-AJ 3 z JY 57 Document of The World Bank FOR OFFICIAL USE ONLY Report No. 9383-EGT STAFF APPRAISAL REPORT ARAB REPUBLIC OF EGYPT GAS INVESTMENT PROJECT JUNE 3, 1991 Country Department III Industry & Energy Operations Division Europe, Middle East and North Africa Regional Office This document has a restricted distribution and may be used by recipients only in the performiance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. CURRENCY EQUIVALENTS Currency Unit Egyptian Pound (LE) - 100 piastres LE 1.0 = US$0.353 (December 1990) US$1.0 - LE2.83 (December 1990) WEIGHTS AND MEASURES BCM (billion cubic meters) 35.3 billion cubic feet GWh (Gigawatt hour) - 1,000,000 kWh cm (centimeter) = 0.4 inch mcf thousand cubic feet mcfd - thousand cubic feet per day mcm = thousand cubic meters mmcfd = million cubic feet/day MT G million tons MTOE million tons of oil equivalent MW (Megawatt) = 1,000 kW One cubic meter = 264 US gallons = 35.31 cubic feet One kilometer (>m) 0.6214 miles One metric ton (mt) (1,000 kg)- 2,205 pounds tcf - trillion cubic feet tonne = 1.1 short ton GLOSSARY OF ABBREVIATIONS AIC - Average Incremental Cost CIDA Canadian International Development Agency EGPC = Egyptian General Petroleum Corporation EIB = European Investment Bank ENPPI = Engineering Company for Petroleum and Process Industries ESMAP = Energy Sector Management Assistance Program GCGDP = Greater Cairo Gas Distribution Project GDP - Gross Domestic Product GEF = Global Environment Fund GOE = Government of Egypt GPC = General Petroleum Company 5UPCO - Gulf of Suez Petroleum Company ICB = International Competitive Bidding IOC = International Oil Company LPG - Liquified Petroleum Gas MIS = Management Information System PETROBEL - Belayim Petroleum Company PETROGAS = Petroleum Gas Company PPC = Petroleum Pipeline Corporation PPAR - Project Performance and Audit Report PRS - Pressure Regulation Stations PSC = Production Sharing Contract SAL = Structural Adjustment Loan SCADA = Supervisory Control ar Data Acquisition SUCO = Suez Oil Company TGG - Trans Gulf Gas TOR - Terms of Reference WEPCO = Western Desert Petroleum Company FISCAL YEAR July 1 - June 30 FOR OMCuL USE ONLY AR"ABRMELIC OF E Table of Contents pare N!o.. LOAN AD PROJECT SUMRY .. .. .-i I. Il RODUCTICN . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 II. SECTORAL STING . . . . . . . . . . . . . . . . . . . . . . . . . 2 A. Energy Endowment . . . . . . . . . . . . . . . . . . . . . . . 2 B. Developments in the Sector . . . . . . . . . . . . . . . . . . 4 Pricing. . .................... 4 Poverty Impact Minimization . . . . . . . . . . . . . . . . 5 SupplyIncreases .5 Value Added Increase of Products . . . . . . . . . . . . . 5 Private Sector Support .5 III. NATURAL GAS SUBSECTOR.6 A. Institutional Setting .. 6 B. Gas Reserves .. 7 C. History of Gas Supply and Consumption . . . . . . . . . . . . 7 D. Gas Supply - Futre . . . . . . . . . . . . . . . . . . . . .9 E. Development Plan ..10 F. Gas Pricing .11 G. Bank's Role in the Sector and Experience in Past Lending 13 IV. THE BORER . . . . . . . . . . . . . . . . . . . . . . . . . . 14 A. Statutory Functions .14 B. Capital Structure .15 C. Organization and Management . . . . . . . . . . . . . . . . 15 D. Functional Structure ....... .. .. .. .. .. .. . 16 Exploration and Production ..... . . . . . . . . . . 16 Refining and Processing . . . . . . . . . . . . . . . . . 16 Petroleum Pipeline . . . . . . . . . . . . . . . . . . . 16 Distribution .16 Accounts and Audit .16 Insurance . . . . . . . . . . . . . . . . . . . . . . . . 17 This report is based on the findings of an appraisal mission to Egypt in November 1990, comprising Nessrs. G. Stuggins (Task Manager), M. Shirazi, N.C. Krlshnamurthy, M. Lavitaky, U. Klrmani, and D. McKay (Consultant). 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. - ii X able of Contents (Contlnued) Page No. E. Petroleum Gas Company (Petrogia) .... . . . . . . . . . . 17 Background ...... . . . .. . . . .. . . . .. . . 17 Capital Structure . . . . . . . . . . . . . . . . . . . . 17 Organization . . . . . . . . . . . . . . . . . . . . . . 17 Insurance ...... . .. . .. . . .. . . .. . . . . 18 Project Engineering and Implementation ... . . . . . 18 V. THEPROJECT .18 A. Project Objectives and Scope . . . . . . . . . . . . . . . 18 B. Rationale for Bank Involvement . . . . . . . . . . . . . . . 19 C. Project Description . . . . . . . . . . . . . . . . . . . . 20 Greater Cairo Gas Distribution Component . . . . . . . . 20 Trans Gulf Gas Component ..20 D. Cost Estimates . . . . . . . . . . . . . . . . . . . . . . . 21 E. Financing Plan . . . . . . . . . . . . . . . . . . . . . . . 22 F. Procurement . . . . . . . . . . . . . . . . . . . . . . . . 23 G. Disbursements . . . . . . . . . . . . . . . . . . . . . . . 25 H. Monitoring and Supervision . . . . . . . . . . . . . . . . . 26 Retroactive Financing and Advance Contracting . . . . . . 26 I. Environment . . . . . . . . . i . . . . . . . . . . . . . . 26 Environmental and Safety Review of GCGDC . . . . . . . . 27 Environmental and Safety Review of Trans Gulf Gas Component . . . . . . . . . . . . . . . . . . . . 27 J. Project Management and Implementation . . . . . . . . . . . 28 Greater Cairo Gas Development Component . . . . . . . . . 28 Trans Gulf Gas Component . . . . . . . . . . . . . . . . 29 VI. FINANCIAL ASPECTS . . . . . . . . . . . . . . . . . . . . . . . 29 A. Historic EGPC Financial Performance . . . . . . . . . . . . 29 B. EGPC Accounts and Audit . . . . . . . . . . . . . . . . . 31 C. Historic Petrogas Financial Performance . . . . . . . . . . 32 D. Future Petrogas Investments and Financing . . . . . . . . . 33 E. Petrogas Accounts and Audit . . . . . . . . . . . . . . . . 35 VII. ECONOMIC ANALYSIS ................ ...... . 36 A. Economic Justification . . . . . . . . . . . . . . . . . . . 36 B. Project Economic Costs . . . . . . . . . . . . . . . . . . . 36 Ci. Project Economic Benefits . . . . . . . . . . . . . . . . . 36 D. Economic Rate of Return ...... . .......... . 38 E. Risks .......................... 39 VIII. AGREEMENTS REACHED AND RECOMMENDATIONS . . . . . . . . . . . . . 39 eiii Zble of Contents (Centinued1 ANNEX I Functional Structure of Oil Industry ANNEX I; EGPC Organization Chart ANNEX III Natural Gas Supply and Potential Demand Assessment ANNEX IV Petrogas Organization Chart ANNEX V Greater Cairo Gas Distritution Component ANNEX VI Trans Gulf Gas Project ANNEX VII Gas Market Development ANNEX VIII Refinery Sector Investment Planning Study - Draft TORs ANNEX IX Gulf of Suez Gas Development Study - Draft TORs ANNEX X Cost of Gas Distribution Study ANNEX XI Project Supervision Plan ANNEX XII EGPC Financial Performance ANNEX XIII Petrogas Financial Performance ANNEX XIV Economic Analysis IBRD Map Nos. 22905 and 22906 - i a RAB REPUBLIC OF EG9PT GAS INVESTMENT PROJECT LOAN AND PROJECT SUMMARY Borrower,: Egyptian General Petroleum Corporation Guarantor: Arab Republic of Egypt Amount: US$84 million Terms: Standard IBRD terms, with 20 years maturity Project Obiectives The primary objectives of the project are to increase and Descrptio5 : the use of a nontradeable commodity, natural gas; to release tradeable petroleum products for export; and to decrease the environmental impact of fuel use. The project focusses not only on increasing the supply of natural gas by reducing flaring and debottlenecking the supply constraints rf transporting gas to market, but also provides the infrastructure required to maximize the value added of the fuels being substituted. The project enables the delivery of a clean-burning fuel to the Greater Cairo area to displace petroleum products, thus mitigating air pollution problems. The institution building efforts for Petrogas initiated in the previous Bank loan would be further enhanced to increase its commercialization. BenLefit$ The gas distribution network extension would allow for and Rlisks: the replacement of higher valued petroleum products (primarily LPG and gas oil), thus substantially increasing the va.ue added of natural gas. Extension of the existing gas network would increase th& delivery capability of the least-cost fuel to an additional 235,000 households, 5,000 commercial and 22 industrial consumers. The Trans Gulf Gas Component would increase gas supplies to the network by about 70 mmcfd as a result of decreased flaring of natural gas in the Gulf of Suez. The gas distribution component also has the environmental benefits of substituting a cleaner burning fuel for other hydrocarbon products and decreasing vehicular traffic in Cairo. The Trans Gulf Gas Component would decrease the flaring of natural gas and largely replace high sulphur fuel oil use in dual-fired power plants, freeing up petroleum products for export. Thus, the project would decrease the budget deficit by lowering the cost of energy supply and help the balance of payments by increasing exports. The financial risks associated with the project largely focus on energy price adjustments. The Government has taken the first two steps in a five- year program of energy price adjustments and is committed to continuing this reform program. This upfront energy . ii - prlce action has mLnimized the risk on financial and economic viability. Estimated Prosect Cost (USt MiL1ion): Foreign as X of X of LQl faŁna TotlL Total one Cot Greater Cairo Gas Distribution Component Materials 13.4 67.8 81.2 83.5 34.3 Construction 67.8 23.3 91.1 25.6 38.5 Technical Services and Training 4.4 8.0 12.4 64.5 5.2 Base Cost 85.6 99.1 184.7 53.7 78.0 Trans Gulf Gas Component Equfipment and Naterials 4.7 31.8 36.5 87.1 15.4 Construction 1.8 5.3 7.1 74.6 3.0 Technical Services and Training 2.1 6.5 8.6 75.6 3.6 Base Cost 8.6 -3L6A 5. 5 _ZZ Base Project Cost 94.2 142.7 236.9 60.2 100.0 Physical Contingency 8.0 7.6 15.6 48.7 Price Contingency .J3j _.6M 29.9 Ha1 Total Project Cost 116.5 165.9 282.4 58.7 Interest During Construction (IOC) 0.0 .3L.1 1 100.0 Total Project Cost + IDC 116.5 169.0 285.5 59.2 wu - uuu3 iii- Financing Plan: Local Foreig Total X o-f Total EGPC 60.5 52.0 112.5 39.4 Petrogas 56.0 0.0 56.0 19.6 IBRD 0.0 84.0 84.0 29.4 EIB O.Q 33.0 33.0 11.6 Total 116.5 169.0 285.5 100% Estimated Disbursement (USIS Million): FY92 FY93 FY94 E95 FY96 FY97 Annual 7.7 35.5 15.3 10.8 11.3 3.4 Cumulative 7.7 43.2 58.5 69.3 80.6 84.0 Economic Rate of Return: 18 percent Map: IBRD Nos. 22905 and 22906 STAFF APPRAISAL REPORT EGYPT GAS-IRVESTMENT PROJECT I. INTRODUCTION 1.01 Between 1973 and the early 1980s, Egypt achieved rapid economic growth accompanied by significant social progress. Not only had GDP expanded by about 9 percent per annum (1974-1981), but the country also benefited from large gains in the terms of trade. The primary engine of growth was the rapid inc:-ease in foreign exchange earnings from oil-based income: oil exports, Suez Canal fees and workers' remittances. This growth scenario began to weaken in 1982 with decreases in world oil prices and finally ended in 1986 when oil prices plummeted. Although the steep rise in oil prices in the August 1990 - anuary 1991 period increased oil export revenue, lost remittances and other costs have substantially aggravated Egypt's financial problems. 1.02 Five major economic problems became increasingly Figure 1: Role of OiI & Gas in Economy acute during the 1980s. 4|_ First, the economy 4 experienced widening financial disequilibria. 3___ _.__ The current account and budget deficits averaged 3_ about 7 and 22 percent of 2__ GDP, respectively. Second, economic growth was achieved 2___. at the cost of increased vulnerability, resulting __ from an overreliance on oil- __ . based revenues (see Figure 1) that made the balance of payments vulnerable to external shocks. Third, FY3 FYE4 Fy5 FYM MI) FYN FY99 pervasive distortions in the Fr9a1 Yew Egyptian economy caused by BSwtsi6 CM Gvt Aven decades of distorted price signals resulted in widespread inefficiencies in investments; the economic structure does not reflect the comparative advantage of the country and can not form the basis for sustained growth, once oil had ceased to play a major role. Fourth, 70 percent of the industrial value added is publicly owned and suffers from pervasive problems, including the maintenance of insolvent companies supported by a complex set of subsidies and overdrafts, barriers to labor mobility and an inappropriate incentive system. Fifth, external debt outstanding and disbursed increased by 64 percent from FY82 to FY87, and debt service tripled, resulting in a debt service ratio exceeding 60 percent. Total debt was estimated at US$50 billion by 1988, equivalent to 147 percent of GDP. -2- Although recent debt forgiveness will ease debt servicing, the problem of debt-driven development still must be addressed. 1.03 The energy sector plays a key role in all of the above macroeconomic problems. Subsidies on domestic energy consumption have been estimated to range from 30 percent to 50 percent of the country's total subsidy burden between FY80 to FY88. The total level of implicit subsidies directed toward downstream sectors in Ff9l is estimated to be 9.6 percent of GDP. As a direct result, per capita energy consumption reached 607 kg of oil equivalent by 1988, 56 percent above the average for countries in the US$500-US$1,500 GNP per capita range. 1.04 As Egypt's oil production is expected to begin its decline in the mid-1990s, it may become a net importer of crude oil before the end of the decade. To compensate for the impact this decline in exports would have on the balance of payment and budget deficit, two specific changes in policy strategy have been adopted. First, a five year (1990-1995) energy price adjustment program has been initiated, directed at ending domestic energy subsidies by June 1995. The pricing reform program is front-loaded with the largest price increases directed to the earlier years. Such an approach is designed: (i) to ensure that the growth in energy consumption will decline in the near term; and (ii) to decrease the budget deficit substantively. The first two steps of the energy price reform have been implemented (in May 1990 and May 1991) resulting in energy prices more than double what they were prior to the start of the program. Furthermore, the Government has also addressed structural imbalances within the mix of energy prices by focussing the largest price adjustments on products with the largest element of subsidy. In addition, in 1986 the Government increased the incentives for oil companies to explore and develop natural gas potential by adopting a new gas clause. This clause establishes the value of natural gas purchased from the oil companies at 85 percent of the price of internationally traded fuel oil. Increasing the role of natural gas in meeting domestic energy demand will free oil products for export and thus mitigate the balance of payments problem. As the cost of the supply of natural gas is economically attractive relative to the remaining supply alternatives, the cost of the domestic energy supply will decrease. Environmental degradation will be ameliorated by substituting high sulphur fuel oil with a clean burning fuel. Decreasing the flaring of associated natural gas will also address global warming by decreasing CO2 releases. II. SECTORAL SETTING A. BDsravy Endowment 2.01 The primary sources of the commercial energy consumption in FY88 of 27.0 MTOE were oil (67 percent), natural gas and condensates (24 percent) and hydro power (9 percent). As of 1988, proven oil and natural gas reserves were 480 million tons (MT) and 12 trillion cubic feet (tcf), respectively. Reserves of coal are limited, and the only mining project under consideration is the Maghara Mine in Sinai, with estimated net proven reserves of about 27.8 - 3 - million tons. Egypt's total hydropower potential is about 12,000 GWh/a, of which 9,000 GWh/a were harnessed with the completion of the Aswan Dam and 1,100 (Wh/a with Aswan II. Given that oil production has stabilized and is expecteJ to decrease over the medium to long term, an&d that the vast majority of hydro potential has been developed, indigenous energy supply growth is primarily restricted to natural gas'. This limitation necessitates that natural gas exploration and development be accelerated to keep Egypt from becoming a net importer of energy in the not too distant future. 2.02 Egypt has been Figure 2: successful in attracting _____________S__"___ international oil companies (IOCs) to explore, develop and X . produce oil. There are some 134 X0. production-sharing agreementc with 50 international companiL. acting as operators for the state oil company, Egyptian General Petroleum Corporation C) (EGPC). Successful oil development has enabled Egypt to supply domestic requirements and a 0 export about 8.3 MT of crude oil (do_I and 3.5 MT (net)' of petroleum .- .6 . products in FY90. The FY90 rNl we Om owo "Wu production rate is perceived to rtpresent a plateau, which Egypt could, at best, maintain until the mid-1990s. The growth of domestic petroleum product consumption decelerated substantially in the FY87-FY9O period, largely due to the modest growth in the economy, increases in the substitution of domestic energy consumption by natural gas and energy price increases. A continuation of this trend would help mitigate the erosion of oil export potential, thereby increasing the revenues required by Egypt for balance of payments support. However, even with the expected increases in energy prices and gas supply, forecast declines in crude oil production during the latter half of the 1990s may result in Egypt becoming a net importer of crude oil by the year 2000 (see Figure 2). 2.03 Over the longer term (beyond 2000), Egypt may have to resort to energy imports. Given its geographic location, a comparative advantage may be natural gas imports from neighboring countries: a gas pipeline from the Gulf countries may be worth exploring. Failing that, the use of alternate fuel 1J There is also a limited potential for commercially exploiting wind and solar power; however, these sources are not expected to have a substantial impact on the primary energy supply over the near to medium term. 2/ Egypt's exports of petroleum products were 4.8 MT consisting primarily of bunker oil, naphtha and fuel oil, while the 1.3 MT of petroleum products imported consisted primarily of gas oil and jet fuel. - 4 - efficient technolories (such as cogeneration) and the relative value of importing coal for the production of electricity (which would have the additional advantage of diversifying the primary energy source) should be considered. However, it is generally felt that a substantial increase in natural gas production is possible by developing off-shore and fragmented on- shore gas fields. B. Develonbments in the Setor 2.04 Pricing. In the 1970s, the Government's perception of indigenous energy resources was that they were plentiful. Therefore, their use was promoted domestically through pricing incentives and investments in downstream products with a high energy input content. This policy has resulted in an industrial base whose capital/energy/labor mix is distorted, imposing financial hardships on the economy. The increasing use of energy resources in the domestic market has severely diminished export capacity by accelerating the depletion of the nonrenewable resource base. The high domestic consumption of natural resources during the mid-1970s to mid-1980s, and the lack of success in finding sizable reserves, has led to projections that Egypt will become a net importer of energy by the mid-1990s. The Government has addressed this problem by a systematic change in policies since 1986, including increases in energy prices and the substitution of high-valued products with lower cost alternatives, including natural gas. Petroleum product prices were nearly tripled betwieen 1986 and 1989, and electricitv prices have been increased by about 30 percent three times in the same period. Unfortunately, much of the progress made in energy price adjustments has been eroded by inflation, which has accelerated from 12 percent to 25 percent p.a. during this period. 2.05 As a result, the Government has adopted a revised strategy to address the pricing issue. in 1989, the Government agreed to increase energy prices to their economic levels by June 1995. In 1990, this agreement was enhanced by adopting annual targets of energy prices as a percentage of their economic levels. Thus, the target of full economic pricing of energy products by 1995 has been fortified by establishing front-loaded annual targets, which address the immediate macroeconomic problems facing the Government. The firLt step in achieving this goal was made in May 1990 with increases in weighted average petroleum product prices (44 percent) and in electricity prices (38 percent). The Government implemented the second step in May 1991 by increasing weighted average petroleum product prices by 52 percent (including bulk sales of natural gas, which were increased by 60 percent) and electricity prices by 50 percent. The focus of petroleum product price increases was on the heavily subsidized products with gas oil, diesel fuel and kerosene prices, all having been doubled. LPG prices were increased by 67 to 83 percent, depending upon the volume of consumption. Thus, the primary products for which natural gas is a substitute were increased by the greatest amount, considerably enhancing the incentive to switch to natural gas use. These increases also allowed the Government to increase the price charged for low natural gas consumpcion levels by 83 percent, without having an impact on the relative attractiveness of gas use. This expected increase in interfuel substitution will decrease the cost of energy supply, free more oil for exports and decrease the environmental impact of energy use. In addition, the Government confirmed a further increase in petroleum product prices, which would take place no later than December 1991, to ensure that domestic petroleum product prices reach 56 percent of world prices. 2.06 Povert3E Impagct Miniization. Although energy plays a secondary role in the basket of commodities purchased by the poor, the proposed energy price adjustment program has been designed to minimize its impact on the poor. Kerosene is the primary fuel used by the poor in Egypt (for cooking and lighting). Because of the country's relatively high level of electrification, electricity is also used - on a limited scale - by the poor (mostly for lighting). In other countries, LPG tends to be a transitional fuel for people living in the urban areas. However because of its low price in Egypt, LPG is also a fuel used by the urban poor for cooking. Therefore, energy price adjustments have been designed to protect the poor from the impact of the price adjustment program: (i) the unit price of LPG in small bottles typically used in households is slightly lower than for larger bottles; (ii) low levels of household electricity consumption receive the highest level of subsidy; and (iii) limited cross-subsidies of petroleum products are possible. 2.07 SunpRI Increases. To complement energy conservation measures, the Government has embarked on a program of decreasing the cost of domestic energy use by increasing the supply of natural gas (as it is the least-cost fuel). This program was reinforced by a new gas clause introduced in 1986. Natural gas from discoveries made by IOCs would be purchased by EGPC on the basis of the price of internationally traded fuel oil. This new gas clause has not only been applied to new fields but also forms the basis for the increasing gas supplies from existing fields. Since 1986, natural gas sales have increased by an annual average of 14 percent, substituting for higher-valued oil products such as gas oil and LPG. 2.08 Value Added Increase of Products. Economic efficiency is also being addressed by reviewing the potential for increasing the value added of products displaced by natural gas. As natural gas is increasingly utilized as a primary energy source, it increases the availability of fuel oil for export. Unfortunately, the international prices for Egypt's fuel oil are relatively low, reflecting its limited market and the availability of the product. Therefore, expanding the uarkets for natural gas, which would increase netback value, is being considered. The primary goal is to increase supplies to urban areas to displace the high-valued fuels used in the commercial and residential sectors (primarily LPG and gas oil). In addition, upgrading the value of Zuel oil through investments in existing refineries (see para. 3.17) is also under consideration. 2.09 Private Sector Support. The oil and gas subsector in Egypt has consistently supported a substantial role for the private sector. Exploration and development have primarily been the responsibility of private IOCs with production-sharing contracts, while the development and operation of the distribution systems have been in the custody of public sector companies. However, the Government has recently allowed gasoline to be marketed by private sector companies. The role of the private sector in marketing gasoline increased dramatically when Caltex (Egypt) entered the market in 1987 and Shell in 1990, joining the long-standing Esso Standard (N.E.) Inc. Furthermore, the Government is considering selling some of its existing gasoline marketing assets to the private sector. An additional boost to the private sector has also been initiated in the petrochemicals industry as the Government is currently entertaining a proposal for an ethylene/polyethylene plant by the private sector. It is expected to form the basis for a privately owned petro-chemical industry in Egypt, which would further increase the value added of natural gas by using ethylene as a feedstock to plastics, PVC and/or polyethylene. III. NATURAL GAS SUBSECTOR A. Institutional Setting 3.01 The Ministry of Petroleum and Mineral Resources functions as the coordinator and policymaker for the oil and gas subsector and decides upon capital investment programs jointly with the Ministry of Planning (MOP). Energy pricing issues are formalized at the ministry level for consideration by the cabinet. In addition, an autonomous planning department within the Ministry of Petroleum and Mineral Resources, the Organization for Energy Planning, provides technical and policy-oriented energy research. 3.02 The government-owned Egypt General Petroleum Company was created in 1956 to oversee all matters relating to the petroleum industry. With the general restructuring of the public sector in 1962, this authority was converted into the Egyptian General Petroleum Organization. With the promulgation of Law 20 of 1976, the Egyptian General Petroleum Organization was converted into the Egyptian General Petroleum Corporation (EGPC), the beneficiary of the proposed loan. The Ministry of Petroleum and Mineral Resources, which was created in 1973, acts as a link between EGPC and other government bodies, while the primary responsibility for managing all exploration, production, and the refining of oil and gas rests with EGPC. The distribution and marketing of oil and gas is largely carried out by EGPC and its subsidiaries, but private companies are involved in the distribution and marketing of gasoline and LPG. EGPC dominates the sector through its wholly or partly owned affiliates and the operating companies formed in partnership with foreign oil companies (see Annex I for details). Each of the major market functions - production, refining, transmission, distribution, and ancillary services - are represented by different organizations (outlined in Annex II). EGPC, as the holding company, acts as the operational and financial coordinator implicitly setting transfer prices between subsidiaries. While the organizations have some financial autonomy, they are generally dependent on EGPC. 3.03 Natural gas activities are dominated by six organizations: EGPC through its Natural Gas Department; three joint operating companies --WEPCO, - 7 - PETROBEL, and GUPCO; and two wholly owned EGPC subsidiaries-- Petroleum Pipeline Corp (PPC) and PETROGAS. PPC constructs and operates the gas transmission network, and PETROGAS is responsible for all gas distribution and most of the LPG distribution. Other EGPC affiliates perform ancillary services, such as Egypt Gas, which carries out distribution network construction. Although EGPC may, in principle, be in charge of developing a long-term gas plan, in practice there is little long-term planning, and planning coordination with major consumers (especially the Egyptian Electricity Authority) seems to be limited. B. Gas Reserves 3.04 Egypt has substantial gas reserves; a large proportion of which have either already been developed or are currently under development. Authoritative sources put reserves at around 12 tcf as of end-1989, with some 8.5 tcf of this nonassociated gas. By comparison, reserves at end-FY80 were around 3.0 tcf. Reserves in producing fields at end-FY90 were 6.4 tcf, and reserves under development were some 2.5 tcf. Most of the balance of 3.1 tcf of unutilized gas is accounted for by fields that require further appraisal, by fields that are far from existing pipelines, or by Gulf of Suez gas that cannot be used at present due to processing and pipeline constraints. 