum prices, but on the overall issue of efficient energy use and how best to utilize and develop Egypt's limited hydrocarbon resources for support- ing its long-term development objectives. Under the proposed project GOE has agreed to increase the price of gas from the project area from the present level to a level which would recover for EGPC the marginal cost of production, and an allowance to account for the depletion of the field. Based on the current estimates, the cost of production works out to $0.83/Mcf and the depletion allowance is estimated at $0.27/Mcf in December 1981 prices (see para. 6.09 for assumptions relating to the depletion allowance). The resulting price of $1.1/Mcf is still significantly below the opportunity cost of gas to Egypt, as represented by the border price of fuel oil replaced ($4.0/Mcf) but would nonetheless represent significant increase over the existing level of $0.20/Mcf. Further, GOE will review their plans to increase the average national price of gas and fuel oil to the level agreed to for Abu Qir gas with the Bank. - 24 - 2.37 An average revenue of $1.10/Mcf would ensure the independent financial viability of the project, as measured by its ability to cover operating costs and debt services, to achieve satisfactory rates of return on revalued net assets after the initial construction period, and to finance future investment in the project area. In order to avoid uneconomic fuel substitution and/or severe financial hardship for certain gas-using enterprises, the average level of $1.10 may be achieved through a differential tariff structure which would vary according to end-use. During negotiations EGPC agreed to undertake a study to evolve an appropriate tariff structure. It further agreed to complete this study by July 31, 1983 and review its findings with the Bank by December 31, 1983, and implement an agreed tariff structure by July 1, 1984. III. THE BENEFICIARY History 3.01 To oversee all matters relating to the petroleum industry, the Egyptian General Petroleum Company was created in 1956. With the general restructuring of the public sector in 1962, this authority was converted into the Egyptian General Petroleum Organization (EGPO) with almost similar functions. With the promulgation of Law 20 of 1976, EGPO was converted into the Egyptian General Petroleum Corporation (EGPC), the borrower of the pro- posed loan. The Ministry of Petroleum, which was created in 1973, however acts as a link between EGPC and other government bodies and the primary responsibility of managing and operating the petroleum sector rests with EGPC. Statutory Functions 3.02 The main functions of EGPC under Law 20 are to: - draw up a general policy for granting concessions, negotiat- ing and preparing concession agreements for approval of the government; - supervise exploration and exploitation activities of the oil companies engaged in the search of oil and production of oil and/or natural gas; - plan, coordinate and control the activities of various affiliates in the field of production, refining, trans- portation and distribution of petroleum products for the domestic market; undertake the export of crude oil and petroleum products and effect similar imports for balancing domestic requirements. - 25 - - determine, in conjunction with other competent authorities, the pricing of petroleum products; 1/ and supervise the the operation and management of all subsidiary companies. Capital Structure 3.03 EGPC's capital of LE 300 million is invested in the capital of joint venture companies and in companies established for participation in oil production with foreign partners. Funds available to EGPC for its operations, consist of its share in the net profits of all its affiliates in the petroleum sector, its share in the net profit of the joint venture companies and profits arising out of supervision and administrative fees. In addition, it secures funds from the government as loans. EGPC, as a distinct corporate entity, can and has borrowed from external financial agencies, including the Bank. Organization and Management 3.04 EGPC is governed by a Board consisting of the chairman and five vice-chairmen who are in charge of exploration and production, planning and projects, operations, administration, and financial and economic affairs. Separately, through a ministerial decree, three chairmen of subsidiary companies (GPC, GUPCO and the Petroleum Cooperative Society) along with the General Manager of the Egyptian Petroleum Research Institute have been appointed to the Board of EGPC (Annex 3.01). 3.05 In relation to other public sector undertakings in Egypt, EGPC has been vested with considerable autonomy. Within the framework of general policies set by the Supreme Petroleum Council and stipulated in the Company's statutes, its Board is competent to issue any decree it deems suitable, any governmental regulation or system to the contrary, notwithstanding. It is, therefore, competent to establish its own internal regulations for financial, administrative and technical management, and also evolve its own norms regarding conditions of employment, remuneration, etc. EGPC is, however, obliged to consider policy directives issued by and otherwise function under the guidance of the Supreme Petroleum Council which is presided over by the Minister of Petroleum and for which EGPC functions as a secretariat. Furthermore, all resolutions of the Board have to be approved by the Minister of Petroleum who can, at his discretion, amend or cancel any such resolution. 3.06 EGPC's management at the senior level is competent and experienced in various aspects of the oil and gas industry. It has, over the last decade, expanded the marketing organization to meet growing demand, set up and rehab- ilitated a number of refineries, laid an extensive network of crude, petroleum products and gas pipelines; facilities which it operates with competence. It has created within its organization a specialized group which has successfully 1/ While Law 20 vests with EGPC the authority to determine prices, in effect prices are fixed through governmental decree in which EGPC, has at best an advisory role. - 26 - negotiated production-sharing agreements with more than 95 foreign oil companies. Separately, EGPC has developed three non-associated gas fields vwithin Egypt and linked them to the market. While foreign partners are largely responsible for the production of oil, EGPC closely monitors their expLoration and develop- ment programs. Egypt's improved energy position is in no small measure due to EGPC's effective intervention in the sector. It currently faces the problem experienced by many national oil companies of comDeting with the private sector and the Gulf area for experienced staffL. Rapid growth has further strained its managerial resources. In order to assist EGPC in its multi-faceted operation under Loan 1732-EGT consultants were appointed to assist it in devising and installing computerized management information system (see para. 3.12). Functional Structure 3.07 EGPC functions as a holding company and oversees the entire spectrum of oil and oil-related operations through fully owned affiliates (8), operating companies formed in partnership with foreign oil companies (4), and joint ventures (3) (Annex 3.02). All work relating to geophysical surveys and exploration is carried out by the General Petroleum Company (fully owned affiliate) and 95 foreign contractors who have entered in1to production-shatring agreements with EGPC. The annual work program of each of the foreign contractors is drawn up under a general framework of its respective agreements, and reviewed and approved by a joint committee consisti ng of EGPC and the company. Once a commercial discovery has been made, a non-profit operating company is formed, which operates and works the concession. Currently there are four such operators, namely, GUPCO, Petrobel, SUCO (Suez Oil Company) and the Western Desert Petroleum Company (WEPCO). All refining and processing of petroleum products is undertaken by three fully owned affiliates of EGPC, namely the El Nasr Petroleum Company, Alexandria Petroleum Company and the Suez Oil Processing Company. Similarly Egypt-s extensive network of pipeLines for transporting crude oil and petroleum products is owned and operated by another fully held affiliate of EGPC, namely, the Petroleum Pipeline Company. Marketing and distribution of petroleum is undertaken by the Misr Petroleum Company and the Cooperative Petroleum Company. LPG and natural gas are, however, marketed by the Petroleum Gas Company (Petrogas). This company along with WEPCO will be responsible for the implementing of the proposed project. The Western Desert Petroleum Company 3.08 The Western Desert Petroleum Company was formed in 1967 as a joint venture company between EGPC and Phillips Petroleum, wilth both partners having equal shares; as of 1972 Hispanoil has subscribed to 15% of the Phillips Petroleum Company's share. Like other operating companies in the petroleum sector, WEPCO is a non-profit making entity whose expenses are proportionately shared by partners. Presently, WEPCO is producing oil from oil fields of Alamin, Yidma and Umbaraka. The cumulative production from these fields is about half million tons of oil. In addition it discovered and subsequently developed the first phase of Abu Qir gas field, and in 1980 produced 18 bil- lion cubic feet of gas and 400,000 barrels of condensates. WEPCO is managed by a Board of Directors consisting of six members: two designated by Phillips, 27 - one by Hlispanoil, and three by EGPC. The Chairman of WEPCO is designated by EGPC and the Managing Director by Phillips Petroleum. In as much as Abu Qir gas field has and will be developed by EGPC under the -sole risk' clause of the production-sharing agreement, WEPCO will function under the exclusive direction of EGPC, with EGPC bearing all administrative and management expenses relatable to this field. At its senior managerial level, WEPCO has competent and experienced staff and as it developed the first phase of the project on its own, it is in a position to satisfactorily oversee the development of the second phase. A review of its management capabilities, however, indicates that it would require expatriate assistance in certain specific areas. Therefore EGPC has appointed a project management firm to take up day to day implementation function under the direct supervision of WEPCO (see para. 4.17). Petrogas 3.09 While WEPCO will be responsible for implementing activities related to the onshore and offshore gas production facilities and extractioa of LPG, Petrogas (beneficiary under IDA Credit 1024-EGT) will be responsible for the construction of the trunk pipeline to Alexandria. Petrogas was created in 1978 with the primary objective of promoting and implementing a natural gas distribution network in Cairo. In addition it is responsible for distributing and marketing LPG in Egypt. 3.10 The pipeline, proposed under the project, will provide gas to the major industrial consumers in Alexandria, though it would be sized so as to meet the load requirements of domestic consumers who would be converted to gas at a subsequent stage. Petrogas, under its statutes, is run by a Board of Directors consisting of a chairman and eight members. The chairman and four members of the Board are appointed by the prime minister and the remaining four are elected by the labor syndicate. Petrogas has drawn upon competent and experienced personnel of EGPC and subsidiaries of EGPC to man its senior levels. While the present managers have extensive experience in the oil industry, they have limited experience in gas distribution. Project imple- mentation as currently designed takes note of these limitations. Overall design specifications and network analysis will be carried out by qualified consultants, and the task of pipeline construction would be entrusted to a contractor who has extensive experience in similar projects. This, supple- mented by the training and experience Petrogas secures under the Cairo gas distribution project, should permit it to oversee project implementation in a satisfactory fashion. It was agreed during negotiations, however, that all obligations relating to the implementation of the trunk pipeline and distribution line components will be assumed directly by EGPC. This would provide EGPC with flexibility in assigning work under these components among its agencies. In the event of a decision to assign the work to an agency other than Petrogas, the Bank would be in a position to ascertain the competence of such agency in the course of its normal supervision. Accounting System and Management Information 3.11 EGPC follows the Unified Accounting System which was established by Presidential Decree in 1966. Its objective was to achieve uniformity in - 28 - the denomination of accounts, rules and terminology for all public sector undertakings. EGPC was, however, vested with considerable autonomy in setting standards which would apply specifically to the petroleum and gas sectors for cost accounting and financial reporting. 