-AJ 3 z JY 57Document 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 IIIIndustry & Energy Operations DivisionEurope, Middle East and North Africa Regional Office

This document has a restricted distribution and may be used by recipients only in the performiance oftheir official duties. Its contents may not otherwise be disclosed without World Bank authorization.

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CURRENCY EQUIVALENTS

Currency Unit Egyptian Pound (LE) - 100 piastresLE 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 feetGWh (Gigawatt hour) - 1,000,000 kWhcm (centimeter) = 0.4 inchmcf thousand cubic feetmcfd - thousand cubic feet per daymcm = thousand cubic metersmmcfd = million cubic feet/dayMT G million tonsMTOE million tons of oil equivalentMW (Megawatt) = 1,000 kWOne cubic meter = 264 US gallons

= 35.31 cubic feetOne kilometer (>m) 0.6214 milesOne metric ton (mt) (1,000 kg)- 2,205 poundstcf - trillion cubic feettonne = 1.1 short ton

GLOSSARY OF ABBREVIATIONS

AIC - Average Incremental CostCIDA Canadian International Development AgencyEGPC = Egyptian General Petroleum CorporationEIB = European Investment BankENPPI = Engineering Company for Petroleum and Process IndustriesESMAP = Energy Sector Management Assistance ProgramGCGDP = Greater Cairo Gas Distribution ProjectGDP - Gross Domestic ProductGEF = Global Environment FundGOE = Government of EgyptGPC = General Petroleum Company5UPCO - Gulf of Suez Petroleum CompanyICB = International Competitive BiddingIOC = International Oil CompanyLPG - Liquified Petroleum GasMIS = Management Information SystemPETROBEL - Belayim Petroleum CompanyPETROGAS = Petroleum Gas CompanyPPC = Petroleum Pipeline CorporationPPAR - Project Performance and Audit ReportPRS - Pressure Regulation StationsPSC = Production Sharing ContractSAL = Structural Adjustment LoanSCADA = Supervisory Control ar Data AcquisitionSUCO = Suez Oil CompanyTGG - Trans Gulf GasTOR - Terms of ReferenceWEPCO = 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 . . . . . . . . . . . . . . . . . . . . . . . 2B. Developments in the Sector . . . . . . . . . . . . . . . . . . 4

Pricing. . .................... 4Poverty Impact Minimization . . . . . . . . . . . . . . . . 5SupplyIncreases .5Value Added Increase of Products . . . . . . . . . . . . . 5Private Sector Support .5

III. NATURAL GAS SUBSECTOR.6

A. Institutional Setting .. 6B. Gas Reserves .. 7C. History of Gas Supply and Consumption . . . . . . . . . . . . 7D. Gas Supply - Futre . . . . . . . . . . . . . . . . . . . ..9E. Development Plan .. 10F. Gas Pricing .11G. Bank's Role in the Sector and Experience in Past Lending 13

IV. THE BORER . . . . . . . . . . . . . . . . . . . . . . . . . . 14

A. Statutory Functions .14B. Capital Structure .15C. Organization and Management . . . . . . . . . . . . . . . . 15D. Functional Structure ....... .. .. .. .. .. .. . 16

Exploration and Production ..... . . . . . . . . . . 16Refining and Processing . . . . . . . . . . . . . . . . . 16Petroleum Pipeline . . . . . . . . . . . . . . . . . . . 16Distribution .16Accounts and Audit .16Insurance . . . . . . . . . . . . . . . . . . . . . . . . 17

This report is based on the findings of an appraisal mission to Egypt inNovember 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 performanceof their official duties. Its contents may not otherwise be disclosed without World Bank authorization.

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able of Contents (Contlnued)

Page No.

E. Petroleum Gas Company (Petrogia) .... . . . . . . . . . . 17Background ...... . . . .. . . . .. . . . .. . . 17Capital Structure . . . . . . . . . . . . . . . . . . . . 17Organization . . . . . . . . . . . . . . . . . . . . . . 17Insurance ...... . .. . .. . . .. . . .. . . . . 18Project Engineering and Implementation ... . . . . . 18

V. THEPROJECT .18

A. Project Objectives and Scope . . . . . . . . . . . . . . . 18B. Rationale for Bank Involvement . . . . . . . . . . . . . . . 19C. Project Description . . . . . . . . . . . . . . . . . . . . 20

Greater Cairo Gas Distribution Component . . . . . . . . 20Trans Gulf Gas Component .. 20

D. Cost Estimates . . . . . . . . . . . . . . . . . . . . . . . 21E. Financing Plan . . . . . . . . . . . . . . . . . . . . . . . 22F. Procurement . . . . . . . . . . . . . . . . . . . . . . . . 23G. Disbursements . . . . . . . . . . . . . . . . . . . . . . . 25H. Monitoring and Supervision . . . . . . . . . . . . . . . . . 26

Retroactive Financing and Advance Contracting . . . . . . 26I. Environment . . . . . . . . . i . . . . . . . . . . . . . . 26

Environmental and Safety Review of GCGDC . . . . . . . . 27Environmental and Safety Review of Trans Gulf

Gas Component . . . . . . . . . . . . . . . . . . . . 27J. Project Management and Implementation . . . . . . . . . . . 28

Greater Cairo Gas Development Component . . . . . . . . . 28Trans Gulf Gas Component . . . . . . . . . . . . . . . . 29

VI. FINANCIAL ASPECTS . . . . . . . . . . . . . . . . . . . . . . . 29

A. Historic EGPC Financial Performance . . . . . . . . . . . . 29B. EGPC Accounts and Audit . . . . . . . . . . . . . . . . . 31C. Historic Petrogas Financial Performance . . . . . . . . . . 32D. Future Petrogas Investments and Financing . . . . . . . . . 33E. Petrogas Accounts and Audit . . . . . . . . . . . . . . . . 35

VII. ECONOMIC ANALYSIS ................ ...... . 36

A. Economic Justification . . . . . . . . . . . . . . . . . . . 36B. Project Economic Costs . . . . . . . . . . . . . . . . . . . 36Ci. Project Economic Benefits . . . . . . . . . . . . . . . . . 36D. Economic Rate of Return ...... . .......... . 38E. Risks .......................... 39

VIII. AGREEMENTS REACHED AND RECOMMENDATIONS . . . . . . . . . . . . . 39

eiii

Zble of Contents (Centinued1

ANNEX I Functional Structure of Oil IndustryANNEX I; EGPC Organization ChartANNEX III Natural Gas Supply and Potential Demand AssessmentANNEX IV Petrogas Organization ChartANNEX V Greater Cairo Gas Distritution ComponentANNEX VI Trans Gulf Gas ProjectANNEX VII Gas Market DevelopmentANNEX VIII Refinery Sector Investment Planning Study - Draft TORsANNEX IX Gulf of Suez Gas Development Study - Draft TORsANNEX X Cost of Gas Distribution StudyANNEX XI Project Supervision PlanANNEX XII EGPC Financial PerformanceANNEX XIII Petrogas Financial PerformanceANNEX XIV Economic Analysis

IBRD Map Nos. 22905 and 22906

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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 increaseand Descrptio5 : the use of a nontradeable commodity, natural gas; to

release tradeable petroleum products for export; and todecrease the environmental impact of fuel use. Theproject focusses not only on increasing the supply ofnatural gas by reducing flaring and debottlenecking thesupply constraints rf transporting gas to market, butalso provides the infrastructure required to maximize thevalue added of the fuels being substituted. The projectenables the delivery of a clean-burning fuel to theGreater Cairo area to displace petroleum products, thusmitigating air pollution problems. The institutionbuilding efforts for Petrogas initiated in the previousBank loan would be further enhanced to increase itscommercialization.

BenLefit$ The gas distribution network extension would allow forand Rlisks: the replacement of higher valued petroleum products

(primarily LPG and gas oil), thus substantiallyincreasing the va.ue added of natural gas. Extension ofthe existing gas network would increase th& deliverycapability of the least-cost fuel to an additional235,000 households, 5,000 commercial and 22 industrialconsumers. The Trans Gulf Gas Component would increasegas supplies to the network by about 70 mmcfd as a resultof decreased flaring of natural gas in the Gulf of Suez.The gas distribution component also has the environmentalbenefits of substituting a cleaner burning fuel for otherhydrocarbon products and decreasing vehicular traffic inCairo. The Trans Gulf Gas Component would decrease theflaring of natural gas and largely replace high sulphurfuel oil use in dual-fired power plants, freeing uppetroleum products for export. Thus, the project woulddecrease the budget deficit by lowering the cost ofenergy supply and help the balance of payments byincreasing exports. The financial risks associated withthe 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 committedto continuing this reform program. This upfront energy

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prlce action has mLnimized the risk on financial andeconomic viability.

Estimated Prosect Cost(USt MiL1ion):

Foreignas X of X of

LQl fa£na TotlL Total one Cot

Greater Cairo Gas Distribution ComponentMaterials 13.4 67.8 81.2 83.5 34.3Construction 67.8 23.3 91.1 25.6 38.5Technical 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 ComponentEqufipment and Naterials 4.7 31.8 36.5 87.1 15.4Construction 1.8 5.3 7.1 74.6 3.0Technical 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 48.7Price 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 59.2wu - uuu3

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Financing Plan:

Local Foreig Total X o-f Total

EGPC 60.5 52.0 112.5 39.4Petrogas 56.0 0.0 56.0 19.6IBRD 0.0 84.0 84.0 29.4EIB O.Q 33.0 33.0 11.6Total 116.5 169.0 285.5 100%

Estimated Disbursement(USIS Million):

FY92 FY93 FY94 E95 FY96 FY97Annual 7.7 35.5 15.3 10.8 11.3 3.4Cumulative 7.7 43.2 58.5 69.3 80.6 84.0

Economic Rateof 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 economicgrowth accompanied by significant social progress. Not only had GDP expandedby about 9 percent per annum (1974-1981), but the country also benefited fromlarge gains in the terms of trade. The primary engine of growth was the rapidinc:-ease in foreign exchange earnings from oil-based income: oil exports, SuezCanal fees and workers' remittances. This growth scenario began to weaken in1982 with decreases in world oil prices and finally ended in 1986 when oilprices plummeted. Although the steep rise in oil prices in the August 1990 -

anuary 1991 period increased oil export revenue, lost remittances and othercosts have substantially aggravated Egypt's financial problems.

1.02 Five major economicproblems became increasingly Figure 1: Role of OiI & Gas in Economyacute during the 1980s. 4|_

First, the economy 4

experienced wideningfinancial disequilibria. 3___ _.__

The current account andbudget deficits averaged 3_

about 7 and 22 percent of 2__

GDP, respectively. Second,economic growth was achieved 2___.

at the cost of increasedvulnerability, resulting __from an overreliance on oil- __ .

based revenues (see Figure1) that made the balance ofpayments vulnerable toexternal 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 pricesignals resulted inwidespread inefficiencies in investments; the economic structure does notreflect the comparative advantage of the country and can not form the basisfor sustained growth, once oil had ceased to play a major role. Fourth, 70percent of the industrial value added is publicly owned and suffers frompervasive problems, including the maintenance of insolvent companies supportedby a complex set of subsidies and overdrafts, barriers to labor mobility andan inappropriate incentive system. Fifth, external debt outstanding anddisbursed increased by 64 percent from FY82 to FY87, and debt service tripled,resulting in a debt service ratio exceeding 60 percent. Total debt wasestimated at US$50 billion by 1988, equivalent to 147 percent of GDP.

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Although recent debt forgiveness will ease debt servicing, the problem ofdebt-driven development still must be addressed.

1.03 The energy sector plays a key role in all of the above macroeconomicproblems. Subsidies on domestic energy consumption have been estimated torange from 30 percent to 50 percent of the country's total subsidy burdenbetween FY80 to FY88. The total level of implicit subsidies directed towarddownstream sectors in Ff9l is estimated to be 9.6 percent of GDP. As a directresult, per capita energy consumption reached 607 kg of oil equivalent by1988, 56 percent above the average for countries in the US$500-US$1,500 GNPper capita range.