3.05 Egypt's undiscovered gas resources are generally held to be substantial, and the country is now viewed by many IOCs as having more undiscovered gas than oil. The enactment of a revised Petroleum Law in 1986, giving companies the right to sell gas to EGPC at a price equivalent to 85 percent of fuel oil, was, thus, essencial in encouraging continued exploration. Several new concession agreements in areas with potential gas reserves have been signed, but drilling in recent years has not identified any new giant gas structures; much more investment will be required to assess the potential of relatively underexplored areas. C. Historr of Gas SUoIXv and ConsumRtion 3.06 Egypt's gas production comes from four main regions: the Eastern Nile Delta (Abu Madi field), the Western Nile Delta (Abu Qir field), the Western Desert (Abu el Gharadig field) and the Gulf of Suez (the Ras Shukeir Processing Plant). Production grew from 230 mmcfd in FY81 to 730 mmcfd in FY90. Egypt's gas production has generally been very low cost, due to the good qualities and favorable location of onshore fields and the low marginal cost of associated gas utilization. 3.07 The development of gas usage has involved the construction of a national pipeline network of 2,000 km. The core of the network, known as the National Grid, connects Alexandria with Cairo, Suez and Port Said and has achieved a high degree of flexibility. The system should be able to cope with anticipated production increases in the next few years with only modest - 8 - upgrading. However, pipelines from peripheral supply areas to the national grid, particularly from the Western Desert and the Gulf of Suez, have limited potential to cope with additional deliveries. 3.08 Natural gas plays an increasing role in supplying the energy of Greater Cairo, in which about one fourth of the country's 55 million people reside. The city is located in the central junction of the national gas transmission network, which by the end of FY90 had a total capacity of about 12 billion cubic meters per annum. The gas from Abu Madi and Abu Qir in the northern part of the country flows through a 20-inch pipeline and enters a 24- inch, high pressure (31 bars) distribution feeder main. This main stretches in two directions and encircles a major port of the city. Towards the west, it crosses the Nile to reach the western part of Cairo; towards the northeast, it receives gas at the Heliopolis pressure regulating station through a new 16-inch pipeline from the Gulf of Suez; towards the south of Cairo it connects to the 24-inch pipeline from the Abu Gharadig field, about 270 km west of Cairo. This pipeline also crosses the Nile in the south of Cairo, and a third, recently completed, crossing supplies gas from the network in the western part of the city to customers on Zamalik Island. The Cairo gas distribution feeder main supplies gas to several areas of the city and a few power plants along its 90-km route. The first Bank-funded Cairo Gas Distribution Project, which included the construction of a major part of the above main and the supply of gas to 160,000 consumers, has now expanded to a larger network supplying about 326,000 residential consumers, 4 power plants and a limited number of commercial users on both sides of the Nile. Gas is being supplied to Cairo under an existing open-ended contract between EGPC and Petrogas. 3.09 Substantial gas reserves in the far northwestern desert (Khalda and nearby fields) are not connected to the national grid. This gas is being partially developed for local power consumption until sufficient reserves can be proved to justify a longer pipeline to Alexandria. The only major centers of energy consumption not linked to the gas grid are the Assiut and Upper Egypt regions. However, the growth of heavy industry and fuel-oil-fired power generation in the Assiut region may justify connection to the gas grid in future, if sufficient supplies of gas are available. 3.10 Gas consumption in Egypt initially focussed on the fertilizer sector, which accounted for 40 percent of demand in FY82. During the past decade, usage has shifted towards power, which now accounts for around 60 percent of demand, with fertilizers accounting for 16 percent. Most heavy industry has been converted to gas, or to dual oil/gas firing. The penetration of the residential market has been modest, with g"s consumption through the first Greater Cairo Gas Distribution scheme accounting for only 1 percent of the total gas supply ir FY90. - 9 - D. Gas Supoly - Future 3.11 Total gas production in Egypt is expected to increase from 730 mmcfd in FY90 to 1,250 mmcfd in FY94, with the development of the North Abu Qir, Badr el Din and El Qara fields. There is no clear plan for field development beyond FY94. Substantial discoveries, which may provide developments in the longer term, arc located offshore of the eastern Nile Delta and in the southern Gulf of Suez/Red Sea area. The likely development cost of these fields is somewhat higher than that of previous fields, due to their location in deeper water and their distance from the National Grid. 3.12 A further option to increase supply is to improve the utilization of Gulf of Suez gas. The Trans Gulf Gas component (see para. 5.06) could result in an additional delivery of around 70 mmcfd of gas from FY94. Substantial additional associated gas may also be available elsewhere in the Gulf of Suez, if facilities are optimized. However, a full assessment of this potential would require a detailed survey of Gulf of Suez gas resources. 3.13 Current potential economic usage of gas in Egypt greatly exceeds gas supply capacity, and this situation is likely to prevail during the next decade, as the gas balance in Annex III indicates. Excess demand arises in all major consuming sectors. In power, gas burning capacity is expected to rise by 40 percent to 10,000 MW by FY94 through the conversion of steam plants co dual firing and the construction of new, combined-cycle plants; the potential gas usage of this capacity represents 80 percent of expected FY94 gas production, thus indicating that continued substantial fuel oil usage in the power subsector is likely. In the fertilizer subsector, the planned expansion at Abu Qir and Suez will increase requirements by 50 mmcfd by 1995, with longer-term potential requirements arising from the need to replace the uneconomic Kima Fertilizer Plant and the need to meet further consumption growth. In the cement sector, which currently accounts for 7 percent of consumption, gas usage potential is forecast to increase as plants at Kattamia and Ameriya are converted to dual firing in the next two years. Long-term growth in cement demand (at least 4 percent p.a.) will generate substantial additional fuel requirements, to be met either by gas or by fuel oil. In other industries, energy usage is currently dominated by oil, and the conversion of even half of this capacity to gas would generate an additional demand of at least 250 mmcfd in FY95. Finally, the residential and commercial sector provides a major potential market for gas, given Egypt's large urbanized population and sizeable service industry base. 3.14 Based upon the anticipated supplies and the potential consumption noted above, in the absence of major new gas discoveries, gas consumption in Egypt will remain supply-constrained in the 1990s. Potential consumption is likely to exceed supply by around 400 mcfd in FY95, while by FY2000, the deficit will reach 600-700 mmcfd if only currently identified reserves are developed. It is possible that substantial discoveries of gas in the 1990s will lead to a transient surplus of gas in Egypt. However, it should be noted that to satisfy potential demand and to replace existing production, 21 tcf of - 10 - new discoveries will be required by 2005, compared with the 12 tef generated in over 25 years of exploration to date. E. DeveloQment Plan 3.15 The medium-term development plan for GOE calls for public sector initiatives to support private sector investments. Gas exploration and development is almost exclusively the domain of the private sector, with production-sharing agreements between EGPC and IOCs. The pipelines that form the National Grid and the distribution network are in the relatively early stages of development, with most of these assets having been established during the 1980s. GOE has put a high priority on completing the first phase of the Cairo Gas Distribution component (supported by Credit No. 1024-EGT), which would supply about 640,000 customers and aim at displaci.ag higher valued fuels; it would also decrease the air pollution problem in Cairo and decrease the transportation load associated with the delivery of petroleum products. Over the medium term, GOE intends to extend the gas distribution grid in Cairo and to install a similar network in Alexandria. 3.16 EGPC estimates that an investment program amounting to about US$800 million per year over the next five years is required to meet the needs of sector development, which will be largely financed from internal cash generation. However, a detailed analysis of EGPC expenditures has not been made recently as this is usually done in preparation of the five-year plan. This update is expected to be undertaken during 1991, after which time a better definition of EGPC capital requirements will be available to the Government. Extensive capital investments in pipelines, refinery upgrading and the distribution of natural gas all look to be economically attractive. Commitments to implement the envisioned investments (such as a gas pipeline and related gas processing facilities for Gulf of Suez associated gas) could also debottleneck some of the potential investments by IOCs. 3.17 Due to the mismatch between the production profile from domestic refineries and the country's consumption profile, Egypt continues to export low-value naphtha and fuel oil (after meeting the domestic demand of about 20 MT of refined products) and to import high-value aviation kerosene and gas oil. After practically exhausting the option of replacing gas oil used for power generation with natural gas during the late 1980s, future increases in gas supply will displace fuel oil use (primarily for power generation), thereby further exacerbating the imbalance between total demand and the supplies from domestic refineries. The seven domestic refineries are of topping or hydroskimming configuration with very little secondary processing capacity for upgrading fuel oil into distillate products. The refineries also lack adequate octane enhancement facilities, resulting in the surplus of naphtha for export. Investment plans for the immediate future include doubling the current capacities at the El Nasr and Assuit refineries, which are both of the hydroskimming type. Hydroprocessing investments are being considered for one of the locations. While this change in focus is preferable, it is expected to be insufficient to address the growing, country- - 11 - wide product imbalances. In order that these may be addressed, EGPC would undertake a Refinery Subsector Investment Planning Study (terms of reference are included in Annex VIII). This study would evaluate secondary conversion investment candidates over the next 10 years in order to: (i) reduce to a minimum the costs of product supply to the domestic market through a combination of imports, domestic refining and exports; (ii) reduce pollution by improving product quality; and (iii) improve the value added of product exports. The study would be completed by December 31, 1993. 3.18 About 90 percent of Egypt's oil production is from Gulf of Suez fields, most of which include associated gas. Many of the fields are mature, and some of them are in their declining stages of production. As these fields continue to mature, the gas/oil ratio will increase, and more natural gas will become available. The infrastructure in the Gulf of Suez area (the Ras Shokeir gas treatment facilities and the Ras Shokeir-Suez pipeline) is already running at full capacity, thus creating problems for incremental production. Developing the gas reserves in this area is complex, both technically and institutionally. Many fields and multiple operators are active in this region. Each field and operator have unique technical approaches to oil and gas recovery. Hence, the logistics of mounting a cohesive development plan are formidable. As a result, EGPC would undertake a study, with the assistance of consultants, to evaluate the problems and opportunities for increased gas delivery from this region on the basis of the terms of reference agreed to in Annex IX. It is anticipated that gas supply from this area could increase by 250-400 mmcfd, or as much as 55 percent of average FY90 production rates. As the study would focus on the reduction of natural gas flaring (global warming concern) and may not be entirely economically viable, Global Environmental Fund resources would be used to finance part of the cost of the study while the balance would be financed from ESMAP resources. The proposed study would be completed by December 31, 1993. F. Gas Pricing 3.19 As outlined above, natural gas is expected to be supply-constrained for the medium and possibly long term, largely due to the substantial potential demand from dual-fired (fuel oil and natural gas) power plants and heavy industry. Thus, any marginal change in natural gas availability will impact fuel oil consumption. Therefore, the Government has established that the marginal value of natural gas at the power plant fence (or city gate) at the equivalent of international fuel oil for the purpose of pricing bulk natural gas supply. 3.20 Until May 1991, about 95 percent of current natural gas consumption is priced at 4.67 piastres/cu.m. or about 27 percent of its economic level'. 1/ Given that the average price of fuel oil over the past twelve months has been $70/tonne, the gas price for fuel oil equivalency at an exchange rate of 2.83 LE/$ is 17 piastres/cu.m. - 12 - The primary recipients of this subsidy are the power and industrial sectors. Within the context of the Government's revised energy pricing policy of increasing the weighted average of petroleum product prices (including bulk natural gas sales), the price of bulk sales of natural gas were increased May 3, 1991 by 61 percent to 7.5 piastres/cu.m. Furthermore, the Government proposes to link domestic natural gas price increases to domestic fuel oil price adjustments to bring bulk sa'les of natural gas to the equivalent of internationally traded fuel oil prices by JuAns 1995. 3.21 The price structure of natural gas supplied to small industrial, commercial and residential customers prior to May 1991 was as follows: Slab (cu.m,/wonth) price (Riastres/cu.m) 0 - 22.5 5.5 22.5 - 37.5 14.5 37.5 - 52.5 18.0 above 52.5 30.0 For levels of consumption typical of commercial customers (about 400 cu.m./mo.), natural gas costs about 30 piastres/cu.m., exceeding international fuel oil equivalent prices and thus contributing to the recovery of distribution costs. Fuel oil, gas oil and LPG are tf.e primary targets for interfuel substitution by natural gas for commercial users. In the case of small industrial consumers currently using either fuel oil or gas oil and commercial consumers using LPG, there has been a substantial disincentive to switch to natural gas because of the low prices of these substitute fuels. Therefore, the Government proposes to increase the price of the heavily subsidized petroleum products (LPG, fuel oil and gas oil) so as to enhance the relative attractiveness of natural gas compared with its substitutes. This will be accomplished by increasing the prices of these products by an amount that exceeds the weighted average petroleum product increase, thus decreasing the level of cross-subsidies. The May 3, 1991 energy price increases fully conformad to these principles. 3.22 Prior to May 1991, the residential consumption of natural gas was priced such that the average cost to the consumer was about 10 piastres/cu.m.', the result of no price adjustments since 1981; thus, natural gas was attractive relative to LPG at modest levels of consumption. However, the price of natural gas to residential consumers is well below its economic cost. Adjusting LPG prices to reflect their international equivalent will allow the structure of natural gas prices to domestic/commercial customers to be addressed. Although the level and structure of natural gas pricing needs 3/ The cost of the supply of natural gas includes a stamp tax of 2.4 piastres/ cu.m., plus 20 piastres for any bill exceeding one LE/month and a maintenance charge of 25 piastres/month. An additional cost of natural gas supply is a meter and payment deposit of LE100. With local interest rates of 12 percent, this amounts to an additional imputed cost for natural gas supply of about one LE/mo. - 13 - to be studied to determine an appropriate strategy for its adjustment, selected increases over the immediate term are warranted. The Government has begun by increasing lower levels of gas consumption (O to 30 cu.m./month) by 83 percent, to 10 piastres/cu.m. Consumption levels from 30 to 60 cu.m./month have been increased to 20 piastres/cu.m., while consumption above 60 cu.m./month is priced at 30 piatres/cu.m. In order that a strategy for further adjustments to the level and structure of natural gas pricing can be established, the Government will work closely with ESMAP on a Cost of Gas Distribution Study focussing on commercial and residential consumption (draft TOR detailed in Annex X). This study would address the reform of the present tariff structure for natural gas distribution in Cairo, which has remained unchanged for ten years and bears no relation to current costs. It would examine the appropriate level and structure of tariffs to different classes of customers in Cairo, in light of the costs of distribution, of Petrogas' finances and of the cost of alternative fuels. The study would recommend the best means of constructing incentives for gas use, especially by commercial customers. The nature of Petrogas' gas sales contracts, particularly with larger commercial customers, would also be addressed. The study would assess the legal framework for these contracts and for Petrogas' operation and formulate any required amendments. G. Bank's Role in the Sector and Experience in Past Lending 3.23 The Bank's first lending operation in the gas subsector was the Gulf of Suez Project (Credit 1732-EGT) approved in 1979 for the recovery of flared associated gas and natural gas liquids. This project addressed critical sector issues such as pricing, the exploration of new areas and the optimum utilization of natural gas. The Cairo Gas Distribution Project approved in 1980 (Credit 1024-EGT) successfully assisted in establishing the first gas distribution system in Egypt, supplying gas to the premium market of residential and commercial consumers to replace high- ralued fuels such as LPG and gas oil. Two other Bank-funded projects, Western Desert Gas Exploration (Credit 1928-EGT) and Abu Qir Gas Development (Credit 2103-EGT), were subsequently approved in 1981 and 1982. The objectives of both projects, to develop additional natural gas supplies and to undertake studies aimed at developing an appropriate gas development strategy, were fully achieved. In addition, the Bank has contributed to the transfer of modern technology in offshore operations, reserves management, process design and operations. The physical implementation of all Bank projects in the subsector has been satisfactory, with EGPC demonstrating a noteworthy capability for efficiency in this area. In addition to gas subsector loans, the Bank has approved six loans in the power subsector, the last of which (Loan No. 3103-EGT: Fourth Power Project) included agreements for both electricity and petroleum product prices (see para. 2.05). 3.24 On the policy front, the results have been mixed. The prices of energy in general, and petroleum products in particular, have been unacceptably low, averaging less than 30 percent of their international equivalents. This issue resulted in the Bank's reluctance to finance projects in this subsector during most of the 1980s. The recent resolution of this - 14 - issue, with a monitorable action plan of substantial, front-loaded price increases by the Government, has permitted the resumption of lending to the subsector. 3.25 Project Performance and Audit Reports (PPAhs) cite the following lessons learned: (i) the resolution of sector issues must be sought through projects; (ii) the packaging of works must be done so that contractual responsibilities are properly secured with a view to avoiding time slippages; (iii) the project scope must be sufficiently comprehensive to ensure that the envisioned benefits can be achieved; and (iv) an appropriate incentive system must be in place for the benefits to accrue. The proposed project has taken these lessons into account in project design. 3.26 The Bank's presence in this sector is designed to help the Government achieve a number of objectives: (i) to assist the development of a sound investment strategy in the sector; (ii) to design an energy pricing system that provides incentives to minimize the cost of energy supply and addresses Egypt's twin problem of current account and budget deficits; (iii) to develop infrastructure and policies that support private sector involvement in the sector; (iv) to address the accelerated adjustment of the prices of heavily subsidized energy products, particularly LPG, gas oil and natural gas; and (v) to maximize the environmentally mitigative features of investments. Specifically, the Bank has actively promoted the adjustment of both the level and structure of energy prices to address the problem of budget support and to establish incentives for the consumer to use the least-cost fuel as well as to conserve energy. The development of infrastructure to debottleneck the transport of gas to market is designed to enhance private sector participation in exploration and development by ensuring a market for output. The resultant increase in gas supply also decreases the use of higher cost fuels and mitigates air pollution problems in urban areas. IV. THE BORROWER A. Statutory Functions 4.01 The main functions of EGPC under Law 20 are to: (i) draw up a general policy for converting and granting concessions (for oil and gas exploration) and to negotiate and prepare concession agreements for the approval of the Government; (ii) supervise the exploration and exploitation activities of the oil companies engaged in the search for oil and the productior. of oil and/or natural gas; (iii) plan, coordinate and control the activities of various affiliates in the production, refining, transportation and distribution of petroleum products; (iv) undertake the export of crude oil and petroleum products and effect similar imports in order to balance domestic requirements; (v) determine, in conjunction with other competent authorities, the pricing of - 15 - petroleum products;' and (vi) manage the operation and management of all subsidiary companies. B. Cauital Structure 4.02 EGPC capital (300 million Egyptian pounds) is invested in the capital of its subsidiaries and in joint companies established for oil production with foreign partners. Funds available to EGPC for its operation consist of a share in the profits of subsidiaries in the petroleum sector, a share in the net profit of the joint companies and profits arising out of supervision and administrative fees. In addition, EGPC secures funds from the Government in the form of loans. EGPC, as a distinct corporate entity, can, and has, borrowed from external financial agencies. Total EGPC capital and reserves now approach LE 5,000 million. C. Or2anization and Management 4.03 EGPC is managed by an executive chairman assisted by eleven deputy chairmen in charge of exploration, production, planning and projects, natural gas. operations, foreign and joint venture companies, financial and economic affairs, internal trade, foreign trade, administration and legal affairs and petroleum agreements. The chairman functions as the chairman of the board and the deputy chairmen as ex-officio members. Five chairmen from the affiliated companies, one of whom is from PETROGAS, are also nominated to the board (Annex II). 4.04 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 to the contrary notwithstanding. It is, therefore, competent to establish its own internal regulations for financial, administrative and technical management and also to dictate 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. 4.05 At the senior level, EGPC management is competent and experienced in various aspects of the oil and gas industry. It has, over the last two decades, expanded its marketing organization to meet growing demands, set up / While Law 20 vests EGPC with the authority to determine prices, in effect, prices have been fixed through governmental decree; EGPC has, at best, an advisory role. - 16 - and rehabilitated a number of refineries, and laid an extensive network of crude oil, petroleum products and gas pipelines. It has created within its organization a specialized group which has successfully negotiated production- sharing agreements with foreign oil companies. Separately, EGPC has developed nonassociated gas fields within Egypt and linked them to the market. While foreign partners are largely responsible for the production of oil, EGPC closely monitors their exploration and development programs. D. Functional Structure 4.06 EGPC functions as a holding company and performs the various finctions with which it is charged through 18 fully and partly owned subsidiaries and through 20 joint-operating companies formed in partnership with the foreign oil companies. These companies have been set up on a functional basis and relate to the following sectors. 4.07 Exploration and Productio . All work relating to geophysical surveys and exploration are carried out by the General Petroleum Company (GPC), a fully owned subsidiary of EGPC; joint venture companies, such as WEPCO and SUCO; and IOCs. These IOCs, under the terms of their agreements, are obliged to spend a fixed amount on exploration and surveys during the primary exploration period. The annual work program of each of these companies is drawn up under its concession agreement, which is reviewed and approved by a joint committee consisting of a representative of EGPC and of the company. Once a commercial discovery has been made, a nonprofit operating company, which operates and works the concession on behalf of the partners in accordance with the terms of the concession agreement, is formed. EGPC comes in as an equal partner at the development stage. 4.08 Refining and Processing. All refining and processing of petroleum products is undertaken by seven fully owned subsidiaries of EGPC, namely, the El Nasr Petroleum Company, the Alexandria Petroleum Company, the Suez Oil Processing Company, the Alameria Oil Refining Company, the Cairo Oil Refining Company, the Assiut Oil Refining Company and the Egypt Petrochemical Company. 4.09 Petroleum Pipeline. Egypt's extensive ,ietwork of pipelines for transporting crude oil, petroleum products and gas is owned and operated by the Petroleum Pipelines Company (PPC), a fully owned subsidiary of EGPC. 4.10 Distribution. The marketing and distribution of petroleum products is undertaken by two subsidiaries, namely the Misr Petroleum Company and the Cooperative Petroleum Company. These companies control the major share of the market, though the marketing of petroleum products is also being undertaken by three foreign companies. Natural gas and LPG are distributed by the Petroleum Gases Company (PETROGAS), another subsidiary formed in 1978. Small private firms are also itnvolved with local LPG distribution. 4.11 Accounts and Audit. EGPC, like other Egyptian public undertakings, follows the "Unified Accounting System," which was established 'uy a - 17 - Presidential Decree in 1966. This accounting system was evolved, inter alia, with a view to establishing a uniform denomination of accounts and accounting rules, definitions and terminology. Similar and compatible financial statements for capital operations, current operations and cash flows for all public sectors undertakings have been stipulated by the system. EGPC is required to prepare detailed accounts and financial statements for periodic review in addition to following a stipulated financial policy. EGPC undertakes detailed internal auditing through its Department of Internal Control and the Department for Financial Evaluation. While the former audits all financial operations within EGPC, the latter is responsible for checking and evaluating financial systems and procedures, not only of ECPC but also of all affiliated companies. This latter department is responsible for assessing and evaluating the efficiencies of various units operated by EGPC and its affiliates and for evolving improved systems and procedures. 