3.12 For this purpose, a general review of accounting practices as well as financial reporting system was initiated as part of the first Bank loan to EGPC (1732-EGT). Consultants were appointed in September 1980, and the study started in October, 1980. The terms of reference specifically covered: 1(i) a comprehensive assessment of EGPC˝s accounting and reporting system, including the review of cost accounting and valuation principles, and the internal control and audit; (ii) the design of a system for capital project accounting and control; (iii) the design of a management information system; (iv) the design and implementation of a planning and forecasting system; (v) the review of the financial structure of EGPC; and (vi) the identification of the training needs of EGPC's staff. The consultants, beside making recommenda- tions, have undertaken the implementation of the agreed improvements, as well as the training of accounting staff. The improvements should lead to the production of meaningful information including consolidated statements by FY82. During negotiations, EGPC agreed to extend the study financed under loan 1732-EGT to the review of the computer needs and applications in order to achieve an optimum utilization of the new computer facilities. Audits 3.13 EGPC undertakes internal audit through its internal cortrol depart- ment and its department for financial evaluation. The financial consultants have proposed a new set up for internal control which is satisfactory and final recommendations have been accepted by EGPC. Procedural manuals have been written, and full implementation is expected by January, 1982. Besides internal audit, EGPC accounts are subject to an annual external audit by the Central Accounting Authority. This review of EGPC accounts is supplemented by a review by the Ministry of Finance of the past expenditures as compared with budgeted amounts. EGPC has agreed to provide the Bank with duly audited financial statements. EGPC has agreed to provide a separate set of accounts for the Abu Qir field operations, duly audited. It was agreed during negoti- ations that both sets of audited statements should be provided to the Bank within six months after the end of each fiscal year. Insurance 3.14 EGPC affiliates carry comprehensive coverages on their assets against major risks. EGPC takes its insurance from Egyptian insurance companies which are in turn reinsured by foreign insurance companies. Abu Qir existing f-eld assets are insured with Misr Insurance Company. Current insurance policies cover risks to platform, process plant, living quarters, pipeline, as well as redrilling expenses. Onshore facilities are also covered for all risks cf physical loss or damage. Similar coverage will be taken for the onshore and offshore facilities proposed under the project; which is adequate. - 29 - IV. THE PROJECT Background 4.01 The Abu Qir offshore gas field was discovered by the Western Desert Petroleum Co. (WEPCO). The field is located in the Mediterranean Sea in about 60 ft of water approximately 17 km from the shore and 35 km from Alexandria (see Map 15212). Since Phillips had no interest in gas production, EGPC undertook in 1973 the development of the field under "sole risk" terms of the production sharing agreement as the exclusive owner. WEPCO completed the first phase development comprising nine wells drilled from a fixed platform along with the necessary offshore and onshore production facilities in 1979. Production commenced in February 1979, but the full production potential of 100 MMcf/d has not been reached because of market constraints. However, this situation will soon reverse itself. It is expected by early 1982 Abu Qir production will no longer be able to satisfy the Alexandria market. Without additional supplies, all incremental demand beyond the 100 MMcf/d presently available from Abu Qir would have to be met through the use of liquid hydro- carbons. Development of the Abu Qir gas reserves represents the least cost means for filling the growing demand-supply gap in the Alexandria area because of the field's proximity to the market and the existing Phase I infrastructure (para. 2.19). 4.02 The proposed project would supply an additional 100 MMcf/d of gas to the Alexandria area market.' A new pipeline would transport gas to Alexandria where it would be distributed to existing consumers 1/ and to industrial plants for which investment commitments have already been made and which are scheduled to be completed by the time gas becomes available. These consumers would otherwise have to use liquid hydrocarbons which can be exported (fuel oil) or those which must be imported (diesel). The project would also produce about 58,000 tons of LPG per year which would displace an equal quantity now imported. Condensate recovered from the incremental gas production, approximately 77,000 tons per year, would be processed in the local refinery, freeing an equivalent amount of crude oil for export. Gas Reserves, Production Potential and Field Development 4.03 The productive sands of the Abu Qir oas field are found in the Abu Madhi and Sidi Salem formations dating from the basal Pliocene to the middle Miocene epochs. They are distributed in four units: upper, middle and lower Abu Madhi and Sidi Salem. The field is bounded by a major fault on the south and by complex faulting on the west and southwest (see Map IBRD 15695). Additional seismic data is needed to determine closure to the south- west and additional wells (not included in the project) will have to be 1/ Annex 2.03 shows market projections in the Abu Qir area. Existing industries which will convert to gas comprise paper, textile, chemical, copper, tire, sanitary ware, cement and aluminum plants and the two local refineries. - 30 - drilled in the northwestern and eastern parts of the structure to completely delineate the areal extent of the field. Consultants financed by the Bank (Loan 1732-EGT, Gulf of Suez Project) have estimated potential recoverable reserves from the four producing zones to be as follows: Zone Gas in Place Recoverable Reserves (TCF) (TCF) Upper Abu Madhi 1.090 0.861 Middle Abu Madhi 0.076 0.046 Lower Abu Madhi 0.910 0.519 Sidi Salem 0.567 0.397 Total 2.643 1.823 4.04 The project proposes to drill nine wells directly southwest of the existing producing area. Spacing and location of the wells, subject to confirmation during drilling, have been agreed to between Bank staff, EGPC,, WEPCO and the consultants (see Map IBRD 15695). Wells 3, 4 and 9 will be development wells and wells 1, 2, 5, 6, 7, and 8 as appraisal/production wells to ascertain t-he extent, thickness and productivity of the sands to the west. They will be completed as producers in those formations showing the best productivity. During negotiations agreement was reached with EGPC and WEPCO that: (i) wells 1 1/ and 2 would be drilled first as their results would allow a more precise positioning of the other appraisal/production wells. Development wells 3 and 4 would be drilled while these results are analyzed; (ii) well 1 would be drilled vertically and cored continuously in the pay zones of Abu Madhi and Sidi Salem to calibrate logs and study the geological and petrophysical character- istics of the sands; (iii) precise gas-water contacts would be determined for all wells through appropriate testing and sampling; (iv) consultants, if considered necessary, would be engaged to check completion procedures for each well; and (v) finding from the drilling of each well would be forwarded promptly to the Bank. 1/ Well 1 would be located directly under the platform which is positioned at 310 24 00"N and 300 12- 00" E. The others would be drilled directionally to a distance of approximately 1.5 km. - 31 - 4.05 Interpretation of old seismic data shows two prospective structures in the general area of the Abu Qir field (see Map IBRD 15695). The project includes a seismic survey (approximately 300 line-km) to map these areas and also to detail the westernmost closure of the Abu Qir field. Southward, the seismic lines will attempt to link, through Lake Idku with previous onshore lines to detect any new structures in this area. 4.06 After completion of the project drilling program, WEPCO will engage consultants to undertake a reservoir study based on the data acquired from drilling the nine wells to determine the optimum plan for further development of the field. The study will entail a new gas reserves estimate and through simulation techniques determine the number and spacing of wells, type of completion and production in each sand and well performance under various development schemes. 4.07 The maximum production capacity of the existing Abu Qir wells is estimated to average about 13 MMcf/d per well or approximately 120 MMcf/d for the field as a whole. In view of the gas supply deficit forecast for Alexandria beginning 1982, it is important to maximize production from the field in the interim period before the project facilities are on stream. In this context, the project includes a feasibility study to determine the maximum gas volumes which can be withdrawn (in accordance with good reservoir management) from the field and the "debottlenecking" measures necessary to increase existing surface facility capacity to handle the higher well flow rates. During negotiations EGPC and WEPCO agreed to undertake and complete, through qualified consultants, such a study by December 31, 1982. Project Design 4.08 The proposed project provides for augmenting Alexandria's gas supplies as the least-cost means of meeting its energy requirements. Abu Qir, because of its close proximity, existing infrastructure and proven production potential is the most economical source of such additional supplies. However, additional production will have to be developed from Abu Qir or elsewhere, to avoid substantial shortfalls over the next five years. Abu Mahdi, in the delta about 200 km west of Alexandria, is the only other gas field now known to have a surplus production potential which could be diverted to Alexandria. Its reserves, however, are dedicated to the Delta market and to make-up shortages in Cairo. If, in lieu of Abu Qir, Abu Mahdi were fully developed and its gas sent to Alexandria, it would not be able to supply the necessary demand. Abu Qir production would still have to be developed to cover short- ages not only in Alexandira but also Cairo which would require facilities to transport the gas from Abu Qir to Cairo. 4.09 In October 1980, Technip (France), qualified consultants appointed by WEPCO, carried out an optimization study of the offshore and onshore production facilities required for the second phase development of Abu Qir. The study included: (i) the type of drilling equipment to be used; (ii) the number and size of platforms; (iii) separation and gas treatment processes; (iv) source of power supply; (v) whether to transport the gas and condensate in a single or separate pipelines; and (vi) onshore facilities including an LPG plant. In evaluating these facilities importance was given to such considerations as investment and operating costs, operating flexibility, safety and reliability. - 32 - 4.10 After examining the various drilling rigs suitable for drilling the Abu Qir wells the consultants recommended the use of a cantilever Jack-up. This recommendation was based on the fact that such a rig was available when required and the fact that it provided the most flexibility and reliability in drilling, and the minimum interference with platform equipment and installation. 4.11 Platform size and design is directly related to the type of rig employed in drilling. To accommodate drilling with a jack-up and provide space for the production equipment a six-pile platform is required. For safety reasons a smaller four-pile platform is provided for operator living accommodations and utilities. 4.12 The offshore gas processing facilities are essentially a duplication of the existing facilities and comprise desanding, gas-liquid separation and dehydration. Design capacity for these facilities is 100-150 MMcf/d. For reliability and ease of well control, the offshore treatment facilities are based on individual separators and glycol contactors. 4.13 Power supplied from offshore and generated on the platform was studied by the consultants. The platform option was found to be less expensive and more reliable than the shore supply. A power cable will connect the existing and project platforms to provide emergency power in case of a power outage on one of the platforms. 4.14 Gas delivery to shore can be achieved by a single pipeline carrying both gas and condensate (two-phase) or by separate gas and condensate lines (single phase). The two-phase line results in the least cost, and since it works satisfactorily in the existing installation, it is the recommended alternative. The 18" pipeline is designed to carry 250 MMcf/d of gas at an inlet pressure of 1305 psig and 1128 psig onshore. This should provide sufficient capacity to accommodate the peak additional production which can be developed from the field in the future and allows gas to be transported from the existing platform in the event of an interruption of flow through the existing 14" line. A 14" line connects the two platforms for this purpose. 