1.04 As Egypt's oil production is expected to begin its decline in themid-1990s, it may become a net importer of crude oil before the end of thedecade. To compensate for the impact this decline in exports would have onthe balance of payment and budget deficit, two specific changes in policystrategy have been adopted. First, a five year (1990-1995) energy priceadjustment program has been initiated, directed at ending domestic energysubsidies by June 1995. The pricing reform program is front-loaded with thelargest price increases directed to the earlier years. Such an approach isdesigned: (i) to ensure that the growth in energy consumption will decline inthe near term; and (ii) to decrease the budget deficit substantively. Thefirst two steps of the energy price reform have been implemented (in May 1990and May 1991) resulting in energy prices more than double what they were priorto the start of the program. Furthermore, the Government has also addressedstructural imbalances within the mix of energy prices by focussing the largestprice adjustments on products with the largest element of subsidy. Inaddition, in 1986 the Government increased the incentives for oil companies toexplore and develop natural gas potential by adopting a new gas clause. Thisclause establishes the value of natural gas purchased from the oil companiesat 85 percent of the price of internationally traded fuel oil. Increasing therole of natural gas in meeting domestic energy demand will free oil productsfor export and thus mitigate the balance of payments problem. As the cost ofthe supply of natural gas is economically attractive relative to the remainingsupply alternatives, the cost of the domestic energy supply will decrease.Environmental degradation will be ameliorated by substituting high sulphurfuel oil with a clean burning fuel. Decreasing the flaring of associatednatural 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 of27.0 MTOE were oil (67 percent), natural gas and condensates (24 percent) andhydro power (9 percent). As of 1988, proven oil and natural gas reserves were480 million tons (MT) and 12 trillion cubic feet (tcf), respectively.Reserves of coal are limited, and the only mining project under considerationis the Maghara Mine in Sinai, with estimated net proven reserves of about 27.8

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million tons. Egypt's total hydropower potential is about 12,000 GWh/a, ofwhich 9,000 GWh/a were harnessed with the completion of the Aswan Dam and1,100 (Wh/a with Aswan II. Given that oil production has stabilized and isexpecteJ to decrease over the medium to long term, an&d that the vast majorityof hydro potential has been developed, indigenous energy supply growth isprimarily restricted to natural gas'. This limitation necessitates thatnatural gas exploration and development be accelerated to keep Egypt frombecoming 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 agreementcwith 50 international companiL.acting as operators for thestate oil company, EgyptianGeneral Petroleum Corporation C)(EGPC). Successful oildevelopment has enabled Egypt tosupply domestic requirements and a 0 export about 8.3 MT of crude oil (do_Iand 3.5 MT (net)' of petroleum .- .6 .

products in FY90. The FY90 rNl we Om owo "Wu

production rate is perceived tortpresent a plateau, which Egyptcould, at best, maintain until the mid-1990s. The growth of domesticpetroleum product consumption decelerated substantially in the FY87-FY9Operiod, largely due to the modest growth in the economy, increases in thesubstitution of domestic energy consumption by natural gas and energy priceincreases. A continuation of this trend would help mitigate the erosion ofoil export potential, thereby increasing the revenues required by Egypt forbalance of payments support. However, even with the expected increases inenergy prices and gas supply, forecast declines in crude oil production duringthe latter half of the 1990s may result in Egypt becoming a net importer ofcrude oil by the year 2000 (see Figure 2).

2.03 Over the longer term (beyond 2000), Egypt may have to resort toenergy imports. Given its geographic location, a comparative advantage may benatural gas imports from neighboring countries: a gas pipeline from the Gulfcountries may be worth exploring. Failing that, the use of alternate fuel

1J There is also a limited potential for commercially exploiting wind andsolar power; however, these sources are not expected to have a substantialimpact on the primary energy supply over the near to medium term.

2/ Egypt's exports of petroleum products were 4.8 MT consisting primarily ofbunker oil, naphtha and fuel oil, while the 1.3 MT of petroleum productsimported consisted primarily of gas oil and jet fuel.

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efficient technolories (such as cogeneration) and the relative value ofimporting coal for the production of electricity (which would have theadditional advantage of diversifying the primary energy source) should beconsidered. However, it is generally felt that a substantial increase innatural 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 indigenousenergy resources was that they were plentiful. Therefore, their use waspromoted domestically through pricing incentives and investments in downstreamproducts with a high energy input content. This policy has resulted in anindustrial base whose capital/energy/labor mix is distorted, imposingfinancial hardships on the economy. The increasing use of energy resources inthe domestic market has severely diminished export capacity by acceleratingthe depletion of the nonrenewable resource base. The high domesticconsumption of natural resources during the mid-1970s to mid-1980s, and thelack of success in finding sizable reserves, has led to projections that Egyptwill become a net importer of energy by the mid-1990s. The Government hasaddressed this problem by a systematic change in policies since 1986,including increases in energy prices and the substitution of high-valuedproducts with lower cost alternatives, including natural gas. Petroleumproduct prices were nearly tripled betwieen 1986 and 1989, and electricitvprices have been increased by about 30 percent three times in the same period.Unfortunately, much of the progress made in energy price adjustments has beeneroded 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 addressthe pricing issue. in 1989, the Government agreed to increase energy pricesto their economic levels by June 1995. In 1990, this agreement was enhancedby adopting annual targets of energy prices as a percentage of their economiclevels. Thus, the target of full economic pricing of energy products by 1995has been fortified by establishing front-loaded annual targets, which addressthe immediate macroeconomic problems facing the Government. The firLt step inachieving this goal was made in May 1990 with increases in weighted averagepetroleum product prices (44 percent) and in electricity prices (38 percent).The Government implemented the second step in May 1991 by increasing weightedaverage petroleum product prices by 52 percent (including bulk sales ofnatural gas, which were increased by 60 percent) and electricity prices by 50percent. The focus of petroleum product price increases was on the heavilysubsidized products with gas oil, diesel fuel and kerosene prices, all havingbeen doubled. LPG prices were increased by 67 to 83 percent, depending uponthe volume of consumption. Thus, the primary products for which natural gasis a substitute were increased by the greatest amount, considerably enhancingthe incentive to switch to natural gas use. These increases also allowed theGovernment to increase the price charged for low natural gas consumpcionlevels by 83 percent, without having an impact on the relative attractiveness

of gas use. This expected increase in interfuel substitution will decreasethe cost of energy supply, free more oil for exports and decrease theenvironmental impact of energy use. In addition, the Government confirmed afurther increase in petroleum product prices, which would take place no laterthan December 1991, to ensure that domestic petroleum product prices reach 56percent of world prices.

2.06 Povert3E Impagct Miniization. Although energy plays a secondary rolein the basket of commodities purchased by the poor, the proposed energy priceadjustment program has been designed to minimize its impact on the poor.Kerosene is the primary fuel used by the poor in Egypt (for cooking andlighting). Because of the country's relatively high level of electrification,electricity is also used - on a limited scale - by the poor (mostly forlighting). In other countries, LPG tends to be a transitional fuel for peopleliving in the urban areas. However because of its low price in Egypt, LPG isalso a fuel used by the urban poor for cooking. Therefore, energy priceadjustments have been designed to protect the poor from the impact of theprice adjustment program: (i) the unit price of LPG in small bottles typicallyused in households is slightly lower than for larger bottles; (ii) low levelsof 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, theGovernment has embarked on a program of decreasing the cost of domestic energyuse 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. Naturalgas from discoveries made by IOCs would be purchased by EGPC on the basis ofthe price of internationally traded fuel oil. This new gas clause has notonly been applied to new fields but also forms the basis for the increasinggas supplies from existing fields. Since 1986, natural gas sales haveincreased by an annual average of 14 percent, substituting for higher-valuedoil products such as gas oil and LPG.

2.08 Value Added Increase of Products. Economic efficiency is also beingaddressed by reviewing the potential for increasing the value added ofproducts displaced by natural gas. As natural gas is increasingly utilized asa primary energy source, it increases the availability of fuel oil for export.Unfortunately, the international prices for Egypt's fuel oil are relativelylow, reflecting its limited market and the availability of the product.Therefore, expanding the uarkets for natural gas, which would increase netbackvalue, is being considered. The primary goal is to increase supplies to urbanareas to displace the high-valued fuels used in the commercial and residentialsectors (primarily LPG and gas oil). In addition, upgrading the value of Zueloil through investments in existing refineries (see para. 3.17) is also underconsideration.

2.09 Private Sector Support. The oil and gas subsector in Egypt hasconsistently supported a substantial role for the private sector. Explorationand development have primarily been the responsibility of private IOCs withproduction-sharing contracts, while the development and operation of thedistribution systems have been in the custody of public sector companies.

However, the Government has recently allowed gasoline to be marketed byprivate sector companies. The role of the private sector in marketinggasoline increased dramatically when Caltex (Egypt) entered the market in 1987and Shell in 1990, joining the long-standing Esso Standard (N.E.) Inc.Furthermore, the Government is considering selling some of its existinggasoline marketing assets to the private sector. An additional boost to theprivate sector has also been initiated in the petrochemicals industry as theGovernment is currently entertaining a proposal for an ethylene/polyethyleneplant by the private sector. It is expected to form the basis for a privatelyowned petro-chemical industry in Egypt, which would further increase the valueadded of natural gas by using ethylene as a feedstock to plastics, PVC and/orpolyethylene.

III. NATURAL GAS SUBSECTOR

A. Institutional Setting

3.01 The Ministry of Petroleum and Mineral Resources functions as thecoordinator and policymaker for the oil and gas subsector and decides uponcapital investment programs jointly with the Ministry of Planning (MOP).Energy pricing issues are formalized at the ministry level for considerationby the cabinet. In addition, an autonomous planning department within theMinistry of Petroleum and Mineral Resources, the Organization for EnergyPlanning, provides technical and policy-oriented energy research.

3.02 The government-owned Egypt General Petroleum Company was created in1956 to oversee all matters relating to the petroleum industry. With thegeneral restructuring of the public sector in 1962, this authority wasconverted into the Egyptian General Petroleum Organization. With thepromulgation of Law 20 of 1976, the Egyptian General Petroleum Organizationwas converted into the Egyptian General Petroleum Corporation (EGPC), thebeneficiary of the proposed loan. The Ministry of Petroleum and MineralResources, which was created in 1973, acts as a link between EGPC and othergovernment bodies, while the primary responsibility for managing allexploration, production, and the refining of oil and gas rests with EGPC. Thedistribution and marketing of oil and gas is largely carried out by EGPC andits subsidiaries, but private companies are involved in the distribution andmarketing of gasoline and LPG. EGPC dominates the sector through its whollyor partly owned affiliates and the operating companies formed in partnershipwith foreign oil companies (see Annex I for details). Each of the majormarket functions - production, refining, transmission, distribution, andancillary services - are represented by different organizations (outlined inAnnex II). EGPC, as the holding company, acts as the operational andfinancial coordinator implicitly setting transfer prices between subsidiaries.While the organizations have some financial autonomy, they are generallydependent on EGPC.

3.03 Natural gas activities are dominated by six organizations: EGPCthrough its Natural Gas Department; three joint operating companies --WEPCO,

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PETROBEL, and GUPCO; and two wholly owned EGPC subsidiaries-- PetroleumPipeline Corp (PPC) and PETROGAS. PPC constructs and operates the gastransmission network, and PETROGAS is responsible for all gas distribution andmost of the LPG distribution. Other EGPC affiliates perform ancillaryservices, such as Egypt Gas, which carries out distribution networkconstruction. Although EGPC may, in principle, be in charge of developing along-term gas plan, in practice there is little long-term planning, andplanning coordination with major consumers (especially the EgyptianElectricity Authority) seems to be limited.