4.12 Insurance. EGPC subsidiaries carry adequate comprehensive insurance on major facilities and equipment against fire, explosions, damage and theft. Insurance agreements are entered into directly by each company with insurance companies within Egypt, which are, in part, reinsured by foreign insurance companies. E. Petroleum Gas Company (PETROGAS) 4.13 BackSround. Petroleum Gas Company (PETROGAS) is a wholly owned subsidiary of EGPC. It was incorporated in September 1978 and assumed all functions relating to processing, distributing and marketing LPG, as well as to promoting and distributing natural gas. Accordingly, Petrogas stores, fills, transports and markets about 850,000 tons of LPG per year; enters into selling arrangements and collects sale proceeds for about 7.8 million cu.m. of natural gas distributed per year through the Petroleum Pipeline Company's grid; and constructs and maintains the Greater Cairo City gas distribution system. The component of the project described as the "Greater Cairo Gas Distribution Component" would be entrusted by EGPC to Petrogas for implementation, as was the Bank-supported Cairo Gas Distribution Project (Credit 1024-EGT), which was successfully completed in mid-1984. 4.14 CaRital Structure. The authorized capital of the company, as of June 30, 1990, was LE 156 million. The long-term debt of the company at the end of FY90 was US$33.3 million in foreign debt (IDA credit, on-lent to Petrogas at a commercial interest rate) and LE 4 million in local debt. 4.15 Organization. Petrogas has an executive chairman, who is also the chairman of the board. The board has eight other members, four appointed by the prime minister and four elected by the labor syndicate. EGPC is not represented on the board, but the chairman of Petrogas is a member of the EGPC board. This arrangement provides a close link between Petrogas and EGPC and enables the EGPC board to keep itself apprised of Petrogas activities. Furthermore, EGPC reviews the company's performance twice a year in the general body meeting. The general body also approves the company's operating and capital budgets. Petrogas, in practice, functions on a "commission" - 18 - basis, as do the other fully held subsidiaries of EGPC. The general body meetings, therefore, assume a tremendous importance since at these meetings Petrogas's projected and past costs are scrutinized and purchase prices payable by Petrogas are determined, so as to allow due margins. 4.16 Petrogas has developed into an efficient gas utility company, capable of expanding the city gas distribution network with its own personnel, albeit with gradually diminishing technical assistance from its foreign technical collaborators (British Gas and William Press, who provided technical support to the IDA-financed Cairo Gas Distribution Project). Petrogas has recently developed in-house computer systems for its accounts, inventory and other management information. Developwents are ongoing, with plans to use local consultants for further systems development, including a linkup witt. the EGPC computers. Computerization of commercial services is also underway with eight on-line customer support terminals ready to be installed once the new building is commissioned. 4.17 Insurance. Petrogas covers all of its major facilities and equipment against fire, explosions, damage and theft through comprehensive insurance schemes. It has entered into specific insurance agreements for its natural gas operations, including third-party liability. The insurers, who are public sector insurance companies, have, in turn, reinsured outside the country. 4.18 Pr-oject Enmineering and ImRlementation. The Natural Gas Department of Petrogas (see Annex IV) is responsible for gas distribution operations, as well as for project planning and development, including market surveys, conceptual design, and project management and supervision. Egypt Gas, with assistance from its foreign partner, undertakes detailed design and procurement services as well as the construction of networks, the installation of consumer piping and the conversion of appliances. Under the ongoing arrangement between Petrogas and Egypt Gas, the Cairo gas distribution system has expanded to its present size on a technically sound basis. V. THE PROJECT A. Proiect Objectives and ScoRe 5.01 The primary objectives of the project are to increase the use of a nontradeable commodity, natural gas; to release tradeable petroleum products for expoLt; and to decrease the environmental impact of fuel use. The project would not only focus on increasing the supply of natural gas by reducing flaring and debottlenecking the supply constraints of transporting gas to market, but also would provide the infrastructure required to maximize the value added of the fuels being substituted. It would enable the delivery of a clean burning fuel to the Greater Cairo area to displace petroleum products, thus mitigating air pollution problems. The institution building efforts for Petrogas initiated in the previous Bank loan would be further enhanced to increase its commercialization. The project scope consists of: (i) the Greater Cairo gas distribution component designed to increase the gas delivery - 19 - capacity of the existing gas distribution network in the Greater Cairo area; (ii) the Trans Gulf gas component designed to increase natural gas supply from the Gulf of Suez area to the national grid; and (iii) the training component which would address increased commercialization of Petrog6s associated with (i). B. Rationale for Bank Involvement 5.02 The Bank's country assistance strategy for Egypt calls for lending for gas investment projects because of the positive impact freeing oil for export has on the balance of payments. Energy pricing has been a cornerstone of the Bank's dialogue with the Government, in view of its importance for energy conservation, budget support and the current account balance. In 1989 the Government agreed to increase petroleum product prices to the equivalent of internationally traded products and to increase electricity prices to LRMC by June 1995. The first steps toward achieving this goal were implemented in 1989 by increasing weighted average petroleum product prices by 16 percent and electricity prices by 30 percent. In March 1990, the energy price adjustment agreement with the Government was upgraded to include annual targets for weighted average petroleum product prices (starting at 45 percent in Hay 1990 and increasing at least 11 percentage points each year thereafter to reach 100 percent by June 1995) and electricity prices (starting at 47 percent of LRMC in May 1990 and increasing by 10-12 percentage points of LRMC each year thereafter to reach 100 percent of LRMC by June 1995). This program of energy price adjustments will not ornly enhance the financial health of the sector but will also have a stAstantial impact on the budget deficit. Transfers from the energy sector to Ow- budget in both FY91 and FY92 are expected to increase by about LE 2 billior (about 2 percent of GDP) in both years. Similar increases in transfers to the budget are projected for the following year. In May 1990, the Government fulfllled the first target by increasing weighted average petroleum product prices by 44 percent and electricity prices by 38 percent. In May 1991, the Gov Ynment met the agreed upon next step of price increases by increasing weighted average petroleum product prices by 52 percent and electricity prices by 50 percent. The Government also addressed the problem of the structure of entvgy prices in addition to the level of subsidies to the sector by targeting pvcdLcts with the highest level of subsidy. Thus, the Bank has already been .ffective in persuading the Government to move faster in setting price incentives that improve the attractiveness of using least cost fuels. The rationale for Bank involvement in this project centers on supporting the Government's energy price reform program, and acting as a catalyst to attract co-financing for investments in the gas subsector which complement private sector initiatives and mitigate environmental problems. - 20 - C. Pro let Descripton 5.03 The project would consist of the following components: (a) the extension of the existing gas distribution network in the Greater Cairo area to new premium markets, including an estimated additional 235,000 households; 5,000 commercial and 22 industrial customers; and related training; (b) the delivery of an additional 70 mmcfd of natural gas from the Gulf of Suez/Sinai area to the national grid; and (c) training for Petrogas staff to increase its commercialization. 5.04 Greater Cairo Gas Distribution Component. The GCGDC would provide gas to an estimated additional 235,000 households, 5,000 commercial and 22 industrial consumers in several areas both in the east and west of Cairo. As shown in Annex V, distribution would include 35,000 residential infill and 3,000 commercial infill consumers to be connected in existing areas and the balance in the new areas. These areas have been selected on the basis of a market survey carried out jointly by Petrogas and their consultants. 5.05 The project would consist of integrated components, including the construction of about 30 km of large diameter steel mains and about 900 km of medium and low pressure polyethylene piping; two pressure reducing stations; about 55 regulating stations and related service connections; and metering and carcassing and burner conversion equipment to supply natural gas to the consumers. The project focusses on supplying gas to areas with a high concentration of large commercial consumers, such as Garden City and Pyramids, as well as on supplying gas to industries located ir13ide Greater Cairo in order to maximize the favorable environmental impact and the return on capital employed. The project includes the formulation of a gas market development strategy to identify and propose necessary measures for developing modern operational facilities such as a supervisory control and data acquisition system (SCADA), meter-proving facilities, training centers, computerized emergency and customer services, cost accounting and inventory control. Furthermore, training programs for technical staff on specialized fields such as safety, gas sales engineering, cathodic protection, market analysis, distribution network analysis and design, measurement and conversion would be provided for. Petrogas has agreed to assign a training officer prior to the selection of consultants so that follow-up on the training program could be assured; this officer would be responsible for the coordination of Petrogas' gas marketing development (terms of reference are shown in Annex VII). Petrogas would also establish facilities for a training center. 5.06 Trans Gulf Gas Component. The project would gather about 70 mmscf/d of natural gas (about 10 percent of FY90 average production rates) from the October fields in the Gulf of Suez and the Belayim fields in the Sina, area and transmit it to the grid for downstream use. Gas is currently being flared because of insufficient compressor capacity and pipeline linkages. The - 21 - proposed project would include the addition of a new compressor station at the Belayim fields and a pipeline from the Sinai area to the October field, where a new offshore template would be conq;tructed. This platform would be connected to an exis ing October platform, where added compressors would accommodate the additional flow of gas from these fields through an existing pitDaline to the west bank of the Gulf of Suez. Additional processing tacilities at the Ras Bakr Gas Processing Plant would treat and compress the increased gas supply for sale in the national grid. The capacity of the existing Ras Shokeir pipeline would be increased to accommodate the increased gas supply as the existing pipeline is operating at full capac'ty. EGPC would construct this facility simultaneously with the proposed Trans Gulf Gas Component. Technical details regarding this Component are included in Annex VI. D. Cost Estimates 5.07 The total project cost is estimated to be US$285.5 million of which 59 percent, amounting to US$169 million, would be in foreign exchange. A summary of cost estimates for the principal components of the project is shown below and detailed estimates for the Cairo Gas Distribution and Trans Gulf components are given in Annexes V and VI, respectively. The base cost is in December 1990 prices and was calculated using recent procurement material and market prices. These estimates are considered to be reasonable for this type of project. Physical contingencies for the GCGDC are 6.5 percent for materials and 6.5 percent for engineering and construction services because of the relative uncertainty of the latter. The physical contingencies for the Trans Gulf Gas component are estimated at 6.5 percent based on the information prepared to date. The price contingencies are based on inflation of foreign costs of 3.4 percent per annum and the following local cost inflation estimates: FY91 FY92 FY93 FY94 FY95 FY96 FY97 20% 28% 15% 9% 6% 5% 5% - 22 - 1st10t2d Costs (US$ Nittion) Foreign 8 X of 1LnGAi forefn Total Locjt Forefan Total Totat ----(millions of LE) ---- ---(millions of US$)--- Greter Cairo Gas Distribution Cotponent Naterials 37.9 191.9 229.8 13.4 67.8 81.2 83.5 Construction 191.9 6S.9 257.8 67.8 23.3 91.1 25.6 Tehnical Services and Training 12.5 22.6 35.1 4.4 8.0 12.4 64.5 Base Cost 242.2 280.5 522.7 85.6 99.1 184.7 53.7 Tr"n Gultf Gas CoWqonent Equipmsnt and Materials 13.3 90.0 103.3 4.7 31.8 36.5 87.1 Construction 5.1 15.0 20.1 1.8 5.3 7.1 74.6 Technical Services and Training 5.9 18.4 24.3 2.1 6.5 8.6 75.6 Base Cost 24.3 123.4 147.7 8.6 43.6 52.2 83.5 Physical Contingenefos 22.6 21.5 44.1 8.0 7.6 15.6 48.7 Price Contingencies 40.5 44.1 84.6 14.3 15.6 29.9 52.2 Total Project Cost 329.7 469.5 799.2 116.5 165.9 282.4 58.7 Interest During Construction (IDC) _.0 _.8 8.8 0.0 _.1 3.1 100.0 Total Project Cost . IOC 329.7 478.3 808.0 116.5 169.0 285.5 59.2 an=35 3=53 3=== === == =-Y E. Financing Plan 5.08 The proposed Bank loan of US$84 million would finance 49 percent of the foreign exchange requirements of the project. The proposed loan would be made to EGPC, guaranteed by the Government. The loan would finance materials required for the GCGDC and gas compressors, gas treatment facilities and an offshore template for the Trans Gulf Gas component. EGPC would on-lend US$48 million of the US$84 million to Petrogas for the GCGDC through a subsidiary loan agreement. The loan to Petrogas would carry the same terms as the Bank loan to EGPC. Petrogas would bear the full foreign exchange and interest rate risks on the portion of the loan allocated to finance the GCGDC. The European Investment Bank would co-finance 25 million ECUs (about US$33 million) of the GCGDC on a parallel financing basis. Conclusion of the EIB Loan Agreement with EGPC would be a condition of loan effectiveness. The remainder of the project would be financed by EGPC and Petrogas. - 23 - Project Financing Plan (US$ Million) Local Foreign Total % of Total EGPC 60.5 52.0 112.5 39.4 Petrogas 56.0 0.0 56.0 19.6 IBRD 0.0 84.0 84.0 29.4 EIB 0.0- 33J_ 33,0 11.4 Total 116.5 169.0 285.5 100% F. Procurement 5.09 All materials to be financed under the proposed Bank loan would be procured in accordance with the Bank's guidelines for the procurement of goods. All major packages of materials would be procured following the International Competitive Bidding (ICB) procedures. Local manufacturers competing under ICB would be eligible for a 15 percent preference margin or the import duty applicable to nonexempt importers, whichever is lower. All bidding packages for materials estimated to cost US$2 million equivalent or more and all packages (instrumentation and control equipment for compressors and gas treatment equipment) to be procured through Limited International Bidding (LIB) would be subject to the Bank's prior review of procurement documents; this would represent more than 70 percent of the loan amount. In addition, the first two packages, regardless of value, would be subject to the Bank's prior review. Procurement arrangements for the Trans Gulf Gas Component would include longer lead time equipment such as compressor station, dehydration and refrigeration equipment and the platform template equipment and materials. All major packages of material, equipment and services for the Trans Gulf Gas Component would be procured follouing ICB procedures except for the following: (a) contracts for equipment and inspection and similar services needed for offshore operations, and which do not exceed or aggregate of US$8.0 million, may be awarded in accordance with the Bank's procurement guidelines for LIB; and (b) contracts for the equipment and materials for the platform template that are proprietary, or contracts to ensure standardization and compatibility with the existing equipment and facilities, which do not exceed an aggregate value of US$4.0 million, may be procured by direct contracting under the terms and conditions acceptable to the Bank. Details of procurement arrangements are included in Annexes V and VI for the GCGDC and Trans Gulf Component, respectively, and summarized in the Procurement Table. For consulting services relating to training, Petrogas would provide a short- list of consultants according to the Bank guidelines. Selection of consultants would conform to the Bank's Guidelines for the Use of Consultants by World Bank Borrowers in Bank-financed projects. - 24 - Procurement Table (US$ million) Procurement Method ICB LZ LIB Other jj Total Cost Greater-Cairo Gas Distribution Co9monent Steel pipes, P.E. pipes and 24.6 24.6 fittings Network regulating stations 7.5 7.5 Customer meters & regulators 18.6 1.4 20.0 (18.3) (18.3) Miscellaneous network fittings _/ 28.9 28.9 (28.6) (28.6) Consulting services 140.4 140.4 Training 1.3 1.3 (1.2) (1.2) Subtotal 47.5 175.2 222.7 (46.9) (1.2) (48.1) Trans Gulf Gas Component Gas surveys 0.4 0.4 Compressors and associated equipment 10.0 4.0 2.5 16.5 (10.0) (4.0) (14.0) Platform template 9.5 9.3 18.8 (9.5) (2.0) (11.5) Submarine pipeline 2.2 2.2 Gas treatment equipment 4.4 4.0 5.0 13.4 & related services (4.4) (4.0) (2.0) (10.4) Construction and consulting 8.9 8.9 services Subtotal 23.9 8.0 28.3 60.2 (23.9) (8.0) (4.0) (35.9) TOTAL 71.4 8.0 203.5 282.9 (70.8) (8.0) (5.2) (84.0) Note: U Figures in parentheses to be financed by the Bank. 2L The components to be cofinanced by EIB (US$33 million) are given under other. a/ Consists of 15 small packages. - 25 - G. Disbursement 5.10 The Bank loan would be disbursed for the items indicated in the procurement section (para. 5.09). The proceeds of the loan would be disbursed over a period of six years (FY92-FY97) on the following basis: (a) 100% of the foreign exchange component of the materials for the GCGDC including customer meters and miscellaneous network fittings; (b) 100% of the foreign exchange component for training in the GCGDC; and (c) 100% of the foreign exchange component of the gas compressors and auxiliary equipment, gas treatment equipment and platform template for the Trans Gulf Gas component. A detailed schedule of disbursement for the GCGDC is in Annex V, and the schedule for the Trans Gulf Gas component is in Annex VI. The proposed schedule for the Trans Gulf Gas component is shorter than average for energy projects in Egypt. However, it is considered feasible given the high priority EGPC has assigned to this component and EGPC success in implementing similar projects in the past. The summary of expected disbursements is indicated below. USS Million Ł92~ FY93 FY94 FY95 FY96 FY97 Greater Cairo Gas Distribution -omponent Incremental 1.2 10.8 10.7 10.8 11.3 3.3 Cumulative 1.2 12.0 22.7 33.5 44.8 48.1 Trans Gulf Gas Component Incremental 6.5 24.7 4.7 0.0 0.0 0.0 Cumulative 6.5 31.2 35.4 35.9 35.9 35.9 Total Incremental 7.7 35.5 15.3 10.8 11.3 3.4 Cumulative 7.7 43.2 58.5 69.3 80.6 84.0 Percentage 9% 51% 70% 83% 96% 100% - 26 - 5.11 Retroactive Financing and Advance Contracting. Retroactive financing of up to US$5 million would be allowed to cover expenditures incurred for the Trans Gulf Gas Project to facilitate the accelerated timetable proposed by EGPC. Disbursements would only be for contracts entered into after December 15, 1990. 5.12 In order to enable EGPC and Petrogas to effectively implement the project and to ensure prompt payments to contractors and consultants, the Bank would advance funds as needed to a special account to be opened at a commercial bank in Egypt for a maximum riount of US$5.0 million; this is expected to cover the Bank's share of eligible expenditures over a period of three months. The account would be denominated in US dollars and replenished against withdrawal applications. Applications with appropriate supporting documentation would be submitted when approximately half of the maximum allocated amount of the account was spent. All disbursements under the project would be made against standard documentation. H. Monitorina and Supervision 5.13 A project launch mission is planned to commence after loan signing. Because of the complexity of the project, which deals with two executing agencies with components focussing in technically disparate fields (gas collection and gas distribution), an average of at least 16 staff-weeks per year would be necessary to allow biannual supervision to monitor project activities while both the GCGDC and Trans Gulf Gas Component are active, and 12 staff-weeks per year thereafter as outlined in Annex XI. The supervision missions would include a gas (upstream) specialist to review the technical aspects of the Trans Gulf Gas Component, a gas (downstream) specialist to review the technical aspects of the GCGDC and a financial analyst. The respective Project Implementation Units in EGPC and Petrogas would be responsible for preparing documents for Bank supervision missions. EGPC and Petrogas would be asked to submit to the Bank quarterly progress reports during project implementation, and prepare and furnish to the Bank, within four months after project completion, a completion report including a reassessment of the project costs and benefits. I. Environment 5.14 Environmental concerns in Egypt, and particularly in Cairo, are of a high priority. The proposed solutions for minimizing the impact of fuel use on the environment are generally in consonance with prudent energy sector operation as they decrease the cost of energy supply. Greater efficiency decreases the use of fuels and, hence, decreases the impact of their use. However, some specific areas are of particular concern. The air pollution problem is particularly acute in and around Cairo. To the extent possible, existing plants near Cairo should be converted to gas-fired operation to limit - 27 - the S0O and N0O output, a measure that would also have a beneficial economic impact. Concurrently, decreasing fuel oil use at existing dual-fired plants would also mitigate the air quality problem. This project would increase the availability of natural gas to the National Grid by decreasing flaring in the Gulf of Suez and providing the infrastructure to debottleneck the transport of associated gas. 5.15 The proposed project would also make natural gas available to industries in the greater Cairo area that are currently using high sulfur fuel oil. Such interfuel substitution would have a considerable impact on local air pollution problems caused by the high level of pollutants in emissions and the low height of the chimneys. Decreasing the delivery of LPG bottles would decrease traffic congestion in the streets of Cairo and air pollution from vehicle exhaust. 5.16 In addition to the direct benefits of using a clean-burning fuel, the distribution extension is expected to replace some of the gas supplied by a small manufactured gas plant (Septia). Not only is this plant uneconomic1, but it also is reported to have pipeline losses of 40-50 percent because of the age (70 years) of some of the equipment. The pipeline losses not only affect the economic viability of the operation but, more seriously, also result in the release of toxic gases into the environment. Increasing the use of natural gas at the expense of this plant would enhance the economic viability of the sector and lessen the environmental problems associated with the manufactured gas plant. 5.17 Environmental and Safety Review of GCGDC. The existing construction contract between Petrogas and Egypt Gas provides necessary codes of practice and standards for the safe implementation of the project. The high pressure steel main would be constructed in utility corridors and no special right of way would be required except a small area (40 by 40 meters) for a pressure regulating station. The steel main would not pass close to the Pyramids (the closest point would be about 1.5 km away). A special permit for trenching would be obtained from the local authorities and the Egyptian Department of Antiquities if determined necessary by the local authorities. Petrogas has operational safety regulations and six safety engineers who send regular safety reports to the Mlnistry of Labor. The safety record of Petrogas has been satisfactory; however, a safety reporting system would be established as part of this project. At the time of negotiations assurances from Petrogas were obtained to implement this system by December 31, 1992. 5.18 Environmental and Safety Review of Trans Gulf Gas Component. The proposed project is an extension to existing facilities in the Gulf of Suez and, hence, does not pose a major potential impact to the environment. The onshore pipelines would not have any significant environmental impact as they would be buried and would include adequate safeguards against leaks and ruptures. The offshore pipelines would be designed in such a manner so as to J/ The manufactured gas process is based on using naphtha as a feedstock, which is substantially more expensive than the cost of natural gas supply. - 28 - avoid environmentally sensitive areas. Standard international petroleum industry practices and codes would be followed for the design of all offshore and onshore facilities. EGPC would undertake an environmental review of the proposed detailed design of the facilities and review the proposals with the Bank in order to address environmental concerns. In addition, EGPC would furnish the Bank with updated quarterly environmental reports indicating their compliance with environmental standards and practices. J. Project Management and Implementation 5.19 Greater Cairo Gas Development Component. -ogas would provide the conceptual design and project management and supervis,on and would have overall responsibility for implementing the component. Egypt Gas, as the sole contractor, would perform detailed engineering, construction and procurement services. Petrogas, with the assistance of Egypt Gas, has been able to expand the First Cairo Gas Distribution Project to a sizable network and has operated it safely for the past eight years. Based on this experience, Petrogas and Egypt Gas have demonstrated their capability to implement the proposed project within the six-year schedule. However, the existing contract between Petrogas and Egypt Gas is on a turnkey basis and needs to be modified so that the Bank can finance the procurement of material. As a condition of loan effectiveness, a revised contract satisfactory to the Bank would be signed. 5.20 The current organizational structure of Petrogas satisfies the concerns raised by the Bank in the First Cairo Gas Distribution Project. As shown in Annex IV, LPG and natural gas operations are now split, each headed by a general manager who reports directly to a chairman. The natural gas department has been strengthened to respond to Petrogas' increased operations. The Gas Department of Petrogas is responsible for the natural gas operations of the companv and would also be responsible for the proposed project's implementation. This department has now expanded to a large operational and project development unit with about 1,200 staff. The department has two operating units, one in East Cairo and the other in West Cairo, which are responsible for the operation and maintenance of the networks as well as for customer emergency service. A Project Development Department is responsible for the planning and development of new projects covering market surveys, basic design, cost estimates and project management and supervision. This department is using computerized techniques for network analysis and load forecasting. 