4.15 The onshore facilities are essentially an expansion of the exist- ing condensate separation and stabilization units. The consultant has also carried out an LPG recovery study which shows this to be an economically attractive undertaking. Production of LPG by means of the turbo-expansion process was shown to be the best alternative for optimum LPG and condensate recovery. The LPG plant will be sized to handle 250 MMcf/d of gas which is large enough to meet the maximum expected throughput, and at the same time provides sufficient operating flexibility (turn down) for operating at low demand rates. 4.16 The trunkline to Alexandria is still under study and on its completion the findings of the study will be reviewed with the Bank. It will be designed to meet peak demand loads in Alexandria including future domestic consumers. Allowance will be made for future gas supplies from - 33 - North Abu Qir discovered by Elf Aquitaine. Preliminary engineering indicates a 24" pipeline will meet these requirements. Description of the Project 4.17 The proposed project comprises the second phase development of the Abu Qir gas field. Nine additional wells will be drilled from a combined drilling and production platform located approximately 3 km southwest of the existing platform. After processing the gas on the platform it will be piped via an 18" submarine line to the shore terminal where it will be stripped of condensate and LPG. From the shore terminal, the gas will then be sent to the Alexandria area over a 24" pipeline and distributed to major industrial consumers in that area. Map IBRD 15212 shows the location of the proposed project, and Map IBRD 15695 the platform and well locations. Offshore (a) one 6-pile platform containing 9 gas wells and the following production facilities: (i) desanders and phase separators; (ii) glycol gas dehydration unit; (iii) water coalescer; (iv) oily water treating system; and (v) fire protection and safety systems; (b) one 4-pile platform connected by a bridge to the production platform and containing: (i) living quarters for 17 persons; (ii) helideck; (iii) gas turbine electric power generation and transmission system with a diesel standby unit; (iv) fire fighting equipment; (v) two cranes; and (vi) safety and survival systems; (c) an 18" submarine pipeline approximately 15 km in length from the production platform to the shore terminal and a 14" submarine line connecting the existing to the proposed platforms; and (d) a submarine electric cable with step-up/step-down transformers at each end linking the existing and proposed platforms. - 34 - Onshore (a) slug catcher and gas separation facilities, gas dehydration unit and condensate stabilizer unit; (b) an LPG plant designed for a flow of 250 MMcf/d with its utilities, approximately 10 days storage capacity and two truck loading stations; (c) a flare system; and (d) a 24" pipeline to the Alexandria area and distribution lines with pressure regulating and metering facilities to approximately 9 major consumers. Technical Assistance and Studies (a) technical assistance in project engineering, management (includiing financial systems and computer needs) and construction supervision; (b) technical assistance in drilling operations, soil investigations, pipeline route survey, third party inspection and materials delivery and expediting services; (c) reservoir evaluation of the Abu Qir field to determine its gas reserves and production potential and to formulate a program for optimum development; (d) study to determine the maximum production potential of the existing Abu Qir wells and the feasibility of increasing the capacity of existing production facilities to match maximum production potential; (e) study to develop a national gas pipeline grid along with a program for installing the necessary pipelines, dispatch and control centers and other required facilities; (f) feasibility study for a Alexandria trunk line and domestic gas distribution project in Alexandria; (g) feasibility study for a gas system for Upper Egypt; and (h) tariff study to develop a rate structure for the various kinds of gas consumers. Project Implementation 4.18 WEPCO will be responsible on behalf of EGPC for implementing the Abu Qir onshore and offshore and LPG portions of the proposed project. Subject to the qualification mentioned in para. 3.10, Petrogas will be similarly responsible for the Alexandria pipeline and the distribution - 35 - network. WEPCO implemented the original Abu Qir project and operates the existing facilities. It is capable of handling, with some outside assistance, the second phase. Accordingly, backup assistance to WEPCO and day-to-day implementation functions will be assigned to ENPPI, a joint engineering enterprise between EGPC and Brown and Root (USA). Petrogas is constructing the Cairo Gas Project (Credit 1024-EGT) and will appoint an engineering firm to carry out its portion of the project in a similar manner. Technical assistance in carrying out of studies would be by consultants whose qualifi- cations, experience and conditions of employment would be satisfactory to the Bank and EGPC. 4.19 The project implementation schedule is shown in Annex 4.01. Be- cause of the world wide shortage of drilling rigs, WEPCO has had to award a drilling contract in April 1981 to Reading and Bates (USA) for a contract period of two years. The rig is scheduled to be on site no later than mid- October 1982, and drilling should take approximately 405 days (45 days per well). The remaining contract period after completion of the Abu Qir wells will be used for other EGPC operations. The various services required in drilling, testing and completing gas wells will be supplied by well service companies specializing in these operations. 4.20 WEPCO issued prequalification documents in March 1981 for the main equipment supply and construction contracts. The contract for the offshore platform was awarded to Petrojet in November, 1981. Contract for other long lead equipment modules are likely to be awarded by February, 1982. This is necessary to enable drilling to start when the drilling rig arrives on site. The remaining contracts are less urgent, and can be deferred until the end of the first quarter 1982. 4.21 Based on the estimated drilling rate, which is consistent with the previous Abu Qir drilling operation, the offshore work should be completed by January 1984 and commissioning by April 1984. This allows ample time to complete the onshore facilities including the LPG plant and the trunkline to Alexandria. Project Costs 4.22 Including contingencies the proposed project is estimated to cost US$189 million of which US$156 million or 83% represents the foreign exchange component. Interest during construction is estimated to add US$11 million to these costs. A physical contingency of 10% was applied to all project costs, and the basic cost estimate, based on 1981 prices, was escalated as follows: Foreign costs - 8.5% (1982); 7.5% (1983 and 1984) Local costs - 14% (1982); 13% (1983) and 12% (1984) 4.23 Detailed engineering, project management, procurement and construc- tion supervision costs are estimated at US$10 million and provide for 700 man-months of expatriate and 350 local engineering personnel from the joint venture engineering firm and other expatriate firms as needed. The average - 36 - man-month cost for expatriates is estimated to be US$12,000 per man-month and US$3,000 for local personnel. US$250,000 is included for vehicles and other local operating expenses. Studies are estimated to cost US$2.0 million based on 200 man-months expatriate consultants at US$10,000 per man-month; the reservoir evaluation cost is estimated at US$700,000 at US$15,000 per man--month for 50 man-months of expatriate services; and technical assistance in driLling in other project services is expected to cost US$2.6 million for 170 man-months of expatriate services at US$15,000 per man-month. The rate for drilling and related project services reflects the current high demand for experts in petroleum exploration and development. All expatriate rates include salaries, benefits, fees, international travel and subsistence. 4.24 Duties and taxes on goods and materials are not included since EGPC is exempt from such payments. The estimated project costs, excluding the US$11 million estimated interest during construction, are summarized in the following table. Annex 4.02 gives a more detailed breakdown of these costs. LE Million US$ Million Local F.E. Total Local F.E. Total Drilling (9 wells) 0.6 22.1 22.7 0.8 32.1 32.9 Offshore platforms 0.7 4.8 5.5 1.0 7.0 8.0 Offshore process and utilities 2.1 17.1 19.2 3.0 24.8 27.8 Submarine pipeline 0.4 7.9 8.3 0.5 11.5 12.0 Power supply 0.4 1.7 2.1 0.5 2.5 3.0 Onshore terminal 0.7 0.7 1.4 1.0 1.0 2.0 Trunkline and distribution 6.2 7.1 13.3 9.0 10.3 19.3 LPG plant 4.6 15.6 20.1 6.7 22.5 29.2 Project Engineering, management, procurement & constr. supvsn. 0.6 6.2 6.8 0.8 9.0 9.8 Technical assistance 0.3 1.6 1.9 0.4 2.2 2.6 Reservoir evaluation 0.1 0.4 0.5 0.1 0.6 0.7 Studies /1 0.3 1.1 1.4 0.4 1.6 2.0 Training 0.1 0.2 0.3 0.2 0.3 0.5 Seismic survey - 0.6 0.6 - 1.0 1.0 Basic Cost Estimate 17.1 87.0 104.1 24.4 126.4 150.8 Physical Contingency 1.7 8.7 10.4 2.4 12.6 15.7 Price Contingency 3.8 11.7 15.5 6.2 17.0 23.2 Estimated Project Cost 22.6 107.4 130.0 33.0 156.0 189.0 /1 The foreign exchange cost of studies is broken down as follows: US$ Abu Qir capacity increase 500,000 Natural gas pipeline grid 500,000 Upper Egypt gas supply 300,000 Financial systems and computer services 300,000 1,600,000 - 37 - Project Financing Plan 4.25 EGPC will provide the estimated US$33 million equivalent local expenditure costs, US$11 million of the estimated US$156 million equivalent foreign exchange requirement and US$11 million interest during construction from its own resources and budgetary allocations from the Ministry of Finance. The remaining foreign exchange expenditures would be funded by the proposed US$90 million equivalent Bank loan and the US$55 million equivalent from the European Investment Bank (EIB) and/or export credits. In this regard, EGPC is in an advanced stage of discussions with EIB for a loan (expressed in ECU's) equivalent to approximately US$32 million and with Chase Manhattan Bank (UK) for arranging a line of credit from various export credit agencies. The proposed Bank loan represents 58% of the foreign exchange portion of the project and 48% of the total estimated project. The proposed allocation and source of funds for the project is shown in the following table. Bank Others 1/ EGPC Total Drilling 16.5 15.6 - 32.1 Offshore Platforms - 7.0 - 7.0 Offshore Facilities 23.5 - 1.3 24.8 Submarine Pipeline 11.5 - - 11.5 Power Supply 2.5 - - 2.5 Onshore Terminal - 1.0 - 1.0 Trunkline and Distribution - 10.3 - 10.3 LPG Plant 22.5 - - 22.5 Consultant Services 7.9 5.3 1.5 14.7 Contingencies on F.E. Costs 5.6 15.8 8.2 29.6 Local Expenditures - - 33.0 33.0 Interest during construction - - 11.0 11.0 Total 90.0 55.0 55.0 200.0 % 45 27.5 27.5 100 1/ EIB and/or line of credit from export credit agencies. - 38 - 4.26 The proposed US$90 million loan would be made to EGPC at the current Bank lending rate plus an annual guarantee fee of 1% for a period of 20 years including 3 years of grace. The life of the gas field is estimated to be of the order of 18-20 years. The loan would be guaranteed by the Government, and EGPC would assume the foreign exchange risk. Procurement, Disbursement and Advance Contracting 4.27 All procurement for works and goods financed by the Bank would be by international competitive bidding (ICB) in accordance with the Bank's guidelines. Drilling services and materials needed for operational flexibility or which might delay the well drilling operation if procured through ICB may be procured through the Government's competitive bidding procedures which do not exclude foreign bidders and are acceptable to the Bank. The aggregate of such procure- ment should not exceed US$2.5 million and no single contract should exceed US$500,000. Goods and materials costing less than US$500,000 equivalent may also be procured through the above-mentioned competitive bidding procedures up to an aggregate amount of US$10 million. Tendering for pipeline construction, platforms, production modules and civil works will be limited to prequalified contractors. All bid packages having a value of US$500,000 or above would be subject to Bank review prior to contract award. The others would be reviewed subsequently. Any goods and equipment which might be available from local suppliers would be granted the usual 15% preference or customs duty if less. Technical assistance consulting and training services would be engaged in accordance with Bank guidelines for the use of consultants (August 1981). 