B. Gas Reserves

3.04 Egypt has substantial gas reserves; a large proportion of which haveeither already been developed or are currently under development.Authoritative sources put reserves at around 12 tcf as of end-1989, with some8.5 tcf of this nonassociated gas. By comparison, reserves at end-FY80 werearound 3.0 tcf. Reserves in producing fields at end-FY90 were 6.4 tcf, andreserves under development were some 2.5 tcf. Most of the balance of 3.1 tcfof 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 thatcannot be used at present due to processing and pipeline constraints.

3.05 Egypt's undiscovered gas resources are generally held to besubstantial, and the country is now viewed by many IOCs as having moreundiscovered 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 85percent of fuel oil, was, thus, essencial in encouraging continuedexploration. Several new concession agreements in areas with potential gasreserves have been signed, but drilling in recent years has not identified anynew giant gas structures; much more investment will be required to assess thepotential of relatively underexplored areas.

C. Historr of Gas SUoIXv and ConsumRtion

3.06 Egypt's gas production comes from four main regions: the Eastern NileDelta (Abu Madi field), the Western Nile Delta (Abu Qir field), the WesternDesert (Abu el Gharadig field) and the Gulf of Suez (the Ras ShukeirProcessing Plant). Production grew from 230 mmcfd in FY81 to 730 mmcfd inFY90. Egypt's gas production has generally been very low cost, due to thegood qualities and favorable location of onshore fields and the low marginalcost of associated gas utilization.

3.07 The development of gas usage has involved the construction of anational pipeline network of 2,000 km. The core of the network, known as theNational Grid, connects Alexandria with Cairo, Suez and Port Said and hasachieved a high degree of flexibility. The system should be able to cope withanticipated production increases in the next few years with only modest

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upgrading. However, pipelines from peripheral supply areas to the nationalgrid, particularly from the Western Desert and the Gulf of Suez, have limitedpotential to cope with additional deliveries.

3.08 Natural gas plays an increasing role in supplying the energy ofGreater Cairo, in which about one fourth of the country's 55 million peoplereside. The city is located in the central junction of the national gastransmission network, which by the end of FY90 had a total capacity of about12 billion cubic meters per annum. The gas from Abu Madi and Abu Qir in thenorthern part of the country flows through a 20-inch pipeline and enters a 24-inch, high pressure (31 bars) distribution feeder main. This main stretchesin 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 new16-inch pipeline from the Gulf of Suez; towards the south of Cairo it connectsto the 24-inch pipeline from the Abu Gharadig field, about 270 km west ofCairo. This pipeline also crosses the Nile in the south of Cairo, and athird, recently completed, crossing supplies gas from the network in thewestern part of the city to customers on Zamalik Island. The Cairo gasdistribution feeder main supplies gas to several areas of the city and a fewpower plants along its 90-km route. The first Bank-funded Cairo GasDistribution Project, which included the construction of a major part of theabove main and the supply of gas to 160,000 consumers, has now expanded to alarger network supplying about 326,000 residential consumers, 4 power plantsand a limited number of commercial users on both sides of the Nile. Gas isbeing supplied to Cairo under an existing open-ended contract between EGPC andPetrogas.

3.09 Substantial gas reserves in the far northwestern desert (Khalda andnearby fields) are not connected to the national grid. This gas is beingpartially developed for local power consumption until sufficient reserves canbe proved to justify a longer pipeline to Alexandria. The only major centersof energy consumption not linked to the gas grid are the Assiut and UpperEgypt regions. However, the growth of heavy industry and fuel-oil-fired powergeneration in the Assiut region may justify connection to the gas grid infuture, 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 ofdemand, with fertilizers accounting for 16 percent. Most heavy industry hasbeen converted to gas, or to dual oil/gas firing. The penetration of theresidential market has been modest, with g"s consumption through the firstGreater Cairo Gas Distribution scheme accounting for only 1 percent of thetotal gas supply ir FY90.

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D. Gas Supoly - Future

3.11 Total gas production in Egypt is expected to increase from 730 mmcfdin 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 developmentbeyond FY94. Substantial discoveries, which may provide developments in thelonger term, arc located offshore of the eastern Nile Delta and in thesouthern Gulf of Suez/Red Sea area. The likely development cost of thesefields is somewhat higher than that of previous fields, due to their locationin deeper water and their distance from the National Grid.

3.12 A further option to increase supply is to improve the utilization ofGulf of Suez gas. The Trans Gulf Gas component (see para. 5.06) could resultin an additional delivery of around 70 mmcfd of gas from FY94. Substantialadditional associated gas may also be available elsewhere in the Gulf of Suez,if facilities are optimized. However, a full assessment of this potentialwould require a detailed survey of Gulf of Suez gas resources.

3.13 Current potential economic usage of gas in Egypt greatly exceeds gassupply capacity, and this situation is likely to prevail during the nextdecade, as the gas balance in Annex III indicates. Excess demand arises inall major consuming sectors. In power, gas burning capacity is expected torise by 40 percent to 10,000 MW by FY94 through the conversion of steam plantsco dual firing and the construction of new, combined-cycle plants; thepotential gas usage of this capacity represents 80 percent of expected FY94gas production, thus indicating that continued substantial fuel oil usage inthe power subsector is likely. In the fertilizer subsector, the plannedexpansion at Abu Qir and Suez will increase requirements by 50 mmcfd by 1995,with longer-term potential requirements arising from the need to replace theuneconomic Kima Fertilizer Plant and the need to meet further consumptiongrowth. In the cement sector, which currently accounts for 7 percent ofconsumption, gas usage potential is forecast to increase as plants at Kattamiaand Ameriya are converted to dual firing in the next two years. Long-termgrowth in cement demand (at least 4 percent p.a.) will generate substantialadditional fuel requirements, to be met either by gas or by fuel oil. Inother industries, energy usage is currently dominated by oil, and theconversion of even half of this capacity to gas would generate an additionaldemand of at least 250 mmcfd in FY95. Finally, the residential and commercialsector provides a major potential market for gas, given Egypt's largeurbanized population and sizeable service industry base.

3.14 Based upon the anticipated supplies and the potential consumptionnoted above, in the absence of major new gas discoveries, gas consumption inEgypt will remain supply-constrained in the 1990s. Potential consumption islikely to exceed supply by around 400 mcfd in FY95, while by FY2000, thedeficit will reach 600-700 mmcfd if only currently identified reserves aredeveloped. It is possible that substantial discoveries of gas in the 1990swill lead to a transient surplus of gas in Egypt. However, it should be notedthat to satisfy potential demand and to replace existing production, 21 tcf of

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new discoveries will be required by 2005, compared with the 12 tef generatedin over 25 years of exploration to date.

E. DeveloQment Plan

3.15 The medium-term development plan for GOE calls for public sectorinitiatives to support private sector investments. Gas exploration anddevelopment is almost exclusively the domain of the private sector, withproduction-sharing agreements between EGPC and IOCs. The pipelines that formthe National Grid and the distribution network are in the relatively earlystages of development, with most of these assets having been establishedduring the 1980s. GOE has put a high priority on completing the first phaseof the Cairo Gas Distribution component (supported by Credit No. 1024-EGT),which would supply about 640,000 customers and aim at displaci.ag higher valuedfuels; it would also decrease the air pollution problem in Cairo and decreasethe transportation load associated with the delivery of petroleum products.Over the medium term, GOE intends to extend the gas distribution grid in Cairoand to install a similar network in Alexandria.

3.16 EGPC estimates that an investment program amounting to about US$800million per year over the next five years is required to meet the needs ofsector development, which will be largely financed from internal cashgeneration. However, a detailed analysis of EGPC expenditures has not beenmade 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 abetter definition of EGPC capital requirements will be available to theGovernment. Extensive capital investments in pipelines, refinery upgradingand the distribution of natural gas all look to be economically attractive.Commitments to implement the envisioned investments (such as a gas pipelineand related gas processing facilities for Gulf of Suez associated gas) couldalso debottleneck some of the potential investments by IOCs.

3.17 Due to the mismatch between the production profile from domesticrefineries and the country's consumption profile, Egypt continues to exportlow-value naphtha and fuel oil (after meeting the domestic demand of about 20MT of refined products) and to import high-value aviation kerosene and gasoil. After practically exhausting the option of replacing gas oil used forpower generation with natural gas during the late 1980s, future increases ingas supply will displace fuel oil use (primarily for power generation),thereby further exacerbating the imbalance between total demand and thesupplies from domestic refineries. The seven domestic refineries are oftopping or hydroskimming configuration with very little secondary processingcapacity for upgrading fuel oil into distillate products. The refineries alsolack adequate octane enhancement facilities, resulting in the surplus ofnaphtha for export. Investment plans for the immediate future includedoubling the current capacities at the El Nasr and Assuit refineries, whichare both of the hydroskimming type. Hydroprocessing investments are beingconsidered for one of the locations. While this change in focus ispreferable, it is expected to be insufficient to address the growing, country-

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wide product imbalances. In order that these may be addressed, EGPC wouldundertake a Refinery Subsector Investment Planning Study (terms of referenceare included in Annex VIII). This study would evaluate secondary conversioninvestment candidates over the next 10 years in order to: (i) reduce to aminimum the costs of product supply to the domestic market through acombination of imports, domestic refining and exports; (ii) reduce pollutionby improving product quality; and (iii) improve the value added of productexports. The study would be completed by December 31, 1993.

3.18 About 90 percent of Egypt's oil production is from Gulf of Suezfields, 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 fieldscontinue to mature, the gas/oil ratio will increase, and more natural gas willbecome available. The infrastructure in the Gulf of Suez area (the RasShokeir gas treatment facilities and the Ras Shokeir-Suez pipeline) is alreadyrunning at full capacity, thus creating problems for incremental production.Developing the gas reserves in this area is complex, both technically andinstitutionally. Many fields and multiple operators are active in thisregion. Each field and operator have unique technical approaches to oil andgas recovery. Hence, the logistics of mounting a cohesive development planare formidable. As a result, EGPC would undertake a study, with theassistance of consultants, to evaluate the problems and opportunities forincreased gas delivery from this region on the basis of the terms of referenceagreed to in Annex IX. It is anticipated that gas supply from this area couldincrease by 250-400 mmcfd, or as much as 55 percent of average FY90 productionrates. As the study would focus on the reduction of natural gas flaring(global warming concern) and may not be entirely economically viable, GlobalEnvironmental Fund resources would be used to finance part of the cost of thestudy while the balance would be financed from ESMAP resources. The proposedstudy would be completed by December 31, 1993.

F. Gas Pricing

3.19 As outlined above, natural gas is expected to be supply-constrainedfor the medium and possibly long term, largely due to the substantialpotential demand from dual-fired (fuel oil and natural gas) power plants andheavy industry. Thus, any marginal change in natural gas availability willimpact fuel oil consumption. Therefore, the Government has established thatthe marginal value of natural gas at the power plant fence (or city gate) atthe equivalent of international fuel oil for the purpose of pricing bulknatural gas supply.

3.20 Until May 1991, about 95 percent of current natural gas consumptionis 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 hasbeen $70/tonne, the gas price for fuel oil equivalency at an exchange rate of2.83 LE/$ is 17 piastres/cu.m.