5.21 Petrogas has been successful in developing a sizeable market in the residential sector in Cairo, but gas consumption in the commercial and industrial sectors has been minimal. Through a gas market development study (Annex VII), strategies would be reviewed in order to increase the penetration of gas in the commercial and industrial markets. As part of this strategy, a core of engineers would be established to promote gas sales in the commercial and industrial markets. The study would also provide assistance for Petrogas in conducting a new detailed market survey in Greater Cairo. A permanent small unit would be established in Petrogas to continuously review and analyze - 29 - the gas market and its impact on other fuels. This unit would initiate necessary policies and promote viable projects for the efficient expansion of the natural gas market. 5.22 To meet the training needs outlined above, Petrogas would: (i) establish a gas marketing unit within its organization and assign key staff to it by June 30, 1992; and (ii) carry out and complete a gas market development study by December 31, 1992, according to TORs satisfactory to the Bank. The study is expected to start by October 1991. 5.23 Trans Gulf Gas Component. EGPC would be the implementing agency for the proposed Trans Gulf Gas Project. A Project Implementation Unit would be established within the Gas Department for the purpose of project control. The basis of this unit was established at the time of the feasibility study with projecc implementation guidance provided by the Gas Production General Manager. The detailed design, procurement and project management would be undertaken by ENPPI, the consulting firm responsible for the feasibility study. Given the extensive experience of EGPC and of the consultants, project implementation risks are expected to be minimal. 5.24 The project is expected to be completed by June 30, 1997. VI. FINANCIAL ASPECTS 6.01 The financial organization of the gas subsector is essentially that of a single profit center (EGPC) with numerous functional subsidiaries, which operate on a cost basis. EGPC acts as the financial coordinator and implicitly sets transfer prices between subsidiaries (functions), which cover costs (including depreciation) plus a commission. The Petroleum Pipeline Company receives sufficient commissions to earn a 6 percent return on assets while Petrogas operates on a zero profit basis. Project funding, to the extent internal funds are not available, is arranged by EGPC. A. Historic EGPC Financial Performance 6.02 The financial performance of EGPC has historically been secure due to the fact that, as the Government's rent collector in the petroleum subsector, EGPC has low costs relative to revenues. EGPC has little debt (US$300 million equivalent as of June 1990 or less than 10 percent of long-term capital) as cash flow has generally been sufficient to cover investment requirements (Table 1 outlines past EGPC performance, with details in Annex XII). EGPC financial performance depends primarily on two factors: international and domestic energy prices and the costs of production under concession agreements. Traditional indicators of financial performance are generally misleading because EGPC's acts as rent collector; as such, returns, self- financing levels and debt service coverage are all very high. Nonetheless, EGPC ha- experienced deteriorating profit levels over the past six years (net - 30 - profit as a percent of revenues fell to 21 percent in FY90 from 39 percent in FY85) largely due to declining crude oil prices. 6.03 These conditions, compounded by the anticipated decline in oil production levels and the rising cost of gas supply (which are payable in foreign currency) could result in a net loss in the EGPC foreign currency account during the next decade. The two avenues Egypt has to control these problems are to increase domestic product prices (to increase revenues and reduce demand) and to expand gas supply to substitute for exportable petroleum products. Table 1: Historic EGPC Income and Cash Flow (millions LE) Prelim. FY85 FY86 FY88 FY89 FY90 Net Export Revenues/l 1,454 831 876 1,033 962 1,300 (percent of total) 43% 27% 28% 26% 24% 28% Total Revenues 3,350 3,088 3,100 3,935 4,089 4,564 Op. Expenses 2.032 1,976 2.007 2.648 2.955 3.590 Net Profit 1,318 1,111 1,093 1,287 1,134 974 (percent) 39% 36% 35% 33% 28% 21% Internal Funds 1,833 1,606 1,604 1,847 1,608 1,469 Taxes & Profit Dist. A 81% 83% 76% 77% 74% 751 Net Internal Sources 355 273 387 419 412 368 External Sources 64 78 66 45 8 n.a. Debt Service/2 15 22 30 67 64 76 Investments 478 299 167 402 176 268 Self-Financing X/3 44% 129% 108% 107X 162% 104% LI Export revenues at petroleum sector exchange rate. /t I'a all years, debt service coverage by internal funds exceeds 100 percent. /3 The ratio of internal funds after surplus disposition, taxes, debt service and working capital changes to three-year moving average capital expenditures. 6.04 As a result of the energy price reform program, high export prices of crude oil in FY91 and increases in supply of natural gas, EGPC's financial position has improved substantially. This improvement has resulted in increased transfers from EGPC to the budget of about LE 2 billion in FY91 and - 31 - EGPC PAYMENTS TO GOVERNMENT PeLyffneo Limited to MaX 40% of Revonues 13…- - - - 12- - w 1 10-- -t _ 6 7 _ FY85 FY 37 FYb Y1 FY3 F7 9 FY 36 FY i8 FY O0 FY 92 3 FYS Y13 Fiscal Year Cendino June 30) & Staus auo 040s Revs x Price Refam @40% V Refcrm + Incr Gls Figure 1 is forecast to increase by in excess of LE 2 billion in FY92. A similar increase in transfer to the Government's budget is forecast for FY93 based largely due to the energy price reform program. As Figure 3 indicates, the domestic energy price increases and increased gas supply would continue to have a considerable impact on the Government budget. B. EGPC Accoupts and Audits 6.05 EGPC would be the executing agency for the Trans Gulf Gas Component. The project is expected to cost approximately US$60.2 million including duties, taxes and contingencies. The proposed Bank loan would fund material costs totaling approximately US$34 million or 56 percent of the costs. This represents a 12 percent increase in outstanding EGPC foreign debt and would entail less than a 5 percent increase in total annual debt service. Should domestic energy prices rise as agreed, EGPC is forecast to easily meet debt service and investment obligations. EGPC accounts are subject to an annual external audit by the Central Audit Organization. Aside from documentary audits, this review is effected in collaboration with the Ministry of Finance to ensure that expenditures are in accordance with authorized budgeted amounts. EGPC would have the project accounts, its own accounts and financial statements, and the accounts and financial statements of the affiliates that - 32 - executed the projects audited by independent auditors and would supply copies of such statements to the Bank no later than six months after the end of each fiscal year. The Special Account would also be reviewed by independent auditors acceptable to the Bank. EGPC has agreed to maintain a debt service coverage of at least 1.5, The Government, as guarantor, has agreed that it would take all necessary actions to enable EGPC to achieve the financial goals agreed to with the Bank. C. _istoric Petrot i a erformancLe 6.06 Given that Petrogas is a cost center, financial performance has been determined by EGPC through commission levels, with net profit generally set to be small. The overall sales margin has been stable at about 0.6 piastre/cubic meter (in FY91 prices) over the past six years as shown in Table 2 (details in Annex XIII). The margin for residential sales has, however, declined by over 70 percent in real terms since FY85. Overall returns on net (historic) fixed assets are estimated to have been around 5 percent for the past six years. However, on a revalued basis, the returns would have been negative. Self- financing levels have been high in recent years, partly because investment dropped sharply after FY86. Over the past four years, annual investment declined from LE 125 million to an average of LE 88 million, in FY91 prices. Table 2: Historic Petrogas Sales Margins (piaster/cubic meter - mid 1990 prices) Prelim. FY85 FY86 FY87 FY88 FY89 FY90 Total Gas Sales 0.7 0.6 0.6 0.7 0.7 0.6 Residential 23.7 17.4 15.8 10.8 8.7 6.8 Power/Industry 0.4 0.4 0.4 0.6 0.6 0.5 LPG Sales 9.6 8.6 7.4 6.4 5.6 5.6 Historic Petrogas Cash Flows (millions LE) Internal Sources_l 22.0 27.2 29.5 30.4 34.9 42.9 of which gas 21% 26% 36% 69% 68% 70X Taxes & Profit Dist. % 10% 18% 18% 23% 29% 34% Net Internal Sources 19.9 22.4 24.1 23.5 24.7 28.5 External Sources 10.9 11.5 0.0 2.6 4.1 7.0 Debt Service 5.2 5.1 4.9 4.7 4.5 6.7 (coverage)e' 0.9 1.4 2.2 4.5 5.2 4.4 Investments 34.4 40.3 25.8 29.7 30.9 50.5 of which gas 76X 76% 65% 70% 67% 80% (Self-financing %)/3 36% 61% 46% 73% 110% 60% /1 Internal sources before interest and taxes. Lg The ratio of internal gas operation funds before interest and taxes to total debt service. 23 The ratio of internal funds after debt service and working capital changes to three-year moving average capital expenditures. - 33 - D. Future Petrogas Investments and Financing 6.07 Petrogas will experience a substantial increase in investment and sales activity over the next six years. The proposed GCGDC requires annual investments of approximately 131 million LE (in FY91 prices), which is double recent gas investment levels but comparable to levels experienced under the first Cairo distribution project. In addition, Petrogas may require substantial investments in LPG facilities in order to efficiently utilize anticipated increases in supplies of LPG'. During a period of rapid expansion of gas and LPG sales, the maintenance of adequate levels of working capital will be important. Cash flow would, therefore, be the prime financial concern of Petrogas over the project period. The proposed project would finance foreign material costs totaling approximately US$67 million (before price contingencies) or 36 percent of total project costs. Consumer contributions are estimated to provide a further 5 percent of project costs. The remaining financing must come from internal funds, local debt or shareholder contributions. 6.08 A self-financing level of 25 percent is considered appropriate for Petrogas at this stage of development. During a period of rapid growth, higher levels would unduly penalize current consumers, while lower levels risk delaying the project due to inadequate cash flow. The margins required to achieve a 25 percent self-financing level are discussed below in light of anticipated changes in petroleum product pricing in Egypt over the next five years. Two price levels are important, consumer prices and transfer prices. Consumer Gas Prices: For the purposes of financial projections, the price for industrial and power sector gas sales was set to fuel oil equivalent plus a small margin to cover working capital carrying costs and contributions towards the network. Residential and commercial prices were based upon fuel oil equivalent, plus a margin sufficient to earn an 8 percent real return on capital, to a maximum of LPG equivalence. LPG prices were assumed to reach 75 percent of international prices by FY96, plus a distribution margin of US$30 per tonne by FY96, and full economic costs of US$150 per tonne by June 1998. Transfer Prices: The current transfer pricing regime is based on zero profit margins and not on economic or market factors. With respect to natural gas, the proper transfer price at the city gate under current conditions is the fuel oil equivalent. 1/ LPG investments could exceed gas investments in some years based on capital costs of LE 525 per incremental tonne of demand, which has been the average over the past six years, including adjustment to official versus preferred petroleum sector exchange rates. - 34 - 6.09 The operating margin resulting from the pricing conditions described above would be about 0.7 piastres/m3 in mid-1990 prices. This would be sufficient to ensure at least a 25 percent self-financing level during the implementation phase of the GCGDC. This implies that until the end of FY95 (while consumer petroleum product prices remain subsidized) Petrogas input prices may be required to remain up to 5 percent less than the fuel oil equivalent. 6.10 The remaining project costs (after Bank financing and consumer contributions) could be funded by local debt or shareholder contributions. In taking on the proposed loan, debt as a percent of long term capital associated with revalued gas assets would rise from 10 percent' currently to 20 percent by FY96 (see Appendix XIII for Petrogas Financial Projections). On an historic cost basis, leverage would reach almost 40 percent by FY96. Typical allowable levels of debt in North American gas utilities are generally between 40 percent and 60 percent. Given that Petrogas is a relatively young utility and expected to grow rapidly over the next five years, additional leverage does not appear prudent in the near term. The potential for cash flow shortages is great due to rising working capital needs and the fact that annual debt service is estimated to increase by a factor of 5 in real terms by FY97. This leaves equity contributions as the only remaining source of funds. EGPC would provide the residual project costs in the form of direct equity and/or reduced shareholder payments. In total, 59 percent of project costs must come from internal funds and equity, implying total annual contributions of approximately LE 83 million (FY91 prices) from FY93 to FY96. Expected project funding is summarized in Table 3 below. To ensure that the financing from internally generated funds would be established, Petrogas has agreed that a 25 percent self-financing ratio would be maintained by Petrogas on its gas operations and that Petrogas' debt service coverage ratio would exceed 1.5 to ensure corporate creditworthiness. I/ Based upon revalued capital, assuming an equal split between foreign and local costs for gas assets. - 35 - Tajle 3: Cairo Gas Distribution: Summary Project Sources and Applications of Funds (millions of LE in constant FY91 prices) IOtL (X) F92Z FY9. = L24 F9 E Y E9k E2 Sources Internal Fundstl 169 26X 0 27 36 37 30 39 IBRD Debt 234 361 6 59 55 57 57 0 Consumers 36 5X 0 8 8 8 8 7 Equity 217 33X 0 51 43 48 59 18 Total 657 1001 6 144 142 149 153 63 Applications Investments 657 100l 6 144 142 149 153 63 L1 Internal funds available after covering debt service and working capital requirements. E. Petrogas Accounts and Audit 6.11 The LPG and gas operations of Petrogas are inherently different. In the future, gas will increasingly compete with LPG for markets and internal resources. At the recommendation of the Bank, Petrogas separated the technical operations of gas and LPG. However, the financial operations are still not formally separated. During project appraisal, it was recomended that Petrogas consider creating separate organizations at some point in time. As a first step, Petrogas would maintain separate accounts for LPG and natural gas and furnish copies of financial statements no later than six months after the end of each fiscal year, as well as budget forecasts for the following fiscal year. This process would be supported through the structuring of loan covenants, which would focus on achieving a 25 percent self-financing capability on gas operations as separate from LPG operations. Petrogas prepares full accounts of its financial position and of its annual operations at the end of every year. These accounts are subject to an external audit by the Egyptian Central Audit Organization and to the approval of the general meeting of stockholders held regularly within six months after the end of each year. Petrogas would prepare project accounts separately, and these accounts and annual accounts and financial statements, would also be audited independently. The Bank would be supplied with copies of all statements no later than six months after the end of every year. - 36 - VII. ECONOMIC ANALYSIS A. Economic Jus..ification 7.01 The principal economic justification for the GCGDC is the replacement of high-value fuels (LPG and gas oil) with a fuel of lower economic value, natural gas. The project would also generate benefits for consumers in terms of the convenience and cleanliness of natural gas. In the case of the Trans Gulf Gas Component, the primary benefit would be the substitur-Jon of shut-in and flared gas for fuel oil, which is currently used as a fuel. in power and industrial applications. 7.02 The critical variables for the economic return are the cost of the project, the level of gas consumption achieved, the cost of gas input to the project, and the value of fuels displaced. The project has been evaluated by comparing the economic value of fuels displaced by gas, and the value of the convenience benefits of gas, with the costs of the project and the opportunity cost of gas. B. Project Economic Costs 7.03 Total project capital costs include both infrastructure financed by the project and any connection and conversion charges financed by consumers. Estimated equilibrium exchange rates' have been used in converting local costs to dollars. The cost of gas has been taken as the fuel oil equivalent at international prices as, in the absence of the project, gas would be used to displace fuel oil in dual-fired power stations and heavy industries. As Egypt is an exporter of fuel oil and projected to remain so over the medium term, any fuel oil displaced would be exported. The gas supply-demand analysis confirms that Egypt is unlikely to have sufficient gas to displace all fuel oil from power and heavy industry. C. Project Economic Benefits 7.04 The volume of gas sales achieved for a given expenditure on the distribution system is critical to gas distribution economics. Given Petrogas's substantial experience with household connections, it is assumed that the target number of residential customers is achieved. Usage per residential household (240 cm/yr) is projected on the basis of those households currently connected to the distribution system. A trend consumption growth of 1 percent per annum is anticipated, primarily due to the lJ The estimated equilibrium exchange rates are 3.95, 4.67, 5.20, 5.50 and 5.62 for FY92 to FY96, respectively. - 37 - increasing penetration of natural gas water heaters. It has been assumed that all the fuel displaced in households is LPG, although electricity is used for cooking and water heating in a small percentage of households. The displacement of electricity will tend to increase economic benefits, relative to LPG displacement. 7.05 Commercial sector demand has been estimated on the basis of existing use, and information on comparable projects, at 6,000 cm/yr per customer. This is above the present average of around 5,000 cm/yr. This latter figure is believed to be depressed because gas to commercial consumers costs around twice as much as LPG. Average commercial consumption is expected to rise by about 5 percent per annum, due to a combination of growth in the service sector and of the switching to gas by large users as LPG prices are raised. While most of the fuel displaced in the commercial sector is expected to be LPG, a significant proportion of gas oil is expected to be displaced among larger users. The estimated industrial demand for gas is based upon current fuel usage as surveyed by Petrogas. 7.06 Because the relatively large unit consumption of commercial consumers greatly improves the load on the distribution system, project economics are sensitive to achieving target consumption in the commercial sector. Under the first phase of Cairo gas distributicn, commercial consumption was held back by the low relative price of LPG and by poor marketing. The risks associated with increased commercial use are being addressed by specifically targeting LPG prices in the energy price reform program, by initiating gas tariff reform, by focussing distribution expansion in areas with relatively high concentrations of potential commercial users and by strengthening the operations of Petrogas. Hence, the target commercial consumption is expected to be achieved. 7.07 The GCGDC would result in the annual displacement of an estimated 76,000 tonnes of LPG, 18,000 tonnes of fuel oil and 26,000 tonnes of gas oil by FY98. These fuels have been valued at border prices. Prices are adjusted for delivery costs to the customer gate or export point. Since approximately 80 percent of the gross benefits of the GCGDC are attributable to LPG displacement, the valuation of LPG is crucial to the project's economics. In the long term, potential LPG demand in Egypt could only be satisfied by imports, and the cif price for LPG has thus been used in the calculation of LPG economic value. In addition, LPG incurs substantial distribution costs, which have been estimated (based upon detailed costings provided by Petrogas) at US$150/tonne. 7.08 Conversion to natural gas confers substantial benefits upon LPG consumers through savings on LPG cylinder delivery, a more secure supply of energy and savings on the space needed for LPG cylinders. These benefits have been estimated at US$30/ton of LPG displaced for residential consumers and at US$15/ton of LPG displaced for commercial consumers (see Annex XIV). 7.09 The project would also yield environmental benefits from the displacement of gas oil and fuel oil in industries and on commercial premises in urban Cairo. However, these benefits have to be balanced against the - 38 - increased fuel oil used in power stations outside urban Cairo due to the diversion of natural gas for the GCGDC. Additional environmental benefits would also arise from a reduction in the transport of LPG cylinders (about 5 million per annum) through congested city streets. D. Economic Rate of Return 7.10 The Economic Rate of Return (ERR) for the project is estimated to be 18 percent. The ERR of the GCGDC is 16 percent (see Annex XIV for details). Sensitivities on key parameters show that the component is robust to a number of adverse assumptions on costs and benefits: ERR(X Base Case 16 Capital Cost -201 20 Capital Cost +20X 13 Unit Gas Consumption +20X 19 Unit Gas Consumption -201 12 LPG Prices +201 18 Oil Prices -201 14 7.11 Given that the marginal use of natural gas is in dual-fired industrial and power boilers, the benefits attributed to the Trans Gulf Gas component are valued at the international price of fuel oil. The ERR of the Trans Gulf Gas Component is estimated to be 28 percent (see Annex XIV for details). The largest risks projected for this Component are lower-than- forecast oil prices and a shorter-than-expected producing life for the fields. With a 20 percent decrease in oil prices, the ERR would remain attractive at 14 percent. Given that the probability distribution of oil prices over the longer term is positively skewed, the risk of the return dropping to this level is unlikely. Should the economic life of the project be reduced from 13 to 6 years, the ERR would remain attractive at 21 percent. The sensitivities of the ERR to key input assumptions are outlined below, indicating that the project's viabllity is robust: ERR (X? Base Case 28 Capital Cost -201 39 Capital Cost +20X 21 Oil Prices +201 41 OLI Prices -201 14 Six Year Life 21 - 39 - E. Risks 7.12 The primary risk associated with the GCGDC is the possibility of an insufficient increase in natural gas consumption by commercial customers due to the relatively low prices of substitute fuels. The pricing issue regarding substitute energy products has been addressed during the appraisal of the project. In May 1990 weighted average petroleum product prices were increased by 44 percent, and LPG (the primary fuel being substituted under the GCGDC) was increased by 130 percent. Furthermore, the Government increased petroleum product prices by 52 percent as of May 3, 1991. This price increase focussed on increasing the price of the most heavily subsidized products by a greater than average amount. In particular, the primary products for which natural gas is a substitute, LPG and gas oil, have been increased substantially. LPG is about four times the price prevailing prior to May 1990 and gas oil has nearly tripled. As a result, Petrogas has had a considerable increase in applications from commercial users for gas supply, thus minimizing the economic risk associated with the GCGDC. The primary risk associated with the Trans Gulf Gas Component is associated with the life of the related gas fields. However, should the economic life be reduced from the expected level of thirteen years to six years, the returns would still exceed 20 percent. Hence, this risk is expected to be minimal. VIII. AGREEMENTS REACHED AND RECOMMENDATIONS 8.01 During negotiations, assurances were obtained from EGPC that: (a) a study of the Cost of Gas Distribution, to be completed by December 31, 1992, would be undertaken in collaboration with the Bank (paras. 3.22); (b) the facility in the existing Ras Shokeir pipeline to enable transfer of gas produced from the Trans Gulf Gas Component would be built simultaneously with this Component (para. 5.06); (c) the Refinery Sector Investment Planning Study (para. 3.17) and the Gulf of Suez Gas Development Plan Study (para. 3.18) would be undertaken and completed by December 31, 1993; (d) EGPC would operate a special account (revolving fund) for Bank loan disbursements (para. 5.12); (e) quarterly progress reports would be submitted to the Bank during project implementation and annually thereafter during the life of the proposed loan; and within four months of project completion, a - 40 - completion report dealing with project implementation and initial operations and a reassessment of the project costs and benefits would be submitted to the Bank (para. 5.13); (f) the construction of facilities for the Trans Gulf Gas Component shall be undertaken in accordance with environmental standards satisfactory to the Bank and the progress reports would include all information regarding adherence to such standards (para 5.18); (g) the finances of EGPC and those of its subsidiaries that would execute project components would be audited by independent auditors within six months of the end of each fiscal year to ensure that the consolidated net revenues of EGPC and its subsidiaries would not be less than 1.5 times the consolidated debt service ratio (para.6.05); and (h) funds would promptly be provided, as necessary, for the GCGDC component, over and above Bank or other loans (para. 6.10). 8.02 During negotiations, assurances were obtained from Petrogas that: (a) quarterly progress reports would be submitted to the Bank during project implementation and annually thereafter during the life of the proposed loan; and within four months of project completion, a completion report dealing with project implementation and initial operations and a reassessment of the project's costs and benefits would be submitted to the Bank (para. 5.13); (b) Prior to loan effectiveness, Petrogas would enter into a revised contract with Egypt Gas, to be approved by the Bank based on the draft contract, which would be reviewed during loan negotiations (para. 5.19); (c) Petrogas would establish a marketing unit within its organization by June 30, 1992 and would undertake a gas market development survey by December 31, 1992 (para. 5.22); (d) margins on natural gas sales of Petrogas would be maintained such that revenues would be sufficient for a debt service coverage ratio of not less than 1.5 and a self-financing ratio of not less than 25 percent for gas operations (paras. 6.10); and (e) Petrogas would provide separate gas and LPG accounts, have financial statements audited independently, and supply the Bank with copies of such statements no later than six months after the end of each fiscal year; Petrogas would also provide both the auditor's reports and financial statements along with budget forecasts for the following fiscal year (para. 6.11). - 41 - 8.03 Am conditions of loan effectiveness: (a) a Subsidiary Loan Agreement would be executed by EGPC on behalf of the Borrower and Petrogas (para. 5.08); (b) the EIB Loan Agreement would be concluded between EGPC and EIB and all conditions precedent to the effectiveness of the EIB Loan Agreement (except for the effectiveness of the Loan Agreement) would be fulfilled (para. 5.08); and (c) a revised contract between Petrogas and Egypt Gas, satisfactory to the Bank, would be signed (para. 5.19). Recommendation 8.04 Subject to the foregoing, the project would be suitable for a Bank loan of US$84 million equivalent for a term of 20 years, including a grace period of five years. EGYPT GAS INVUES PROJECT Ftmetional Structure of Oil Industry MNinister of Petroles I iSupri Petroles i IE1tPloation IProductin Refining and Pipeline Narketing Ie ConstructI PrcsiPro ng Distribution Engineering & U ' ~~~~~~~~~~~~~~~~~~~~~~Services Foreign Partners .. Foreign Partners CPC 6~CPC GILOSuz i Processing PPC ISR ; Fe9 || EPOCO R C Caany Pet. Co. Oil Los.