4.28 Disbursement would be made against: (i) 100% of the foreign exchange expenditure for the LPG plant, 100% of the foreign exchange expenditures for directly imported goods and equipment and 70% of local expenditures for goods procured locally; (ii) 90% of installation expenditures for the submarine pipelines; and (iii) 100% of the foreign exchange costs for consultant services, studies and training. Annex 4.03 gives the estimated disbursement schedule. In the absence of a regional profile for this sector, the disbursement profile is based on: (i) a three-month lag between the time the expenditure has been incurred (according to the project schedule) and the time funds are disbursed against this expenditure; and (ii) the loan becoming effective in July 1982. The loan would be fully disbursed by June 30, 1985, and the closing date would be December 31, 1985. 4.29 As indicated (para. 4.19), WEPCO has already had to contract (approximately US$16 million) for a rig to begin drilling operations in October 1982. It was also necessary to award a contract for the offshore platforms and long delivery production and utility modules on the platforms in the fourth quarter 1981. This will necessitate advance contracting to the maximum extent of about US$25 million for these items. It is proposed that expenditures which may be incurred for downpayments for the above purpose be retroactively financed from the Bank loan to the maximum amount of US$2.5 million. - 39 - Project Risks 4.30 The project carries operational and geological risks inherent to the petroleum production and pipeline industry. Offshore operations pose additional risks, but the industry has developed techniques and technology over the years to minimize these, especially since it has had to cope with the hostile environment in the North Sea. Because of the growing deficit in gas supplies for the Alexandria area, there is minimal commercial risk. 4.31 The offshore project facilities are located in shallow water (about 60 ft), and weather conditions are relatively mild. In view of this and the fact that WEPCO is operating similar facilities successfully, risks associated with offshore operations are considered to be minimal. The facilities are designed by qualified consultants with extensive experience, and only pre- qualified contractors will be invited to bid for construction of the project facilities. Construction standards and the structural integrity of the offshore platforms and pipeline will be reviewed by an internationally recognized authority (probably Lloyd's Register of Shipping, which reviewed the existing installations). Onshore operational risks are minimal. The risks of accident and fire are discussed separately (para. 4.34). In the event of a blowout and fire during drilling it is possible that the drilling platform and production equipment could be lost. This would delay production by two years, but even with this production loss, the project would still yield an economic rate of return of over 50%. 4.32 Reservoir consultants financed under Loan 1732-EGT have assessed the field's recoverable reserves and production potential (para. 4.03). Data from the nine wells already drilled and the seismic survey of the area indicate that there is a high probability that the new wells will be capable of producing at least 100 MMcf of gas. Nevertheless, it must be recognized that subsurface geological formations can never be predicted with absolute certainty, and that there is a possibility that not all the wells will be producers. However, we believe it is reasonable to expect that at least six of the nine wells will be producers, which would still give an attractive (over 50%) economic rate of return on the project. Training 4.33 WEPCO has been successfully operating and maintaining the offshore and onshore Abu Qir gas production facilities since February 1979. Additional personnel recruited for the corresponding project facilities can be trained in-house in accordance with WEPCO's present recruitment and training pro- cedures. The LPG production facilities, however, will introduce new equip- ment, instrumentation, processes and quality control measures requiring different operating and maintenance skills. An effective training program will be essential to the successful operation of this facility. Provisions for training are included in the proposed loan. WEPCO has agreed to submit to the Bank, for its review by December 31, 1982, a satisfactory recruitment and - 40 - training program detailing job classification, duties and duration. Petrogas has an ongoing training program provided under Credit 1024-EGT (Cairo Gas Distribution Project) which should cover its needs for operating the onshore pipeline and distribution system. Ecology and Safety 4.34 The proposed project is not expected to have a significant impact on the environment. Although negligible when compared to total marine pollution (by tankers), offshore oil operations do pose the danger of pollution from oil spills during the drilling and production phases. However, in the case of gas fields, such as Abu Qir, there is little chance of appre- ciable oil spillage. Water and condensate are separated from the gas on the production platform, but the oily water effluent is treated to reduce the oil content to 100 parts per million before disposal, which is satis- factory. Both the offshore and onshore pipelines will be buried and original surface features restored. Since the gas will go largely to consumers who would otherwise burn fuel oil, the project in effect will reduce atmospheric pollution in the Alexandria area. 4.35 In handling gas the chief safety concern is fire. During drilling operations, EGPC and WEPCO will monitor and enforce all safety equipment, blowout prevention and well control regulations. In addition EGPC has agreed to allocate funds immediately for recruiting specialized interna- tional services in the event of a blowout and fire. Platform and production facilities will be designed and constructed in accordance with appropriate international safety standards. Adequate provisions will be made for fire detection, fire safety and fire fighting systems and for abandoning the platforms, if necessary. Additional safety to personnel is provided by having their living quarters on a separate platform away from the production unit. To ensure safe operation of the wells, EGPC and WEPCO have agreed that all wells will be equipped with surface controlled subsurface safety devices, using the best technology presently available, and with surface safety valves. 4.36 The offshore and onshore pipelines offer no particular safety problems other than what might result from poor operating and maintenance practices. So far, EGPC-s affiliates have an excellent track record in operating pipelines safely. Moreover, the pipelines will be designed and constructed in accordance with internationally accepted standards and pro- vided with the necessary protection against corrosion and overpressure for safe operations. - 41 - V. FINANCIAL ANALYSIS Introduction 5.01 EGPC functions as a holding company and oversees all the operations related to the petroleum industry. Full corporate analysis of EGPC's finances is not feasible at this time due to lack of information about the operation of its many subsidiaries and of consolidated accounts, nor is it necessary as yet. Bank's projects are self-contained components of EGPC or of its different financially sound subsidiaries. EGPC's foreign exchange revenues from exports alone were LE 1.1 billion in FY 1979. They far exceed operating expenses, debt service, as well as the entire capital expenditure program. Indeed they contribute massively to Egypt's foreign exchange earnings and also to Government fiscal revenues. EGPC is allowed to retain between 10% and 15% of net profits as needed to help meet the company's investment requirements. This situation will continue into the 90 s if the very active exploration programs undertaken by EGPC and foreign oil companies - currently LE 500 million per year - continues and if domestic pricing is increased, contributing to higher revenues as well as improved efficiency in the use of hydrocarbons. 5.02 As noted in para 2.34, EGPC could become a large borrower of foreign capital markets on its own credit, thus help to free additional resources for Egypt's economic development. The three earlier projects as well as the proposed project helped prepare a number of public sector projects, primarily gas development, focused on domestic consumption, and complementary to the large export-oriented program of foreign oil companies. Over the next few months, the Bank will help finalize feasibility studies for various proj- ects and integrate them into a time phased and costed program of priority investments which are eligible for commercial financing as well as Bank support. In parallel, the completion in October 1981 of the financial studies and their implementation in the coming year should allow a full corporate analysis of EGPC's condition, prospects and projects to be initi- ated within FY 1982. The financial analysis in this report is another interim step in the general direction of a full corporate analysis. It highlights the main features of EGPC's present financial situation, and the finances of the Abu Qir gas field which, in view of the foregoing, is still treated as a financial entity. Past Financial Performance 5.03 EGPC's unconsolidated statements over 1977 - 1979 are summarized below. Details are shown in Annex 5.01. - 42 - EGPC Unconsolidated Income Statement In LE Million FY1977 % FY1978 % FY1979 % Export revenues 191 30 242 34 1,127 59 Local revenues 352 56 405 58 649 34 Total sales revenues 543 86 647 92 1,776 93 Other non-operating revenues 87 14 55 8 136 7 Total revenues 630 100 702 100 1,912 100 Operating expenses and taxes (432) (69) (478) (68) (1,092) (57) Net profit 198 31 224 32 820 43 In FY 1979, domestic sales accounted for about one third of total EGPC revenues although they were about 50% of the sales volume. This was mainly due to the low level of domestic petroleum product prices (see para. 2.23, 2.24 and 2.25) in relation to international prices. Distribution of net profit to Government was 177 million LE in 1977, and increased to 192 million LE in 1978 and 729 million LE in 1979. Total resource mobilization from EGPC, including all profit distribution, taxes, duties, etc., was 379 million LE in 1977, and 1,460 million LE in 1979, a consequence of the boost in the level of export earnings in the last three years. 5.04 The unconsolidated balance sheets of EGPC are shown in Annex 5.02 for the period 1973 - 1979. A summary balance sheet for 1979 (the latest audited balance sheet available) is given below. - 43 - EGPC Unconsolidated Balance Sheet (in LE millions) 1979 % Assets Fixed assets 56.8 10 Projects in progress 94.0 17 Investments 400.8 72 Working capital 8.1 1 Total assets 559.7 100 Equity and Liabilities Total equity 380.7 68 Long term financing 179.0 32 Total equity and liabilities 559.7 100 These unconsolidated statements largely underestimate the net worth of EGPC. Investments in subsidiaries are carried at costs, and have never been revalued. The debt equity ratio as shown on the unconsolidated statement (32/68) would therefore be much lower on a consolidated basis, as the indebtedness of the subsidiaries is currently very limited. This is indicative of the borrowing capability of EGPC as a group. It emphasizes the financial ability of EGPC to seek commercial borrowings to finance its future projects. Current Income 5.05 Export Sales. EGPC's export sales from 1978 to 1979, which were mainly crude oil, and to a lesser extent, naphtha were as follows: Export Sales % of Total % of Total 1978 Revenue 1979 Revenue Crude (000 tons) 4,628 83 5,011 86 Naphtha (000 tons) 781 17 686 12 Other Refined Products (000 tons) 20 - 180 2 Total Revenues from Exports (LE million) 242 100 1,127 100 - 44 - 5.06 Domestic Sales. As described in para. 3.07 to 3.10, EGPC's activities in refineries, transmission and marketing are handled by specialized subsidiaries. EGPC reimburses its refineries on a cost plus basis. EGPC sells refinery products to its marketing companies at the consumer prices 'Less a commission to cover marketing expenses and to provide an adequate rate of return to the marketing entity. Although these practices do not encourage efficiency improvements, they provide for the financial viability of all the subsidiaries of EGPC in an environment of administered pricing structure. 5.07 EGPC's Net Back. The "net back" to EGPC (i.e. the average price of the sales of refined products to marketing companies less the budgeted costs paid to refining and transportation companies, as well as Government taxes, excise fees and dues) has progressed from 1977 to 1979 as follows: Average EGPC Net Back Per Ton of Crude Oil (in LE and US dollars) 1977 1978 1979 L.E. $ % L.E. $ % L.E. ' % Weighted average revenue from sale to distributors 22.3 26.5. 100 23.6 28.1 100 28.7 34.2 100 Weighted average opera- tional expenses (5.2) (6.2) (23) (5.5) (6.6) (23) (8.0) (9.5) (28) Taxes, excise fees, P'd Treasury rights (9.3)(11.0) (42) (9.7)(11.5) (42) (14.0)(16.7) (49) Net income .'