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The primary recipients of this subsidy are the power and industrial sectors.Within the context of the Government's revised energy pricing policy ofincreasing the weighted average of petroleum product prices (including bulknatural gas sales), the price of bulk sales of natural gas were increased May3, 1991 by 61 percent to 7.5 piastres/cu.m. Furthermore, the Governmentproposes to link domestic natural gas price increases to domestic fuel oilprice adjustments to bring bulk sa'les of natural gas to the equivalent ofinternationally 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 5.522.5 - 37.5 14.537.5 - 52.5 18.0above 52.5 30.0

For levels of consumption typical of commercial customers (about 400cu.m./mo.), natural gas costs about 30 piastres/cu.m., exceeding internationalfuel oil equivalent prices and thus contributing to the recovery ofdistribution costs. Fuel oil, gas oil and LPG are tf.e primary targets forinterfuel substitution by natural gas for commercial users. In the case ofsmall industrial consumers currently using either fuel oil or gas oil andcommercial consumers using LPG, there has been a substantial disincentive toswitch to natural gas because of the low prices of these substitute fuels.Therefore, the Government proposes to increase the price of the heavilysubsidized petroleum products (LPG, fuel oil and gas oil) so as to enhance therelative attractiveness of natural gas compared with its substitutes. Thiswill be accomplished by increasing the prices of these products by an amountthat exceeds the weighted average petroleum product increase, thus decreasingthe level of cross-subsidies. The May 3, 1991 energy price increases fullyconformad to these principles.

3.22 Prior to May 1991, the residential consumption of natural gas waspriced such that the average cost to the consumer was about 10piastres/cu.m.', the result of no price adjustments since 1981; thus, naturalgas was attractive relative to LPG at modest levels of consumption. However,the price of natural gas to residential consumers is well below its economiccost. Adjusting LPG prices to reflect their international equivalent willallow the structure of natural gas prices to domestic/commercial customers tobe 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 maintenancecharge of 25 piastres/month. An additional cost of natural gas supply is ameter 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 oneLE/mo.

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to be studied to determine an appropriate strategy for its adjustment,selected increases over the immediate term are warranted. The Government hasbegun by increasing lower levels of gas consumption (O to 30 cu.m./month) by83 percent, to 10 piastres/cu.m. Consumption levels from 30 to 60 cu.m./monthhave been increased to 20 piastres/cu.m., while consumption above 60cu.m./month is priced at 30 piatres/cu.m. In order that a strategy forfurther adjustments to the level and structure of natural gas pricing can beestablished, the Government will work closely with ESMAP on a Cost of GasDistribution Study focussing on commercial and residential consumption (draftTOR detailed in Annex X). This study would address the reform of the presenttariff structure for natural gas distribution in Cairo, which has remainedunchanged for ten years and bears no relation to current costs. It wouldexamine the appropriate level and structure of tariffs to different classes ofcustomers in Cairo, in light of the costs of distribution, of Petrogas'finances and of the cost of alternative fuels. The study would recommend thebest means of constructing incentives for gas use, especially by commercialcustomers. The nature of Petrogas' gas sales contracts, particularly withlarger commercial customers, would also be addressed. The study would assessthe legal framework for these contracts and for Petrogas' operation andformulate 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 Gulfof Suez Project (Credit 1732-EGT) approved in 1979 for the recovery of flaredassociated gas and natural gas liquids. This project addressed criticalsector issues such as pricing, the exploration of new areas and the optimumutilization of natural gas. The Cairo Gas Distribution Project approved in1980 (Credit 1024-EGT) successfully assisted in establishing the first gasdistribution system in Egypt, supplying gas to the premium market ofresidential and commercial consumers to replace high- ralued fuels such as LPGand gas oil. Two other Bank-funded projects, Western Desert Gas Exploration(Credit 1928-EGT) and Abu Qir Gas Development (Credit 2103-EGT), weresubsequently approved in 1981 and 1982. The objectives of both projects, todevelop additional natural gas supplies and to undertake studies aimed atdeveloping an appropriate gas development strategy, were fully achieved. Inaddition, the Bank has contributed to the transfer of modern technology inoffshore operations, reserves management, process design and operations. Thephysical implementation of all Bank projects in the subsector has beensatisfactory, with EGPC demonstrating a noteworthy capability for efficiencyin this area. In addition to gas subsector loans, the Bank has approved sixloans in the power subsector, the last of which (Loan No. 3103-EGT: FourthPower Project) included agreements for both electricity and petroleum productprices (see para. 2.05).

3.24 On the policy front, the results have been mixed. The prices ofenergy in general, and petroleum products in particular, have beenunacceptably low, averaging less than 30 percent of their internationalequivalents. This issue resulted in the Bank's reluctance to finance projectsin this subsector during most of the 1980s. The recent resolution of this

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issue, with a monitorable action plan of substantial, front-loaded priceincreases by the Government, has permitted the resumption of lending to thesubsector.

3.25 Project Performance and Audit Reports (PPAhs) cite the followinglessons learned: (i) the resolution of sector issues must be sought throughprojects; (ii) the packaging of works must be done so that contractualresponsibilities are properly secured with a view to avoiding time slippages;(iii) the project scope must be sufficiently comprehensive to ensure that theenvisioned benefits can be achieved; and (iv) an appropriate incentive systemmust be in place for the benefits to accrue. The proposed project has takenthese lessons into account in project design.

3.26 The Bank's presence in this sector is designed to help the Governmentachieve a number of objectives: (i) to assist the development of a soundinvestment strategy in the sector; (ii) to design an energy pricing systemthat provides incentives to minimize the cost of energy supply and addressesEgypt's twin problem of current account and budget deficits; (iii) to developinfrastructure and policies that support private sector involvement in thesector; (iv) to address the accelerated adjustment of the prices of heavilysubsidized 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 leveland structure of energy prices to address the problem of budget support and toestablish incentives for the consumer to use the least-cost fuel as well as toconserve energy. The development of infrastructure to debottleneck thetransport of gas to market is designed to enhance private sector participationin exploration and development by ensuring a market for output. The resultantincrease in gas supply also decreases the use of higher cost fuels andmitigates 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 generalpolicy for converting and granting concessions (for oil and gas exploration)and to negotiate and prepare concession agreements for the approval of theGovernment; (ii) supervise the exploration and exploitation activities of theoil companies engaged in the search for oil and the productior. of oil and/ornatural gas; (iii) plan, coordinate and control the activities of variousaffiliates in the production, refining, transportation and distribution ofpetroleum products; (iv) undertake the export of crude oil and petroleumproducts and effect similar imports in order to balance domestic requirements;(v) determine, in conjunction with other competent authorities, the pricing of

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petroleum products;' and (vi) manage the operation and management of allsubsidiary companies.

B. Cauital Structure

4.02 EGPC capital (300 million Egyptian pounds) is invested in the capitalof its subsidiaries and in joint companies established for oil production withforeign partners. Funds available to EGPC for its operation consist of ashare in the profits of subsidiaries in the petroleum sector, a share in thenet profit of the joint companies and profits arising out of supervision andadministrative fees. In addition, EGPC secures funds from the Government inthe form of loans. EGPC, as a distinct corporate entity, can, and has,borrowed from external financial agencies. Total EGPC capital and reservesnow approach LE 5,000 million.

C. Or2anization and Management

4.03 EGPC is managed by an executive chairman assisted by eleven deputychairmen in charge of exploration, production, planning and projects, naturalgas. operations, foreign and joint venture companies, financial and economicaffairs, internal trade, foreign trade, administration and legal affairs andpetroleum agreements. The chairman functions as the chairman of the board andthe deputy chairmen as ex-officio members. Five chairmen from the affiliatedcompanies, one of whom is from PETROGAS, are also nominated to the board(Annex II).

4.04 EGPC has been vested with considerable autonomy. Within theframework of general policies set by the Supreme Petroleum Council andstipulated in the company's statutes, its board is competent to issue anydecree it deems suitable, any governmental regulation to the contrarynotwithstanding. It is, therefore, competent to establish its own internalregulations for financial, administrative and technical management and also todictate its own norms regarding conditions of employment, remuneration, etc.EGPC is, however, obliged to consider policy directives issued by andotherwise function under the guidance of the Supreme Petroleum Council, whichis presided over by the Minister of Petroleum and for which EGPC functions Asa secretariat. Furthermore, all resolutions of the board have to be approvedby the Minister of Petroleum.

4.05 At the senior level, EGPC management is competent and experienced invarious aspects of the oil and gas industry. It has, over the last twodecades, 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, anadvisory role.

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and rehabilitated a number of refineries, and laid an extensive network ofcrude oil, petroleum products and gas pipelines. It has created within itsorganization a specialized group which has successfully negotiated production-sharing agreements with foreign oil companies. Separately, EGPC has developednonassociated gas fields within Egypt and linked them to the market. Whileforeign partners are largely responsible for the production of oil, EGPCclosely monitors their exploration and development programs.

D. Functional Structure

4.06 EGPC functions as a holding company and performs the variousfinctions with which it is charged through 18 fully and partly ownedsubsidiaries and through 20 joint-operating companies formed in partnershipwith the foreign oil companies. These companies have been set up on afunctional basis and relate to the following sectors.

4.07 Exploration and Productio . All work relating to geophysical surveysand exploration are carried out by the General Petroleum Company (GPC), afully owned subsidiary of EGPC; joint venture companies, such as WEPCO andSUCO; and IOCs. These IOCs, under the terms of their agreements, are obligedto spend a fixed amount on exploration and surveys during the primaryexploration period. The annual work program of each of these companies isdrawn up under its concession agreement, which is reviewed and approved by ajoint 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 inaccordance with the terms of the concession agreement, is formed. EGPC comesin as an equal partner at the development stage.

4.08 Refining and Processing. All refining and processing of petroleumproducts is undertaken by seven fully owned subsidiaries of EGPC, namely, theEl Nasr Petroleum Company, the Alexandria Petroleum Company, the Suez OilProcessing Company, the Alameria Oil Refining Company, the Cairo Oil RefiningCompany, the Assiut Oil Refining Company and the Egypt Petrochemical Company.

4.09 Petroleum Pipeline. Egypt's extensive ,ietwork of pipelines fortransporting crude oil, petroleum products and gas is owned and operated bythe Petroleum Pipelines Company (PPC), a fully owned subsidiary of EGPC.

4.10 Distribution. The marketing and distribution of petroleum productsis undertaken by two subsidiaries, namely the Misr Petroleum Company and theCooperative Petroleum Company. These companies control the major share of themarket, though the marketing of petroleum products is also being undertaken bythree foreign companies. Natural gas and LPG are distributed by the PetroleumGases Company (PETROGAS), another subsidiary formed in 1978. Small privatefirms 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

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Presidential Decree in 1966. This accounting system was evolved, inter alia,with a view to establishing a uniform denomination of accounts and accountingrules, definitions and terminology. Similar and compatible financialstatements for capital operations, current operations and cash flows for allpublic sectors undertakings have been stipulated by the system. EGPC isrequired to prepare detailed accounts and financial statements for periodicreview in addition to following a stipulated financial policy. EGPCundertakes detailed internal auditing through its Department of InternalControl and the Department for Financial Evaluation. While the former auditsall financial operations within EGPC, the latter is responsible for checkingand evaluating financial systems and procedures, not only of ECPC but also ofall affiliated companies. This latter department is responsible for assessingand evaluating the efficiencies of various units operated by EGPC and itsaffiliates and for evolving improved systems and procedures.

4.12 Insurance. EGPC subsidiaries carry adequate comprehensiveinsurance on major facilities and equipment against fire, explosions, damageand theft. Insurance agreements are entered into directly by each companywith insurance companies within Egypt, which are, in part, reinsured byforeign insurance companies.

E. Petroleum Gas Company (PETROGAS)

4.13 BackSround. Petroleum Gas Company (PETROGAS) is a wholly ownedsubsidiary of EGPC. It was incorporated in September 1978 and assumed allfunctions relating to processing, distributing and marketing LPG, as well asto promoting and distributing natural gas. Accordingly, Petrogas stores,fills, transports and markets about 850,000 tons of LPG per year; enters intoselling arrangements and collects sale proceeds for about 7.8 million cu.m. ofnatural gas distributed per year through the Petroleum Pipeline Company'sgrid; and constructs and maintains the Greater Cairo City gas distributionsystem. The component of the project described as the "Greater Cairo GasDistribution Component" would be entrusted by EGPC to Petrogas forimplementation, 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 ofJune 30, 1990, was LE 156 million. The long-term debt of the company at theend of FY90 was US$33.3 million in foreign debt (IDA credit, on-lent toPetrogas at a commercial interest rate) and LE 4 million in local debt.