~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~~~r r . _ MAM EL. ASARIr . PETRCOEL Cily Petrolesa SIED |Coop EIPPI _ Egptian | . Caqny . . Pet. Co. _ Drilling Co. C IEL-MiNIMlF Shoa s R | ~Al l Alexan drial . . . . . -S ~~~~Petroleua I PEIROGAS I I hSE APIDOOO 541C Cb pany Ga 1 6S | DfOCO C Cairo Oil| OSOO Refining Pet roen I gyptan General Petrole1 CorporatioSenrvce IEL-ANAL F- Egypt Petrol gEGffi TCO Ccspany South~~ of0APETCO Esso Assycut Oil X Raaadan I 1 huucalI |ALAHERIA| g Refining Source: Egypt1an General Petroleum Corporation EGYrPT GAS NVESTh PROJECT Egyptian General Petroleum Corporation Organization Chart 1Board of Oi1 t1 Vice Vice ~~~~~~~~~~~~~~~~~Vice Vice Vice v ice Chairmn Caian Vice Chairman Vice Vice Chairoma Vice Chairom Chairman Chairman Finanee Plannn Chair"n Foreign and Chuinn Chaimen hinistratian Chain n Exploratlon Natuml 6as Production h Econnaic and Operations Joint Venture Internal Trade Foreign Trade and Legal h1e ieeti n m E6 - 1 E6PC # ISecreterRstl Internal Auditl Security Depart et rpr n EGPC E6PC Engineering Refining and Oepartot eanufacturing Department g E6PC l l | EGPC Follow-up Distribution Department Department EGPC Crmmercial Souree: Egyptian 6eneral Petroleum Corporation Department - 44 - Annex UII Page 1 of 7 Egm GAS JNVESTMENT PROJ,~.: An assessment has been made of the outlook to the year 2005 for natural gas demand and supply in Egypt. The principal purpose of this assessment is to determine whether Egypt can be considered a gas deficit country, in that there will remain unsatisfied demand for gas in sectors where gas use would be economic. This assessment also provides a framework for judging priorities in gas utilization and supply. The methodology essentially consists of estimating the potential gas use in power and in the main gas-using industries, which are either already connected to the gas grid or could easily be connected to the grid in the future. To this is added an estimate of possible demand in other industries and in the residential and commercial sector. Supply projections are based upon the outlook for production from fields currently producing or under development and from discoveries that may be developed in the future. The net deficit position represents a relatively conservative estimate of the unsatisfied economic demand for gas. An estimate is made of the rate of discoveries needed both to replace ongoing production and to cover this deficit. Gas Demand Rower Potential demand for gas in the power sector has been calculated on the basis of the Egyptian Electricity Authority's long-term investment plan. The potential demand in a given year is taken to be the sum of the gas requirement of gas-dedicated plants (e.g., turbines and combined cycle) and the requirement of dual-fuelled steam plants if all fuel requirements of these plants were met by gas. Fuel requirements are calculated on the basis of historical fuel requirements of EEA plants. Power demand is assumed to grow at 4 percent p.a. to 1994/95 and at 6 percent p.a. thereafter. Hydro output is assumed constant at an annual average of 9,300 MW, with all growth coming from thermal capacity. Nea1ly all of the forward investment plans of EEA consist of investments in combined cycle plants or dual-fired steam plants. It is assumed that combined cycle plants run at base load (70 percent), while the load on gas turbines falls from an average of 54 percent in 1988/89 to 20 percent in 1993/94 as system efficiencies reduce reliance on turbines for base and medium load. Dual-fired steam plants pick up the balancing load, with any remaining older (and hence inefficient) fuel oil plants phased out by 1993/94. The only exception to this pattern is the 300 MW Assiut oil plant, which is not - 45 - Annex III Page 2 of 7 connected to the gas grid and consumes the fuel oil output of the Assiut refinery. The forward program to 1995 includes the conversion of thermal stations at Damanhour, Cairo West and Talkha (current capacity ca. 500 MW) to gas, leaving only a very small (ca. 200 MW) quantity of inefficient fuel-oil-fired capacity apart from Assiut. The Cairo West and Talkha plants will receive new dual-fired units, and the existing Abu Qir dual-fired thermal station will be expanded. By FY95 however, about 25 percent of capacity will come from combined cycle units, with a total of 2,300 MW at Talkha, Dammieta, Cairo South, Mahmoudia and Damanhour. All larger gas turbines had been converted to dual gas oil/gas firing by 1990, the only exceptions being small units off the gas grid. The overall efficiency of fuel use in Egyptian power stations is likely to rise substantially by 1995, due to several factors: the lowering of the load on gas turbines as system efficiency increases; the conversion of some large pre-built turbines and existing steam units to combined cycle operation; the refurbishment of older steam units during their conversion to natural gas dual firing; and the construction of new steam units. Average effici.ency is likely to improve from around 286 g/kwh (fuel oil equivalent) in 1988/89 to 225 g/kwh by 1994/95. Longer term capacity growth, at around 600 MW/yr is assumed to come from dual-fired steam stations, starting with Kureimat in 1995/96. Construction of further combined cycle plants is unlikely unless large new discoveries are made, which could ensure long-term dedicated gas supplies. The main downside risks to this forecast of potential gas demand in power lie with possible lower power demand growth due to greater efficiency of end use, in response to price rises or slow economic growth. Upside risks lie with higher growth in electricity demand in the long term, assuming successful economic restructuring, and with a lowering of hydro capacity at Aswan due to falling water levels. Egypt currently has three nitrogenous fertilizer plants using gas (at Talkha, Abu Qir and Suez), which have been using gas for many years and consumed around 120 mmcfd in FY90. The balance of demand is met through production from the Kima electrolysis plant in Upper Egypt, a small plant at Helwan that uses coke oven gas and imports. Egyptian fertilizer requirements are expected to grow at 4 percent p.a., as fertilizer application rates and the fertilized agricultural area rise. To meet this additional demand without a large growth in imports, there will be a major expansion of the Abu Qir plant, and new units at Suez will be built. The small Helwan plant could be replaced by a natural gas unit. - 46 - Annex III Page 3 of 7 The future of the Kima plant, which is currently highly uneconomic, is subject to some uncertainty. It has been assumed that this plant will be replaced with an enlarged plant based upon fuel oil, as natural gas is not planned to be supplied to Upper Egypt at present. Celmen-t At present four of Egypt's seven cement plants (Turah, Helwan, Suez and National) are dual fired by fuel oil and natural gas; consumption in 1990/91 was 54 mmcfd. However, fuel oil usage is still around 1 million tons p.a. Plans exist t, connect the plants at Kattamia and Ameriyah to gas in the next two years. 'The only other large plant is at Assiut, which is not served by the gas grid. The pace of growth in cement demand in Egypt in the l990s is expected to be well below the 15 percent p.a. seen between 1975 and 1985. Growth is anticipated to be closer to GDP (4 percent p.a.), to be met by expansion of the more efficient plants. The phasing out of wet process manufacture by FY96 is expected to reduce energy requirements. Wet process manufacture, which accounted for some 20 percent of supplies in FY90, uses about 75 percent more energy than the dry process. Total potential gas usage in plants connected to the gas grid is thus likely to rise at about 3 percent p.a. during the 1990s. Other Industries Outside of the above sectors, industrial energy use in Egypt remains dominated by oil. Other industries used nearly 4 million tons of fuel oil and gas oil in FY90, compared with only 1.2 million tons of fuel oil equivalent of natural gas. Most of the demand in this sector is around the major cities served by gas and is thus potentially substitutable (the GCGDEP will substitute about 65,000 tons of this demand by 1998). In practice, the substitution of at least 50 percent of industrial energy demand with gas should be seen as a reasonable long-term goal; this is taken as the potential demand of this sector beyond 2000. There is also significant potential demand for gas in the petroleum sector, principally for refinery fuel. Two of Egypt's refineries (Alexandria and Suez) are connected to gas, and a third (Ameriya) is expected to be connected in the next two years. However, consumption in FY90 was only 8 mmfd. Potential consumption in all the refineries (excluding Assiut) is conservatively estimated at about 90 mmcfd by 2000. Residential and Commercial Despite relatively low per capita household energy consumption and the lack of a space heating requirement, Egypt's large urbanized population and sizeable commercial and services sector provides a substantial potential demand base. Current plans calling for extending the grid in Cairo, with - 47 - Annex III Page 4 of 7 a smaller grid in Alexandria, are likely to lead to a demand of only some 25 mmcfd in 2000, which has been taken as the base case forecast. However, actual potential consumption could be far above this level, if funds were available to connect suitable areas in all major cities. Upper Egvit Demand All the estimates of potential demand above exclude the demand which would arise if Upper Egypt, including the city of Assiut and points further South, were connected to gas. Total additional potential demand from connection of Upper Egypt could be at least 150 mmcfd by the late 1990s, or an additional 7 percent above the base case for the rest of Egypt. This potential demand would come from the Assiut power plant (50 mmcfd), Assiut cement plant (40 mmcfd), Kima fertilizer replacement (40 mmcfd) and miscellaneous demand from the Assiut refinery and other industries (at least 20 mmcfd). If sufficient gas were available, this level of demand could justify a pipeline either from the Red Sea coast, or from Cairo, at least as far as Assiut. Gas Production Estimates of future gas production are based upon discussions with EGPC and published industry sources. Figures are shown by field processing plant and are net of any LPG extracted at the plant (LPG is extracted at all plants except Badr El Din). Of the established fields, production at Abu el Gharadig, which started in 1976, is expected to decline steadily from 1994/95 as the reservoir is depleted. Production from the Abu Madi field is expected to be boosted by around 25 percent in 1992/93 and to maintain this higher level until 2005. However, this may be optimistic and production could remain steady at around 340 mmcfd. Abu Qir production has suffered some well productivity problems and is not expected to exceed previous production levels. Gulf of Suez associated gas production is constrained by capacity at the Ras Shukeir processing plant and in the pipeline to Suez, and hence no expansion is possible from the established infrastructure. The principal increment to production is expected to come from the Badr El Din (BED) developments and from the El Qara development in the Abu Madi area. BED 3 came on stream in the second half of 1990 and is expected to build a plateau of 150 mmcfd during 1991. BED 2 is expected to contribute around 75 mmcfd from the beginning of 1992. The Abu Senan field will link into the BED line to Ameriya, producing an estimated 75 mmifd from 1991 onwards. El Qara is expected to produce 120 mmnfd from 1992, which will be processed jointly with Abu Madi gas. Gas from the Khalda area in the Western Desert, which is located too far from the main consumption areas for transport to be economic at present, is being developed to supply a power plant in Metruh, on the Mediterranean coast. With no link to the national grid, output is demand constrained and will - 48 - Annex IU Page 5 of 7 increase with the expansion of power generation capacity. If substantial additional gas discoveries are made in the area, transport of the gas to the Cairo/Alexandria areas may be possible, although it is unlikely that any such project will materialize before the late 1990s. Of the potential developments identified, the most promising is the recovery of additional associated gas from the Gulf of Suez, beginning with the Trans Gulf Project. This should supply some 70 mmcfd from 1993. It is assumed that an additional increment of this amount is recovered from 1997 onwards, although the potential could be above this level. The Harid field, which lies at the Red Sea entrance of the Gulf of Suez, is at present assumed to be too small to develop, although additional exploration may prove reserves in the Red Sea that would make development economic, although production is unlikely before 2000. Port Fouad, El Timsah and some related structures, which lie offshore from the Eastern Nile Delta, are currently under evaluation by IOCs and provide the most substantial longer term development options. It is assumed that around 1.5 tef of reserves from this area can be developed. However, much additional appraisal drilling is required before a development decision can be taken, and the 1997/98 start-up date assumed may be optimistic. Supply-Demand Balance The comparison of potential demand with potential supply, based upon existing identified reserves detailed in the table below, shows an excess of potential demand over supply of around 160 mmcfd in 1992/93, rising to 700 mmcfd in 2000. Some of this gap will no doubt be filled by production from new discoveries. However, the level of new discoveries needed to sustain self- sufficiency, particularly beyond 2000, is relatively high. Moreover, any new discoveries will take at least three years to come into production (probably much longer if they are located well away from existing pipelines); hence self-sufficiency is not possible before about 1995, whatever the level of future discoveries. The total quantity of reserves required to achieve self-sufficiency, on the basis of potential demand projections, has been calculated on the following assumptions: that sufficient gas will have to be discovered, on average, each year to replace production in that year; and that additional reserves will have to be discovered to cover the growing gap between potential demand and supply. It is assumed that the reserves/production ratio for all new discoveries will be 20. On this basis, total new discoveries required to maintain self- sufficiency until 2000 would be about 12 tcf. With growing demand, however, discoveries would have to rise to 20 tcf by 2005. These figures appear large relative to the total discoveries to date of around 13 tcf and would probably require the discovery of a major new gas-prone geological play system. Hence, the balance of probability is that Egypt will remain a gas-deficit country in the long term. N: \ehbad\Saz\wm*x3. e& 49 - .4~ ~~~~... ARAB REPUBLIC OF EGYPT :. -Annex III GAS INVESTMENT LOAN - Pae6 of7 NATURAL GAS SUPPLY/DEMAND BALANCE , . OTENTIAL DEMAND FY89 FY90 FY91 FY92 FY93 FY94 PY95 FY96 FY97 FY98 FY99 POWER 6,486 7,214 8,755 9,499 9,333 10,163 10,909 11,813 12,679 13,602 14,579 Steam NG/HFO 4,394 4,634 5,803 6,821 5,979 6,099 6,845 7,599 8,465 9,388 10,365 Combined C 0 0 610 610 2,012 3,348 3,348 3,348 3,348 3,348 3,348 Gas Turbines 2,092 2,580 2,192 1,918 1,193 567 567 567 567 567 567 FERTILIZERS 1,161 1,251 1,145 1,325 1,530 1,609 1,663 1,681 1,707 1,785 1,867 CEMENT 1,394 1,530 1,362 1,364 1,367 1,385 1,453 1,435 1,509 1,586 1,666 PETROLEUM 288 305 365 400 550 620 660 693 728 764 802 INDUSTRY 1,976 2,079 2,131 2,216 2,305 2,397 2,493 2,593 2,696 2,804 2,916 RES/COM 67 74 81 100 120 140 160 180 200 220 240 TOTAL DEMAND 11,372 12,453 13,839 14,904 15,205 16,314 17,337 18,395 19,519 20,762 22,070 POTENTIAL SUPPLY FYL.9 FY90 FY91 FY92 FY93 FY94 FY95 FY96 FY97 FY98 FY99 PRODUCING 7,279 7,908 8,037 8,037 10,325 10,325 10,271 10,220 10,172 10,126 10,082 Abu el Gharadig 1,195 1,073 1,073 1,073 1,073 1,073 1,019 968 920 874 830 Abu Madi (+Qara) 2,619 3,484 3,484 3,484 6,772 5,772 5,772 5,772 5,772 5,772 5,772 Abu Qir (+N.A.Q) 2,016 1,959 2,000 2,000 2,000 2,000 2,000 2,000 2,000 2,000 2,000 Guff of Suez 1,372 1,313 1,400 1,400 1,400 1,400 1,400 1,400 1,400 1,400 1,400 Sinai 77 79 80 80 80 80 80 80 80 80 so UNDER DEV. 0 0 925 2,475 3,250 3,2. ) 3,250 3,400 3,400 3,400 3,400 BED/A Sennan 0 0 775 2,325 3,100 3,100 3,100 3,100 3,100 3,100 3,100 Khalda 0 0 150 150 150 150 150 300 300 300 300 POTENTIAL DEV 0 0 0 0 0 750 750 750 750 3,000 4,500 El Temsah/P.Fouad etc 1,500 3,000 Gulf of Suez Add. 750 750 750 750 1,500 1,500 TOTAl SUPPLY 7,279 7,908 8,962 10,512 13,575 14,325 14,271 14,370 14,322 16,526 17,982 BALANCE 4,093 4,545 4,877 4,392 1,630 1,989 3,066 4,024 5,197 4,236 4,088 Annex III - 50 - Page 7 of 7 EGYPT: NATURAL GAS SUPPLY/DEMAND GAP 25,000 Potential Gas Demand 20,000 15,000 . o,000 5,000 0 88/89 89/90 9091 91/92 92193 93/94 94/95 95/96 96/97 97/98 98/99 99/00 Page 1 - 51 - Annex IV d ~~~~~~jX 16 a~~ 4E - 52 - Annex M Page 1 of 9 GAS INVESTMENT PROJECT Greateg Cairo Gas pistribution CMonpt The proposed Cairo Gas Distribution Project would consist of: 1. Construction of 16-km steel mains with a 12" diameter high pressure main from the Nasr City's pressure regulating stations (PRS) to Abbasia to supply gas to industries along the route and to provide additional supply to Nasr City, El Obour and Abbasia; 2. Installation of one PRS with 60,000 CM/hr capacity in Abbasia to reduce the main feeder's pressure from 30-bar to 7-bar; 3. Installation of some 8-km additional steel mains to supply gas to industries in the west of Cairo; 4. Construction of a 900-km medium pressure and low pressure polyethylene (PE) netwotk; 5. Installation of 55 district rAgulating stations and 500 service regulators to reduce the pressure from 7-bar to 4-bar and from 4- bar to 75-milli. bar, the required pressure for the service islands; 6. Installation of river crossings from Roda Island to East Cairo, Garden City and Monira areas; 7. Construction of 31,080 service connections for residential apartment buildings, 5,000 (3,000 infill and 2,000 new areas) for commercial consumers, and 17 for industrial consumers; 8. Installation of 3,720-km carcassing for the apartment buildings and internal piping for the residential consumer premises; 9. Installation of 235,000 meter and governor kits for residential and 5,017 meters and regulator stations for industrial and commercial consumers; 10. Conversion of about 400,000 consumers; appliance/burners; and 11. Technical assistance that would finance: (a) conversion of some existing facilities to training centers to be equipped with modern facilities; and training of technical staff both in Egypt and in other countries with advanced gas industry, to maximize operational efficiency; and (b) computerization of customer services, planning and engineering, emergency centers, and MIS. - 53 - AnanexV Page 2 of 9 The details regarding the number of new customers expected to be serviced by the infrastructure financed under the loan and their location are based on a series of surveys undertaken by Petrogas and their consultant since 1982. In the Garden City area, gas would be supplied to hotels, some of which are still using costly manufactured gas. In the West Cairo area, which is a new gas development area, a mixed development c.. the west bank of the River Nile stretching from Madinet El Omal in the north to Giza in the south and the Pyramids in the west is planned. There are a number of high-rise apartment buildings along the banks of the Nile on the islands of Zamalik and Manial El Rodah, and on the opposite side of the islands in the main banks, that are targeted for connection to natural gas. Some of these blocks are more than 20 stories high. The housing potential along the banks of the Nile and in the center of the area designated for the gas network tends to be good. New housing and large- and medium-size commercial consumers concentrated around the parallel roads that lead towards the Pyramids are also targeted for connection to natural gas. The details regarding the expected location of new consumers are as indicated below: No. of Customers A. Cairo West 1. El Haram Area (Pyramid) 110,000 2. Giza 15,000 3. Imbaba l15.000 Subtotal 140,000 B. Cairo East 1. 15 of May City (Helwan) 10,000 2. Emtedad Rameses (Abbasia) 7,000 3. Sheraton (Heliopolis) 5,000 4. El Eskan El Swesry (N. City) 5,000 5. Medinet El Solb (Helwan) 5,000 6. El Nozhah (Heliopolis) 3,000 7. El Soudia (Zeitoon) 3,000 8. New Developments (N. City) 3,000 9. El Obour Extension 2,000 10. El Obour 2 1,000 11. Awel Mayo City (N. City) 1,000 12. Eskan El Mohandeseen (N. City) 1,000 13. Garden City and Monira 14.000 Subtotal 60,000 C. Commercial and Infill 1. Residential Infill 35,000 2. Commercial Infill 3,000 3. New Commercial 2,000 Subtotal 40,000 D. Industrial Consumers 17 Total Consumers Under the Proposed Project 240,017 - 54 - Annex V Page 3 of 9 The yearly progress for the distribution network and the conversion of customer appliance/burners from their existing fuels to natural gas is shown below: FY93 FY94 WA 9 FY96 FY7 Total - Ind'l steel mains, km 8 15 ... ... --- 23 - PE mains, km 175 175 175 175 175 900 Customer Connection - Residential 40,000 40,000 40,000 40,000 40,000 200,000 - Residential winfills" 7,000 7,000 7,000 7,000 7,000 35,000 - Coumercial 400 400 400 400 400 2,000 - Coimercial winfills" 600 600 600 600 600 3,000 - Industrial 1 4 4 4 4 17 - 55 - Annex V Page 4 of 9 The project cost estimate is as shown in the table below. L9oca Foreign Total --- (US$ million)---- I. Materials Line Pipes & Valves 0.32 16.72 17.04 Regulating Stations 0.03 2.45 2.48 Service Connections 0.08 2.65 2.73 Customer Meters & Regulators 0.19 21.30 21.49 Customer Piping & Conversion Q.,8 23.00 23.38 Subtotal 1.00 66.12 67.12 II. Engineering & Construction & Procurement Services Engineering & Procurement Services 4.40 7.90 12.30 Construction Equipment 2.40 9.70 12.10 Pipelines & Valves 9.45 3.99 13.43 Regulating Stations 0.86 0.18 1.04 Service Connections 0.82 0.17 1.00 Customer Meters and Regulators 5.08 1.14 6.22 Customer Piping and Conversion 48.36 7.99 56.34 Subtotal 71.37 31.07 102.43 III. Market Development & Training 0.10 1.00 1.10 IV. Taxes & Duties 12,00 0.00 12.00 Total Base Cost, End-1990 Prices 84.47 98.19 182.65 Physical Contingency 7.00 3.20 10.20 Price Contingency 13.70 14.10 27.80 TOTAL PROJECT COST 105.17 115.44 220.65 Annex V - 56 Page 5 of 9 Estimated Schedule of Disbursement Cummulative Disburement End of Quarter (US$ 1000) Calendar Year and Quarter Incremental Cummulative FY 92 3rd quarter 0.2 0.2 4th quarter 0.7 0.9 FY 93 1st quarter 2.7 3.6 2nd quarter 2.7 6.3 3rd quarter 2.7 9.0 4th quarter 2.7 11.7 FY 94 1st quarter 2.7 14.4 2nd quarter 3.0 17.4 3rd quarter 2.5 19.9 4th quarter 2.5 22.4 FY 95 1st quarter 2.5 24.9 2nd quarter 2.5 27.4 3rd quarter 2.5 29.9 4th quarter 3.3 33.2 FY 96 1st quarter 3.3 36.5 2nd quarter 3.3 39.8 3rd quarter 3.3 43.1 4th quarter 1.4 44.5 FY 97 1st quarter 1.4 45.9 2nd quarter 1.0 46.9 3rd quarter 1.2 48.1 - 57 - Page 6 of 9 Key Acto2nPlan 1ŁMEPA Completion Date 1. Basic design including survey of commercial and residential consumers 01/91 2. Material tender document preparation 01/91 3. Draft of Revised EgyptGas/Petrogas Contract 03/91 4. General Procurement Notice (60 days prior to issuance of bid documents) 02/91 5. World Bank review of tender documents (15 days) 02/91 6. Bid documents issued (45 days minimum required for suppliers to submit bids) 04/91 7. Expected World Bank consideration of loan 05/91 8. Bids received and evaluated 06/91 9. World Bank review of bid evaluation report (within 15 days for contracts below $5 million and 30 days for contracts above $5 million) 07/91 10. Materials ordered 09/91 11. Materials received (first shipment) 01/92 12. Construction start-up 07/92 13. Const.z'stion completion 06/97 - 58 - Annex V Page 7 of 9 Idustrial Consumers Prooosed for Conversion to Natural Gas Current Consumption of Petroleum Products Estimated Equiv. DeseriRtio-n Gas Oil Fuel Oil Kerosene LPG Gas ReIuirements --t/yr .- -----mcm/yr--.- 1. Glass Factory 12,479 14,688 2. 7-Up Factory 3,000 80 3,630 3. Pencils and Graphite Factory 900 17 1,080 4. Ideal Factory 300 450 5. Abbassia Industrial Area 1,644 90 1,935 6. El Nasr Castings 1,427 5,884 8,400 7. Berzy Factory 150 168 8. Olympic Electric Company 357 420 9. Wooltex Weaving Factory 735 840 10. Shorbagy Factory 551 630 11. El Ahram Beer Factory 700 4,707 1 4,700 12. Coca Cola Factory 130 514 560 13. Eastern Company for Cigarettes 3,310 4 3,790 14. El Nasr Company for Cigarettes 20 147 1 193 15. Pepsi Cola Factory 200 507 30 852 16. Seed Pharmaceuticals 50 235 25 358 17. Aromatics Factory 368 9 430 Subtotal Consumption 21,207 17,108 90 167 43,134 Helwan Industrial Area 1. Railway Wagon Factory 10,537 245 11,772 2. Military Factory No. 09 449 200 763 3. Helwan Cooperation for Non-Ferrous Industries (No. 63) 2,923 1,740 5,230 4. Factory No. 909 . 1,067 1,218 5. El Nasr Company, Steel Pipes 3,830 460 163 5,077 Total Consumption 29,476 29,845 90 775 67,194 Annex V -59- Page 8 of 9 Procurement Table (US$ million) Procurement Method ICB Other Total cos High pressure steel pipes 2.1 2.1 (larger than 2") Low pressure steel pipes 8.4 8.4 (2" and smaller) P.E. pipes and fittings 14.1 14.1 Network regulating stations 7.5 7.5 Customer meter and 18.6 1.4 20 regulators (18.3) (18.3) Ball valves 7.6 7.6 (7.5) (7.5) Pipe fittings 7.2 7.2 (7.1) (7.1) Conversion kits 6.6 6.6 (6.5) (6.5) Expansion bellows 2.1 2.1 (2.1) (2.1) Service connections 1.8 1.8 (1.8) (1.8) Miscellaneous network 3.6 3.6 fittings a/ (3.6) (3.6) Engineering & construction 140.4 140.4 & procurement services ( - ) ( - ) Consultancy services for 1.3 1.3 studies and training (1.2) (1.2) TOTAL 47.5 175.2 222.7 (46.9) (1.2) (48.1) Note: Figures in parantheses would be financed by the Bank. a/ Consists of 10 small packages. GREATER CAIRO GAS DISTRIBUTION PROJECT PROJECT SCHEDULE 1991 1992 1993 1994 1995 1996 1997 ACTIVITY 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 Network Design and Consumer Survey Material Procurement SI ' MR _ _ _ . __ _ _ _ _ .. . .. . .. _ _ _ . ..._ a'.... Network Construction M M_ MISS Consumer Connecton 48,000 4000 i 3 48,000 LEGEND: TP = Tender Preperatlon Bi =Bid Issued MO = Material Ordered x MR = Material Received - 61 - Afxex VI Page 1 of 16 MES GAS INVESTMNT PROECT Trangs-Gulf Gas Cgomo-nq" 1. Project Objective More than 90 percent of Egypt's oil production is concentrated in the Gulf of Suez. During 1990 as much as 873,000 bbl/day of oil and about 1,180 million cu ft/day (MMCFD) of associated gas was being produced. Of these, over 760 MMCFD fed the existing 2,000 km gas pipeline system. However, with increasing demand for natural gas in the country, GOE has declared a policy of minimizing flaring of associated gas. In order to pursue this objective, EGPC has proposed the Trans Gulf Gas Project to utilize additional associated gas from the October (about 70 MMSCFD) and Sinai/Belayim fields (about 37 MMSCFD) in Gulf of Suez. The perceived benefits are: (a) providing additional natural gas that would substitute for liquid petroleum products, which could alternatively be exported or utilized in areas where natural gas is not currently available; (b) enabling EGPC to obtain value-added natural gas liquids (e.g., LPG, gasolir.e, etc.) by processing the additional associated gas that is now being flared; and (c) contributing towards environmental protection objectives by reducing CO2 and other emissions in the Gulf of Suez area, thus mitigating atmospheric pollution and global warming problems. 