.8 9.3 35 8.4 10.0 35 6.7 8.0 23 Less crude transport cost ( .7) ( .8) (3) (1.0) (1.2) (4) (1.6) (1.9) (6) Net back 7.1 8.5 32 7.4 8.8 31 5.1 6.1 17 Weighted average revenues from sales to distributors grew by 22% in 1979, following the price increase of selected domestic petroleum products. The revenues to EGPC, net of payments to Government were 16.4 LE per ton in 1977, and 19.1 LE per ton in 1979; however, increases in the level of excise fees resulted in a fall of the final "net back" to EGPC from 7.1 LE in 1977 to 5.1 LE per ton in 1979. EGPC's Future Position 5.08 As indicated in para. 2.05, Egypt-s oil production is not expected to decline until the late 1980's. Production is expected to marginally increase from a level of 29.5 million tons in 1980 to a level of 34 million tons in 1986. In comparison to the forecast production, domestic consumption of liquid hydrocarbon products is expected to increase from 11.3 million tons in 1980 to only 17 million tons in 1986 due to the increased use of - 45 - natural gas. Egypt will therefore remain in a large oil overall surplus position until at least the last years of the 1980's. EGPC income statements for the period 1981 - 1983 are summarized below. EGPC Projected Income Position - Main Indicators 1981 - 1983 (in Million LE) 1981(Est.) % 1982 % 1983 % Export Sales 979 38 1,560 50 1,747 49 Domestic Sales 1,601 62 1,609 50 1,802 51 Total Revenues from Sales 2,580 100 3,169 100 3,549 100 Net Income before dis- tribution 1,143 42 1,657 53 1,832 51 Surplus transferred to Government 943 35 1,060 34 1,166 34 5.09 EGPC's own investments will total LE584 million from 1981 to 19F3. Investments of EGPC in its subsidiaries will total LE440 million during the same period. A summary of EGPC's group financing plan is shown below: EGPC's Financing Plan 1981 - 1983 (in Million LE) 1981 % 1982 % 1983 % Total % Applications EGPC's Projects 50 22 145 44 389 60 584 48 Investment in subsidiaries 89 38 120 36 231 36 440 36 Loan Repayments 94 40 68 20 27 4 189 16 Total Applications 233 100 333 100 647 100 1,213 100 Sources Internal Cash Generation 218 96 281 84 340 53 839 69 Loans from Subsidiaries 4 1 5 2 - - 9 1 Domestic Loans - - - - 51 7 51 4 Foreign Loans 11 3 47 14 256 40 314 26 233 100 333 100 647 100 1,213 100 This financing plan reflects the increasing role that foreign borrowings and suppliers credit are expected to play in the financing of EGPC's investments for the next three years. The review of this investment plan indicates that adequate provisions have not been made for developing Egypt's natural gas resources and the related infrastructure (see para. 2.34). Projects such as gas distribution and pipeline construction projects would be especially suitable for external borrowings. In the context of this project, it was agreed to repeat the condition of loan 1732-EGT, that the debt service coverage of EGPC should at all times be not less than 1.5. - 46 - ABU QIR FIELD 5.10 Introduction. Although separate accounts are maintained for present operations in the Abu Qir field, there is no separate company to administer and operate the field; operations are controlled by EGPC. Production at Abu Qir is presently carried out by WEPCO on a reimbursable basis. Revenues and expenses for the field form part of the overall revenue and expenditures of EGPC. With the extension of production under the project, EGPC has agreed to closely monitor the financial viability of the operations of the Abu Qir field. In effect, Abu Qir would be operated as an autonomous enterprise for accounting purposes within EGPC-s accounting system. 5.11 Accounting Arrangements. The objective of the proposed arrangements would be to protect the project finances and allow at all times an assessment to be made of the financial performance and cash requirements of Abu Qir field operations independently from the rest of EGPC operations. Therefore, during negotiations, EGPC agreed to maintain separate accounting records for the operation and development of Abu Qir field. EGPC has also agreed to prepare separate financial statements for the Abu Qir field operations. It was agreed that these statements would be audited by independent auditors satisfactory to the Bank, and forwarded to the Bank within six months after the end of each fiscal year (see para. 3.13). Present Finances 5.12 Fixed assets held by EGPC in the Abu Qir field at the end of FY 1980 consisted of a nine well platform and related facilities and installations amounting to LE 39.9 million ($58 million) in revalued terms. These assets had been financed by a loan from the Kuwait Fund (15 years - 4%) of LE 10 million with the balance coming from EGPC's internal funds. Gas production from existing facilities which was 25,422 MMcf in FY 1980, is expected to reach 36,500 MMcf in 1981 and thereafter; condensate production was 47,850 tons in FY 1980, and is expected to be 68,700 tons per year starting in FY 1981. 5.13 Production from the Abu Qir field contributes significantly to lthe earnings of EGPC, as it permits EGPC to export fuel oil at LE 110/ton against selling it in the domestic market for LE 7/ton. It is estimated that at full production from existing and project facilities alone, the contribution of gas replacing fuel oil to EGPC-s earnings would be LE 160 million per annum. The current price of gas however does not ensure the recovery of ithe direct costs of production of the field and the gas field, per se, incurred net losses of LE 0.7 million and LE 1.8 million in 1979 and 1980 respectively. Even at full production in 1981, the field would still be expected to achieve a net loss of LE 0.3 million. The operating ratio was 150% in 1980, and would remain at about 100% at full production from the existing facilities unde;r current pricing policy. Return on revalued net assets was -3.5% in 1980 and - 47 - at the current pricing level would be .2% in 1981. Debt service coverage was 2.1 times in 1980. EGPC currently ensures the financial viability of the operation of the field through direct contribution as needed. Financial Viability of the Abu Qir Field 5.14 The production of gas from the project facilities is expected to start in March 1984 at a rate of 100 MMcf/d; this would bring total gas production from the field to 73,000 MMcf/d per year; the production of condensate and LPG would then reach 146,000 tons and 58,000 tons per year respectively. As indicated in para. 2.18 the Alexandria market is expected to take all the expected gas production; condensate production would be sold to refineries and LPG to Petrogas for domestic consumption. This substantial increase in production would not result, however, in the recovery of the cost of production of the gas of the field at present prices. The cost of production of the gas is estimated at $.83/Mcf for the new wells, and $.60/Mcf in average for the overall field. This cost compares with current average selling price for Abu Qir gas of $.20/Mcf. 1/ The Government s decision to increase gas prices to a level which would be above the marginal cost of production of the field will significantly change the financial performance of Abu Qir field; and the new pricing levels would permit the field to achieve independent financial viability. The prime financial objec- tives of the financial conditions agreed upon during negotiations are: 5.15 Firstly, the field should yield a normal return on the investment. For this purpose, GOE and EGPC agreed to ensure that revenues from the sale of gas of Abu Qir field are sufficient to earn a rate of return on revalued net fixed assets of not less than 10% in the first three years of operation of the Abu Qir project (FY 1985 - FY 1987) and 15% thereafter. Secondly, the cash flow position of the field should be satisfactory at all times. In order to achieve this objective, during negotiations GOE and EGPC agreed that (i) EGPC would promptly provide any funds (in local and foreign currency) needed for the project; (ii) revenues from the sales of Abu Qir gas should cover at all times operating expenses, debt service, working capital requirements of the Abu Qir field, and a reasonable contribution to the investments in the project area; and (iii) EGPC would not incur any debt for the Abu Qir field other than that for the proposed development, unless the projected internal cash generation from the Abu Qir field for each future fiscal year shall be at least 1.5 times the total debt service of the field for that year. Financing Plan 5.16 The following table gives a summary of the capital investment requirements of the Abu Qir field for the period FY 1981 - FY 1985 and the sources from which they would be met, based on the revenues required to meet the financial criteria indicated in para. 5.15. A detailed sources and application of funds statement for the field is given in Annex 5.03. 1/ Exchange Rate LE .84 = US$1. - 48 - Financing Plan for Abu Qir Field FY 1981-FY 1985 Requirements LE Million $ Million % Fixed Investments 130 189 94 Working capital 9 13 6 Total requirements 139 202 100 Sources Internal cash generation 68 99 49 Less debt service (35) (51) (25) Net internal cash generation 33 48 24 EGPC contribution 6 9 4 Borrowings - IBRD (proposed loan) 62 90 45 - Others 38 55 27 Total sources 139 202 100 5.17 The proposed Bank loan would be lent to EGPC at the current Bank lending rate, with a repa,-nt period of 20 years, including three years of grace; in addition, GOE would charge EGPC a guarantee fee of 1%. This would bring the average cost of the loan to EGPC to about 14%, i.e., somewhat higher than the projected domestic inflation rate in the country after FY 1982. EGPC will bear the foreign exchange risk. During negotiations, EGPC indicated that it intended to seek co-financing of up to $55 million for this project. Projected Financial Position 5.18 The table below summarizes the performance of Abu Qir field under the assumption that Abu Qir field earns a rate of return on revalued net assets reaching 10% in the first three years of operation of the project (FY 1985 - FY 1987), and 15% thereafter. Detailed forecasts for the period FY 1981 through 1988 are shown as Annexes 5.04 and 5.05, with related assumptions in Annex 5.06. It is expected that internal cash generation would contribute LE 33 million towards the project, and that EGPC would further contribute LE 6 million. - 49 - Financial Indicators - Abu Qir Field 1984 1986 1988 Production of gas (MMcf) 45,625 73,000 73,000 Sales to consumers ('000 LE) 33,200 62,200 92,145 Net income before interest ( 000 LE) 11,500 20,700 30,300 Rate of return on assets (%) 10 10 15 Debt/Equity ratio 58/42 43/67 30/70 Current ratio 0.6 3.0 8.2 Debt service coverage (times) 1.7 1.8 2.6 Straight-line depreciation over the life of the field has been assumed. For the purpose of computing rates of return on revalued assets, EGPC agreed at negotiations to annually revalue its Abu Qir fixed assets, according to a method acceptable to the Bank. In the financial projections a revaluation rate of 9% a year has been assumed. 5.19 Forecasts indicate that the financial performance of the Abu Qir field as measured in terms of earnings, debt service coverage, current ratio and debt/equity ratio would be satisfactory after project completion. The DCF rate of return has been calculated at 8% in real terms over the life of the project. The financial criteria described above will make Abu Qir field an independently viable unit within EGPC. VI. ECONOMIC ANALYSIS 6.01 The project, once fully developed, will allow the yearly incremental production of 36,500 MMcf of gas (100 MMcf/d); 77,000 tons of condensate and 58,000 tons of LPG. Gas produced will replace mainly exportable fuel oil (16,800 MMcf) and imported gas oil (19,700 MMcf) which would have been consumed by industries and power stations. Condensate will upgrade crude oil and result in the production of higher value refined products. LPG will substitute imports and will serve requirements of the domestic market. The project would result in major foreign exchange gains for Egypt. It is the least cost solution for meeting energy needs in the Alexandria area, and makes optimal use of the Abu Qir field production. Under this project gas prices will be increased, as an interim step toward general energy pricing reform (see paras. 2.36 and 2.37), resulting in a substantial decrease of the gap between domestic price and opportunity cost. For the purpose of economic analysis, the shadow value of the currency has been taken to be 1 $ = .84 LE. - 50 - Least Cost Solution 6.02 The potential market for gas in Alexandria will increase from 50 MMcf/d in CY 1980 to 265 MMcf/d in FY 84 and 380 MMcf/d in FY 86 (see para. 2.19). This forecast potential consumption compared to existing gas supply would leave, in the absence of new development, a growing gap reaching 280 MMcf/d in FY 86, which would have to be served with liquid hydrocarbons. Due to the location of the Abu Qir field and the established demand, it is clear that the best domestic use of the gas is the Alexandria market. The project has further been designed as the least cost solution of meeting this demand, as demonstrated in para. 4.08. 