4.15 Organization. Petrogas has an executive chairman, who is also thechairman of the board. The board has eight other members, four appointed bythe prime minister and four elected by the labor syndicate. EGPC is notrepresented on the board, but the chairman of Petrogas is a member of the EGPCboard. This arrangement provides a close link between Petrogas and EGPC andenables the EGPC board to keep itself apprised of Petrogas activities.Furthermore, EGPC reviews the company's performance twice a year in thegeneral body meeting. The general body also approves the company's operatingand capital budgets. Petrogas, in practice, functions on a "commission"

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basis, as do the other fully held subsidiaries of EGPC. The general bodymeetings, therefore, assume a tremendous importance since at these meetingsPetrogas's projected and past costs are scrutinized and purchase pricespayable by Petrogas are determined, so as to allow due margins.

4.16 Petrogas has developed into an efficient gas utility company, capableof expanding the city gas distribution network with its own personnel, albeitwith gradually diminishing technical assistance from its foreign technicalcollaborators (British Gas and William Press, who provided technical supportto the IDA-financed Cairo Gas Distribution Project). Petrogas has recentlydeveloped in-house computer systems for its accounts, inventory and othermanagement information. Developwents are ongoing, with plans to use localconsultants for further systems development, including a linkup witt. the EGPCcomputers. Computerization of commercial services is also underway with eighton-line customer support terminals ready to be installed once the new buildingis commissioned.

4.17 Insurance. Petrogas covers all of its major facilities and equipmentagainst fire, explosions, damage and theft through comprehensive insuranceschemes. It has entered into specific insurance agreements for its naturalgas operations, including third-party liability. The insurers, who are publicsector insurance companies, have, in turn, reinsured outside the country.

4.18 Pr-oject Enmineering and ImRlementation. The Natural Gas Departmentof Petrogas (see Annex IV) is responsible for gas distribution operations, aswell as for project planning and development, including market surveys,conceptual design, and project management and supervision. Egypt Gas, withassistance from its foreign partner, undertakes detailed design andprocurement services as well as the construction of networks, the installationof consumer piping and the conversion of appliances. Under the ongoingarrangement between Petrogas and Egypt Gas, the Cairo gas distribution systemhas 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 anontradeable commodity, natural gas; to release tradeable petroleum productsfor expoLt; and to decrease the environmental impact of fuel use. The projectwould not only focus on increasing the supply of natural gas by reducingflaring and debottlenecking the supply constraints of transporting gas tomarket, but also would provide the infrastructure required to maximize thevalue added of the fuels being substituted. It would enable the delivery of aclean burning fuel to the Greater Cairo area to displace petroleum products,thus mitigating air pollution problems. The institution building efforts forPetrogas initiated in the previous Bank loan would be further enhanced toincrease its commercialization. The project scope consists of: (i) theGreater Cairo gas distribution component designed to increase the gas delivery

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capacity of the existing gas distribution network in the Greater Cairo area;(ii) the Trans Gulf gas component designed to increase natural gas supply fromthe Gulf of Suez area to the national grid; and (iii) the training componentwhich 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 lendingfor gas investment projects because of the positive impact freeing oil forexport has on the balance of payments. Energy pricing has been a cornerstoneof the Bank's dialogue with the Government, in view of its importance forenergy conservation, budget support and the current account balance. In 1989the Government agreed to increase petroleum product prices to the equivalentof internationally traded products and to increase electricity prices to LRMCby June 1995. The first steps toward achieving this goal were implemented in1989 by increasing weighted average petroleum product prices by 16 percent andelectricity prices by 30 percent. In March 1990, the energy price adjustmentagreement with the Government was upgraded to include annual targets forweighted average petroleum product prices (starting at 45 percent in Hay 1990and increasing at least 11 percentage points each year thereafter to reach 100percent by June 1995) and electricity prices (starting at 47 percent of LRMCin May 1990 and increasing by 10-12 percentage points of LRMC each yearthereafter to reach 100 percent of LRMC by June 1995). This program of energyprice adjustments will not ornly enhance the financial health of the sector butwill also have a stAstantial impact on the budget deficit. Transfers from theenergy sector to Ow- budget in both FY91 and FY92 are expected to increase byabout LE 2 billior (about 2 percent of GDP) in both years. Similar increasesin transfers to the budget are projected for the following year. In May 1990,the Government fulfllled the first target by increasing weighted averagepetroleum 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 increasesby increasing weighted average petroleum product prices by 52 percent andelectricity prices by 50 percent. The Government also addressed the problemof the structure of entvgy prices in addition to the level of subsidies to thesector by targeting pvcdLcts with the highest level of subsidy. Thus, theBank has already been .ffective in persuading the Government to move faster insetting price incentives that improve the attractiveness of using least costfuels. The rationale for Bank involvement in this project centers onsupporting the Government's energy price reform program, and acting as acatalyst to attract co-financing for investments in the gas subsector whichcomplement private sector initiatives and mitigate environmental problems.

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C. Pro let Descripton

5.03 The project would consist of the following components:

(a) the extension of the existing gas distribution network in theGreater Cairo area to new premium markets, including an estimatedadditional 235,000 households; 5,000 commercial and 22 industrialcustomers; and related training;

(b) the delivery of an additional 70 mmcfd of natural gas from theGulf 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 providegas to an estimated additional 235,000 households, 5,000 commercial and 22industrial consumers in several areas both in the east and west of Cairo. Asshown in Annex V, distribution would include 35,000 residential infill and3,000 commercial infill consumers to be connected in existing areas and thebalance in the new areas. These areas have been selected on the basis of amarket survey carried out jointly by Petrogas and their consultants.

5.05 The project would consist of integrated components, including theconstruction of about 30 km of large diameter steel mains and about 900 km ofmedium and low pressure polyethylene piping; two pressure reducing stations;about 55 regulating stations and related service connections; and metering andcarcassing and burner conversion equipment to supply natural gas to theconsumers. The project focusses on supplying gas to areas with a highconcentration of large commercial consumers, such as Garden City and Pyramids,as well as on supplying gas to industries located ir13ide Greater Cairo inorder to maximize the favorable environmental impact and the return on capitalemployed. The project includes the formulation of a gas market developmentstrategy to identify and propose necessary measures for developing modernoperational facilities such as a supervisory control and data acquisitionsystem (SCADA), meter-proving facilities, training centers, computerizedemergency and customer services, cost accounting and inventory control.Furthermore, training programs for technical staff on specialized fields suchas safety, gas sales engineering, cathodic protection, market analysis,distribution network analysis and design, measurement and conversion would beprovided for. Petrogas has agreed to assign a training officer prior to theselection of consultants so that follow-up on the training program could beassured; 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/dof natural gas (about 10 percent of FY90 average production rates) from theOctober fields in the Gulf of Suez and the Belayim fields in the Sina, areaand transmit it to the grid for downstream use. Gas is currently being flaredbecause of insufficient compressor capacity and pipeline linkages. The

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proposed project would include the addition of a new compressor station at theBelayim fields and a pipeline from the Sinai area to the October field, wherea new offshore template would be conq;tructed. This platform would beconnected to an exis ing October platform, where added compressors wouldaccommodate the additional flow of gas from these fields through an existingpitDaline to the west bank of the Gulf of Suez. Additional processingtacilities at the Ras Bakr Gas Processing Plant would treat and compress theincreased gas supply for sale in the national grid. The capacity of theexisting Ras Shokeir pipeline would be increased to accommodate the increasedgas supply as the existing pipeline is operating at full capac'ty. EGPC wouldconstruct this facility simultaneously with the proposed Trans Gulf GasComponent. Technical details regarding this Component are included in AnnexVI.

D. Cost Estimates

5.07 The total project cost is estimated to be US$285.5 million of which59 percent, amounting to US$169 million, would be in foreign exchange. Asummary of cost estimates for the principal components of the project is shownbelow and detailed estimates for the Cairo Gas Distribution and Trans Gulfcomponents are given in Annexes V and VI, respectively. The base cost is inDecember 1990 prices and was calculated using recent procurement material andmarket prices. These estimates are considered to be reasonable for this typeof project. Physical contingencies for the GCGDC are 6.5 percent formaterials and 6.5 percent for engineering and construction services because ofthe relative uncertainty of the latter. The physical contingencies for theTrans Gulf Gas component are estimated at 6.5 percent based on the informationprepared to date. The price contingencies are based on inflation of foreigncosts of 3.4 percent per annum and the following local cost inflationestimates:

FY91 FY92 FY93 FY94 FY95 FY96 FY9720% 28% 15% 9% 6% 5% 5%

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1st10t2d Costs

(US$ Nittion)

Foreign8 X of

1LnGAi forefn Total Locjt Forefan Total Totat

----(millions of LE) ---- ---(millions of US$)---

Greter Cairo Gas Distribution CotponentNaterials 37.9 191.9 229.8 13.4 67.8 81.2 83.5Construction 191.9 6S.9 257.8 67.8 23.3 91.1 25.6Tehnical 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 CoWqonentEquipmsnt and Materials 13.3 90.0 103.3 4.7 31.8 36.5 87.1Construction 5.1 15.0 20.1 1.8 5.3 7.1 74.6Technical 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 48.7Price 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 59.2an=35 3=53 3=== === == =-Y

E. Financing Plan

5.08 The proposed Bank loan of US$84 million would finance 49 percent ofthe foreign exchange requirements of the project. The proposed loan would bemade to EGPC, guaranteed by the Government. The loan would finance materialsrequired for the GCGDC and gas compressors, gas treatment facilities and anoffshore template for the Trans Gulf Gas component. EGPC would on-lend US$48million of the US$84 million to Petrogas for the GCGDC through a subsidiaryloan agreement. The loan to Petrogas would carry the same terms as the Bankloan to EGPC. Petrogas would bear the full foreign exchange and interest raterisks on the portion of the loan allocated to finance the GCGDC. The EuropeanInvestment Bank would co-finance 25 million ECUs (about US$33 million) of theGCGDC on a parallel financing basis. Conclusion of the EIB Loan Agreementwith EGPC would be a condition of loan effectiveness. The remainder of theproject would be financed by EGPC and Petrogas.

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Project Financing Plan(US$ Million)

Local Foreign Total % of Total

EGPC 60.5 52.0 112.5 39.4Petrogas 56.0 0.0 56.0 19.6IBRD 0.0 84.0 84.0 29.4EIB 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 beprocured in accordance with the Bank's guidelines for the procurement ofgoods. All major packages of materials would be procured following theInternational Competitive Bidding (ICB) procedures. Local manufacturerscompeting under ICB would be eligible for a 15 percent preference margin orthe import duty applicable to nonexempt importers, whichever is lower. Allbidding packages for materials estimated to cost US$2 million equivalent ormore and all packages (instrumentation and control equipment for compressorsand gas treatment equipment) to be procured through Limited InternationalBidding (LIB) would be subject to the Bank's prior review of procurementdocuments; this would represent more than 70 percent of the loan amount. Inaddition, the first two packages, regardless of value, would be subject to theBank's prior review. Procurement arrangements for the Trans Gulf GasComponent would include longer lead time equipment such as compressor station,dehydration and refrigeration equipment and the platform template equipmentand materials. All major packages of material, equipment and services for theTrans Gulf Gas Component would be procured follouing ICB procedures except forthe following: (a) contracts for equipment and inspection and similarservices needed for offshore operations, and which do not exceed or aggregateof US$8.0 million, may be awarded in accordance with the Bank's procurementguidelines for LIB; and (b) contracts for the equipment and materials for theplatform template that are proprietary, or contracts to ensure standardizationand compatibility with the existing equipment and facilities, which do notexceed an aggregate value of US$4.0 million, may be procured by directcontracting under the terms and conditions acceptable to the Bank. Details ofprocurement arrangements are included in Annexes V and VI for the GCGDC andTrans 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 ofconsultants would conform to the Bank's Guidelines for the Use of Consultantsby World Bank Borrowers in Bank-financed projects.