2. Gas SuDplies and Reserves Oil and associated gas is currently being produced from over 70 fields in the Gulf of Suez. These fields are being produced by 11 operating companie.. In 9 out of 11 of these operating companies, EGPC is 50 percent partner. Two operating companies --General Petroleum Company (GPC) and GEISUM-- are 100 percent ownied by EGPC. The Gulf of Suez Petroleum Company (GUPCO) is the operating company formed between AMOCO (50 percent) and EGPC (50 percent) and is responsible for about 50 percent of the total oil production from the area. GUPCO operates 24 fields with oil production of about 400,000 B/D. Petrobel (AGIP/EGPC) is producing about 200,000 B/D followed by SUCO (ESSO/EGPC) at 100,000 B/D. Under the old oil-production sharing agreements, all associated gas belonged to EGPC. More recently (1988), EGPC modified production-sharing contracts by including a new gas clause. GUPCO is operating in new contract areas under this clause. Over the years, EGPC has taken steps to utilize associated gas from various fields e.g., Amal, October, Ramadhan, Shoaib Ali, Morgan, Zeit Bay, East Zeif, etc. (about 180 to 200 MMCFD of associated gas is being produced from such fields). Aite' extracting LPG (650 tons/day) and natural gas liquids (560 tons/day) i as Shukeir gas plants, EGPC supplies dry sales gas (about 150 MMCFD) to - 62 - Annkez VI Page 2 of 16 the Ras Shukeir-Suez pipeline for onward transmission to Cairo and Suez areas. October and AbuReis Associated Gas. The October Field was discovered by GUPCO in 1975 and is currently producing oil and associated gas from 27 offshore wells. Some additional production is also being obtained from the nearby North October field from six producing wells. Currently, ubout 45 MHSCFD of associated gas from the October field is transmitted through an existing 30-inch diameter pipeline to Ras Bakr facilities; after processing, dry sales gas is supplied through the 16-inch diameter Ras Shukeir pipeline to Suez. With the increase in oil production from October fields from 100,000 B/D to 160,000 B/D, additional associated gas is being produced; this is in excess of the capacity of the existing facilities being flared. As oil production declines, gas oil ratios will tend to increase and associated gas production will continue for a longer period than oil production. The proposed project plans to utilize surplus gas, which is currently being flared from these fields. The nearby North October field is in its early stages of delineation and may provide additional gas to the project. Belavim Fields. The Belayim Fields in the Sinai area cover both onshore and offshore fields. Belaim (Land) was discovered by Petrobel in '955. Other areas are Belaim Marine, Rudeis and Sidri (offshore) fields. Original recoverable reserves were over two billion bbl from these fields. Remaining recoverable reserves are estimated at about one billion bbl. Currently, about 160,000 b/d oil and 47 MMCFD of associated gas is being produced. The review of the production profile indicates an average decline of 8 percent in oil production. However, associated gas production is estimated at about 37 over the first 5 years of the project life and to decline at about six per cent per annum thereafter. Along with the above-mentioned surplus gas, the proposed scheme envisages the utilization of any additional associated gas from these fields. 3. Status of Project Preparation Currently, 40 of MMCFD associated gas from the October Field is being transmitted to the Ras Bakr facilities through the existing 30-inch diameter pipeline. As discussed above, in order to minimize flaring and optimally utilize the surplus associated gas of about 30 MMCFD from the October Field, and 37 MMCFD from the LPG recovery plant at Belayim in Sinai, EGPC commissioned ENPPI, a 100 percent EGPC owned oonsulting services company, to conduct a feasibility study. The objective was to evaluate alternatives and develop budgetary cost estimates for optimizing the utilization of surplus- associated gases from the Sinai/Belayim and October Fields. ENPPI completed this study and submitted its report to EGPC in September 1990. After evaluating various techno-economic options, ENPPI's main recommendations were: (a) to add a new gas compression facility at the existing Belayim plant (within Petrobel's SAGP plant) to compress 37 MMSCFD of Belayim/Sinai Gas, using two new compressors; (b) to extend the existing Sinai gas pipeline by about 12 km and 12 inch in diameter to link with the October field; - 63 - Annex Vl Page 3 of 16 (c) to add an offshore platform template (a four-legged conventional steel jacket structure) to the existing October production platform; (d) to add two turbine driven compressors and associated facilities to the platform extension to compress about 70 MMSCFD of associated gas from the October field; and (e) to install additional processing facilities at the existing Ras Bakr gas processing plant comprising two stage compression, refrigeration and dehydration facilities in order to treat 107 MMSCFD of wet gas and provide: (i) 40 MMSCFD dry gas to Unit 104; and (ii) to transmit 67 MMSCFD of dry gas to the Sales gas pipeline to Suez. The above-mentioned ENPPI feasibility study submitted to EGPC was reviewed by the Bank. The mission broadly agreed with the recommendations made in this study regarding the project. Further, the mission reviewed with EGPC the reservoir behavior and the production profile for both the October and Belayim fields. The expected production profile for the Belayim and October fields are as indicated below. Eield Year 1992/93 93L94 94L25 95 p96 96/97 97/98 98/99 99/2000 Belayim 37 37 37 37 37 35 33 30 October 50 60 70 70 70 55 40 30 Based on the above profile, the associated gas feed to the LPG plants will be in the range of about 50 to 60 MMCFD up to year 2000, yielding about 37 MMCFD dry gas for the pipeline and will later follow the natural decline behavior of the oil reservoirs. While oil production is expected to decline, gas oil ratios will increase resulting in relatively lower decline in gas production rates. Since appraisal, EGPC has awarded a turnkey contract to ENPPI for consulting services for the Trans Gulf component. These include basic and detailed design and engineering, procurement services, project management, construction supervision and overall responsibility for project performance, start-up, etc. ENPPI has started preparation of basic design and the preparation of the bidding documents in accordance with ICB procedures for the Bank financed components. - 64 - Xnnex. MI Page 4 of 16 4. rtoAect Description The project would consist of the following: (i) Fabrication and installation of an extension to the existing offshore platform of a template (a four-legged conventional steel jacket structure) about 40 meters northeast of the existing October production platform, with a bridge connection to the existing platform; modifications to the flare hook-up; blowdown systems; topside facilities, the installation of two gas compression units; and associated facilities, utilities and infrastructure. (ii) Construction of a 12 km extension to the existing 30-inch diameter Sinai gas pipeline of a new 12-inch diameter submarine pipeline to link the October field platform. (iii) Installation of a new gas compression facility at the existing Belayim (within Petrobel's SAGP plant) to compress 37 MMSCFD of Belayim/Sinai gas. (iv) Expansion of the Ras Bakr Facilities -Installation of gas processing facilities comprising two gas compressor units, refrigeration and dehydration facilities in order to process 107 MMSCFD of gas; of this, 40 MMSCFD of gas would pass through existing unit 104 and 67 MMSCFD would be supplied to the Suez pipeline. (v) Technical assistance, project management consulting services, surveys, inspection and engineering services. (vi) Training of EGPC Staff relating to engineering, reservoir evaluation and planning pipeline network and gas processing. The location of these facilities are illustrated in Map No. IBRD 22905. The existing Ras Shukeir gas compression and processing facilities and the 16-inch diameter Ras Shukeir Suez gas pipeline were constructed under the Bank-financed Gulf of Suez Project (No. 1732-EGT). The project components relating to Ras Bakr and the 16-inch diameter loop line are considered an extension of these facilities. At the time of loan negotiations, assurances would be sought from EGPC that it would directly finance the Ras Shukeir-Suez pipeline component and complete it by the time the proposed Trans Gulf Gas component was commissioned; without this pipeline expansion, it would not be possible to transmit the additional 67 MMSCFD of sales gas to Suez. 5. Project Implementation EGPC would have the overall responsibility for implementing the proposed project. However, various components of the project would involve other entities: GUPCO would be involved in modifications at the October platform and other facilities; Petrobel would be involved with the Sinai/Belain - 65 - Anmpx Page 5 of 16 components; PPC would implement pipeline components; and ENPPI would handle consulting services, etc. In order to speedily and efficiently implement the project, EGPC would form a Project Implementation Unit (PIU) headed by a project manager, who would be responsible to the Head of Planning and Projects in EGPC. PIU would coordinate and supervise various implementation functions necessary to design, procure, construct and commission the project facilities. The other entities would support PIU's program as follows: (i) ENPPI, a 100 percent owned subsidiary of EGPC, would be responsible for detailed design, procurement, project management and construction supervision; and (ii) The construction and commissioning phase of the project would be assigned - the following operating companies: (a) GUPCO for the October field offshore facilities and the Ras Bakr facilities; (b) Petrobel for gas compression and associated facilities at Belain/Sinai; and (c) Petroleum Pipeline Company (PPC) for the offshore pipeline and the Ras Shukeir-Suez pipeline loop to the existing 16-inch diameter Ras Shukeir-Suez pipeline. ENPPI. ENPPI has vast experience with the design, management and supervision of similar projects in Egypt. ENPPI was actively involved in similar projects under the two previously financed Bank projects, i.e., the Gulf of Suez Project (LN 1732-EGT), the Abu Qir Gas Development Project (LN 2103-EGT), as well as other projects completed by EGPC. ENPPI would form a project management team who would be fully responsible to PIU for this project in all its phases. Proiect Implementation Unit (PIU). EGPC would staff the Project Implementation Unit (PIU) from the experts working on similar projects and, if necessary, from other operating companies with the requisite experience. Additional technical assistance requiring skill/equipment not available within EGPC organizations would be obtained from local and expatriate consulting services whose qualifications, experience and conditions of employment would be satisfactory to the Bank and EGPC. During negotiations, the composition and qualifications of the PIU unit would be reviewed by the Bank and the PIU team would be agreed upon with EGPC. Implementation Schedule. EGPC plans to complete the Ras Shukeir-Suez Pipeline component by June 1992. The implementation issues relating to the remaining components would be discussed and finalized with EGPC during negotiations. In order to speedily complete the project, it would ')e essential to conduct offshore route surveys and finalize a detailed engineering design of the project. Based on the detailed engineering design, procurement packages for International Competitive Bidding would be prepared. For construction and installation of onshore and offshore components, prospective contractors should be prequalified in accordance with the Bank's procurement guidelines. During negotiations agreement would be sought with EGPC on (a) the finalization of procurement and contracting tasks; (b) planning the project activities including preparation of a critical path plan - 66 - Annex VI Page 6 of 16 of its activities leading to the award of contracts for onshore/onshore activities; (c) the quarterly review of the progress of the project with the Bank; and (d) the appointment of independent third party inspection services. 6. Project Costs The project is estimated to cost US$62.6 million equivalent including contingencies. of which US$50.5 million or 80 percent represents the foreign exchange component. A physical contingency of 10 percent was applied to all project costs. The price contingencies are estimated based on a forecast of foreign inflation of 3.4 percent per annum and local iiZlation of 16.7, 11.1 and 8.7 percent for FY92, FY93 and FY94, respectively. The cost of material, equipment and installation is estimated at US$49.0 million. Detailed engineering, project management, procurement and construction supervision costs are estimated at US$5.7 million. As discussed in para. 3, ENPPI has been designated by EGPC for the above-mentioned services, to be financed by EGPC through their ongoing arrangements. ENPPI would be assisted by some expatriate personnel. The average man-month cost for expatriates is estimated at US$15,000 per man-month and US$4,000 for local personnel. Other project related services, e.g., inspection, are estimated at US$2.0 million and these would be procured by EGPC in accordance with the Bank procurement guidelines. These estimates are based on current rates for similar services. Duties and taxes on goods and materials are not included since EGPC is exempt from such payment. The estimated project costs, excluding interest during construction, is summarized in below. 7. Financing Plan The proposed Bank loan of US$35.9 million for the Trans Gulf Project component would finance about 60 percent of the total project cost, net of duties and taxes, and would meet about 72 percent of foreign costs. All local currency expenditures, including duties and taxes, if any, would be financed by EGPC. EGPC would also finance, through its own resources, the total expenditures, both foreign and local for (i) an on-going contract with ENPPI for the study, design, project management, procurement and construction supervision of the proposed Trans Gulf Project and the Ras Shukeir-Suez gas pipeline expansion component; (ii) and all expenditures, both local and foreign, for the Ras Shukeir-Suez gas pipeline component. The proposed financing plan is summarized in Table 1. - 67 - Annex V Page 7 of 16 Table 1 Prolect Financing Pla USS million Source of Funds LQcagj Total X -of Financing PlaI IBRD - 35.9 35.9 597.6 EGPC 152 24.3 40.4 Total 11.8 48.7 60.2 100.0 8. Procurement Bank financing is proposed for the following main procurement packages: - Supply, installation and commissioning of the gas-turbine-driven compressor package and offshore facilities on the October Platform. - Supply, installation and commissioning of two gas-engine-driven compressor packages and associated facilities in the Sinai/Belaim area. - Supply, installation, and commissioning of two gas-turbine-driven compressor packages and associated facilities at Ras Bakr. - Supply, installation and commissioning of gas processing facilities at the Ras Bakr processing plant. -68 - Annex VI Page 8 of 16 TRANS GULF PROJECT Table 2 Procurement Arrangements (in US$ million) Gas Surveys ICB 1/ LIB Other 2/ Total Compressors and associated equipment 10.0 4.0 2.5 16.5 (10.0) (4.0) (14.0) Platform template 9.5 9.3 18.8 (9.5) (2.0) (11.5) Submarine pipeline 2.2 2.2 Gas treatment equipment & 4.4 4.0 5.0 13.4 related services (4.4) (4.0) (2.0) (10.4) Construction and consulting 8.9 8.9 services Subtotal 23.9 8.0 27.9 59.8 (23.9) (8.0) (4.0) (35.9) Note: 1/ Figures in parantheses to be financed by the Bank. 2/ The components to be cofinanced by EIB (US$ 33 million) are given under Other. - 69 - Amex VI Page 9 of 1 6 All Bank-financed procurement for goods and services would be in accordance with the Bank's procurement guidelines. Detailed procurement arrangements and list of packages proposed for Bank financing are given in Table 2. All major packages of material, equipment and services for EGPC and its implementing agencies would be procured in accordance with the Bank's International Competitive Bidding (ICB) procedures except for the following: (a) Contracts for equipment and inspection and similar services needed for offshore operations, e.g., specialized equipment, instruments and specialized services (inspection and similar services), which are available only from a limited number of suppliers, and which do not exceed an aggregate of US$3.0 million, may be awarded in accordance with the Bank's procurement guidelines for Limited International Bidding (LIB). (b) Contracts for the equipment and material that are proprietary, or needed to ensure standardization and compatibility witn the existing equipment and facilities, which do not exceed in value the equivalent of US$200,000 each, and do not exceed in aggregate the equivalent of US$2.0 million may be procured by direct contracting under the terms and conditions acceptable to the Bank. All bid packages having a value of US$300,000 equivalent or greater would be subject to prior Bank review. Other contracts would be subject to selective post award review by the Bank. In order to expedite procurement, all bid packages would be prepared by EGPC in accordance with the Sample Bidding Documents prepared by the Bank. Retroactive financing to the extent of US$5.0 million equivalent would be permitted to cover advance contracting for the materials and equipment procured in accordance with ICB procedures, if acceptable to the Bank. 9. Disbursement Disbursement of the Bank loan would be made against (a) 100 percent of the foreign exchange components of the imported equipment and material; and (b) 100 percent of the ex-works cost of equipment and materials manufactured locally and procured under ICB procedures, and 80 percent of the total expenditures procured locally off-the-shelf. The disbursement profile essentially conforms with the statistical profile for Bank/IDA energy projects (e.g., oil, gas, refinery, energy conservation), excluding power projects. It is generally in line with the disbursement profile of past Bank-financed projects in Egypt. The disbursement profile is based on (i) a three-month lag between the time expenditures have been incurred (according to the project implementation schedule) and the time funds are disbursed against this expenditure; and (ii) the loan becoming effective in November 1991. - 70 - Annex VI Page 10 of 1 6 10. =WnLtoring and Renorting Satlsfactory procedures for monitoring the progress of the project in terms of physical executlon and financial reporting would be agreed with EGPC during negotiations. PIU would furnish to the Bank quarterly progress reports in a format to be agreed wlth EGPC and the Bank. In additLon, EGPC would submLt monthly progress report to the Bank. Any major issues that are likely to hamper or delay project implementation would be tmmediately communicated by EGPC to the Bank. 11. Environmental IMRact By minimlzing the flaring of associated gas in the Gulf of Suez, the project would directly contribute toward the abatement of global warming and the reduced emission of CO. in the atmosphere; it would indirectly contribute by displacing fuel oil, the additional associated gas from the Gulf of Suez area, which would reduce the emlssion of CO, ln the area, particularly where power and chemical/industrial plants are located. The natural gas pipelines, both offshore and onshore, would not create any environmental problems, as offshore lines would be laid on seabed and adequately protected, and onshore lines would be buried. Adequate monitor-ng arrangements would be installed on these plpellnes to safeguard agalnst lea" and ruptures due to overpressurization, corrosion and third-party damage. Standard international petroleum industry practices and codes would be followed for Gulf of Suez offshore installations, offshore and onshore natural gas plpelines, and at Ras Bakr gas processing facilities. Safety distances and appropriate safety codes would be applied for all gas processlng plants. The operations, maintenance, flre preventlon and pollution control measures taken by EGPC ln the existing Ras Bakr gas processing facilities and by its operating companies (GUPCO and PETROBEL) ln offshore Gulf of Suez operations are satisfactory. As a condltion of negotlations, EGPC would be requlred to furnish to the Bank an updated quarterly environmental report lndlcating their compliance wlth the standards satisfactory to the Bank. During negotiations, EGPC agreement would be sought that prior to construction, an environmental review of the proposed construction details would be furnished to the Bank for review to ensure that all necessary environmentally mitigative features have been addressed. 12. Project RLsks The offshore associated gas production from the October and Sinal/Belaim oil fields carry the normal geological and operatlonal risks inherent to petroleum production and process operations. Offshore gas operations pose additional safety risks. However, the international oil and gas industry has developed sophisticated techniques and standard safety, operations and maintenance codes that are being stringently followed by EGPC and its operating companies in the Gulf of Suez areas, both offshore and onshore. As a result of this, EGIC operating companies have demonstrated a satisfactory - 71 - Amrex MI Page 11 of 16 operating record in terms of safety and environmental impact. Therefore, the physical risks in the proposed project are minimal. During the last Bank- financed project (LN 2103-EGT), stringent safety codes were followed and found satisfactory. With the arrangements made for third-party inspection services (to be obtained from renowned firms, e.g., Lloyd's Register of Shipping), sufficient safeguards for safety in installation and commissioning have been provided. The commercial risks for this project are minimal, as the associated gas supply is expected to be adequate over the project life, and the availAbility of additional dry natural gas, LPG and natural gas liquids would significantly benefit Egypt in terms of minimizing the cost of energy supply and reducing the environmental impact of hydrocarbon fuel use. H: %gbaed%agy%am*x6 . oar TRANS GULF GAS COMPONENT Detailed Cost Flow FY92 FY93 FY94 Total Cost Loc. For. Tot. Loc. For. Tot. Loc. For. Tot. Loc. For. Tot. Surveys 0.1 0.2 0.3 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.2 0.3 Basic Engineering and Design 0.2 0.3 0.5 0.0 0.0 0.0 0.0 0.0 0.0 0.2 0.3 0.5 Subtotal 0.3 0.5 0.8 0.0 0.0 0.0 0.0 0.0 0.0 0.3 0.5 0.8 Sinai/Belaim Area -Gas Compressor Package 0.1 0.2 0.3 0.1 1.0 1.1 0.0 0.3 0.3 0.9 1.5 1.7 -Bulk Material Equipment 0.0 0.4 0.4 0.1 0.1 0.2 0.1 0.2 0.3 0.2 0.7 0.9 -Construction 0.1 0.1 0.2 0.1 0.2 0.3 0.0 0.1 0.1 0.2 0.4 0.6 -Project Man't/Const'n Supv. 0.0 0.1 0.1 0.1 0.1 0.2 0.0 0.0 0.0 0.1 0.2 0.3 Subtotal 0.2 0.8 1.0 0.4 1.4 1.8 0.1 0.6 0.7 0.7 2.8 3.5 Offshore October Platform -Template 0.1 0.4 0.5 0.3 1.6 1.9 0.2 0.2 0.6 2.0 2.6 -Gas Compressor Package 0.9 1.4 2.3 0.9 6.9 7.8 0.0 2.1 2.1 1.8 10.4 12.2 -Construction 0.2 0.5 0.7 0.2 1.0 1.2 0.1 0.1 0.2 0.5 1.6 2.1 -Project Man't/Const'n Supv. 0.1 0.2 0.3 0.2 0.5 0.7 0.1 0.5 0.6 0.4 1.2 1.6 Subtotal 1.3 2.5 3.8 1.6 10.0 11.6 0.4 2.7 3.1 3.3 15.2 18.5 Belaim/October Submarine P'line -Material and Equipment 0.1 0.4 0.5 0.1 1.0 1.1 0.0 0.0 0.0 0.2 1.4 1.6 -Construction 0.1 0.1 0.2 0.0 0.1 0.1 0.0 0.1 0.1 0.1 0.3 0.4 -Project Man't/Const'n Supv. 0.0 0.0 0.0 0.0 0.1 0.1 0.0 0.0 0.0 0.0 0.1 0.1 Subtotal 0.2 0.5 0.7 0.1 1.2 1.3 0.0 0.1 0.1 0.3 1.8 2.1 West Bank Facilities Gas Compressors 0.1 1.0 1.1 0.7 7.6 8.3 0.2 0.4 0.6 1.0 9.0 10.0 Dehydration Unit 0.1 0.2 0.3 0.6 0.4 1.0 0.1 0.1 0.2 0.8 0.7 1.5 Refrigeration Package 0.1 0.5 0.6 0.5 4.0 4.5 0.1 0.5 0.6 0.7 5.0 5.7 Bulk Material and Equipment 0.1 0.3 0.4 0.5 1.9 2.4 0.0 0.0 0.0 0.6 2.2 2.8 Construction 0.2 0.3 0.5 0.6 2.0 2.6 0.2 0.4 0.6 1.0 2.7 3.7 Consulting Svcs for Proiect 0.1 0.8 0.9 0.5 1.0 1.5 0.2 1.0 1.2 0.8 2.8 3.6 Subtotal 0.7 3.1 3.8 3.4 16.9 20.3 0,8 2.4 3.2 4.9 22.4 27.3 Total Base Cost 2.7 7.4 10.1 5.5 29.5 35.0 1.3 5.8 7.1 9.5 42.7 52.2 Physical Contingency 0.2 0.5 0.7 0.4 1.9 2.3 0.1 0.4 0.5 0.6 2.8 3.4 x Price Contingency 0.3 0.9 1.3 0.7 3.7 4.4 0.2 0.7 0.9 1.2 5.4 6.6 Base Cost incl. contingencies 3.2 8.8 12.0 6.6 35.1 41.7 1.5 6.9 8.5 11.3 50.9 62.2 0 Interest During Construction 0.0 0.3 0.3 0.0 2.1 2.1 0.0 0.7 0.7 0.0 3.1 3.1 0 Total Cost 3.2 9.1 12.4 6.6 37.2 43.8 1.5 7.6 9.1 11.3 54.0 65.3 - 73- !S_y Page 13 of 16 Producton Data (as of 1/1/91) Estimated Proven Oil Reserves . 4,500 MM Barrels Estimated Proven Gas Reserves : 12,400 BCF No. of Producing wells . 896 Estimated 1990 Daily Production 873,000 B/D Percent Change From 1989 : +2.6 percent RŁeLnin No. of Refineries .8 Crude Refining Capacity : 523,153 BOPD Thermal Operations : 16,470 BOPD Catalytic Reforming : 33,540 BOPD Catalytic Cracking . Nil Gas Processing CaRacity (as of 1/1/91) A. Summary Total No.of Gas Processing Plants : 8 Gas Capacity : 1320 MHSCFD Avg Gas Throughput During 1989 : 1188 MMSCFD S Production (Average based on past 12 months L.P.G. mix : 691,700 gallons/day Other NGL : 1,158,500 gallons/day Total Products : 1,1850,200 gallons/day 1 To be verified with EGPC B. Gas Processing U_its (Data us of 1/1/91) Process Production Comoanv Location Gas Capact Gas througbDut Conditi in 1000 gal/dav (MMSCFD) LPG NGL Others Amoco Egypt Oil Co. 125.0 101.0 Cryogenic expander/ 103.3 .... 84.9 Dahshour, Abu Gharadig stabilizer Desert, Block 30 Egyptian General 132.0 124.0 Absorption/stabilizer .... .... 210.9 Petroleum Corp. - Abu Gharadig field, 286 km west of Cairo, Western Desert Abu Nadi LTS plant and 242.0 236.0 Absorption/Cryogenic .... .... 203.0 field, K. Sheikh Joule Abu Nadi LPG plant and 236.0 225.0 Absorption/stabilizer 60.4 ... 215.0 > and field, K. Sheikh I Abu Qir plant and field 206.0 198.0 Absorption/stabilizer 48.8 .... 206.2 offshore, 60 km east of Alexandria Dahshour, Abu Charadig 124.0 118.0 Cryogenic Expander 132.0 .... .... field, 65 km west of Cairo, Giza Ras-Shukeir 177.0 131.0 Refrigeration/absorption/ 283.2 .... 190.7 stabilizer Zeit Bay 78.0 55.0 Absorption/refrigertation ..0..Q 48.4. Total 1,320.0 1,180.0 691.7 1,158.5 Ix 0 75 - iam~~hnex VI Page 15 of 16 Gas Com2ogitions/Plouct Strea BelaYXLmLinai 9Sx8L:r mixed Composition (NOL X) H120 0.01 1.63 1.07 C02 0.83 3.37 2.50 N2 0.78 0.87 0.84 CH4 65.74 57.24 60.14 C2H6 19.57 14.43 16.19 ONH 12.56 12.07 12.24 I'4110 0.18 1.77 1.23 tAH10 0.29 4.48 3.05 C5H12 0.02 1.26 0.84 C5H12 0.02 1.44 0.95 C5H14 + I JA4 0.95Q.2 H2S (parts per million) 11 10 10 Design flows NMSCFD (dry basis) EGYPT IMPLEMENTATION SCHEDULE FOR TRANS GULF GAS PROJECT DURATION DESCRIPllON IN MONTHS _ 1 2 3 4 5 _ 7 8 9 10 1112 13 14 15 11617 1819201211222 1N 2526 27 2 0031312 33 ONSHO(EI OFFSHORE SURVEY WF-4U4IET & DEWVERY SStdB~AYtM AREAH 1I GASCOMPRESSOR PACKAGE . . > m * * * m . (GA BGMDRW" ItL MATEPJAL owwON WORK OFFSHORtE OCTOBER PLATFORM TW A E (800 TON) 0q U _ . U _ _ U" x0 00 000 00 @00 00 @0 00 00 0 1=-E (oI - t Il BOOS! COW. PKG (2 UNIS um *urm mm m 'c (CAS lURSIN DFIVEN RAS BAKR FACILITIE GAS COM[PRESSOS Rr* u m u ' (GASTUI3U4E U I GLYCOL_ t u.n _ _...... . P VESSEI.S &H. EXCHAN'GERS *u m *LLK M-TERAL CONSTRUCTION WORK COMM. & STARr-UP UESBRD BIDDING UDELiVER FOSBARCTO BID EVAWLATION *DEUVERY AT SrrEINTLAO -PLACING FORMAL P.O. oceecc CONSTRUCTION WORK S.umw ENPPl wpIAmlAw49097a - 77 - Ann-- Vil Page 1 of 2 EGYPT GAS INVESTMENT PROJECT Gas Market DeveloRment The Cairo gas distribution network consists of a relatively low proportion of gas sales to commercial and industrial consumers. As the cost of distribution to residential consumers is relatively high, primarily caused by cost of piping installation, and consumption is low, residential supply is less commercially viable than sales to other sectors. These issues need to be addressed along wfth pricing so that a rational market development strategy can evolve. The market development strategy was discussed with Petrogas, and it was agreed that a study be initiated with the objective of reviewing strategies to increase the penetration of gas sales to the commercial and industrial market as well as to develop new markets, such as for gas-based air conditioning. The study should also identify the areas where the cost of distribution could be reduced or the operational capabilities of Petrogas be enhanced. For example, a building construction code should be developed and ratified so that the new buildings in the existing or foreseeable gas areas are equipped with one gas piping installation during the building construction. Furthermore, the study should provide a training component to strengthen Petrogas' market development and operational capability. The scope of the study would consist of: 1. the establishment of a core of gas sales engineers consisting of about five engineers who would be trained in sales promotion in the commercial and industrial markets. The members of this core should be capable of negotiating gas sales contracts with industrial and large commercial consumers involving inter-fuels relationships, conversion costs and economics of gas use from the standpoint of consumers. The unit should also include a woman who would focus on the cooking aspects of natural gas use, payiug particular attention to the changes in cooking practices that would enhance safety and energy conservation; 2. the surveying of markets in Greater Cairo and Alexandria; 3. the preparation of a feasibility study for gas distribution in Alexandria; 4. the improvement of emergency maintenance operations and customer services; 5. the identification of cost reduction measures such as incorporating the installation of gas piping in the building construction codes; - 78 - Annex VII Page 2 of 2 6. a study of the uses of supervisory control and data acquisition system in maximizing gas distribution efficiency in Cairo; 7. the establishment of a computerized design and cost estimate center; 8. the improvement of safety engineering practices and the development of a modern reporting system; and 9. the identification of training requirements and the preparation and implementation of a training program. N: \*az.d\Sery\anmwx. sar - 79- Annex VIII Page 1 of 3 EGYPT GAS INVESTMENT PROJECT Refinery Sector Investment Planning Study Terms of Reference Introduction 1. The Egyptian General Petroleum Corporation (EGPC), a para-statal, owns and controls six wholly owned refineries located at Cairo, Suez, Alexandria, and Assiut in Upper Egypt. Tne individual subsidiary refineries are managed by boards of directors and operate the facilities for a refining fee, ixed annually by EGPC. The refineries, except for three lube production and one delayed coking facilities, are of simple hydro-skimming or topping configuration and process domestic crude oils. Refined products are marketed by Misr Petroleum Company and the Cooperative Petroleum Company, both fully owned subsidiaries of EGPC, as well as by Mobil, Esso and Caltex at the retail level. 