6.03 The reserve estimates are not sufficient to justify any LNG project at this time. However, even if reserves were proven in sufficient amount to permit LNG production, such alternative would be less attractive. It is esti- mated that the net back of LNG would be $2.50/Mcf. In comparison, the fuel oil international prices are taken to be $4.0/Mcf FOB, and the marginal extraction development cost of Abu Qir are about $.8/Mcf, leaving a "net back" of $3.2/Mcf. 6.04 The other main alternative would be to keep the gas in the ground for use in the future. This would be a more economic alternative if the real increase per year in the net back from oil replaced were greater than the social discount rate in Egypt. The current discount rate is, however, esti- mated at 10%, while the increase in oil prices is estimated to be 3% per year in real terms. The optimum use of Abu Qir gas is therefore the replacement of fuel oil/gas oil and LPG in the Alexandria area. Cost Stream 6.04 The cost stream includes all capital costs and operating costs involved in the project development and the operation of the field. The economic analysis also takes into account the capital costs to be incurred in 1993 to maintain the field production at the forecast level, through the addition of compressors. Based on current estimates, the marginal cost of extraction of the gas would be $0.83 per Mcf using a social discount rate of 10% per year. Direct Benefits 6.05 For the purpose of deriving the benefit stream, gas has been assumed to release fuel oil for export at $160 per ton, and to replace imported gas oil at $300 per ton in 1982 terms. Condensate will be blended with crude oil in order to derive higher value refined products. For the purpose of economic projections, its value has been conservatively assumed to be 90% of gasoline value, i.e. $310 per ton. LPG value was taken at $400/ton. These prices are based on December 1981 international prices for petroleum products and are assumed to increase by 3% in real terms each year until they reach a ceiling equivalent to $60 per barrel of crude oil. They are assumed thereafter to remain constant in real terms. - 51 - Rate of Return 6.06 The economic projections are shown as Annex 6.01. The economic rate of return for the base case is over 100% and the net discounted benefits are estimated at LE 1.5 billion. Should the project be delayed by one year, the net discounted benefits would still be LE 1.3 billion. Should the production be only 70 MMcf/d, the net economic benefit would be LE 1 billion. In the worst case, where the project is delayed by one year, incurs 10% cost overruns and only achieves a production of 70 MMcf/d, the rate of return would still be very high (62%) and the economic benefits would reach LE .9 billion over the life of the project. Gas Pricing 6.07 The economic value of Abu Qir's natural gas is the border price of fuel oil displaced for export. This would indicate a price of LE 3.3/Mcf ($4.0/Mcf) in December 1981 terms, as compared with the current domestic price for the Abu Qir field gas of LE 0.17/Mcf ($0.20/Mcf). 6.08 The objective of gas pricing policy in Egypt must be considered as part of an overall energy pricing policy. Toward this end, a petroleum products pricing and gas utilization study was undertaken as part of the Gulf of Suez project, financed under Loan 1732 EGT. This study, completed in September 1981, provides valuable guidance on the impact of various price scenarios on the different sectors of the economy (para 2.35). 6.09 In the meantime, under this project GOE and EGPC have agreed to set the price of Abu Qir gas at a level sufficient to recover at least the marginal cost of extraction of the gas, and an allowance for its depletion. As noted above, the marginal extraction cost is estimated at $0.83/Mcf. The depletion allowance has been taken to be the present value of future imports required when Egypt's reserves are exhausted by depleting the field at this time. The computation of the depletion allowance is based on an estimated life of Egypt-s reserves of 35 years, a real increase of 3% per year of the inter- national price of fuel oil, until international prices of crude oil reach an equivalent of $60/barrel, and on a social discount rate of 10%. Based on these assumptions, the minimum level of gas prices from Abu Qir would be $1.1/Mcf in December 1981 terms. Other Benefits 6.10 In addition to the direct benefits described above, this project will result in a reduced level of environmental pollution, with the replace- ment of fuel oil with natural gas. It will also be an important step toward encouraging more efficient energy usage through more appropriate energy prices. - 52 - VII. RECOMMENDATIONS 7.01 During negotiations assurances were obtained that EGPC would: (a) undertake and complete by March 31, 1983 a study on (i) expan- sion of pipeline capacity for moving associated gas from the Gulf of Suez to Cairo (para. 2.31); (ii) expansion and/or creation of pipeline capacity, and its phasing, for transferring natural gas from the surplus to deficit areas (paras. 2.21 and 2.32); and (iii) economic viability and phasing of national gas pipeline grid (para. 2.32) and, review the findings of the study with the Bank; (b) undertake and complete by March 31, 1983 a feasibility study for a gas system for Upper Egypt (para. 2.33); (c) undertake and complete by July 31, 1983 a study on differential gas tariffs and review its findings with the Government and the Bank by December 31, 1983 and implement an agreed tariff structure by July 1, 1984 (para 2.37); (d) review its computer needs and applications and implement the findings of its financial consultant by June 30, 1984 (para. 3.12); (e) allocate funds promptly for international services to deal with emergencies such as a blow-out and fire (para. 4.35).; (f) maintain its debt service coverage at not less than 1.5 times (para 5.09); (g) maintain separate accounts for the project (para. 5.11); (h) promptly provide any funds in local or foreign exchange required for the project (para. 5.15); (i) revalue Abu Qir field's fixed assets according to a method accept- able to the Bank for the purpose of computing rates of return on revalued asets (para. 5.18); (j) not incur debts related to Abu Qir field unless the projected debt service coverage for the field is at least 1.5 for any year (para. 5.15). - 53 - 7.02 During negotiations assurances were obtained that WEPCO would carry out the drilling activities in accordance with a program satisfactory to the Bank. Agreement was also reached that WEPCO would: (a) undertake through consultants, a reservoir study by December 31, 1984 for evolving the optimum development plan for the field, and review the findings with the Bank (para. 4.06); (b) undertake and complete by December 31, 1982 a study to increase production from existing Abu Qir installations and review the findings with the Bank (para. 4.07); (c) submit to the Bank for its review a satisfactory training and recruitment program by December 31, 1982 (para. 4.33). 7.03 During negotiations assurances were obtained that EGPC would (i) undertake through qualified consultants, a feasibility study for domestic gas distribution network for Alexandria, and review the findings with the Bank; and (ii) review the findings of the Alexandria trunk pipeline study with the Bank (para. 4.16). 7.04 During negotiations assurances were obtained from the Government and EGPC to (a) as of July 1, 1984, set prices for Abu Qir field gas in such a way as (i) to reach an average level representing at least the marginal cost of gas production and an allowance for depletion of gas resources; (ii) to achieve a minimum of 10% rate of return on revalued net fixed assets in FY 1985 - FY 1987 and 15% thereafter (paras. 5.15 and 6.09); and (iii) revenues from the sales of Abu Qir gas should cover at all times operating expenses, debt service, working capital requirements of the Abu Qir field, and a reasonable contribution to the investments in the project area; (b) review with the Bank their plans to increase the average national price of gas and fuel oil to the level agreed to for Abu Qir gas (para 2.36). 7.05 With satisfactory resolution of the items outlined above, the project constitutes a suitable basis for a Bank Loan of US$90 million for a period of 20 years, including three years of grace at the current Bank lending rate plus an annual guarantee fee of 1%. -4 ANNEX 2.01 ARAB REPUBLIC OF EGYPT Page 1 of 2 Unit 1 .000 S ABU QIR GAS DEVELOPMENT PROJECT PETPOLFTu FXPL`PATTO8 A177 'RODUCTION AGREEMENTS 04) C '- C) 0 ;-a 0 - ABU MD GA > 2 BraSPetrO X 18000 14400 8 14400 1 54-~- -_ a -~ 00) 3 3 3 2.77 z 0 o0-- ..2 - -i : 0. Ix L.a~ C) '-xQo ox- u x I 10O*--.0 4) Lii O~~~ ~~~~~~UJ LLXLAi n UI I Delpco ABU NIAD I GAS FIELD 1PRODUCION AGREENENT 21. 5.73 2 Braspetro x18000 14400 8 14400 15400 3 330 330 29. 7.73 3 Transwor-ld 100 5625 4 20025 1125 2 125 455 28. 8,73 4 Mobil Delta 6500 23000| 8 43025 13000 4 2500 2955 24.12.73 5 Esso Delta x 15000 50000 12 93025 18000 4 - 2955 22.11,73 6 Deminex W.GuIf 2000 22000 8 115025 10000 4 3000 5955 2. 2.74 7 IEOC - Marathon 13000 20000 8 135025 4000 2 - 5955 26. 3. 74 8 Tripco x 7300 9000 6 144025 2500 2 - 5955 26. 3.74 9 L V 0 X 3000 9000 8 153025 2000 3 500 6455 23. 5.74 10 Conoco Delta 8500 23000 10 176025 4000 3 500 6955 20. 5.74 11 Amoco S.Gharib 100 2000 2 178025 2000 2 3000 9955 21. 7.74 12 Mobil Hurghada 2350 21500 8 199525 11500 4 6000 15955 21. 7.74 13 Union Banas 10000 30000 7 229525 12000 3 5500 21455 21. 7.74 14 Santa Fe E.Cairo X 4500 18000 7 247252 6000 3 1000 22455 10.12.74 15 Chevron Qattara X 7000 17000 7 264525 7000 3 2000 24455 10.12.74 16 Arco Matruh x 3500 11000 8 1 275525 7000 4 2000 26455 12.12.74 17 Shell S.Barrani X 640 25500 8 1 301025 13500 4 2500 28955 18.12.74 18 Shell Dabaa X 850 39500 8 1 340525 22000 4 3000 31955 18.12.74 19 Deminex-SheIl-BP 1350 30000 8 1 370525 16000 4 7500 39455 18.12.74 20 Phil. Hisp. 1200 45000 8 415525 17000 4 1000 40455 18.12.74 21 Esso R. S. 1200 48000 12 463525 1600C 4 4500 44955 14.12.74 22 MObil Sallum X 530 8250 8 471775 4250 4 - 44955 14.12.74 23 B. P. Natrun 400 10500 8 482275 4500 4 500 45455 18.12.74 24 Amoco S.Ghara 1350 29000 7,5 511275 14000 2,5 12000 57455 14.12.74 25 Amoco S.Belayim 600 20500 7,5 531775 7500 2,5 8500 65955 14.12.74 26 Transworld Amend 100 5625 4 2625 2 - 65955 18.12.74 27 Epedeco 52 12000 6 543775 7000 3 3000 68955 16. 6.75 28 GSI Mediterr. 3000 Speculta ive ISeismic & lnternati nal Bidding 31. 1.75 29 ELF Aquitaine 220 37000 8 580775 13000 3 2500 71455 30. 6.75 30 Amoco "Merged" 1223 (Gupco, Fapcoq & Nipco) into prod ction - Sharing 1. 7.75 31 Chevron Gemsa 720 22000 7 602775 ' 10000 3 5000 76455 4. 3.76 32 Murphy Mariut 5200 10000 8 612875 1000 2 1000 77455 18. 8.76 3 C.Super.Hurgh. 2000 11000 7 623875 6000 4 500 77955 4. 8.76 34 Union Amend. 11190 40000 10 633875 16000 4 - 77955 4. El.76 35 Conoco U.Egypt 300000 30000 12 663875 1500 1 1000 77955 7. 3.77 36 Mobil Sliver 5 4000 2 667875 4000 2 1000 78955 21. 3.77 37 Gulf Qantara 240 28000 8 696075 14000 3 4000 82955 28. 5.77 38 I.E.O.C. Sinai 2400 28000 8 724075 10000 3 1000 83955 31. 5.77 39 Conoco Bahariya 90000 26500 10 750575 4000 2 1000 84955 27.10.77 40 ELF Amendment 2600 45500' 8 1 759075 16000 3 3500 85955 3.11.77 41 S. S. L. Sinai x 4800 1000 2 760075 Spec. Sh t Cancelle 42 Transworld Amend 100 17625 7 772075 8000 1 - 85955 9. 2.78 43 COnoco Sinai 3600 24000 8 796075 10000 3 3000 88955 16. 2.78 44 Mobil Sudr 1000 8500 8 804575 1 25001 2 1250 90205 20. 2.78 IE 0 C Belayim |CONV[RTING COPE INTO PRfD. SHARING AS OF 1.12.78 ; I I I ~~~~~~~~~~6 - - 55 - ANNEX 2.01 Page 2 of 2 _' 0 - _ .2 49 BP Ras El Sabil 700 19000- -0 L- 70 0! 0 3 0 - 50 IE C N.or Sai 2400 200 7 805 50 1 10 70 .67 51 Conoco Qa>Pl ai n 86c 53000 10 90 4 > z c 0:6 0 a- ~~~- E2~R k a E 0 E ) E 53~~( SeISita262800 8 1097 230 : 4 200 1 050d7.27 q) ~ ~ ~ ~ * oLU- 3n s-DO 46 Agypetco Meleiha 1600 14000 8 818575 2000 2 1500 91705 30. 8.78 47 Murphy & Ultramar 5000 7000 8 825575 1000 2 1000 92705 30. 5.79 48 Union Zaforana 600 20000 8 845575 8000 3 2000 94705 3. 6.79 49 BP Ras El Sabil 700 19000 8 864575 7000 3 2000 96705 5. 6.79 50 IECoN.Port Said 2400 20500 7 885075 500 1 1000 9705 5. 6.79 51 Conoco Qa Plain 866 53000 10 938075 17000 4 5000 102705 7. 6.79 52 QuintanaT t hukeir 135 18000 8 956075 6000 3 1000 103705 70 6.79 53 Shell Sitr-a 25672 83000 8 1039075 23000 4 2000 105705 27.12.79 54 Agypetco W.Razzak 1800 14000 8 1053075 2000 2 1000 106705 29. 5.80 55 Totafl Darag 400 16000 8 1069075 6000 3 1050 107705 5. 6.80 56 Shelf Badrel Din 6700 23000 8 1092075 5000 4 500 108205 5. 6.80 57 Total Nebwi 125 16000 8 1108075 6000 3 1000 109205 25. 8.80 58 Sedco Tiba 6000 12000 8 1120075 3000 3 295 109500 25. 