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Procurement Table(US$ million)

Procurement MethodICB LZ LIB Other jj Total Cost

Greater-Cairo Gas DistributionCo9monent

Steel pipes, P.E. pipes and 24.6 24.6fittings

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 0.4Compressors andassociated 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 8.9services

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.

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G. Disbursement

5.10 The Bank loan would be disbursed for the items indicated in theprocurement section (para. 5.09). The proceeds of the loan would be disbursedover a period of six years (FY92-FY97) on the following basis:

(a) 100% of the foreign exchange component of the materials for theGCGDC 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 andauxiliary equipment, gas treatment equipment and platform templatefor the Trans Gulf Gas component.

A detailed schedule of disbursement for the GCGDC is in Annex V, and theschedule for the Trans Gulf Gas component is in Annex VI. The proposedschedule for the Trans Gulf Gas component is shorter than average for energyprojects in Egypt. However, it is considered feasible given the high priorityEGPC has assigned to this component and EGPC success in implementing similarprojects in the past. The summary of expected disbursements is indicatedbelow.

USS Million£92~ FY93 FY94 FY95 FY96 FY97

Greater Cairo Gas Distribution-omponent

Incremental 1.2 10.8 10.7 10.8 11.3 3.3Cumulative 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 0.0Cumulative 6.5 31.2 35.4 35.9 35.9 35.9

Total Incremental 7.7 35.5 15.3 10.8 11.3 3.4Cumulative 7.7 43.2 58.5 69.3 80.6 84.0Percentage 9% 51% 70% 83% 96% 100%

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5.11 Retroactive Financing and Advance Contracting. Retroactive financingof up to US$5 million would be allowed to cover expenditures incurred for theTrans Gulf Gas Project to facilitate the accelerated timetable proposed byEGPC. Disbursements would only be for contracts entered into after December15, 1990.

5.12 In order to enable EGPC and Petrogas to effectively implement theproject and to ensure prompt payments to contractors and consultants, the Bankwould advance funds as needed to a special account to be opened at acommercial bank in Egypt for a maximum riount of US$5.0 million; this isexpected to cover the Bank's share of eligible expenditures over a period ofthree months. The account would be denominated in US dollars and replenishedagainst withdrawal applications. Applications with appropriate supportingdocumentation would be submitted when approximately half of the maximumallocated amount of the account was spent. All disbursements under theproject 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 executingagencies with components focussing in technically disparate fields (gascollection and gas distribution), an average of at least 16 staff-weeks peryear would be necessary to allow biannual supervision to monitor projectactivities while both the GCGDC and Trans Gulf Gas Component are active, and12 staff-weeks per year thereafter as outlined in Annex XI. The supervisionmissions would include a gas (upstream) specialist to review the technicalaspects of the Trans Gulf Gas Component, a gas (downstream) specialist toreview the technical aspects of the GCGDC and a financial analyst. Therespective Project Implementation Units in EGPC and Petrogas would beresponsible for preparing documents for Bank supervision missions. EGPC andPetrogas would be asked to submit to the Bank quarterly progress reportsduring project implementation, and prepare and furnish to the Bank, withinfour months after project completion, a completion report including areassessment of the project costs and benefits.

I. Environment

5.14 Environmental concerns in Egypt, and particularly in Cairo, are of ahigh priority. The proposed solutions for minimizing the impact of fuel useon the environment are generally in consonance with prudent energy sectoroperation as they decrease the cost of energy supply. Greater efficiencydecreases the use of fuels and, hence, decreases the impact of their use.However, some specific areas are of particular concern. The air pollutionproblem 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 economicimpact. Concurrently, decreasing fuel oil use at existing dual-fired plantswould also mitigate the air quality problem. This project would increase theavailability of natural gas to the National Grid by decreasing flaring in theGulf of Suez and providing the infrastructure to debottleneck the transport ofassociated gas.

5.15 The proposed project would also make natural gas available toindustries in the greater Cairo area that are currently using high sulfur fueloil. Such interfuel substitution would have a considerable impact on localair pollution problems caused by the high level of pollutants in emissions andthe low height of the chimneys. Decreasing the delivery of LPG bottles woulddecrease traffic congestion in the streets of Cairo and air pollution fromvehicle exhaust.

5.16 In addition to the direct benefits of using a clean-burning fuel, thedistribution extension is expected to replace some of the gas supplied by asmall manufactured gas plant (Septia). Not only is this plant uneconomic1,but it also is reported to have pipeline losses of 40-50 percent because ofthe age (70 years) of some of the equipment. The pipeline losses not onlyaffect the economic viability of the operation but, more seriously, alsoresult in the release of toxic gases into the environment. Increasing the useof natural gas at the expense of this plant would enhance the economicviability of the sector and lessen the environmental problems associated withthe manufactured gas plant.

5.17 Environmental and Safety Review of GCGDC. The existing constructioncontract between Petrogas and Egypt Gas provides necessary codes of practiceand standards for the safe implementation of the project. The high pressuresteel main would be constructed in utility corridors and no special right ofway would be required except a small area (40 by 40 meters) for a pressureregulating station. The steel main would not pass close to the Pyramids (theclosest point would be about 1.5 km away). A special permit for trenchingwould be obtained from the local authorities and the Egyptian Department ofAntiquities if determined necessary by the local authorities. Petrogas hasoperational safety regulations and six safety engineers who send regularsafety reports to the Mlnistry of Labor. The safety record of Petrogas hasbeen satisfactory; however, a safety reporting system would be established aspart of this project. At the time of negotiations assurances from Petrogaswere obtained to implement this system by December 31, 1992.

5.18 Environmental and Safety Review of Trans Gulf Gas Component. Theproposed project is an extension to existing facilities in the Gulf of Suezand, hence, does not pose a major potential impact to the environment. Theonshore pipelines would not have any significant environmental impact as theywould be buried and would include adequate safeguards against leaks andruptures. 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.

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avoid environmentally sensitive areas. Standard international petroleumindustry practices and codes would be followed for the design of all offshoreand onshore facilities. EGPC would undertake an environmental review of theproposed detailed design of the facilities and review the proposals with theBank in order to address environmental concerns. In addition, EGPC wouldfurnish the Bank with updated quarterly environmental reports indicating theircompliance with environmental standards and practices.

J. Project Management and Implementation

5.19 Greater Cairo Gas Development Component. -ogas would provide theconceptual design and project management and supervis,on and would haveoverall responsibility for implementing the component. Egypt Gas, as the solecontractor, would perform detailed engineering, construction and procurementservices. Petrogas, with the assistance of Egypt Gas, has been able to expandthe First Cairo Gas Distribution Project to a sizable network and has operatedit safely for the past eight years. Based on this experience, Petrogas andEgypt Gas have demonstrated their capability to implement the proposed projectwithin the six-year schedule. However, the existing contract between Petrogasand Egypt Gas is on a turnkey basis and needs to be modified so that the Bankcan finance the procurement of material. As a condition of loaneffectiveness, a revised contract satisfactory to the Bank would be signed.

5.20 The current organizational structure of Petrogas satisfies theconcerns raised by the Bank in the First Cairo Gas Distribution Project. Asshown in Annex IV, LPG and natural gas operations are now split, each headedby a general manager who reports directly to a chairman. The natural gasdepartment has been strengthened to respond to Petrogas' increased operations.The Gas Department of Petrogas is responsible for the natural gas operationsof the companv and would also be responsible for the proposed project'simplementation. This department has now expanded to a large operational andproject development unit with about 1,200 staff. The department has twooperating units, one in East Cairo and the other in West Cairo, which areresponsible for the operation and maintenance of the networks as well as forcustomer emergency service. A Project Development Department is responsiblefor the planning and development of new projects covering market surveys,basic design, cost estimates and project management and supervision. Thisdepartment is using computerized techniques for network analysis and loadforecasting.

5.21 Petrogas has been successful in developing a sizeable market in theresidential sector in Cairo, but gas consumption in the commercial andindustrial sectors has been minimal. Through a gas market development study(Annex VII), strategies would be reviewed in order to increase the penetrationof gas in the commercial and industrial markets. As part of this strategy, acore of engineers would be established to promote gas sales in the commercialand industrial markets. The study would also provide assistance for Petrogasin conducting a new detailed market survey in Greater Cairo. A permanentsmall unit would be established in Petrogas to continuously review and analyze

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the gas market and its impact on other fuels. This unit would initiatenecessary policies and promote viable projects for the efficient expansion ofthe 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 toit by June 30, 1992; and (ii) carry out and complete a gas market developmentstudy by December 31, 1992, according to TORs satisfactory to the Bank. Thestudy is expected to start by October 1991.

5.23 Trans Gulf Gas Component. EGPC would be the implementing agency forthe proposed Trans Gulf Gas Project. A Project Implementation Unit would beestablished within the Gas Department for the purpose of project control. Thebasis of this unit was established at the time of the feasibility study withprojecc implementation guidance provided by the Gas Production GeneralManager. The detailed design, procurement and project management would beundertaken by ENPPI, the consulting firm responsible for the feasibilitystudy. Given the extensive experience of EGPC and of the consultants, projectimplementation 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 thatof a single profit center (EGPC) with numerous functional subsidiaries, whichoperate on a cost basis. EGPC acts as the financial coordinator andimplicitly sets transfer prices between subsidiaries (functions), which covercosts (including depreciation) plus a commission. The Petroleum PipelineCompany receives sufficient commissions to earn a 6 percent return on assetswhile Petrogas operates on a zero profit basis. Project funding, to theextent 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 tothe 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 millionequivalent as of June 1990 or less than 10 percent of long-term capital) ascash flow has generally been sufficient to cover investment requirements(Table 1 outlines past EGPC performance, with details in Annex XII). EGPCfinancial performance depends primarily on two factors: international anddomestic energy prices and the costs of production under concessionagreements. Traditional indicators of financial performance are generallymisleading 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

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profit as a percent of revenues fell to 21 percent in FY90 from 39 percent inFY85) largely due to declining crude oil prices.

6.03 These conditions, compounded by the anticipated decline in oilproduction levels and the rising cost of gas supply (which are payable inforeign currency) could result in a net loss in the EGPC foreign currencyaccount during the next decade. The two avenues Egypt has to control theseproblems are to increase domestic product prices (to increase revenues andreduce demand) and to expand gas supply to substitute for exportable petroleumproducts.

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 4,564Op. 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 1,469Taxes & Profit Dist. A 81% 83% 76% 77% 74% 751Net Internal Sources 355 273 387 419 412 368External Sources 64 78 66 45 8 n.a.

Debt Service/2 15 22 30 67 64 76Investments 478 299 167 402 176 268Self-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 capitalexpenditures.

6.04 As a result of the energy price reform program, high export pricesof crude oil in FY91 and increases in supply of natural gas, EGPC's financialposition has improved substantially. This improvement has resulted inincreased transfers from EGPC to the budget of about LE 2 billion in FY91 and

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EGPC PAYMENTS TO GOVERNMENTPeLyffneo Limited to MaX 40% of Revonues

13…- - - -

12- -

w 110--

-t _ 6 7 _

FY85 FY 37 FYb Y1 FY3 F7 9FY 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 similarincrease in transfer to the Government's budget is forecast for FY93 basedlargely due to the energy price reform program. As Figure 3 indicates, thedomestic energy price increases and increased gas supply would continue tohave 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. Theproject is expected to cost approximately US$60.2 million including duties,taxes and contingencies. The proposed Bank loan would fund material coststotaling approximately US$34 million or 56 percent of the costs. Thisrepresents a 12 percent increase in outstanding EGPC foreign debt and wouldentail less than a 5 percent increase in total annual debt service. Shoulddomestic energy prices rise as agreed, EGPC is forecast to easily meet debtservice and investment obligations. EGPC accounts are subject to an annualexternal audit by the Central Audit Organization. Aside from documentaryaudits, this review is effected in collaboration with the Ministry of Financeto ensure that expenditures are in accordance with authorized budgetedamounts. EGPC would have the project accounts, its own accounts and financialstatements, and the accounts and financial statements of the affiliates that

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executed the projects audited by independent auditors and would supply copiesof such statements to the Bank no later than six months after the end of eachfiscal year. The Special Account would also be reviewed by independentauditors acceptable to the Bank. EGPC has agreed to maintain a debt servicecoverage of at least 1.5, The Government, as guarantor, has agreed that itwould take all necessary actions to enable EGPC to achieve the financial goalsagreed to with the Bank.