2. There are significant mismatches between the production of refined products from domestic refining and demand, resulting in significant exports of fuel oil and naphtha and imports of gas oil and LPG. The surplus of fuel oil is expected to increase with the increased substitution of fuel oil by natural gas. EGPC has been planning to install secondary processing facilities to convert surplus fuel oils to higher value distillates, including a hydrocracker. 3. In order to develop a rational investment program over the next 5 to 10-year time frame for the refining and distribution subsector, EGPC intends to carry out a consultant study, as well as acquire in-house institutional capabilities in the methodologies and techniques for medium to long-term investment planning. The objectives of the investment program would be to minimize the cost of products supply, consistent with future demand growth and with the product specification changes over time. 4. Consistent with the above-mentioned objectives, the consultant would carry out the following tasks. a) Future demand estimates: The consultant would analyze historic consumption, by major energy and non-energy products, with reference to the major factors that affect demand such as GDP growth, prices of competing products, automobile fleet growth, population etc. and would develop appropriate equations to explain historic consumption and to project demand over the period up to the year 2005. The demand projections would take into account the increase of gas use. - 80 - Annex VIII Page 2 of 3 b) grices: The consultant would develop scenarios for petroleum and product prices translated to each refinery location and to each major distribution storage point in the country, for purposes of economic comparison of various investment options as inputs to investment planning model. c) Matbematical model for investment planning: The consultant would develop a mathematical model (suitable for EGPC computing systems) that would be capable of analyzing the impact of investment options on the cost of product supply through a combination of domestic refining, imports and exports. For this purpose, the consultant would consider all domestic crude oils and an agreed list of four foreign crude oils for refining at each existing refinery location. (d) Investment Program: The consultant would run the developed model to determine the effects on costs of product supply, consistent with the demand projections, of the following options: (i) import all products to meet demand without domestic refining (for the purposes of establishing a reference case); (ii) supply products while operating the refineries with current crude slates, capacity utilization, and operating practices, without new investments; (iii) supply products when the crude slate, capacity utilization, imports and exports are optimized, but without new investments; (iv) supply products under optimized crude slate and imports and exports, and use new process unit and energy conservation investment options at each refining location. The model's logic and structure should be capable of handling variations in input data, and of expressing the defined objective functions as discrete output. Capital costs used for investment options inputs should have an accuracy of ± 20 percent. e) Deliverables: The techniques used and results of the study, together with explanations, should be presented as follows: (i) products demand projections; (ii) price projections; (iii) the structure and logic of the model, and model software; (iv) capital and operating cost estimates for investment options; (v) recommendations on future investments at any or all locations, capital cost estimates and a time schedule for the implementation of such investments; and - 81 - Annex VIII Page 3 of 3 (vi) a data base on the crude oil analyses used for model software generation and on investment options analyses. f) Two representatives of EGPC would participate with the consultant for the duration of this study. The consultant would submit a draft report six months after the effective date of the contract, for review, comments and discussions with EGPC and the World Bank. Following the receipt of such comments, the consultant would submit the final study report within six weeks. Concurrently, t'"e consultant would install the model at EGPC and train EGPC personnel in the hands-on use of the model. M: \ubared\say\arwex9. sar - 82 - Annex TX Page 1 of 2 EGYPT GAS INVESTMENT PROJECT Gulf of Suez Gas Develo2ment Study Terms of Reference Introduction The Gulf of Suez has been the most prolific oil-producing area in Egypt. Currently, over 85 percent of the total oil production comes from over 50 oilfields in the Gulf of Suez area. Associated gas is produced with oil in varying quantities, dependent on gas oil ratios and other reservoir characteristics. Egyptian General Petroleum Corporation (EGPC) is currently utilizing some of the associated gas to supply Egyptian consumers. However, some associated gas is being flared. As the oilfields are depleted, the gas oil ratios tend to increase, whilst oil p.oduction declines and increasing relative quantities of associated gas continue to be produced. In addition, EGPC and other international oil companies (IOCs) operating in the Gulf of Suez area have been exploring and have discovered new oil and non-associated gas fields. With continued exploration, there is a high probability of finding additional oil and gas reserves in the near future. Obiective The objective of the proposed study is to update the previous studies and: (i) to evaluate the present and the prospective gas supply potential of the Gulf of Suez area with a view to maximize the utilization of associated and nonassociated gas and minimize the flaring of associated gas; (ii) to develop an optimal transmission and distribution system integrating the existing gas transmission and distribution system with the medium- and long-term gas development and utilization plans; and (iii) to provide EGPC with the economic evaluation of various investment scenarios based on a phased-gas development strategy to meet the medium- and long-term gas demands of Egypt. ScoRe of Wo-rk In order to achieve the objectives of this study, the consultant or the entity undertaking the task would: - 83 - Annex IX Page 2 of 2 (i) review the geological, reservoir and production data on the oil and gas fields in the Gulf of Suez and Sinai area; (ii) collate and integrate the data relating to the availability of recoverable gas reserves (both associated and nonassociated) and develop gas deliverability profiles for the next twenty years; (iii) review the gas prospects from the fields discovered but not yet developed, as well as evaluate potential gas reserves in the Gulf of Suez area; (iv) review past and present development costs for the existing fields with a view to prepare investment plans to optimize the utilization of (a) associated gas from existing fields; (b) the development of gas discovered from new fields, both oil and nonassociated gas in the Gulf of Suez and Sinai areas; and (c) est:imate the costs for discovery and for the development of new gas prospects; (v) review the existing gas gathering, transportation compression and distribution system; (vi) review the gas demand forecast of EGPC for the medium and long term; (vii) evaluate transmission and distribution options with a view to optimize the existing system and develop least-cost options for investment in gas transmission and distribution systems; (viii) make recommendations that would enable EGPC to prepare its investment plans to maximize gas development and utilization from the Gulf of Suez and Sinai area; and (ix) prepare an environmental assessment consistent with the guidelines of the Government and the Bank. U: %dw*\aqvmz1O. seg - 84 - Annex X Page 1 of 2 GAS INVESTMENT PROJECT Cost of Gas Distribution Terms of RefeLrnce Thie current tariffs charged by Petrogas have remained unchanged since 1981 and bear little relation to the costs of distribution or to alternate fuel costs. In order to achieve the anticipated financial and economic benefits from the GCGDEP, it is important that a new and more appropriate tariff structure for residential and commercial consumers is put in place. In addition, the contractual and regulatory environment for natural gas distribution shoutld be examined and appropriate changes implemented. This is particularly important if Petrogas is to extend natural gas distribution to a substantial number of larger commercial consumers (e.g., hotels, hospitals etc.). For these consumers, a proper framework of contracts and obligations is essential. The study would: 1. assess the current level of tariffs in relation to the pattern of consumption and costs of alternative fuels (both current and expected); 2. calculate the appropriate fixed and variable costs to be allocated to gas distribution; 3. advise on practices adopted by other gas utilities both in developed and developing countries; 4. address the particular aspects of gas distribution in Egypt that call for specific tariff structures; 5. determine the best practice for offering incentives to commercial and small industrial consumers to convert to natural gas; 6. formulate a set of contracts for Petrogas sales to commercial and small industrial consumers; 7. assess the status of gas distribution within the legal framework prevailing in Egypt and advise on any changes to ensure proper regulation of gas distribution; and - 85 - Annex X Page 2 of 2 8. formulate a complete tariff structure and contractual framework for all classes of consumers to address the requirements of economic efficiency in fuel Oistribution and financial viability for Petrogas. This study should be carried out with the assistance of consultants as soon as possible, preferably prior to the commencement of gas consumption under the project. There should be a very close link between the work of this study and other market studies to be funded under the project. M: *ha*d\saz\ami11 . 6ar -86 - Annex XI Page 1 of 1 GAS INVESTMENT PROJECT Project SuDervision Plan 1. Records will be maintalned shoving original schedule against actual achievements and supplied to the Bank at agreed intervals on the following aspects: (a) procurement action by bid packages (bid specifications, bid invitation, opening of bids, bid evaluation, award of contract, signing of contract and contract price as amended from time to time); (b) physical progress according to project components and contracts (highlighting critical activities and bottlenecks); (e) actual project costs and expenditures (local and foreign) and estimated remaining expenditure (local and foreign) projected quarterly through project completion; gd) disbursement schedule (for the Bank loans and other loans); (e) information on problems encountered during implementation (including major mishaps) and expected impact on commissioning schedules; and (f) minutes of the meetings and progress reports of the consultants. 2. The proposed Bank supervision missions and their composition would be as follows: miaeLLQ COMpositi2D Proposed Dates Project launch mission Gas (upstream) Specialist September 1991 Gas (downstream) Specialist Financial Analyst Project supervislon and Gas (upstream) Specialist March 1992 Study revLew Gas (downstream) Specialist Energy Economist Financial Analyst Project supervisLon Gas (upstream) Specialist Twice/year Gas (downstream) Specialist 1992-1994 Financial Analyst Project supervision Gas (downstream) Specialist Twice/year Financial Analyst 1995-1997 N:%dienAs*&7%=e1Leet - 87 - Annex XII Page 1 of 9 CAS INVESTHENT PROJECT EGPC Financial Performance 1. Domestic Energy Prices: assumed to reach 100 percent of international prices by FY96 including alignment of the petroleum and official exchange rates by the start of FY91. 2. Crude Oil Output: assumed to maintain current output levels of 870,000 bbls/day until FY93 then decline by 4 percent per annum thereafter. 3. E=yvt's Share of Oil Production: residual after assumed foreign oil company cost recovery of US$1,600 million, to a minimum of 70 percent and a maximum of 85 percent. 4. Condensate: assumed to be 15 percent of equivalent natural gas production, with 50 percent available for petroleum product production. 5. Refinery OutRut: current capacity of 21.4 million metric tonnes assumed to be increased by 10 percent in both FY92 and FY94, with the same product slate. 6. Crude Oil Exports: residual after refinery requirements and 5 percent refinery losses. 7. Petroleum Product Demand: product demand growth based on assumed price elasticities (-0.05 to -0.20) and underlying GDP (4.0 percent) or population (2.3 percent) based growth. 8. Natural Gas Substitution: annual fuel oil demand reduced by 100 percent of equivalent natural gas sales to the power sector, 67 percent of equivalent gas sales to industry, and 100 percent of gas sales to construction and cement. Gas-oil demand reduced by 33 percent of equivalent natural gas sales to industry. 9. Product ExVorts: difference between refinery output and domestic demand. 10. Product Exnort Revenues: increased from FY90 base by assumed changes in international crude oil prices. 11. Gas Production Cos;s: based on assumed output from "old" versus "new" gas fiel' . and an assumed price of 40 percent of fuel oil equivalent for "new" gas. 12. Domestic Product Sales: based on estimated sales and assumed domestic price changes (see point 1) for petroleum produczs and Petrogas purchases of natural gas (see Petrogas asstumptions). - 88 - Annex XII Page 2 of 9 13. Ahar In-AffiWiagt-e rm-fits: set to 5 percent of product revenues. 14. Cost of PMrchases: set to gas purchase costs plus historic average petroleum product purchase costs, which are assumed to increase with inflation and output. 15. 2natin&--Costs: asstmed to increase directly with inflation and production. 16. Depreciation: set to 9 percent of historic valued assets. 17. Foreign Exchange Losses: amortized at 9 percant per annum. 18. Royalties: set to 3 percent of sales revenues as per historic average. 19. Social Bank Payment: EGPC is exempt from these payments. 20. Income Taxes: effective tax rate of 25 percent of income before tax assumed as per historic average. 21. Surplus Payout: set to 75 percent of income after tax as per historic average. 22. Working Capital: set to maintain current ratio of 1.1 excluding cash used as balance item in projections. H: \shared\gry\annexl3 . ar - 89 - hab RFmbrie of EgYM Annex XII ILvem-mog Page 3 of 9 Actual mid DriecteV FG Sfor-EGPC 01-Apr-91 AsswmqIr EY-88 Y yn FY91 FY92 FY94 FY95 fY96 FY97 Price Assumoticna Ys 9 Local inflation 14% 21% 23% 20Q% 28% 15% 9.0%0 6.0% 5.0% 5.0% Foreign Inflation 8.6% 3.5% 3.0% 7.7% 5.1% 0.4% 0.6% 2.7% 3.9% 4.4% Local Pr. Index (FY91=100) 58.7 67.1 81.3 100 128 147 160 170 179 188 Foreign Pr.Andex (FY91=10 86.4 93.8 97.1 100 105 105 106 109 113 118 Real Exchange Rate Devaluation 0% 0% 0%/0 0% 0% 096 Petroleum Exchange Rate 0.70 0.70 1.03 2.31 3.95 4.67 5.20 5.50 5.62 5.66 Exchange Rate (LEI$) 2 2.38 2.65 2.91 3.95 4.67 5.20 5.50 5.62 5.66 International Crude Oil Prices Bank Forecast Calendar Yr 13.6 16.3 21.2 20.5 17.3 18.5 19.6 20.9 22.6 24.5 r-olowing Based on IBRD Forecast Crude Oil (S/bbl) 15.4 15.0 18.8 20.9 18.9 17.9 19.1 20.3 21.8 23.6 Crude Oil ($/bbl 1990 price 17.8 15.9 19.3 20.9 18.0 17.0 18.0 18.6 19.2 19.9 Annual Real Increase -12% -11% 21% 8% -14% -6% 6% 4% 3% 4% DomesticEneEraPrces weightedavg. 41% 89% 104% 104% 103% 111% 109% (Nominal Index FY91=100) Fuel Oil 56 70 70 100 160 271 382 597 876 957 % of Economic Pnce 29% 30% 46% 24% 28% 40%h 55% 74% 100% 100o LPG 65 100 11t 218 286 416 568 620 % of Economic Price 23% 23% 37% 48% 60% 75% 75% Gasoline 74 100 133 179 177 183 198 216 % of Economic Price 65% 142% 133% 163% 155% 139% 139% 139% Kerosene 74 100 200 327 426 616 836 913 % of Economic Price 21% 30% 51% 64% 80% 100% 100%h Gas Oil 100 200 339 445 648 886 968 % of Economic Price 23% 33% 49% 62%h 79% 100% 100% Other Products 74 100 133 149 177 199 218 238 % of Economic Price 75% 100% 100% 100%/o 100% 100% 100% Domestic Enerav Prices (Nominai Prices) Fuel Oil (LE/mt) 28.0 35.0 35.0 50 80 136 191 299 438 478 LPG(p/litre) LEtbottle 1.5 2.0 3.3 4.3 6.2 8.5 9.3 Gasoline (p/litre) 56 72 97 96 99 107 117 Kerosene (plitre) 10 20 33 43 62 84 91 Gas Oil (p/litre) 10 20 34 44 65 89 97 Other Products (LE/mt) 100 200 224 265 298 327 357 Fuel Oil (LE/mt) 28.0 35.0 35.0 50 80 136 191 299 438 478 LPG (LEtmt) 120 160 262 343 499 682 744 Gasoline (LEtmt) 783 1012 1360 1340 1391 1504 1642 Kerosene (LEImt) 126 252 412 537 776 1053 1150 GasOil(LE/mt) 120 240 407 533 778 1064 1161 Other Products (LE/mt) 100 200 224 265 298 327 357 - 90 - Annex XII AlabReoub&dEaZ Page 4 ot 9 AlU and LrbZfe ed o-r EGPC 01 Apr-91 ()est (est) (etl) (est) (e7t) Eroduytbnlo A 5y% rts FY88 FY89 F90 -FY91 fY92 F93 FY94 F95 FY6E9 fyj~~ ____~ 9 000 38,48 6, crude Oil uttXO mt) 44,200 44,200 43 00 43, 43, 43500 41'760 '000 Baneiffda 884 884 870 870 870 870 835 802 770 739 Pecent Increase 0% 0% -2% 0% 0% 0% -4% -4% -4% -4% EgypWs Share d Cnude Oi 30,100 29,676 31,320 32,951 31,863 31,212 30,214 29d228 28,380 27,613 In Pemrntage 68% 67% 72% 76% 73% 72% 72% 73% 74% 75% CostRecove.yPmts. mln. 1,370 1,370 1,440 1,387 1,387 1,387 1.387 1,387 1,387 1,387 pMgg ProdM roo0 M0 LPG 280 285 285 0 0 0 0 0 0 0 GasolineTN~ha 3,380 3,400 3,400 3.400 3,400 3,740 4,114 4,114 4,114 4,114 Kerosene 2,447 2,530 2,530 2,530 2,530 2,783 3,061 3,061 3.061 3,061 Jet Fuel 170 170 170 170 170 187 206 206 206 206 Gasliesel Oi 3,613 3,600 3,600 3,600 3,600 3,960 4,356 4,356 4,356 4,356 Fuel il 10,380 10,450 10,450 10,450 10,450 11,495 12,645 12,645 12,645 12,645 AspthsX 583 651 651 651 651 716 788 788 788 788 Lube 00 185 208 206 206 206 227 250 250 250 250 Othem 307 343 343 343 343 378 416 416 416 416 Total 21,345 21,636 21,83 21,X5T 21,M-5 23,4M 25,83 25,83 25,09 25,835 Crude Oil Exports ('000 nt) 10,003 8,661 8,25 11,103 10,123 7,440 4,021 3,032 2,191 1,420 ratio actual to est. exports 124% 119% 91% 100% Petroleum Product 0e0 mt) LPG (70) (60) (20) 0 0 0 0 0 0 0 Butane Gas (79) 28 41 0 0 0 0 0 0 0 Naptha/Gasoline 1,106 1,270 1,428 1,210 1,178 1,537 1,814 1,751 1,711 1,675 Kenosene 92 66 318 563 1,437 1,416 1,337 Jet Fuel (30 (52) 224 237 255) (2457 (258) (278) (300) (322) Gas OWDiese (676 (779) 774 968) 827) 245) 34 312 297 134 Fuel OI 636 884 1,022 77 1 140 4,687 6,210 5,494 4,876 3,887 Bunker Fuel 1,378 1,716 1,952 1,834 1,834 1,834 1,834 1,834 1,834 1,834 Other 46 51 25) fM 74 184 139 92 43 Total Net Exports 2,026 2,853 3,476 1,983 3,110 7,948 10651 10688 9927 8588 Total Expowts 3,151 3,944 4,494 3,213 4,218 8,450 10909 10966 10226 8910 Total Imports 1,125 1,091 1,018 1,230 1,108 802 258 278 300 322 - 91 - Annex XII Page 5 of 9 01-Apr 91 actua (Ms) (ast) (est) (es) (es) ( -) (es) 0-MeWISt C;EMons FY83 FY89 FY90 FY91 FY92 FY93 fY94 FY95 FY9 FY97 Ful ON 4,144 3,993 4,143 4,004 3,76 3,298 2,944 2,895 2,798 2,896 Fuel Oil Power 4,144 3,993 4,143 4,535 3,712 1,676 1,656 2,422 3,136 4,027 Gas Oi 1,022 1,043 1,012 1,060 987 895 826 804 788 819 Gas Oi Tmnspont 3,065 3,128 3,361 3,518 3,441 3,310 3,226 3,240 3,271 3,402 Kerosene 2,406 2,422 2,358 2,438 2,464 2,465 2,498 1,624 1,645 1,724 Gasoline 2,121 2,096 2,174 2,190 2,222 2,203 2,300 2,363 2,403 2,439 Jet Fuel 390 390 390 407 425 444 463 484 505 527 Lube Oils 185 206 206 208 206 227 250 250 250 250 Other A 1020 1 0201. 1.020 1.02 1.020 1j065 1.112 1.161 Petroleum Products 87497 11 1619368 18241 15538 1518 15146 15908 17246 Natural ˘as §ae LmilKncubic meters) Domestic 60 65 70 73 76 85 97 110 123 138 Commercial 0 1 2 2 2 6 14 22 31 40 FertiTcer 1,147 1,161 1,251 1,147 1,323 1,530 1,612 1,864 1,685 1,706 Constr/Petrol 719 710 922 1,726 1,768 1,933 2,078 2,098 2,202 2,305 Industry 743 828 931 2,129 2,212 2,305 2,398 2,491 2,594 2,698 Power CC/CT 4,105 4,377 2,580 2.801 2,532 3,204 3,918 3,918 3.918 3,918 Power Steam 0 0 2111 1.083 2.599 4.09 4.199 3.961 3.815 3.514 Total 67774 7142 78 8962 10612 13572 14316 14264 14368 14316 LPG Sale f0 Lonnes) Dlomesic 616 631 647 642 614 626 638 1.496 1,509 1,504 Commercial 140 158 193 199 204 207 207 207 206 205 Investment Companies 3 6 6 6 6 6 Total 759 792 846 847 824 840 852 1,709 1,721 1,715 Revenues from Petroas Gas Revenues 192 232 315 412 662 1,595 2,428 3,843 5,741 6,295 LPG Revenues 7 8 9 39 78 104 162 647 9866 1,435 Average Increase of Petroleum + Gas Supply 6%Y 1% 5% 6% 1% 0% 1% 3% 3% 4% Annex XII Page 6 of 9 Aolual a de for EGPC 01-Ar91 (est ) (est)(et ed (sl (s) (s) Value of Ex 01s a pd Sale FY89 FY90 FY91 F9 F4 FY95 FYe9) a d l n 1,104 819 892 TM ia7 441 353 2 Total (mln. LE) 773 573 922 3,078 4,352 3,578 2,293 1,943 1,542 1,091 Avg Rev (LEln mid 1990 pr 132 99 137 277 336 327 355 377 394 410 Avg. Rev. ($mt mid 199 pr $128 $101 $111 $120 $104 $96 $103 $107 $111 $115 Avg Rev. Wbbl current $14.9 $12.7 $14.5 $16.2 $14.7 $13.9 $14.8 $15.7 $16.9 $18.3 Discount on OPEC Avg. $0.5 $2.2 $4.2 $4.7 $4.2 $4.0 $4.3 $4.5 $4.9 $5.3 % of Benchmark OPEC Pric e 97% 85% 78%6 78% 78% 78% 78% 78% 78% 78% Net PetEoleum Product gupm (minm Butane Gas (15) (2) (1) 0 0 0 0 0 0 0 Naptha 162 182 224 211 186 230 289 296 311 330 Kerosene 23 15 67 126 341 362 370 Jet Fuel 3E) (2) (28 ((33) (32 (30) (32) (37 (43) (50) Gas OiVDiesel (97) (109 (137 (190) (147 41 54 59 61 30 Fuel Oil 57 63 84 7 94 367 518 487 465 401 Bunker Fuel 146 164 203 212 192 182 194 206 222 240 Other 4 15 20 I f 28 73 59 42 21 Total (mln. $) 221 285 366 219 298 802 1,222 1,412 1,418 1.341 Total (min. LE) 155 200 378 506 1,179 3,745 6,352 7,763 7,966 7.594 Tal Exports (min $) 1,325 1,104 1,268 1.552 1,400 1,569 1,663 1,765 1,693 1,534 (constant mid 90 prices) 1.533 1,177 1,295 1,552 1,332 1,488 1,567 1,620 1,495 1,298 Domes Ses EGPC FuiuOlD 427 598 675 878 1,587 2,60n1 3.312 Gas Oi Transport 548 1,063 1,711 2,162 3,144 4,317 4,902 Kerosene 307 621 1,016 1,340 1,260 1,733 1,983 Gasoline 1,716 2,248 2,997 3,082 3,286 3,615 4,006 Jet Fuel 51 107 183 249 376 532 607 Other 123 245 279 337 392 446 -4 Total Petroleum Products 2006 2152 2271 517 42 6861 8 10046 13243 15314 osts an uRevenues Fuel Dcosi( lmi) 74 72 90 101 91 a6 92 98 105 114 Gas Cosit(%rueliEquiv 4% 5% 6% 5% 8% 15% 16% 17% 18% 19% Annual as Costs ($ m:n) 14 21 36 44 68 165 200 222 252 284 EGPC Gas Revenues (LE) 192 232 315 412 662 1,595 2,428 3.843 5,741 6,295 NetGasRevenues(LE) 182 217 278 311 395 824 1,387 2.620 4,325 4,687 -93 Annex XII Ara Rob of E Page 7 of 9 G-as InvesS.nent Loan Actual and px-cted Fn W_ Slate tements for EGPC 01-Apr-91 (prelim) (est) (est) (est) (est) (est) (est) (est) Revenues FY88 FY89 FY90 FY91 FY92 F93 FY94 FY95 FY96 FY97 Domesi Sales Petroleum Products 2,006 2,152 2,271 3,172 4,882 6,861 8,048 10,046 13,243 15,314 Crude Oil 248 338 175 0 0 0 0 0 0 0 Natural Gas 159 Q 292 406 §6Z 11,530 2,331 4.042 6,036 6, Sub-total 2,413 2,678 2,738 3,578 5,549 8,390 10,379 14,088 19,279 22.271 Expor Sales Crude Oil 913 763 922 3,078 4,352 3,578 2,293 1,943 1,542 1,091 Net Petrol Products 120 2 378 506 1..79 3.74S 6.352 7.763 7.96fi -594 Sub-total 1,033 963 1,300 3,584 5,530 7,323 8,646 9,707 9,508 8,685 Total Sales 3,446 3,641 4,038 7,162 11,079 15,713 19,025 23,794 28,787 30,957 Share in Affiliate Profits (est) (est) and Management Fees 489 448 b26 546 554 786 95 1.190 1.439 1,548 Total Revenues 3,935 4,089 4,584 7,708 11,633 16,499 19,976 24,984 30,226 32,504 CosOt and EXpenSeS Cost of Purchases 1,641 2,053 2,581 3,189 4,220 5,772 7,037 7,578 8,088 8,615 Operating Expenses 327 327 327 414 499 489 521 551 608 692 DePreCiatiOn 140 119 154 205 260 360 478 610 754 907 ROYaltieS 120 100 187 215 332 471 571 714 864 929 FOreinr Exchange Losses 0 0 0 17 50 83 90 92 88 81 IntereSt & Debt Expenses 25 23 20 48 70 72 69 57 43 28 Income Taxes 395 333 321 869 514 2.277 2.766 3!80 4 909 5.277 Total 2,648 2,955 3,590 4,956 6,946 9,524 11.5532 13,412 15,353 16,528 Net Profit After Tax 1,287 1,134 974 2,752 4,687 6,975 8,444 11,572 14,873 15,977 % Retained by EGPC 20% 24% 20% 25% 25% 25% 25% 25% 25% 25% Reserves 254 270 194 688 1,172 1,744 2,111 2,893 3,718 3,994 Distr;bUted to Govemment 1,033 864 780 2,064 3,516 5,231 6,333 8,679 11,155 11,983 Reserves Retained by EGPC 254 270 194 688 1,172 1,744 2,111 2,893 3,718 3,994 Total Govt. Payments 1,548 1,297 1,288 3,148 5,362 7,979 9,670 13,202 16,928 18,189 Govt. Pmts. as % Total Revs 39% 32% 28% 41% 46% 480%O 48% 53% 56% 56% Avg. Tax Rate 25% 25% 28% 25% 25% 25% 25% 25% 25% 25% Avg. Royalty Rate 3% 3% 5% 3% 3% 30/O 3%/O 3% 3% 3% - 94 - Annex XII Page 8 of 9 01-Apr-91 01-Apr-91 -(~~~~~est) lest) (Zm (estl (est) lest) lest) ASSETS _88 FY89 FY90 M91 FY9 Ł9i FY94 FY9_ F-96 f Net Cash 950 815 746 864 1,017 1,621 2,501 4,165 6,688 9,580 Current Assets 1,100 1,200 1,890 2,604 3,650 4,"5 6,030 6,990 7,982 8,547 Ivestments in Affiliates 2,925 3,135 3,135 3,135 3,135 3,135 3,135 3,135 3,135 3,135 Propelty, Plant & Equipment At Cost 1,528 1,830 2,005 2,273 2,889 3,996 5,308 6,780 8,378 10,073 Less Depreciation: 1.012 I1.336 149Q 1.64 2.314 2 724 4.156 5§ Net Property, Plant & Equip 516 494 515 578 934 1,682 2,517 3,378 4,222 5,011 Projcts in Progress 325 251 343 692 1,183 1,388 1,547 1,674 1,771 1,860 Foreign Exchange Reval 0 Q 186 551 9 10 1 019 974 00 822 TOTAL ASSETS 5,815 5,895 6,816 8,425 10,842 13,825 16,750 20,316 24,697 28,955 LIABILTIES AND EQUITY Current Liabilities 1,005 1,040 1,718 2,367 3,318 4,541 5,482 6,355 7,256 7,770 Long-terrn Debt Foreign Banks 268 239 309 593 900 929 814 626 401 163 Domestic Sources 124 128 108 95 83 71 58 46 33 21 Equity 300 300 300 300 300 300 300 300 300 300 Reserves 4.118 4.187 4381 5$069 6.241 7.985 10,096 12.989 16.Z07 20.701 TOTAL LIABILITIES AND 5,815 5,895 6,816 8,425 10,842 13,825 16,750 20,316 24,697 28,955 EQUITY - 95 Arab Reo"bib d E Annex XII Gas!rivestnientLoaii Page 9 of 9 Actual and DrojectF tteets for EGPC Source and ADWication of Fuds 01-Apt-91 FFst) (est) (ed) (est) (est) (est) (est) FY88 FY89 FY90 t1 FY93 FY94 FFS FY96 FY97 Sources of Funds Income before It. and Tax 1,707 1,490 1,315 3,669 6,272 9.324 11,280 15,439 19,825 21,282 Depreciation 140 119 154 221 310 443 568 702 842 988 Total Intemal Funds 1,847 1,609 1,469 3,890 6,582 9,766 11,848 16,141 20,667 22,269 Foreign Debt 0 0 0 0 54 64 0 0 0 0 Local Debt 45 8 0 0 0 0 0 0 0 0 Equity 0 0 0 2 Q 0 2 2 0 0 Total Extemal Funds 45 8 0 0 54 64 0 0 0 0 Total Sources 1,893 1,618 1,469 3,890 6,636 9,830 11,848 16,141 20,667 22,269 Dlication of Funds Income Taxes and 395 333 321 869 1,514 2,277 2,766 3,809 4,909 5,277 Social Bank Debt Service Interest 25 23 20 48 70 72 69 57 43 28 Repayment 42 41 56 111 180 211 234 248 251 253 Total Debt Service 67 64 76 159 251 283 303 304 294 2C1 TransferstoGovt. 