8.80 59 Esso East Zeit 0063 33000 4,5 -11 53075 17000 1,5 5000 114500 60 Tot. GPC Amal 70025 18000 4 1171075 6000 2 3000 117500 61 Tot. G PC S.Rmadan 0025 18000 4 1189075 6000 2 1750 119250 62 Phoenix Khalda 4000 18000 6 1207075 2000 2 1000 120250 63 Gulfstream Shadwan 600 9000 4 1216075 4000 2 0250 120500 64 II Sadat 2800 9500 4 1225575 4500 2 0250 120750 65 Total Mariut 2000 12500 4 1238075 0500 1 0000 120750 66 LL & e N. Amer 700 13000 6 1251075 5000 3 2500 123250 67 IEOC Feiran 100 15000 4 1266075 6000 2 1000 124250 68 Conoco Bitter Lakes 1200 19500 7 1285575 7500 3 1 000 125250 69 Agypetco MeL.Amend adding intangible drilling costs 70 Agypetco W-Razzak "I .1 71 Conoco Ras oh. 1600 13100 7 1298675 0600 1 1500 126750 72 iEOC Delta GAS 8000 63000 6 1361675 23000 2 - 126750 73 Medoil Matruh 4000 20000 6 1381675 8000 3 2000 128750 74 Sant Joe Tankai 250 23000 4 1404675 7500 2 4000 132750 75 Locheil Slieiba 5200 17000 5,5 1421675 5000 2,5 1500 134250 76 Locheil Hekmna 3200 11000 4 1432675 1000 1 2000 136250 77 Conaot Lagia 0045 20000 4 1452675 8000 2 2500 138750 78 Elf. B5P.Rosetta 4300 42000 6 1494675 18000 2 2000 140750 79 Totai N.Sinai sh27 2400 4900 675 1543675 25000 3 1000 141750 8OIEOCN. o 16,22M28 3600 74500 6.5 1618175 22500 2.5 4500 146250 81 B.P.N. " 21 1200 20000 7 1638175 10000 3 2000 148250 82 Con. Tot.W. Feiroan 0042 42000 8 1680175 16000 4 4000 152250 83 Petrofiria S.Dorag 416 21000 6 1701175 10000 3 1500 153750 84 Total Magawish 600 24000 7 1725175 10000 3 1500 155250 85 Conoco Mid Gulf 1200 134000 8 1859175 80000 4 9600 164850 86 Total N. Darcag 200 29000 7 1888175 10000 3 2000 166850 87 Total Bonos 10000 40000 10 1928175 10000 4 3000 169850 88 Murphy Taposiris 400 t 7300 6 1945475 0800 1 2250 172100 (A) 6 EGYPT ABU QIR GAS PROJECT NEW HYDROCARBON DISCOVERIES Name of Oil Company Location Name of Well Pay Zone Thickness API Gravity Flow Feet Bbl/day New Discoveries GUPCO Offshore 1. GS 160-30 Nukhul 86 16.8' 19,000 Gulf of Suez formation 2. GS 277-1 Kareem 38 36° 4,300 formation 3. GS 363-1 Nubia 60 440 7,588 Deminex Offshore 4. GS 195-1 L. Senonian 16 29.70 2,045 Gulf of Suez 5. HH 83-1 L. Senonian 90 13'-15' 1,900 6. KK 84-4A Turonian 100 30° 4,450 -2A Belayim 7. LL 87-3 Kareem 20 1,860 formation Total Shukheir 8. SB-1 Rudeis 26 35' 3,280 Bay formation Mobil Harguda, 9. Geisum-I Lower 143 23' 3,780 Offshore, Miocene Red Sea GPC Onshore 10. El-Khalique-4 Rudeis 26 29.40 1,180 Eastern Desert formation Petrobel Onshore Sinai 11. Rudeis S-I Nubia 16 17° 770 Upward Revision of Reserves from Producing Fields GUPCO Offshore 12. GS-19S Estimate of reserves enhanced by 2,000 million Bbls. Gulf of Suez Petrobel Offshore 13. Belayim Estimate of reserves enhanced by 500 million Bbls. Gulf of Suez CD ARAB REPUBLIC OF EGYPT ABU Q1R GAS DEVELOPMENT PROJECT PROJECTED AVERACE DEMAND FOR NAT'URAL CAS FOR ALEXANDRIA (In Million Standard Cubic Feet Per Day) 1980-81 1981-82 1982-83 1983-84 1984-85 1985-86 1986-87 1987-88 1988-89 1989-90 Power Stations Abu Qir - 4 36 58 72 72 72 72 72 72 El Mohmodia - 23 29 36 36 36 36 36 36 36 El Suff - 9 18 18 18 18 18 18 18 18 Damanhour 23 23 23 23 23 23 23 23 23 23 Kafer El Dawar - 15 31 32 41 41 41 41 41 41 Abu Qir Fertilizer Co. 38 38 38 38 38 38 38 38 38 38 Sponge Iron Complex - - - - 57 57 57 57 96 96 Cement Company - 10 15 15 15 15 15 15 15 15 Refineries - - - 20 20 20 20 20 20 20 Domestic - - - - - 1 4 7 7 7 Other Industries - 18 25 40 50 59 66 73 74 84 Total Demand 61 140 215 265 370 380 390 400 440 450 = = = = = = = = = = = ARAB REPIlBLIC OF EGYPT ABU QIR GAS DEVELOPMENT PROJECT PROJECTED AVERAGE I)EMAND FOR NATURAL GAS FOR CAIRO (In Million Standard Cubic Feet Per Day) 1980-81 1981-82 1982-83 1983-84 1984-85 1985-86 1986-87 1987-88 1988-89 1989-90 Power Stations Helwan 13 17 17 17 17 17 17 17 17 17, El Tebbien 3 7 7 7 7 7 7 7 7 7 Cairo East - 7 7 7 7 7 7 7 7 7 X Heliopolis - 5 5 5 5 5 5 5 5 5 Shobra El Kheima - - - - 19 58 96 116 116 116 Upper Egypt - - - - - 19 58 96 135 154 Helwan Cement Company 12 31 46 46 46 50 50 50 50 50 Tora Cement Company 10 31 31 31 31 31 31 31 31 31 El Kawmia Cement Company 8 24 39 39 39 39 39 39 39 39 Iron and Steel Company 22 33 36 39 39 39 39 39 39 39 Suez Fertilizer Company 6 6 - - - - - - - - Aluminum Company 1 1 1 1 2 2 2 2 2 2 Fire Bricks Company - - 2 2 2 2 2 2 2 2 Sandbricks Company 2 2 2 2 3 3 3 3 3 3 Household Consumption - 1 2 7 7 7 7 7 7 7 Total Demand 77 165 195 202 224 286 363 421 460 479 =S= ==S :=== C== ==j_ === =5 === SSS === ARAB REPUBLIC OF EGYPT ABU QIR GAS DEVELOPMENT PROJECT PROJECTED AVERAGE DEMAND FOR NATURAL GAS (In Million Standard Cubic Feet Per Day) 1980-81 1981-82 1982-83 1983-84 1984-85 1985-86 1986-87 1987-88 1988-89 1989-90 DELTA AREA Talkha Fertilizer Company 59 59 59 59 59 59 59 59 59 59 Talkiia Power Station 18 22 25 25 25 25 25 25 25 25 El Mahala Spinning & Weaving Company - 17 26 26 26 26 26 26 26 26 El Mahala Fiber Dying Company - 3 6 6 6 6 6 6 6 6 Total Demand 77 101 116 116 116 116 116 116 116 116 === SUEZ Power Stations Suez (ST) - - 9 39 68 77 77 77 77 77 Ismailia (ST) - - 9 39 58 58 58 58 58 58 Ismailia (CT) - - 3 3 3 3 3 3 3 3 Port Said (GT) - - 5 5 5 5 5 5 5 5 Suez Fertilizer Company 13 13 13 13 13 13 13 13 13 13 Suez Cement Company - - 13 13 13 13 13 13 13 13 Suez Refineries - - - - - 20 20 20 20 20 Suez Fertilizer Extension - - - - 39 39 39 39 39 39 Total Demand 13 13 52 112 199 228 228 228 228 228 === === === C== === = = S:s5 ==5 ==C 50 - 60 - ANNEX 2.06 EGYPT ABU QIR GAS DEVELOPMENT PROJECT PUBLIC INVESTMENT PROGRAM - OIL AND GAS SECTOR FY 1981 - FY 1983 1981 1982 1983 Total Production and Exploration EGPC 35 109 119 263 Others 21 28 84 133 Total 56 137 203 396 Refining and Processing EGPC - 3 124 127 Others 51 127 180 358 Total 51 130 304 485 Marketing and Distribution EGPC 15 33 146 194 Others 45 83 94 222 Total 60 116 240 416 Total EGPC 50 145 389 584 Total Others 117 238 358 713 Total Investments 167 383 747 1297 Retained earnings of the group will be insufficient, by far, to cover the estimated public funding of LE 1.3 billion over the next three years. The balance would have to be contributed through loans and appropriation of Govern- ment resources. Increased efforts to promote cofinancing in the oil and gas sector will permit the release of Government resources for users in other sectors. EGYPT ABU QIR GAS DEVELOPMENT PROJECT EGPC's ORGANIZATION STRUCTURE Minister of Petroleum .Supreme Petroleum .Council EGPC Board of Directors __ti Chairman Vice Chairman for DeputV Chairman Vice Chairman Deputy Chairman Vice Chairman Exploration and Finance and Economic for for for Production Affairs Planning & Projects Administration Operation Exploration Finance Engineering Administration Refin. & Manu. Department Department Department Department Department Production Follow-up Distribution Department Department Department Agreements Commerical Department Department Source: Egyptian General Petroleum Corporation t World Bank - 20395 0 EGYPT ABU QIR GAS DEVELOPMENT PROJECT FUNCTIONAL STRUCTURE OF OIL INDUSTRY Minister of Petroleum Supreme Petroleum Council |E.G. P.CC. Refining & ~~~~~~~~~~~~Marketing & Construction & CQ 0 Expol-at on l l Production FProcessing Pipelines E istribution Engineering Srr- _ | _ _ F~~~~~~~~~~~~~~~~~oreign _Foeg__ Partners Prnr ("PC - E g 3 - - -| Processing PPC P PETR - I |Foreign | _ ELNASAR l oop (95;||WPC)-- Company _SMD_Co,_ NP Alexandria PETROBEL __ Petroleum _ PETROGAS 0 Source: Egyptian Genral Petroleum Corporation WVorld Bank -20396 - 63 - ANNEX 4.01 EGYPT ABU QIR GAS DEVELOPMENT PROJECT PROJECT SCHEDULE 1980 1981 1982 1983 1984 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 PROJECT PREPARATION ENGINEERING AND DESIGN OFFSHORE FACILITIES ONSHORE FACILITIES SUBMARINE PIPELINE LPG PLANT TRUNKLINE _ _ PROCUREMENT DRILLING RIG B C DRILLING MATERIALS B) C OFFSHORE PLATFORMS P B OFFSHORE FACILITIES 1' B ONSHORE FACILITIES E B SUBMARINE PIPELINE ' B C TRUNK LINE p PIPING MATERIALS B -MCC LPG PLANT [ B C CONSTRUCTION OFFSHORE PLATFORMS _ _ _ OFFSHORE FACILITIES ONSHORE FACILITIES 3UBMARINE PIPELINE TRUNK LINE a LPG PLANT I WELL DRILLING j -_ _ COMMISSIONING AND START-UP LEGEND mf] Prequalification Completed nB Bids Received [j Contract Awarded World Bank-22696 - 64 - ANNEX 4.02 EGYPT ABU QIR GAS DEVELOPMENT PROJECT PROJECT COST ESTIMATE LE Millions US$ Millions Local Foreign Total Local Foreign Total DRILLING (9 WELLS) Materials (tubulars and wellhead) - 3.2 3.2 - 4.6 4.6 Services and consumables 0.6 6.4 7.0 0.8 9.3 10.1 Rig (cantilever jack-up) - 11.1 11.1 - 16.2 16.2 Mobilization and demobilization - 1.4 1.4 _ 2.0 2.0 Sub-Total 0.6 22.1 22.7 0.8 32.1 32.9 OFFSHORE PLATFORMS 6-pile platform - 2.1 2.1 - 3.1 3.1 4-pile platform - 1.3 1.3 - 1.9 1.9 Transport and installation 0.7 1.4 2.1 1.0 2.0 3.0 Sub-Total 0.7 4.8 5.5 1.0 7.0 8.0 OFFSHORE PROCESS AND UTILITIES Materials and equipment modules - 15.7 15.7 - 22.8 22.8 Installation 2.1 1.4 3.5 3.0 2.0 5.0 Sub-Total 2.1 17.1 19.2 3.0 24.8 27.8 SUBMARINE PIPELINES Materials - 2.6 2.6 - 3.7 3.7 Construction 0.4 5.3 5.7 0.5 7.8 8.3 Sub-Total 0.4 7.9 8.3 0.5 11.5 12.0 POWER SUPPLY Materials and equipment - 0.9 0.9 - 1.3 1.3 Installation 0:4 0.8 1.2 0.5 1.2 1.7 Sub-Total 0. 1.7 2.1 0.5 2.5 3.0 ONSHORE TERMINAL Materials and equipment 0.1 0.7 0.8 0.2 1.0 1.2 Construction 0.6 - 0.6 0.8 - 0.8 Sub-Total 0.7 0.7 1.4 1.0 1.0 2.0 TRUNKLINE AND DISTRIBUTION Materials 1.0 6.4 7.4 1.5 9-3 10.8 Construction 5.2 0.7 5.9 7-5 1-0 8-S Sub-Total 6.2 7.1 13.3 9.0 10.3 19.3 LPG PLANT 4.6 15.5 20.1 6.7 22.5 29.2 CONSULTANTS AND TECHNICAL SERVICES Project engineering, management, procurement and constructidn 0.6 6*2 6.8 0.8 9.0 9.8 supervision Technical Assistance 0.3 1.6 1.9 0.4 2.2 2.6 Reservoir evaluation 0.1 0.4 0.5 0.1 0.6 0.7 Studies 0.3 1.1 1.4 0.4 1.6 2.0 Training 0.1 02. 0.3 0.2 0.3 0.5 Seismic survey - 0.6 0.6 - 1.0 1.0 Sub-Total 1.4 10.1 U.5 1.9 14.7 16.6 Basic Cost Estimate 17.1 87.0 104.1 24.4 126.4 150.8 Physical Contingency 1.7 8.7 10.4 2.4 12.6 15.0 Price Contingency 3.8 11.7 15.5 6.2 17.0 23.2 Estimated Project Cost 22.6 107.4 130.0 33.0 156.0 189.0 - 65 - ANNEX 4.03 EGYPT ABU QIR GAS DEVELOPMENT PROJECT Estimated Schedule of Disbursement IBRD Fiscal Year and Quarter Cumulative Disbursement at End of Quarter (US$ 000) 1982/83 September 30, 1982 5,000 December 31, 1982 10,000 March 31, 1983 15,000 June 30, 1983 30,000 1983/84 September 30, 1983 50,000 December 31, 1983 70,000 March 31, 1983 75,000 June 30, 1984 80,000 1984/85 September 30, 1984 85,000 December 31, 1984 87,000 March 31, 1985 89,000 June 30, 1985 90,000 February 1982 ANNEX 5.01 - 66- EGPC Unconsolidated Income Statement (In Million of Egyptian Pounds) 1977 1978 1979 Revenue from Operations 543 647 1776 Operating Expenses (357) (366) (590) Operating Income 186 281 1186 Non-Operating Income 87 55 136 Net Profit before Taxes 273 336 1322 Taxes (75) (112) (502) Net Profit after Taxes 198 224 820 Retained by EGPC 21 32 91 Distributed to Government 177 .192 729 E.G.P.C. BALANCE SHEET IN L.E. MILLIONS 1973 1974 1975 1976 1977 1978 As at December 31st Fixed Assets 58.5 68.5 74.6 77.0 79.8 124.7 Less Accumulated Depreciation (30.7) (31.8) (35.7) (44.) (53.6) (90.8) 27.8 36.7 38.9 32.9 26.2 33.9 Projects in Progress 14.1 13.0 36.8 50.2 64.7 89.2 Investments 137.4 186.6 235.3 269.0 297.7 320.6 Domestic Lending 6.7 0.9 0.5 15.6 - - Current Assets 83.9 123.3 265.7 355.7 346.7 344.5 o Less Cutrent Liabilities (78.3) (124.4) (252.0) (335.1) (336.9) (357.2) Working Capital 5.6 ( 1.1) 13.7 20.6 9.8 ( 12.7) Total Assets 191.6 236.1 325.2 388.3 398.4 431.0 Equity 50.0 50.0 50.0 50.0 50.0 50.0 Reserves 42.5 52.5 96.4 152.5 141.1 201.0 Total Equity 92.5 102.5 146.4 202.5 191.1 251.0 Long Term Financing 99.1 1I1.6 178.8 185.8 207.3 180.0 Total Liabilities and Equity 191.6 ru.1 325.2 388.3 398.4 431.0 Current Ratio 1.1 1.0 1.1 1.1 1.1 1.0 a U, 0g DATL: 02108/82TIME: 11114128 ABO QIR GAS DEVELOPMENT PROJECT T'ITAL GAS FIELDS SOURCE AN' APPLICATTnN OF FUNDS IN THO,SAN0 OF EGYPTIAN POUNDS AFTER REVALUATIDN or ASSET3 1981 19A2 1983 1984 1985 1986 1987 1988 1989 1990 S1 JRCES3 ....._..___._ N-T INClnME RFFnRE TNTEREST 88 4,842 6,815 11,529 20,051 20,668 20,459 30,328 30,615 30,684 DEP9ECrATIfN 2,484 2,7^7 2,951 4,700 11,984 13,063 14,239 15.520 16,917 18,440 TJ9TERNAL CASH GENERATIOtJ Z,572 7,5't9 9,766 16,229 32,041 33,731 3'J,698 :048 47953.2 49.124 35333 Xmz32Z x33x33 3a332X 3w33323 gXt33S 3Bauma Mangan mag333 363333 INCREASF IN ACCOUNTS PAYABLE 249 1,547 12,241 2,506 (15,502) 127 139 154 168 186 WORLD RANK DRA4WOWN , 600 20,010 41,400 * OTHER LONG TEQM 0RAWDOA' e 4P3 12,227 25,300 * - * * * INCREASF IN CAPITAL 537 , 5,297 * 6 s . . *----W _ ,w.. ., .