C. _istoric Petrot i a erformancLe

6.06 Given that Petrogas is a cost center, financial performance has beendetermined by EGPC through commission levels, with net profit generally set tobe small. The overall sales margin has been stable at about 0.6 piastre/cubicmeter (in FY91 prices) over the past six years as shown in Table 2 (details inAnnex XIII). The margin for residential sales has, however, declined by over70 percent in real terms since FY85. Overall returns on net (historic) fixedassets 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 investmentdropped sharply after FY86. Over the past four years, annual investmentdeclined 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 0.6Residential 23.7 17.4 15.8 10.8 8.7 6.8Power/Industry 0.4 0.4 0.4 0.6 0.6 0.5LPG 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 42.9of 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 28.5External Sources 10.9 11.5 0.0 2.6 4.1 7.0Debt 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 50.5of 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.

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D. Future Petrogas Investments and Financing

6.07 Petrogas will experience a substantial increase in investment andsales activity over the next six years. The proposed GCGDC requires annualinvestments of approximately 131 million LE (in FY91 prices), which is doublerecent gas investment levels but comparable to levels experienced under thefirst Cairo distribution project. In addition, Petrogas may requiresubstantial investments in LPG facilities in order to efficiently utilizeanticipated increases in supplies of LPG'. During a period of rapid expansionof gas and LPG sales, the maintenance of adequate levels of working capitalwill be important. Cash flow would, therefore, be the prime financial concernof Petrogas over the project period. The proposed project would financeforeign material costs totaling approximately US$67 million (before pricecontingencies) or 36 percent of total project costs. Consumer contributionsare estimated to provide a further 5 percent of project costs. The remainingfinancing must come from internal funds, local debt or shareholdercontributions.

6.08 A self-financing level of 25 percent is considered appropriate forPetrogas at this stage of development. During a period of rapid growth,higher levels would unduly penalize current consumers, while lower levels riskdelaying the project due to inadequate cash flow. The margins required toachieve a 25 percent self-financing level are discussed below in light ofanticipated changes in petroleum product pricing in Egypt over the next fiveyears. Two price levels are important, consumer prices and transfer prices.

Consumer Gas Prices: For the purposes of financial projections, theprice for industrial and power sector gas sales was set to fuel oilequivalent plus a small margin to cover working capital carryingcosts and contributions towards the network. Residential andcommercial prices were based upon fuel oil equivalent, plus a marginsufficient to earn an 8 percent real return on capital, to a maximumof LPG equivalence. LPG prices were assumed to reach 75 percent ofinternational prices by FY96, plus a distribution margin of US$30 pertonne by FY96, and full economic costs of US$150 per tonne by June1998.

Transfer Prices: The current transfer pricing regime is based onzero profit margins and not on economic or market factors. Withrespect to natural gas, the proper transfer price at the city gateunder current conditions is the fuel oil equivalent.

1/ LPG investments could exceed gas investments in some years based on capitalcosts of LE 525 per incremental tonne of demand, which has been the averageover the past six years, including adjustment to official versus preferredpetroleum sector exchange rates.

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6.09 The operating margin resulting from the pricing conditionsdescribed above would be about 0.7 piastres/m3 in mid-1990 prices. This wouldbe sufficient to ensure at least a 25 percent self-financing level during theimplementation phase of the GCGDC. This implies that until the end of FY95(while consumer petroleum product prices remain subsidized) Petrogas inputprices may be required to remain up to 5 percent less than the fuel oilequivalent.

6.10 The remaining project costs (after Bank financing and consumercontributions) could be funded by local debt or shareholder contributions. Intaking on the proposed loan, debt as a percent of long term capital associatedwith revalued gas assets would rise from 10 percent' currently to 20 percentby FY96 (see Appendix XIII for Petrogas Financial Projections). On anhistoric cost basis, leverage would reach almost 40 percent by FY96. Typicalallowable levels of debt in North American gas utilities are generally between40 percent and 60 percent. Given that Petrogas is a relatively young utilityand expected to grow rapidly over the next five years, additional leveragedoes not appear prudent in the near term. The potential for cash flowshortages is great due to rising working capital needs and the fact thatannual debt service is estimated to increase by a factor of 5 in real terms byFY97. This leaves equity contributions as the only remaining source of funds.EGPC would provide the residual project costs in the form of direct equityand/or reduced shareholder payments. In total, 59 percent of project costsmust come from internal funds and equity, implying total annual contributionsof approximately LE 83 million (FY91 prices) from FY93 to FY96. Expectedproject funding is summarized in Table 3 below. To ensure that the financingfrom internally generated funds would be established, Petrogas has agreed thata 25 percent self-financing ratio would be maintained by Petrogas on its gasoperations and that Petrogas' debt service coverage ratio would exceed 1.5 toensure corporate creditworthiness.

I/ Based upon revalued capital, assuming an equal split between foreign andlocal costs for gas assets.

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Tajle 3: Cairo Gas Distribution: Summary Project Sourcesand Applications of Funds

(millions of LE in constant FY91 prices)

IOtL (X) F92Z FY9. = L24 F9 E Y E9k E2SourcesInternal Fundstl 169 26X 0 27 36 37 30 39IBRD Debt 234 361 6 59 55 57 57 0Consumers 36 5X 0 8 8 8 8 7Equity 217 33X 0 51 43 48 59 18

Total 657 1001 6 144 142 149 153 63

ApplicationsInvestments 657 100l 6 144 142 149 153 63

L1 Internal funds available after covering debt service and working capitalrequirements.

E. Petrogas Accounts and Audit

6.11 The LPG and gas operations of Petrogas are inherently different. Inthe future, gas will increasingly compete with LPG for markets and internalresources. At the recommendation of the Bank, Petrogas separated thetechnical operations of gas and LPG. However, the financial operations arestill not formally separated. During project appraisal, it was recomendedthat Petrogas consider creating separate organizations at some point in time.As a first step, Petrogas would maintain separate accounts for LPG and naturalgas and furnish copies of financial statements no later than six months afterthe end of each fiscal year, as well as budget forecasts for the followingfiscal year. This process would be supported through the structuring of loancovenants, which would focus on achieving a 25 percent self-financingcapability on gas operations as separate from LPG operations. Petrogasprepares full accounts of its financial position and of its annual operationsat the end of every year. These accounts are subject to an external audit bythe Egyptian Central Audit Organization and to the approval of the generalmeeting of stockholders held regularly within six months after the end of eachyear. Petrogas would prepare project accounts separately, and these accountsand annual accounts and financial statements, would also be auditedindependently. The Bank would be supplied with copies of all statements nolater 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 thereplacement of high-value fuels (LPG and gas oil) with a fuel of lowereconomic value, natural gas. The project would also generate benefits forconsumers in terms of the convenience and cleanliness of natural gas. In thecase of the Trans Gulf Gas Component, the primary benefit would be thesubstitur-Jon of shut-in and flared gas for fuel oil, which is currently usedas a fuel. in power and industrial applications.

7.02 The critical variables for the economic return are the cost of theproject, the level of gas consumption achieved, the cost of gas input to theproject, and the value of fuels displaced. The project has been evaluated bycomparing the economic value of fuels displaced by gas, and the value of theconvenience benefits of gas, with the costs of the project and the opportunitycost of gas.

B. Project Economic Costs

7.03 Total project capital costs include both infrastructure financed bythe project and any connection and conversion charges financed by consumers.Estimated equilibrium exchange rates' have been used in converting local coststo dollars. The cost of gas has been taken as the fuel oil equivalent atinternational prices as, in the absence of the project, gas would be used todisplace fuel oil in dual-fired power stations and heavy industries. As Egyptis 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 analysisconfirms that Egypt is unlikely to have sufficient gas to displace all fueloil from power and heavy industry.

C. Project Economic Benefits

7.04 The volume of gas sales achieved for a given expenditure on thedistribution system is critical to gas distribution economics. GivenPetrogas's substantial experience with household connections, it is assumedthat the target number of residential customers is achieved. Usage perresidential household (240 cm/yr) is projected on the basis of thosehouseholds currently connected to the distribution system. A trendconsumption 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 and5.62 for FY92 to FY96, respectively.

- 37 -

increasing penetration of natural gas water heaters. It has been assumed thatall the fuel displaced in households is LPG, although electricity is used forcooking and water heating in a small percentage of households. Thedisplacement of electricity will tend to increase economic benefits, relativeto LPG displacement.

7.05 Commercial sector demand has been estimated on the basis of existinguse, 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 figureis believed to be depressed because gas to commercial consumers costs aroundtwice as much as LPG. Average commercial consumption is expected to rise byabout 5 percent per annum, due to a combination of growth in the servicesector 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 beLPG, a significant proportion of gas oil is expected to be displaced amonglarger users. The estimated industrial demand for gas is based upon currentfuel usage as surveyed by Petrogas.

7.06 Because the relatively large unit consumption of commercialconsumers greatly improves the load on the distribution system, projecteconomics are sensitive to achieving target consumption in the commercialsector. Under the first phase of Cairo gas distributicn, commercialconsumption was held back by the low relative price of LPG and by poormarketing. The risks associated with increased commercial use are beingaddressed by specifically targeting LPG prices in the energy price reformprogram, by initiating gas tariff reform, by focussing distribution expansionin areas with relatively high concentrations of potential commercial users andby strengthening the operations of Petrogas. Hence, the target commercialconsumption is expected to be achieved.

7.07 The GCGDC would result in the annual displacement of an estimated76,000 tonnes of LPG, 18,000 tonnes of fuel oil and 26,000 tonnes of gas oilby FY98. These fuels have been valued at border prices. Prices are adjustedfor delivery costs to the customer gate or export point. Since approximately80 percent of the gross benefits of the GCGDC are attributable to LPGdisplacement, the valuation of LPG is crucial to the project's economics. Inthe long term, potential LPG demand in Egypt could only be satisfied byimports, and the cif price for LPG has thus been used in the calculation ofLPG 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 LPGconsumers through savings on LPG cylinder delivery, a more secure supply ofenergy and savings on the space needed for LPG cylinders. These benefits havebeen estimated at US$30/ton of LPG displaced for residential consumers and atUS$15/ton of LPG displaced for commercial consumers (see Annex XIV).

7.09 The project would also yield environmental benefits from thedisplacement of gas oil and fuel oil in industries and on commercial premisesin urban Cairo. However, these benefits have to be balanced against the

- 38 -

increased fuel oil used in power stations outside urban Cairo due to thediversion of natural gas for the GCGDC. Additional environmental benefitswould also arise from a reduction in the transport of LPG cylinders (about 5million per annum) through congested city streets.