1.033 864 780 2,064 3,516 5,231 6,333 8,679 11,155 11,983 Investments 402 175 268 616 1,107 1,313 1,471 1,598 1,696 1,784 Increase Worldng Capital (80) 64 13 65 95 122 94 87 90 51 NetChangeinCash 75 117 12 118 153 606 880 1,663 2,523 2,893 Financial Ratios Self Financing 107% 162% 104% 119% 109% 141% 160%o 204% 249% 262% Rate of Return 50% 41% 34% 87o 130% 171% 180% 219% 253% 248% Debt Service 27.7 25.2 19.2 24.5 26.2 34.5 39.1 53.1 70.2 79.3 Operating Margin 400% 33% 26% 46% 53% 56% 66% 61% 65% 66% Current 1.1 1.2 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 Current Assets/Sales 32%h 330/o 47% 36% 330/o 32% 32%o 29% 28fYe 28% Current Liabilities/Expenses 40%o 37n 50% 50% 50%o 50% 50% 50% 50% 50% DetbV(Debt+Equfty) 8% 8% 8% 11% 13% 11% 8% 5% 2% 1% - 96 - Annex XIII Page 1 of 7 GAS INVESTMENT PRQJECT Pet. gas. Financia. Proiection Assumptions 1. Domestic Energy rices: assumed to reach 100 percent of international prices by FY96 including alignment of .he petroleum and official exchange rates by the start of FY91. 2. LPG Retail Prices: fuel component assumed to reach international prices by FY96, plus distribution costs assumed to reach 30 percent of the economic cost of US$150/mt by FY96 and 100 percent by FY98. 3. Retail Domestic Gas Prices: set to an average of 19.8 piasters/cubic meter in FY92 and thereafter set to the fuel oil equivalent, plus a margin sufficien to cover operating costs and the average incremental cost of network expansion (estimated to be 57 piasters per cubic meter in FY91 prices) to a maximum of the LPG equivalent. 4. Incremental Gas Sales and Customers: 30,000 additional domestic and 300 additional commercial customers in both FY91 and FY92, thereafter as per project description. 5. Cost of Gas Sold: set to domestic fuel oil equivalent beginning in FY91. 6. Depreciation: set to the historic average of 5 percent of historic valued assets. 7. Foreign Exchange Losses: amortized at 5 percent per annum. 8. Wazes and Salaries: increased by local inflation and an el.-ticity of 0.75 with respect to gas sales. 9. Income,Tax: effective tax rate on income before tax of 25 percent assumed. 10. LPG Sales: assumed to be supply driven and equal to the historic average of 13 percent of equivalent gas production. 11. Cost of LEG Sold: set to 15 percent of the distribution cost component of LPG sales. 12. Surplus Payout: by law 2 percent of income before taxes is paid to the Nasser Social Bank plus 85 percent of after-tax-income; however, to achieve a 25 percent self-financing level, the retention of almost 90 percent of income after taxes under current depreciation rules is necessary. 13. Cash: used as balance item in projections and as a proxy for required equity contributions. 14. Working Capital: set to maintain a current ratio of 1.2, excluding cash. 15. Consumer ContribuarLns: assumed to average LE 150 per additional domestic customer and LE 400 per additional commercial customer. H: \sharad%\\a=exzt . ser Annex XIII - 97 -ageTof7 Arab Reoubhc of Egvyt Gas Investment Loan Achal and Prolected PetDoass Financial Summary Income Statement (LE million) 01-Apr-91 (eat) (est) (est) (est) (est) (est) FY87 FY88 FY89 FY90 FY91 FY92 E93 FY94 FY95 FY96 Natural Gas Sales Domestic 5.0 5.3 5.7 6.3 8 12 18 28 46 70 Commercial 0.1 0.2 0.3 0.5 1 1 2 4 9 18 Industrial 178.0 234 396 726 1,078 1,733 2,636 PowerStations 111.9 164.0 181 383 971 1,438 2,183 3,145 Totad Natural Gas Sales 116.9 218.7 262.1 349.1 423 793 1,717 2,548 3,971 5,869 Sold Services 1.4 1.2 1.9 4.6 4 8 17 25 40 59 Total Revenues 118.3 219.9 264.0 353.8 427 800 1,734 2,574 4,011 5,928 CostSales%FOE 70o 110%Y* 101% 124% 100% 86% 94% 97/o 98% 99% Cost of Sales 101.7 191.9 231.8 314.7 412 662 1,595 2,428 3,843 5,741 Sales Margin 16.7 28.0 32.3 39.1 15.6 138.0 139.4 145.7 167.6 187.7 Margin piaster/mA3 0.3 0.4 0.5 0.5 0.2 1.3 1.0 1.0 1.2 1.3 Depreciation 11.0 10.0 10.7 13.3 14.1 15.1 16.9 27.5 38.9 51.5 Foreign Exchange Losses 0.0 2.1 4.5 5.3 6.2 6.7 wages & Salaries 5.0 7.2 8.3 8.9 12.1 17.4 24.3 27.6 29.1 30.8 Other Faxed Coats 0.9 0.1 0.1 0.0 2.4 3.5 4.9 5.5 5.8 6.2 Other Costs 1.5 1.3 1.5 1.6 2.2 3.3 4.9 5.7 6.0 6.3 Total Expese 18.3 18.5 20.6 23.8 30.8 41.5 55.4 71.5 86.0 101.5 Operating Inoome (1.7) 9.5 11.7 15.2 (15.2) 96.5 83.9 74.2 81.6 86.2 Interest Expenses 2.6 2.4 2.2 3.0 6.6 10.3 10.5 10.2 9.2 7.9 Income Tax 0.6 1.- 2.7 3.1 0.0 0.0 0.0 0.0 0.0 0.0 Net Operating Income Gas (4.8) 5.7 6.9 9.2 (21.8) 86.2 73.5 64.0 72.3 78.3 Reserves Retained (4.8) 0.9 1.1 1.4 (21.8) 13.4 73.5 64.0 72.3 78.3 Surplus Distributed 0.0 4.8 5.8 7.8 0.0 72.8 0.0 0.0 0.0 0.0 Annex XIII - 98 - Page 3 of 7 01-Apr-91 LPG Income (est) (eOt) (est) (est) .(est) (eat) FY87 EX.: FYf9 F EO FY9 3 FY94 FY95 FO LPG Revenues Domestic 36.5 40.9 43.2 55.5 84.8 105.5 163.9 218.9 747 1,029 Commercial 28.2 35.1 54.3 71.1 103 140 Investment Companies 1.4 1.3 1.7 1.7 U 44 _5. 6.0 7 4 Total LPG Sales 37.9 42.1 44.8 57.2 113.8 146.1 223.2 296.0 857 1,174 Cylinder Sales 10.6 12.6 19.8 16.3 20.1 25.0 29.3 32.4 69 73 Appliance Sales 17.6 26.2 25.6 28.9 35.6 44.3 51.9 57.4 122 129 Services Revenues 3.4 3.3 6.9 11.6 13.9 17.3 20.3 22.4 48 50 EGPC Subsidies 7 06 0.0 .0. 0 0.0 0 2 Total LPG Revenues 77.1 84.3 97.1 114.0 183.4 231.6 324.6 408.2 1,095 1,426 39% 60% 48% 56% 1 1 Cost of LPG 7.1 6.7 7.6 9.0 39.3 78.4 104.4 162.2 647 966 Cost of Cyclinders 15.6 10.9 9.3 11.0 19.1 23.8 27.8 30.8 65 69 Cost of Appliances 9.5 2.6 3.8 4.5 33.8 42.0 49.3 54.5 116 123 Total Cost of Sales 32.2 41.1 47.8 56.6 92.2 144.2 181.5 247.5 829 1158 Sales Margin 44.9 43.2 49.4 57.5 91.1 87.4 143.1 160.7 266 268 Depreciation 9.0 9.3 9.4 1 02 10.6 11.4 12.4 46.9 85 96 Wages & Salaries 17.7 19.9 23.3 26.7 32.9 41.0 48.0 53.1 113 119 Other Fixed Costs 5.9 9.9 10.2 12.3 14.8 18.4 21.6 23.9 51 54 Other Costs 3.8 5.3 5.9 6.9 8.5 10.5 12.4 13.7 29 31 Total Expenses 36.4 44.4 48.7 56.1 66.9 81.4 94.4 137.6 278 300 Operating Income 8.5 (1.2) 0.6 1.4 24.3 6.0 48.7 23.1 -11 -32 Interest Expenses 0.0 0.0 0.0 0.0 income Tax 0.4 0.0 0.2 0.3 0.0 0.0 0.0 0.0 0 0 Net Operating Inoome 8.2 (1.2) 0.5 1.1 24.3 6.0 48.7 23.1 -11 -32 Combhned Gas & LPG Operatio s Non-Operating Revenues 7.1 8.5 12.7 14.5 18.4 24.5 30.1 33.2 35 37 Non-Operating Expenses 4.3 5.4 10.0 11.3 14.4 19.2 23.5 26.0 28 29 Nasser Social Bank 0.1 0.2 0.3 0.3 0.1 2.0 2.6 1.9 1 1 Net Non-Operating Revenues 2.6 2.9 2.5 2.8 3.9 3.4 4.0 5.3 6 7 Net InCome 6.9 7.4 9.8 13.1 6.4 95.6 126.1 92.4 67 54 Reserves 0.9 1.2 1.5 2.0 1.0 14.8 126.1 92.4 67 54 W/C Subsidy Reserve 0.6 0.7 1.0 0.0 0.6 0.0 0.0 0.0 0 0 1st DivWiends 4.4 5.5 7.3 7.8 4.8 7.8 0.0 0.0 0 0 Govt. Admin Charges 0.0 0.0 0.0 0.3 0.0 7.3 0.0 0.0 0 0 2nd Dividend Shareholders 0.0 0.0 0.0 2.2 0.0 49.2 0.0 0.0 0 0 2nd Dividend Employees 0.0 0.0 0.0 0.7 0.0 16.4 0.0 0.0 0 0 Distributed to Governent 3.3 4.1 5.5 8.4 3.6 62.4 0.0 0.0 0 0 DlstrlbutedtoEmployees 1.1 1.4 1.8 2.7 1.2 18.4 0.0 0.0 0 0 Reservs Retfaned 1.5 1.9 2.5 2.0 1.6 14.8 126.1 92.4 67 54 Annex XIII 99 Page 4 of 7 Aab Peot of EgyrA Actual and Proiected PetMras Financial SuMmary Blabne Sheet (l.E mooin Ol-Apr-91 (est) (od) (eat) (eat) (eat) (et) FY87 FY88 FY89 FY90 FY91 FY92 FY93 FY94 FY95 FY96 ASSETS Gros Historic Fxed Assets 255.7 26.1 288.7 339.9 388.1 417.1 461.3 1,018 1,624 1,V'1 Less: Accumulated Depm. 84.3 90.8 107.4 126.3 151.0 177.5 208.8 281 406 552 Revaluation Index 0% 0% 0% 0% 0% 0% 0% 0 0 0 Gross Rb alued FiXed Assets 255.7 269.1 288.7 339.9 388.1 417.1 481.3 1,018 1,624 1,991 Less: Aocumulated DOpm. 84.3 90.8 107.4 126.3 151.0 177.5 206.8 281 405 552 Not Revakled Fixed Assets 171.4 178.3 181.3 213.6 237.1 239.5 254.5 737 1,220 1,439 Foreign Exchange Losses 42.5 89.6 106.6 124 135 136 Prmecs Under Constr. 25.2 22.7 35.9 56.0 34.4 49.7 562.0 612 372 521 Other Long Tern Assets 4.6 4.9 6.9 6.6 8.1 10.5 12.2 13 14 15 Current Assets Cash 42.0 59.4 73.1 47.4 68.1 5.8 (352.6) -728 -860 -1,145 Accounts Receivable 26.2 58.4 51.0 63;5 64.9 120.9 368.1 480 760 1,083 Others (Incl. Irmty.) 35.8 27.6 37.0 39.2 14.6 20.9 23.1 51 81 100 Total Current Assets 104.0 145.4 161.0 150.1 147.6 147.6 38.6 -197 -19 38 = =g=ua=n== -== s_* TOTAL ASSETS 305.1 351.2 385.2 426.3 469.8 537.0 972.9 1,289 1.722 2,149 IUABILITIES AND EQUITY Capital 146.1 148.7 151.2 156.5 156.5 156.5 156.5 157 157 157 Total Reserves 50.9 71.9 80.8 93.8 95.5 110.3 236.4 329 396 450 Reval Reserve 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 0 0 Total Capkal and Reserves 197.0 220.6 232.0 250.3 252.0 266.8 392.9 485 553 606 Proviions 8.8 14.0 22.8 32.6 32.6 32.6 32.6 33 33 33 CoInswer Cotributions 0.0 0.0 0.0 0.0 0.0 3.2 14.1 28 39 52 TOTAL EQUITY 205.8 234.6 254.8 283.0 284.6 302.6 43.7 544 624 691 Long-Term Debt 30.8 28.7 28.1 40.6 72.9 116.3 207.3 302 397 473 Acounts Payable 60.0 80.4 79.0 61.7 63.0 100.8 222.1 334 584 862 Others 8.5 7.6 23.4 41.0 4S.2 17.3 103.9 108 117 123 TOTAL LUABILMES 99.3 116.7 130.4 143.3 1852 234.4 533.3 745 1,098 1,458 TOTAL LIAB. & EQUITY 306.1 351.3 3852 426.3 469.8 537.0 973.0 1.2 1,722 2,149 Anrnex XIII - 100 - Page 5 of? Arab Republ˘i of Eavot nas Invedment Loan Actual and Projected Petroaas Finarcial Summaiv Source and Avoh_ajlon of Funda (LE mlllion) 01-Aor-91 (est) (eat) (eel) (eel) (eet) (eet) FY87 FY88 FY89 FY90 FY91 FY92 FY93 FY94 FYSS FY96 SOURCES OF FUNDS - - - Net Income Before Interest 9.4 11.2 14.8 19.4 13.0 105.9 1386.6 102.7 76.7 61.5 Depreciation 20.0 19.3 20.0 23.5 24.7 28.7 33.7 79.6 129.7 154.3 Internal Cash Generation 29.5 30.4 34.9 42.9 37.7 134.6 170.4 182.3 206.4 215.8 Long-Term Debt 0.0 0.0 1.6 1.6 0.0 7.5 88.3 88.8 96.4 101.8 EGPC Contribution 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Consumer Contributions 0.0 3.2 11.0 12.0 12.7 13.3 Total Sources 29.5 30.4 36.5 44.5 37.7 145.2 287.7 283.0 315.5 330.9 APPLICATIONS OF FUNDS Taxes 1.0 1.4 2.9 3.4 0.0 0.0 0.0 0.0 0.0 0.0 Payments of Surplus 4.4 6.5 7.3 11.0 4.8 80.8 0.0 0.0 0.0 0.0 Increase Other Assets 0.6 0.3 2.0 (0.3) 1.6 2.4 1.7 1.2 1.0 0.9 Capital Expenditures 25.8 29.7 30.9 50.5 28.9 44.3 556.6 606.3 366.6 615.7 Debt Service 4.9 4.7 4.5 6.7 14.5 23.7 26.3 27.8 27.8 42.3 Increase Working Capital 9.3 4.4 (12.3) 14.4 (32.8) 56.4 41.6 23.4 51.6 56.9 Total Applications 46.0 48.0 35.2 85.8 17.0 207.5 626.1 858.7 447.0 615.8 Net Change in Cash 20.7 (62.3) (358.4) (375.7) (131.5) (284.9) - 101 - Annex XIII Page 6 of 7 Arab eubc of Eav ts Inestment Loan Actual and Proecd Petraas Financial Summav Natural 3asBalance Sheet (LE rrIllign} (est) (est) (esl) (eel) (est) (esl) FY87 FY8B FY89 FY90 FY91 FY92 FY93 FY94 FY95 FY96 ASSEIS Gross Historic Fixed Asss 165.5 173.3 190.0 240.5 281.7 302.8 337.4 549 777 1,031 Less: Accumulated Depm. 43.5 43.9 54.4 67.6 81.6 96.8 113.6 141 180 231 Revaluation Index 0% 0% 0% 0% 0% 0% 0% 0 0 0 Gros Revalued Fixed Assets 165.5 173.3 190.0 240.5 281.7 302Q8 337.4 549 777 1.031 Less: Accumulated Dep.n. 43.5 4 54,4 67.5 81.6 98.8 113.6 141 180 231 - Net Revalued Fixed Assets 122.1 129.4 135.6 173.0 200.0 206.0 223.8 408 597 799 (% of totalassets) 71% 73%O 75% 81% 84% 86% 88% 1 0 1 Foreign Exchange Losses 0.0 0.0 0.0 0.0 42.5 89.6 106.6 124 135 136 Projects Under Constr. 14.7 12.4 21.3 33.0 13.7 27.3 204.4 221 246 266 Other Long Term Assets 2.5 3.9 4.1 2.6 3.3 4.2 4.9 5 6 6 Cufrern Assets Cash 41.6 40.8 53.2 34.4 65.0 (9.4) (84.2) -152 -232 -334 Accoudts Receivable 20.3 49.2 44.2 51.6 53.4 105.0 347.1 467 678 957 Others (Incm. Invty.) 13.2 5.5 6.4 7.4 7.0 15.1 16.9 27 39 52 Total Current Assets 75.0 95.6 103.9 93.4 125.5 110.8 279.7 342 485 675 = = = = = = = -- TOTAL ASSETS 214.4 241.3 264.9 302.0 385.1 437.9 818.5 1,100 1,469 1,883 LIABILITIES AND EQtUITY Capita 100.7 103.2 105.7 111.0 111.0 111.0 111.0 111 111 111 Total Reseves 35.4 39.0 58.6 85.9 66.1 81.1 156.6 223 299 380 Reval Reserve 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 0 0 …~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ TotalCapital and Reserves 136.0 142.2 164.2 196.9 177.1 192.2 267.6 334 410 491 Proisons 7.0 12.6 20.0 27.0 26.1 26.1 26.1 26 26 26 Consumfe Contrbutions 0.0 0.0 0.0 0.0 0.0 3.2 14.1 26 39 52 TOTAL EQUITY 143.0 154.9 184.3 224.0 203.2 221.5 307.9 386 475 570 Long-Term Debt 30.3 28.0 25.7 36.7 72.9 116.3 207.3 302 397 473 (adj) Acounts Payable 38.4 56.6 49.8 32.9 77.2 82.8 199.4 303 480 718 Otder 2.6 1.9 6.2 8.6 31.7 17.3 103.9 108 117 123 TOTAL LIABIUTIES 71.3 8B.4 80.6 78.1 181.8 218.4 510.6 714 994 1,313 TOTAL LUAB. & EQUITY 214.3 241.3 264.9 302.0 385.0 437.8 818.4 1,100 1,469 1,883 - 102 - Annex XIII Page 7 of 7 OnInvedm Loan A" mW Pr LEd mEdmmFnni u atuval Ga Sourc and AoUIcalon of Eunda (oa) (et) (et) (et) (eat) (etd) FY87 FY88 FY89 FY9O FY91 FY92 FY93 FY94 FY95 FY96 SOURCES OF FUNDS - ._. - Ne Inot.m Before Intert (0.4) 10.9 12.9 16.6 (132) 982 85.9 76.8 84.7 89.6 Depecio 11.0 10.0 10.7 13.3 14.1 17.3 21.4 32.7 45.1 58.3 Internal Cash Generation 10.8 20.9 23.6 29.9 0.8 115.5 107.3 109.6 129.8 147.9 % Of Total 36% 69% 68% 70% 2% 89% 63% 60% 63% 69% Long-Term Dot 0.0 0.0 1.6 1.6 0.0 7.5 86.3 88.8 96.4 101.8 EGPC Contbb. Gas 0.0 2.6 2.5 5.4 0.0 0.0 0.0 0.0 0.0 0.0 Consurrw n Contrbuions 0.0 0.0 0.0 0.0 0.0 3.2 11.0 12.0 12.7 13.3 Total Sources 10.6 23.5 27.7 36.9 0.8 126.1 204.6 2103 238.8 263.0 APPUCATIONS OF FUNDS Taxes 0.6 1.4 2.7 3.1 0.0 0.0 0.0 0.0 0.0 0.0 Paymets of Surplus 0.0 4.8 5.8 7.8 0.0 72.8 0.0 0.0 0.0 0.0 IncreaseOtherAueets 0.6 1.4 02 (1.5) 0.6 1.0 0.7 0.5 0.4 0.4 Capit Ehxptures 16.8 20.7 20.6 40.3 21.1 34.6 211.8 228.3 253.2 273.6 Debt Service 4.9 4.7 4.5 6.7 14.5 23.7 26.3 27.8 27.8 42.3 lncrease Workn Capi (8.7) 3.8 (0.6) ?2.0 (66.0) 68.4 40.6 21.7 37.1 48.7 Total Applications 14.1 36.8 33.2 78.4 (29.8) 200.5 279.4 278 318.4 384.9 Net Change In Cash 30.6 (74.4) (74.8) (67.9) (79.6) (101.9) - 103 - AnnexL XIV Page 1 of 7 EG5x GAS INVESTMENT PROJECT Assumptions Used in the Economic Analygis Number of Consumers Petrogas's planned figures for customer connections have been assumed. In the residential sector, Petrogas's policy of finai,cing customer connections at the time of laying pipelines in new areas produces a high and historically predictable level of penetration. The estimated number of commercial consumers is based upon area surveys. The take-up of gas by these consumers will be sensitive to the relative price of gas, and to Petrogas's marketing efforts. It is assumed that pricing reforms and an improved marketing performance by Petrogas (promoted by technical assistance under the project) would result in the target number of customers being achieved. Gas Consumptio Residential Consumption Average gas consumption in the residential sector is estimated on the basis of average consumption on the current distribution system. Since 1987, consumption has been relatively stable at around 240 cm/yr. This level of consumption is below the levels expected at the time of the first phase of Greater Cairo gas distribution. Two factors appear to be acting to depress apparent usage: (i) A substantial proportion of the Egyptian housing stock is unoccupied, and these customers are registered as having used no gas, which lowers recorded average consumption. The opinion of Petrogas is that between 5-10 percent of apartments are unoccupied in lower income areas but that in upper income areas, the proportion is 20-25 percent. When average consumption figures are adjusted to exclude unoccupied residences, the average usage per household rises to 279 cm. While Petrogas endeavors not to connect unoccupied apartments (at its own expense) during the coverage of a new area, it is likely that the proportion of unoccupied apartments will be about the same in the next phase of Cairo gas distribution. (ii) The relative prices of gas and LPG, and the structure of gas prices, have create a substantial incentive to limit gas consumption to the first slab (22.5 cn/month) and to use LPG for any additional requirements. Some consumers may have been using gas for cooking and LPG for water heating. The increase in LPG prices in May 1990 removed the incentive to use LPG in place of gas, but it is too early to assess the full impact on usage patterns. In the long term, continuing - 104 - Annex XIV Page 2 of 7 LPG and gas pricing reform will lead to the conversion of any remaining LPG appliances to gas, and the elimination of the incentive to restrict consumption to the first slab, which should increase average consumption. Trend growth in average household consumption of 1 percent per annum is anticipated, mainly due to the LPG substitution referred to above and to the increased use of gas for water heating as living standards rise (current appliance density per household is about 1.6). It is assumed that the price elasticity of demand is very low, since gas cooking and water heating are essential services. There is, thus, likely to be little response to the anticipated long term raising of prices to economic le-els. Commercial Consumgtion The average consumption of commercial users is also estimated on the basis of current consumption. However, there were only 363 commercial customers in FY90, compared with the 5000 expected to be connected under the GCGDEP. The average of 4900 cm/yr may not be fully representative of consumption potential, due to the following reasons: (i) Gas to commercial consumers is, at present, priced well above the cost of LPG and gas oil. Hence, commercial consumers have the same incentive as residential consumers to limit gas consumption and use LPG or gas oil where possible. (ii) Few sizeable consumers (hotels, hospitals, large restaurants) are connected to gas, and none are using it to its full potential. Incorporation of these consumers wouldl raise the average consumption level. Based upon experiences in other cities, an average of 6000 cm/yr per customer is considered reasonable for the start of the project (FY93), when initial LPG and petroleum product pricing reform will have created a greater incentive to use gas. This average is expected to rise by 5 percent per annum (to a ceiling of 10000 cm/yr) as more large consumers are connected and the service sector grows. Fuel Substitution All fuel substituted in the residential sector is assumed to be LPG. Ele'.tricity is also used in a few households, particularly for water heating (probably no more than 5 percent). The relatively high running cost of electric heaters leadL to their substitution by gas heaters where consumers have a choice. Since the economic cost of electricity is above that of LPG, inclusion of this benefit would raise returns to the project. In the commercial sector, 90 percent of substitutions are expected to be for LPG. with 10 percent for gas oil, which is used by larger consumers for water heating. - 105 - Annex XIV Page 3 of 7 Industrial substitution is based upon surveyed fuel use in the targeted factories, with x percent being fuel oil, y percent, gas oil and z percent, LPG. Valuation of Spubstitute Fuels All fuels have been valued on the basis of international product prices and the economic costs of transportation and delivery. Although Egypt's modest imports and exports are in balance, there is an excess of potential demand over supply for LPG. Despite future growth in supply as more gas is utilized, in the long run the LPG requirements of Egypt's rapidly growing population can only be met by imports. Hence the cif price of LPG is used to value the LPG displaced by gas. This is taken as the Mediterranean LPG price, adjusted for freight to Egypt (US$20/ton). Allowance is also made for the substantial transport, bottling and distribution costs of LPG. This has been estimated at US$150/ton, based upon economic costs provided by Petrogas. The main cost components are as follows (capital and operating costs): USSZton Port Handling and Transport to Bottling Plant 20 Bottling Plant 25 LPG Cylinders 85 Transport and Distribution of Cylinders 20 TOTAL COST 150 The capital intensive nature of LPG means that most of this cost represents imported capital equipment. For gas oil, the cif price is taken, reflecting Egypt's substantial current deficit in middle distillates. This price is adjusted for freight to Egypt, and for transport, distribution and storage distribution within Egypt. Fuel oil, which is in substantial surplus, is valued at its FOB price, adjusted to reflect additional costs within Egypt. All fuel prices are escalated in line with World Bank oil price forecasts. Base Fuel Values and Costs (USS/ton) Transport, Storage & 1990 Price and Basis Distribution Adjustment LPG 219 (cif) 150 Fuel Oil 80 (fob) 15 Gas Oil 220 (cif) 20 - 106 - Annex XIV Page 4 of 7 Convenience and Supply Security Benefits from LPG Replacement In addition to the benefit to the country of displacing tradeable petroleum products with lower cost gas, natural gas distribution yields a benefit to consumers due to its convenience and security of supply. It is generally recognized that consumers are willing to pay a premium for natural gas over LPG, reflecting its superior qualities in use. In the absence of direct market data in Egypt, this willingness to pay has been approximated by the costs borne by consumers to obtain a quality of service from LPG that approximates that obtained from natural gas. - The convenience benefits of natural gas have been approximated by: (a) the tip that most consumers pay to have cylinders taken up to their apartments; and (b) the imputed rent of the space occupied by LPG cylinders. - The security of supply benefit of natural gas has been approximated by the holding cost of a spare LPG cylinder (which is held by most consumers to guarantee availability of LPG). Using average costs observed in Cairo, the value of these consumer benefits for the purposes oi economic analysis has been estimated at US$30 per ton of LPG displaced for residential consumers and US$15/ton displaced for commercial consumers. It should be mentioned that industrial consumers benefit in a similar manner from the replacement of fuel oil and gas oil with natural gas, since conversion to gas reduces working capital requirements (for stored oil products) and usually lowers the operating and maintenance costs of boilers. Since these benefits will vary widely between users, no attempt has been made to value them, and, in this sense, the valuation of the benefits of gas substitution to industry is conservative. MA: \hared\gary\annex5. sar EGYPr GAS INVESTMENT LOAN I OREATER CARO OAS DSTRIBUTION EXPANSION COMPONENT BASE CASE ....... ......... . 1893 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2008 2007 2008 2009 2010 Residenial 47000 94000 141000 186000 235000 235000 235000 235000 235000 235000 235000 235000 235000 235000 235000 235000 235000 235000 _ommntc 1000 2000 3000 4000 5000 5000 5000 5000 S500 5000 5000 5000 5000 5000 5000 5000 5000 5000 Industrial 2 8 13 1a 22 22 22 22 22 22 22 22 22 22 22 22 22 22 CONSUMPTlN PER UNIT (an Resudtal 245 247 250 252 255 257 280 262 265 288 270 273 276 279 281 284 287 290 Commenc 6000 6300 6815 6948 7293 7658 6041 d443 8865 9308 9773 10000 10000 10000 10000 10000 10000 10000 Industtbt (mIr) 3050 3080 3111 3142 3174 3205 3237 3270 3303 3338 3389 3403 3437 3471 3508 3541 3578 3812 GAS SALES (nEcm) ResdntIal 5753 17433 29345 41494 53883 60468 61073 61634 62301 62924 63553 64188 64830 8547s 66133 6870s 67463 88137 Commewdal 3000 9450 18538 24310 32819 38288 40203 42213 44324 46540 48867 50000 50000 50000 SOO0 50000 s5ooo 500S0 Industiral 3050 15402 32867 48704 63473 70518 71224 71936 72855 73382 74118 74857 75605 76361 77125 77898 78675 79462 Total 11603 42284 78549 114508 150174 16927S 172S00 175833 179280 182845 186535 189045 190436 191840 193256 194891 196138 197599 FUELSWJ9SWtUTEOOns) ULF 6796 20928 35760 51261 67469 76757 78627 00571 82583 84695 88883 86215 80738 69285 69796 00336 90870 91428 Fuel 06 1357 6851 14531 21664 2t233 31367 31681 31998 32318 32641 32967 33297 33030 33986 34306 34649 34996 35346 ri0 o0 1602 7593 15798 23524 30756 34330 34807 35296 35797 36310 36836 37260 37589 37921 38257 36588 38938 39264 ...... ...... ...... ...... ...... ...... ....... ...... ...... ...... ...... . .... ...... ...... ...... ...... ...... ............-§ ----e*.-o -- ^*^--o -----* -v*--- Total 9757 35372 66089 98449 126458 142454 145115 147865 150707 153646 156666 158773 159957 161153 162381 163580 164812 M6057 IRuCu aFRiUSmUTEO(WSa ..... ..... .. .... 1 - - - -- - - -- - CoFadFOB pRasns 17.7 17.1 17.6 18.5 19.4 20.2 21.1 21.9 22.3 22.1 21.9 21.0 21.4 21.4 21.4 21.4 21.4 21.4 LPG (rla TtMp.3 O11J 334.5 329.7 335.0 342.8 350.5 356.4 366.4 374.3 377.4 375.4 373.5 371.6 368.? 369.7 369.7 369.7 369.7 389.7 Fuel Cl (bid Tawpi Sk1, ) 79.6 77.4 60.2 63.2 66.7 90.3 93.S 97.4 98.6 97.9 97.0 96.2 95.3 953 95.3 95.3 95.3 95.3 GMON o0(t Tamsp.& DIaL) 193.7 168.7 195.1 202.1 210.4 218.7 227.0 235.3 236.5 236.5 234.5 232.5 230.5 230.5 230.5 230.5 230.5 230.5 Tampoet Dstdabn Coa OUaIMut LPG Sub efts UIlon USln of IPO LP 1SO Realda" 30 Fudl 0 1s CommterIal 1S Go0 (11120 VALUEOFR sELS nTVED (WI lUr ........*........ ............ ................................. . tUO 2.27 6.90 12.01 17.56 23.65 27.51 26.61 30.16 31.17 31.60 31.45 32.70 32.61 33.00 33.20 33.40 33.60 33.60 Fud 0C 0.11 0.53 1.16 1.60 2.45 2.63 2.97 3.12 3.19 3.20 3.20 3.20 3.21 3.24 3.27 3.30 3.4 3.37 amON 0.31 1.43 3.08 4.75 6.47 7.51 7.90 S,31 8.54 6.59 6.64 6.6 66 8.74 as,2 a9c 6n97 9.05 .... .... .... .... .... ... ... .. . ... ... ... .... .... .... ... ... .... -----.. Total 2.69 6.60 16.28 24.12 32.57 37.85 J9.60 41.56 42.90 43.56 44.29 44.65 44.87 44.98 45.26 45.59 45.91 46.22 lD X (9 uX WEEFITS OF LPG sLeffTTu1oiO (WI mom) COT OF GAS FudCUEqulv. S 1.66 1.63 1.70 1.76 1.67 1.96 2.05 2.15 2.18 2.16 2.14 2.11 2.09 2.09 2.09 2.09 2.09 2.0 C .................................................. ecoNOUCRA1E OF FET1R ANALYSIS (USS s) 192 19"3 194 1995 1999 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 .... .... . .... .... .. .... .... . . .... .... . . ---- ----. . .... .... . . -- . ----. . ... . ...... .... ---- .. ----.. .. .... ........._ .......... hvmesw Cost 2.4 38.1 37.3 37.1 37.2 20.2 O4M * 0.40 0.80 1.20 1.80 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 Z00 2.00 2.00 2.00 oa ofa 0.70 2.43 4.71 7.16 9.91 11.73 12.51 13.33 13.81 13.94 14.06 14.12 14.07 14.18 14.28 14.39 t4.49 14.60 Tdl CO5 2.40 39.21 40.57 43.04 4s.97 32.13 13.73 14.51 15.33 15.81 15.94 16.08 16.12 16.07 16.18 1.28 6.39 16.49 16.60 .......... FOs RegiE 2.69 6.86 16.26 24.12 32.57 37.85 39.66 41.56 42.90 43.56 44.29 44.65 44.67 44.98 4s.26 45.59 45.91 4.22 GM Oumi. Buifs 0.17 0.52 0.88 1.26 1.65 1.66 1.90 1.94 1.97 2.01 2.05 2.08 2.10 2.11 213 2.14 2.16 2.18 TOMl 8in 0.00 2.86 9.38 17.14 25.37 34.22 39.72 41.58 43.52 44.87 45.59 46.34 46.73 46.77 47.09 47.41 47.74 46.07 46.40 Ni B_meN -2.40 -36.35 -31.19 -25.90 .20.59 2.06 25.99 27.07 28.19 29.06 29.65 30.26 30.61 30.70 30.91 31.13 31.35 31.57 31.80 E -- 15.8% 00 I . o >.4 - 109 - Annex XIV Page 7 of 7 ARAB REULCOFEGP GAS INVESTMENT LA Trn u Gas O Cagital Cost AssumDtions Local Cost = 25% Foreign Cost = 75% Product Mix Assumptions Feed Gas = 70 MMSCFD Products = 60 MMSCFD Gas 35 Tons/Day LPG 900 BbVday Condensate Capdal Cost O&M Production Revenue (US$ million) Net Year TGGC Ploeline Cost Profile 1/ Gas LPG Condensate Revenue FY91/92 10.3 15.0 8.34 -33.64 FY92193 38.1 15.0 8.34 42 24.16 1.12 3.48 42.68 FY93/94 7.5 5.0 8.34 52 29.06 1.45 4.18 13.84 FY94/95 8.34 62 35.97 2.05 5.17 34.86 FY95/96 8.34 62 37.35 2.20 5.37 36.58 FY96/97 8.34 62 38.97 2.21 5.60 38.44 FY97/98 8.34 45 29.51 1.61 4.24 27.02 FY98/99 8.34 28 19.15 1.00 2.75 14.57 FY99/2000 8.34 15 10.70 0.54 1.54 4.44 FYOQ(01 8.34 14 9.91 0.48 1.43 3.47 FY01/02 8.34 13 9.18 0.42 1.32 2.58 FY02/03 8.34 12 8.50 0.39 1.22 1.77 FY03104 8.34 11 7.87 0.38 1.13 1.02 FY04/06 8.34 10 7.29 0.34 1.05 0.33 13 year ife ERR* 28% 6 year life ERR 21% 1/ Production profile is net of existing gas production. MAP SECTION 1P10nt ~Au Ei6 \ ~~~~~~~~~~~~~~RASBLJDRANt> ~ / AIRPORT RAS ABU RUDEI$' P October Field12 ToSuez - 1 2Km Poin o Rasker a r 169 Processin 190 KM Facilities _ _ tj/ \ 9 ~~~~~~~~~~~~~~~~~~~~26 Km I ~~~~OF \ < j ~~~~~SUL-, / Ras Baker 16R Facltes Petrobel and } t) ~~~~~~~~~~~~~~~~~~~Plant(*s/ FEIRANp To Suez WEST~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~1e w E S T F acial, ens BANK BELAYI MEOITfRAtN SEGAS ARAB REPUBLIC OF EGYPT GAS INVESTMENT PROJECT TRANS GULF COMPONENT ___ ~~~~~~~~~Proiec Existi ng: OFMA A ON LAND PIPELINES ARABIA OFFSHORE SUBMERGED PIPELINES LBA ARAB REPULIBLYIC AA \NJ MEASURINGANDCONTROLSTATIONS OF E GYP T * COMPRESSION STATIONS BUL-ROADS SUDAN BU ILT- UP AREAS ARAB REPUBLIC OF EGYPT GREATER CAIRO GAS DISTRIBUTION PROJECT ' ks Nos' Cay< i 1th may Cily / / ,f , / / f3 . , f 2. 4 - - /, '~~~~~~~~~~~~~~~~~~~~~~~~~~~~ ~ ' H/w // +2,R..;, A/ I~~~~~~~~~~~~~~~~~~~~~~~~~~ . /t A t R X Z t _1 / * POWER-H. DISTRIBUTIONSMAIN l2 , ,/ ~//64iyei1 ; A >g 7-BAR MAINS , PRESSURE REGULATING STATIONS (Z=n /: ,,, DISTRICT REGULATING STATIONS AREAS TO HAVE GAS Y6e>;g ~~~~~~~~~~~~~~~H.P. DISTRIBUTION MAIN t24' J t 0 . > +< : --- ~~~~~~~~~~~~~~~~~7-BAR MAINS / / *8 ' > * ~~~~~~~~~~~~~~~~~~~POWER STATIONS /f J ,,,>~~~ ~~ ~~~~~~~~mids i PRESSURE REGULATING STATIONS / / °, . i' 7, 4 5 ,, ~~~~~~~~~~~~~~~~~DISTRICT REGULATING STATIONS / /\ ~~~~~~~~~~~~~~~~~~~~~~~~GAS AREAS BUILT-UP AREAS oD .2 , INDUSTRIAL CONSUMERS _ _eL,. t~~~~~~~~~~~ ....... , . ,._ . .__3 ;W.Q. S h:~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~a