-. _.,,, ." ... t 71TAL SnUJRCES 3,358 10#2s9 59,541 85,435 16,555 33,858 34,637 46,002 47,700 49,310 :suzz axtMen ux5gSg wss-s- Bananas ma*gma *ggGXx man-, *uages assume USFS OF FWilnS FIELD ASSTS 683 7,048 56,629 65,838 * ' ' INCREASF !k1 ACCOUNTS RECEIVABLE 538 1,567 789 2,003 4,114 652 657 '4,26l 1,029 1,033 l'ICREASF IT' CASH 1,022 4;4 I1,205) 7,771 (7,S25) 14#079 15,893 24,294 30,064 32,509 TNTLRF5T nf WORLD BANK LOAN a I8 1,487 5,755 8,378 7,870 7,363 6,155 6,347 5,839 INTEREST n, OTHER LONG TERM LOANS 410 4n6 1,137 3,361 4,699 4,367 4,035 3,703 3,372 3#039 REI1RURSEMFNT, WORLD RANiK LOAN - , , , 3#653 3,653 3,653 3,653 3,653 3,6S3 RrTI43t)iREMFNTp OTHFR LONG TERM LnANS 706 7rh 706 706 3#236 3,236 3,236 3,236 3,236 3,236 TOTAL DF8T SERVICE 1,116 1,IO 3,330 9,822 19,966 19,126 18,257 7,4'47 16,608 15,7,7 9=9=9 =zxxx ss;-scs =mamas smsanso *u-sa *as--s *Naxos Nams*- *ls-au TITAL, APPLICATITNS 3,359 1D0259 59,543 85,434 16,555 33,857 34,837 46,002 47,701 49#309 ozzsw 288,480 sttsss xxoauu Banans- *ze-g gammas Naxos* xam-ls Samoan DFaT SERVICE COVERAGE 2.30 °6,1 2.93 1,65 1.60 1.7b 1.90 2,63 2.86 3.1 RETJRN nN ITVESTMENT s 17.999X DATLI 02/DA/82TIME, 11113127 ABU QIR GAS DEVELOPMENT PROJECt TOTAL GAS FIELDS INCOME STATEMENT IN THOU9SAND OF EGYPTIAN POUNDS AFTER REVALUATInN OF ASSETS 1981 1942 1983 1984 1985 1986 1987 1968 1989 1990 PRICE IF LPG, LE/TON 24,00 26,10 29,00 31.00 34,00 37,00 41,00 44,00 46.00 53.00 PRICE 3F CnNDENSATE, LE/TIN 7,4n 8.*l 8,*1 9,62 10.51 11.47 12,51 13,62 14,87 16.21 AVFRAGE PRTCF nF GAS, LE/4CF 0.17 0,o3 0.56 0,70 0,75 0,80 0,85 1.20 1.28 1,36 YrARLY SALE OF GAS, MMCF 36,500 36,5nO 36,500 45,625 73,000 73,000 73,000 73,000 73,000 73,000 YEARLY SALFS OF CONDENSATEt 000 TON 69 69 69 88 146 146 146 146 146 146 YeARLY SALFS OF LPG, 000 TONS . 15 56 so s8 5U 58 58 SALL OF CONDENSATE* 000 LE 508 594 605 846 1,531 1,?67 1,623 1,984 2,166 2,361 SALES OF LPG. 000 LE * - m 452 1,977 2,156 2,352 2,561 2,798 3,048 SALL OF GAS, 000 LE 6,205 15,6q5 20,440 3t,938 54,750 56,400 62,050 67,600 93,440 99,280 TlTAL RFVENUES 6,713 16,2a9 21,045 33,236 58,256 62,2Z9 66,225 92,145 95,404 104,669 rsznxt *Nxos *Sts:t *X=sax Banno mammas *-g"$- *as$g mammas *tos"" c OPFRATING EXPENSES O3ERATyiNG COSTS 3,134 3.3p6 3,659 6,524 15,427 16,970 16,667 20,533 22,586 24,846 DEPRECIATInN 2,484 2,7n7 2,951 4,700 11,984 13,063 14,239 15,520 o16917 1,0440 RIyALTy & TNCOME TAXES 1,007 5,374 7,620 10,483 10,790 11,528 12,860 25,764 20,286 3071 9 TITAL. COST nF GAS 6,625 11,4n7 14,230 21,707 38,Z01 41,561 45,766 61,017 67,709 74,005 I'JCOME aEFORF V4TEREST 88 4,842 6,815 11,529 20,057 20,6680 20,459 30,328 30,615 30,684 I'TEREST, LONG TERM LOANS 410 3R1 353 2,523 13,077 12,237 11,396 10,558 9,719 a6,88 ,.0- 0--t s. w,-- 0 f Ow"" ....... ,.O.- w*" ."00 . . ,.0 "_w-0 "--._w NET INCOME AFTER INTEREST (322) 4,4h1 6,462 9,006 6,980 6,431 9,061 19,770 20,696 21,806 OPERATING RATIO 0.99 0,70 0.68 0.65 0.66 0.67 0,69 0.67 0.69 0.71 DATLI 02/1A/8? TT4El 11113145 AWJ OIR GAS DEVEL8PMENT PROJEMT TOTAL GAS FIELOS BALANCE SHEET IN THOlJSANDS OF EGYPTIAN POUNDS AFTER REVALuATION oF ASSETS lq8B 19'2 1983 1984 1985 19s6 1967 1908 1989 1990 RrVALUEFr rPOSs FTXEn ASSETS 46,634 So8j1 55,406 206,428 225,007 245,258 267,330 291,390 317,616 346,202 LrSS ACCUMULATED )EPRECIATION (5,576) (8,706) (12,527) t18,354) (31,991) (47,933) (66,486) (87,989) (112,824) (141,418) NET RFVALIIED FIXED ASSETS 41,058 :;7045 42,879 788,074 1937 016 197,325 200,844 203,401 204,792 204,734 PRTJECTS IN PROGRESS 683 7,9¶5 67,528 ' ' ' TITAL REVALUED FIXED ASSETS J1, 741 49,960 110,407 188,074 193#016 197,325 200,844 203,401 204,792 204,784 ACClJ!TS RECEIVABLE t,104 2,67t 3,460 5,464 9,577 10,230 10.886 15#147 16,176 17,109 CA94 1,026 1,40 254 8,025 501 14,580 30#474 54,767 84,831 117,340 1VJTAL ASSETS 43,871 54,041 114,121 201,563 203s094 222t135 242,204 273,315 305s799 339,33 2s-mzz amWaxa xx=xxz axassall *asomaxas"a noaal axnx *snows wassai-g somas--" L!TPILITIES AND EQUITY EIPC SHARE 22,354 22,354 27,650 27,650 27,667 27,667 2766T7 27,b67 27,667 27,667 RFSLRVE OF REVALUATION 14,038 17,744 22,292 32,228 49,154 66,526 84,265 102.362 120*667 139,p99 RETAINED EARNINGS (ACC LOSSES) (2,834) 1#627 8,090 17,097 24#076 32,506 41,569 61,339 82,234 104,041 *~~fl5 *fl~~S ~fln sinS* *ss... SeSsne. ..... we "..awe" lS..--.. TOTAL E4UITY 33,558 41,775 58,032 76,975 100,697 126,699 153,521 191,368 230,S68 270,807 WIRLD BANK LnAN * 640 20,700 58,447 54,794 51,141 47,486 43,635 40,182 36,529 OTHER BORROWINGS 9,180 8,8q7 20,417 42,481 39,245 36,009 32,773 29,537 26,301 23,065 TOTAL LONG TERM LIABILITIES 9,180 9,587 41,117 100928 94,039 87,150 80,261 73,372 66,483 59,594 CURRENT PnpTION, WORLD BANK LOAN - a . 3,653 3,6S3 3,653 3,653 3,653 3,653 3,653 CURRENT POpTYON, OTHER LOAN 706 70h 706 3,236 3.236 3,236 3,236 3#236 3,236 3P23- Wee.". flfl* .*5 Wem5YU minSfi.. 0ineOSfig ainSfim SinSUCwt 0n-in... o*wflfl CURRENT PIRTTON, LONG TERM LOANS 706 716 706 6,889 6,689 6,689 6,889 6089 6,889 6,so9 ACCOUNTS PAYABLE 426 2, 03 14,264 16,771 1,268 1i395 1,534 1,067 1 ,67 2,043 s.e.c. en..- .,..we _*.**"- mess-e. WUSWw-S --fl5SU WS*Sfl .Ssw*.* *SS@l*q- TOTAL CURRENT LIABILITIES 1,132 277S0 14,970 23,60 6,157 8,283 8,423 8,76 6,746 8,931 I TITAL EUi)ITY AND LIABILITIES 43,870 54,0Q2 114,119 201,563 203,093 228#132 242,S05 273,316 305,797 339,332 > *w3333 u* U Buanau R333 333 3333333 3333333 333333 3333333 533333 DEAT EQUITY RATIO 0.23 0,20 0.42 0,S8 0,50 0,43 0,36 0.30 . 0.24 0.20 CJRRENT RATIO 1.88 1.51 0.2S 0,57 1.24 3,00 4,91 o0.15 11,SS 15*07 RFT'JRN nN REVALUED NET FIXED ASSETS 0,2 11.7 16.0 10,0 1O.S 10o6 10.3 15, 015,0 15.0 - 71 - ANNEX 5.06 ARAB REPUBLIC OF EGYPT ABU QIR GAS DEVELOPMENT PROJECT Assumptions for Financial and Economic Statements 1. Inflation on local cost has been estimated at 16% in 1981, 14% in 1982, 13% in 1983 and 12% in 1984 and thereafter. Inflation on foreign costs has been estimated at 9% in 1981, 8.5% in 1982, 7.5% in 1983 to 1985, and 6% thereafter. 2. Sales of gas are based on a selling price increasing progressively to meet a 10% rate of return in FY1985 through 1987, and 15% thereafter. Sales of condensate are taken at LE 7.4/ton in 1981 increasing with local inflation thereafter, based on the EGPC average net back for one ton of crude oil. Sales of LPG are supposed to be realized at LE 24/ton in 1981 increasing in line with inflation each year. 3. Assets are assumed to be depreciated on a straightline basis over the life of the field (18 years). Royalties are taken at 15% of the sales and income taxes are 50% of net income. For income tax purposes, depreciation expense is based on historical cost. Balance Sheet and Flow of Funls 4. Gross capital assets and accumulated depreciation are revalued at the composite rate of 9% per year. 5. Accounts receivables represent two months of sales. 6. Accounts payable are one month of operating expenses. 7. Cash is assumed to be at least one week of debt service and local expenditures. Economic Statements 8. Social discount rate is assumed to be 10% per year. 9. Fuel oil, gas oil and LPG economic costs are based on December 1981 quotation, and are expected to increase by 3% a year in real terms until they reach the equivalent of $60/barrel of crude oil. EGYPT AQU OIR GAS DEVELOPMENT PROJECT ECnNOMIC ANALYSIS I's THOlISAND OW EGYPTIAN POUNDS rOHISTANT DECEMBER 1981 PRICES NEW WELLS 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 N4TAiRAL GAS VALUE, LE/MCF AS FUIEL nTL REPLACEMFNT 3,27 3.37 3.47 3.57 3,68 3,79 3.90 4.02 4,14 4.26 AS GAS nTL REPLACE4ENT 6,15 6,33 6.52 6,72 6h92 7.13 7.34 7,56 7,79 g,lo C'lel)ENSATE VALUE, LE/TON 253 261 269 277 285 294 303 312 321 331 LPG VALIIE, LE/TO)N 327 336 346 357 361 379 390 402 414 42* NAT!)RAL GA8 PRODUCTION , 9,125 36,500 36,500 36,50 36,500 36,500 36,500 C1P;ENSATE PROnIJCTTlNr 000 TONS - . , 19 77 77 77 77 77 77 LPG PQ.1rUC?TJON, 000 TINS s o5 58 58 s8 56 5s 5S VALJE oF NATURAL GAS, OOOLE . 48,098 198,180 204,166 210,152 216,503 223,052 229,600 VALJE OF CrVNDENSATE, OOOLE . 5,327 21,942 22,b0O 23,278 23,977 24,696 25,437 VALJE *F LPG, OOOLE - - 5,173 21,314 21,954 22,612 23,291 23,990 24,710 -000 , __..... . ..,_ ...... .. . . ~*_,. ..w... ~w.w. * ..... . .w..u ,S *,.. ........., .,...,w**, IlTAL SFNIEFTTS , 58,598 241,436 248,720 25b,042 2a3,771 271,738 279,747 O1T4L CAPITAL CnSTS 808 8,322 61,330 65,102 a . . . . OPFRATTKIG FXPENSFS . 2,526 10,104 10,104 10,104 tO,104 10,104 10,104 ....* , , ,,,,,,, 3w ,. _ . *-w_o* 77 W . w.ae *ff;7.7-w. TOT&L COSTS 808 8,322 61,330 67,628 10,104 10,104 10,104 10,104 10,104 10,104 3333 gas33 33x3333 33s333 3333t33 *33333 3xss333 3m3ssage *833333 333n33d NrT BEN4FITS (808) (8,322) C61,330) (9,030) 231,333 238,616 245,939 253,667 261,634 269,642 ACCJMlIl-ATE0 PRFSENT VALUE OF NET BENEFITS (889) (9,210) (64.965) (72,428) t01t380 264,363 417,074 560#266 694,526 820,320 RrTJRN ON T"QVESTMENT a t2t,836K EGYPT ABU QIR GAS DEVELOPMENiT PROJECT fCONDMIC ANALYSIS IN THOJISAND OF EGYPTIAN POUNOS CONSTA1t DECEMBER 1981 PRICES NEW WELLS 1991 1992 1993 1994 1995 1996 1997 NAT'lRAL GAS VALUE, LE/OCF A4 FtUFL nIL REPLACEMENT x4o3q 4,52 4.66 4,80 4,9i 5,09 5.24 AS GAS (ITL PEPLACE"EJT d,2A B,5: 8.77 9,03 9,30 9*58 9,87 C14nENSATE VALIIE, LE/TnO 3'Ji 351 301 372 383 395 4401 LPG VALU1E, LE/TON L31 4 466 480 494 509 524 NATJRAL GAS PPflDUCTIflnr 3,5n, 36,5 36,500 36,500 3b,500 38,500 3v,500 CO4)EMSATE PROnUCTIVN, 000 TONS 17 7 T7 77 77 77 71 LPG PRJPUCTYON, 000 TONS 5R S8 S6 so 58 58 Bf)LFTT$ VALJE IF NAtJRAL GAS. (,OLE 236.sit 2 433, 251,098 258,573 28b,246 274,283 282,517 VALUF ')F CINDENSATE, DOOLE 2 2 0h, 26,9wt 27,796 28,830 29,489 30,374 31,265 VALUE IF LPG# nOOLE 25,4Si 28,2i4 27,001 27,811 28,648 29,505 30,390 T"eTAL RFUEFITS 268,I' 296824 305,895 315,014 324,381 3340182 3440192 sunmNu2 uzuzzugg: a3fttg*UW3 R.UWUMUUU sSzauESta *--.35333 auuuuuuuu C^PTP lIT4L CAPITAL COSTS 6,69. 4 - OPERATTIG FXPENSES I lOuIQ 10164 10,104 10104 10,104 10,10 4 1OP104 JITAL CrSTS 10.lOiu 10,104 16,798 10,104 10,104 10,104 10.104 24=X:SU *aXSU:N*s- : JaxntgSX Jax---$x *t---$a *--lxY XERN-$-xxxag- NET 4F4FFITS 27 806t 286,72" 289,097 304,910 314P276 324,058 334,068 ACCJr4LILATED) PRESENT VALUiE (IF NET 9ENEFITS 938p24k l,O48,795 !,150,121 1,247,278 1,338,316 1,423,652 lpboj3631 0 m' Mb O - 74 - ANNEX 7.01 EGYPT ABU QIR GAS DEVELOPMENT PROJECT Selected Documents and Data Available in the Project File EGPC Law 20/1976 pertaining to the functions and authority of EGPC Order No 758 of 1972, the Executive Regulation of Law No 66 (1953) Financial Statements of EGPC for FY1978, FY1979, and FY1980 Organization Chart of EGPC Investment program of EGPC for FY1981-FY1983 Arthur Andersen reports on the financial systems of EGPC. WEPCO Phillips Petroleum Concession Report WEPCO financial statements (FY1979, FY1980) Organization Chart Abu Qir Gas Development Report on Abu Qir optimization study Report on Abu Qir reservoir study Report on LPG recovery study Emergency procedures for Abu Qir operations Study of market for Abu Qir gas Financial projections for Abu Qir project. Related listings and computer programs. Abu Qir financial statements (FY1979 - FY1980) IBRD 15795 27'~~~~~~~~~~ ; ,'29' 'SS l ?: j .i '/' t r r rJ a oa' S a -a Ab' M: ' MATRUH AhpOr..71 -' 7 _~~~~~~~~I~?RT SAID ALEXANGE.A,1 Zlh112 RAS El DABAA 0 T ir Yi EL HAMRA MEAM3- /~~~~~~~~~R - G 'T "K~~~~~~K - \'X 0-OAN11/ ' | n _ Wad R NcI k-n. SM IAg J 12' x\ > g~~~~~~~ ~~~~~~~~IiAIRO 112'~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~~~~~0 -30' SUEZ5/Xt,a\= > =~= W8 -- WAS-.A {~~~~~~~~~~~~~~~h I Gh-,:d,,31 ;Ar - 32_ ELWAN Ab. Gh-d,B25 E (. r / ID 42 : r re r3 -ryrEr--23-2 Senn~~~~~~~~~~~~An/ SW-3am + AIN ELBSOUKHNA 27-~~~~~~~~~~~~~~~~ A7m fiu 'O IrI' :~~~ ~ wo. Won \' --- --- | , ___ B-d-- 27'LEBANdSYRIA ARAB REPUBLIC OF EGYPT WAN 'e-!Z;~~ ~ /v /S.-ENO IRAQ ABU QIR GAS DEVELOPMENT PROJECTX f ' -- 8\z x. \ fJ0RDA>z > ~~~~~~~~~~~Sr dy .-b-d-3y 49 Wells SAUD ARSA---BIAst g-s pipe.ld- , Sue2 C-/o2 ' I LIBYA ARAB REPUJBLIC; ,SUIAbl --c' p -0 pelhne, -de,-osfrUct,o. - vR,Y., ° 25 "I 75 10 _ OF EGYPT,' -25- --- -G pipelh-e -nd., c-nSrut-o t- ,. D.p-es,-s KILOMETER5S ~ 28' X L - _._ _ ,5._ _ .- _ _ \ ®J=B= A = _ Len, =w X SV2 ! -eAz ,N ,tS UHN CHADu~~~~~~~~~~~~~ ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ 29' D 20 2p' 1 30 ' pS ' 28< __ __ _ 3n« ) 3,IA 32N33@ '\ 9 27'~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~0 1 2 3 3009' 30-12' 30'15' 30-15' 30 30' PROPOSED WELL LOCATIONS QpGAS EGYPT Proo-d G.,os W.ll, ABa ABU QIR GAS DEVELOPMENT PROJECT E.o g G.,Vos QI6~ - EQist nSt GDS Witils f>_+2 AGl DA > eAOI 11 EXISTING PROPOSED | O -4-AOI5 21 t I-4- _31 45 _ Plorloso 31'45' ___ _ _/ xS_-{g75O __S >AOI7, /AOl- 31'24'_ - - - 24 onor IS SEoo. AC' 3MX- ~~~~~~~~~~~~~~~~~~~24" T-k 7 E - 9 o -e ipl- i0t - 3 8" -od 12" Dm,EbwIo- Go, P,p.Ihnes GOsoosO T--',nl LPG PlMn _ ________,;,, _____ / I r.o Plons s_ ~~~~~~~~~~~-__ __-~~~~~~~~~~~~~~~~~~~~~ / _ ~~~~~~~~Power Stations - - - - - - - - - - - - - - - ~ ~ ~ ~ - oocss,ooBoodo,. -- ------- -------F---S/ Zone----- / Cootots, 30 09 3012 201l5 7 I- RD,IWOYS SYRIAN 30~o0 LEBANON ARA 3_ Ab Q ISRAEL, _R\ / ABU QIR LEASE Ac ISRAEL )AI'ttondsRo0 -JORD6AN NORTH AZFXAVDRA_IA CAIO OFFSHORE----- SAUDI A_ - ARABIA… ARAB REPR OP J i U D A N -31-30' 31i30 CHAD i I ' 2 ABU O/F / ~~~GAS FIELD _---,Z GAS f/-D ,; ROSETTA /-~ / ____--~ _-~~~~~ -' - - 31-15', 3i15' XANDRIAND FOWA- EL MAHMUDIYA / /~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ KILOME7ERD ; 0 5 -S 5 20 DAMANHUR \ 90G/ M~~~~~~~~~~~~~1., mto to bees sWsfsr, Df ehe Wori/ fsso. oS mf ..sspt,nss fstsLhe sto,o'1flsests\ _/n @~~~~~~~~~~~istf,Oot,A',o-- noj odoossisosssodod> _ l~ ~~ ~ ~ ~~~~~~~~~~~~~~~~~~~~tNisssp'slo Wust_ __ 3u-uosstt\o_ 1