D. Economic Rate of Return

7.10 The Economic Rate of Return (ERR) for the project is estimated tobe 18 percent. The ERR of the GCGDC is 16 percent (see Annex XIV fordetails). Sensitivities on key parameters show that the component is robustto a number of adverse assumptions on costs and benefits:

ERR(X

Base Case 16Capital Cost -201 20Capital Cost +20X 13Unit Gas Consumption +20X 19Unit Gas Consumption -201 12LPG Prices +201 18Oil Prices -201 14

7.11 Given that the marginal use of natural gas is in dual-firedindustrial and power boilers, the benefits attributed to the Trans Gulf Gascomponent are valued at the international price of fuel oil. The ERR of theTrans Gulf Gas Component is estimated to be 28 percent (see Annex XIV fordetails). 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 at14 percent. Given that the probability distribution of oil prices over thelonger term is positively skewed, the risk of the return dropping to thislevel is unlikely. Should the economic life of the project be reduced from 13to 6 years, the ERR would remain attractive at 21 percent. The sensitivitiesof the ERR to key input assumptions are outlined below, indicating that theproject's viabllity is robust:

ERR (X?

Base Case 28Capital Cost -201 39Capital Cost +20X 21Oil Prices +201 41OLI Prices -201 14Six Year Life 21

- 39 -

E. Risks

7.12 The primary risk associated with the GCGDC is the possibility of aninsufficient increase in natural gas consumption by commercial customers dueto the relatively low prices of substitute fuels. The pricing issue regardingsubstitute energy products has been addressed during the appraisal of theproject. In May 1990 weighted average petroleum product prices were increasedby 44 percent, and LPG (the primary fuel being substituted under the GCGDC)was increased by 130 percent. Furthermore, the Government increased petroleumproduct prices by 52 percent as of May 3, 1991. This price increase focussedon increasing the price of the most heavily subsidized products by a greaterthan average amount. In particular, the primary products for which naturalgas is a substitute, LPG and gas oil, have been increased substantially. LPGis about four times the price prevailing prior to May 1990 and gas oil hasnearly tripled. As a result, Petrogas has had a considerable increase inapplications from commercial users for gas supply, thus minimizing theeconomic risk associated with the GCGDC. The primary risk associated with theTrans Gulf Gas Component is associated with the life of the related gasfields. However, should the economic life be reduced from the expected levelof 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 byDecember 31, 1992, would be undertaken in collaboration with theBank (paras. 3.22);

(b) the facility in the existing Ras Shokeir pipeline to enabletransfer of gas produced from the Trans Gulf Gas Component would bebuilt simultaneously with this Component (para. 5.06);

(c) the Refinery Sector Investment Planning Study (para. 3.17) andthe Gulf of Suez Gas Development Plan Study (para. 3.18) would beundertaken and completed by December 31, 1993;

(d) EGPC would operate a special account (revolving fund) for Bankloan disbursements (para. 5.12);

(e) quarterly progress reports would be submitted to the Bank duringproject implementation and annually thereafter during the life ofthe proposed loan; and within four months of project completion, a

- 40 -

completion report dealing with project implementation and initialoperations and a reassessment of the project costs and benefits would besubmitted to the Bank (para. 5.13);

(f) the construction of facilities for the Trans Gulf Gas Componentshall be undertaken in accordance with environmental standardssatisfactory to the Bank and the progress reports would include allinformation regarding adherence to such standards (para 5.18);

(g) the finances of EGPC and those of its subsidiaries that wouldexecute project components would be audited by independent auditorswithin six months of the end of each fiscal year to ensure that theconsolidated net revenues of EGPC and its subsidiaries would not be lessthan 1.5 times the consolidated debt service ratio (para.6.05); and

(h) funds would promptly be provided, as necessary, for the GCGDCcomponent, 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 duringproject implementation and annually thereafter during the life of theproposed loan; and within four months of project completion, acompletion report dealing with project implementation and initialoperations and a reassessment of the project's costs and benefits wouldbe submitted to the Bank (para. 5.13);

(b) Prior to loan effectiveness, Petrogas would enter into a revisedcontract with Egypt Gas, to be approved by the Bank based on the draftcontract, which would be reviewed during loan negotiations (para. 5.19);

(c) Petrogas would establish a marketing unit within its organization byJune 30, 1992 and would undertake a gas market development survey byDecember 31, 1992 (para. 5.22);

(d) margins on natural gas sales of Petrogas would be maintained suchthat revenues would be sufficient for a debt service coverage ratio ofnot less than 1.5 and a self-financing ratio of not less than 25 percentfor gas operations (paras. 6.10); and

(e) Petrogas would provide separate gas and LPG accounts, have financialstatements audited independently, and supply the Bank with copies ofsuch statements no later than six months after the end of each fiscalyear; Petrogas would also provide both the auditor's reports andfinancial statements along with budget forecasts for the followingfiscal year (para. 6.11).

- 41 -

8.03 Am conditions of loan effectiveness:

(a) a Subsidiary Loan Agreement would be executed by EGPC on behalf ofthe Borrower and Petrogas (para. 5.08);

(b) the EIB Loan Agreement would be concluded between EGPC and EIB andall 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 tothe Bank, would be signed (para. 5.19).

Recommendation

8.04 Subject to the foregoing, the project would be suitable for a Bankloan of US$84 million equivalent for a term of 20 years, including a graceperiod of five years.

EGYPTGAS INVUES PROJECT

Ftmetional Structure of Oil Industry

MNinister of Petroles I

iSupri Petroles i

IE1tPloation IProductin Refining and Pipeline Narketing Ie ConstructIPrcsiPro ng Distribution Engineering &

U ' ~~~~~~~~~~~~~~~~~~~~~~ServicesForeignPartners .. Foreign

Partners

CPC 6~CPC GILOSuz iProcessing 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. CIEL-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 XRaaadan I 1 huucalI

|ALAHERIA|g Refining

Source: Egypt1an General Petroleum Corporation

EGYrPTGAS NVESTh PROJECT

Egyptian General Petroleum CorporationOrganization 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 nExploratlon 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 SecurityDepart et rpr n

EGPC E6PCEngineering Refining andOepartot eanufacturing

Department

g E6PC l l | EGPCFollow-up DistributionDepartment Department

EGPCCrmmercialSouree: Egyptian 6eneral Petroleum Corporation Department

- 44 -

Annex UIIPage 1 of 7

Egm

GAS JNVESTMENT PROJ,~.:

An assessment has been made of the outlook to the year 2005 for naturalgas demand and supply in Egypt. The principal purpose of this assessment isto determine whether Egypt can be considered a gas deficit country, in thatthere will remain unsatisfied demand for gas in sectors where gas use would beeconomic. This assessment also provides a framework for judging priorities ingas utilization and supply.

The methodology essentially consists of estimating the potential gas usein power and in the main gas-using industries, which are either alreadyconnected to the gas grid or could easily be connected to the grid in thefuture. To this is added an estimate of possible demand in other industriesand in the residential and commercial sector. Supply projections are basedupon the outlook for production from fields currently producing or underdevelopment and from discoveries that may be developed in the future.

The net deficit position represents a relatively conservative estimateof the unsatisfied economic demand for gas. An estimate is made of the rateof discoveries needed both to replace ongoing production and to cover thisdeficit.

Gas Demand

Rower

Potential demand for gas in the power sector has been calculated on thebasis of the Egyptian Electricity Authority's long-term investment plan. Thepotential demand in a given year is taken to be the sum of the gas requirementof gas-dedicated plants (e.g., turbines and combined cycle) and therequirement of dual-fuelled steam plants if all fuel requirements of theseplants were met by gas. Fuel requirements are calculated on the basis ofhistorical fuel requirements of EEA plants.

Power demand is assumed to grow at 4 percent p.a. to 1994/95 and at 6percent p.a. thereafter. Hydro output is assumed constant at an annualaverage of 9,300 MW, with all growth coming from thermal capacity.

Nea1ly all of the forward investment plans of EEA consist of investmentsin combined cycle plants or dual-fired steam plants. It is assumed thatcombined cycle plants run at base load (70 percent), while the load on gasturbines falls from an average of 54 percent in 1988/89 to 20 percent in1993/94 as system efficiencies reduce reliance on turbines for base and mediumload. Dual-fired steam plants pick up the balancing load, with any remainingolder (and hence inefficient) fuel oil plants phased out by 1993/94. The onlyexception to this pattern is the 300 MW Assiut oil plant, which is not

- 45 -

Annex IIIPage 2 of 7

connected to the gas grid and consumes the fuel oil output of the Assiutrefinery.

The forward program to 1995 includes the conversion of thermal stationsat 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-firedcapacity apart from Assiut. The Cairo West and Talkha plants will receive newdual-fired units, and the existing Abu Qir dual-fired thermal station will beexpanded. By FY95 however, about 25 percent of capacity will come fromcombined cycle units, with a total of 2,300 MW at Talkha, Dammieta, CairoSouth, Mahmoudia and Damanhour. All larger gas turbines had been converted todual gas oil/gas firing by 1990, the only exceptions being small units off thegas grid.

The overall efficiency of fuel use in Egyptian power stations is likelyto rise substantially by 1995, due to several factors: the lowering of theload on gas turbines as system efficiency increases; the conversion of somelarge pre-built turbines and existing steam units to combined cycle operation;the refurbishment of older steam units during their conversion to natural gasdual firing; and the construction of new steam units. Average effici.ency islikely to improve from around 286 g/kwh (fuel oil equivalent) in 1988/89 to225 g/kwh by 1994/95.

Longer term capacity growth, at around 600 MW/yr is assumed to come fromdual-fired steam stations, starting with Kureimat in 1995/96. Construction offurther combined cycle plants is unlikely unless large new discoveries aremade, which could ensure long-term dedicated gas supplies.

The main downside risks to this forecast of potential gas demand inpower lie with possible lower power demand growth due to greater efficiency ofend use, in response to price rises or slow economic growth. Upside risks liewith higher growth in electricity demand in the long term, assuming successfuleconomic restructuring, and with a lowering of hydro capacity at Aswan due tofalling water levels.

Egypt currently has three nitrogenous fertilizer plants using gas (atTalkha, Abu Qir and Suez), which have been using gas for many years andconsumed around 120 mmcfd in FY90. The balance of demand is met throughproduction from the Kima electrolysis plant in Upper Egypt, a small plant atHelwan 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. Tomeet this additional demand without a large growth in imports, there will be amajor 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 IIIPage 3 of 7

The future of the Kima plant, which is currently highly uneconomic, issubject to some uncertainty. It has been assumed that this plant will bereplaced with an enlarged plant based upon fuel oil, as natural gas is notplanned to be supplied to Upper Egypt at present.

Celmen-t

At present four of Egypt's seven cement plants (Turah, Helwan, Suez andNational) are dual fired by fuel oil and natural gas; consumption in 1990/91was 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 nexttwo years. 'The only other large plant is at Assiut, which is not served bythe gas grid.

The pace of growth in cement demand in Egypt in the l990s is expected tobe well below the 15 percent p.a. seen between 1975 and 1985. Growth isanticipated to be closer to GDP (4 percent p.a.), to be met by expansion ofthe more efficient plants.

The phasing out of wet process manufacture by FY96 is expected to reduceenergy requirements. Wet process manufacture, which accounted for some 20percent of supplies in FY90, uses about 75 percent more energy than the dryprocess. Total potential gas usage in plants connected to the gas grid isthus likely to rise at about 3 percent p.a. during the 1990s.

Other Industries

Outside of the above sectors, industrial energy use in Egypt remainsdominated by oil. Other industries used nearly 4 million tons of fuel oil andgas oil in FY90, compared with only 1.2 million tons of fuel oil equivalent ofnatural gas. Most of the demand in this sector is around the major citiesserved by gas and is thus potentially substitutable (the GCGDEP willsubstitute about 65,000 tons of this demand by 1998).

In practice, the substitution of at least 50 percent of industrialenergy demand with gas should be seen as a reasonable long-term goal; this istaken as the potential demand of this sector beyond 2000.

There is also significant potential demand for gas in the petroleumsector, principally for refinery fuel. Two of Egypt's refineries (Alexandriaand Suez) are connected to gas, and a third (Ameriya) is expected to beconnected in the next two years. However, consumption in FY90 was only8 mmfd. Potential consumption in all the refineries (excluding Assiut) isconservatively estimated at about 90 mmcfd by 2000.

Residential and Commercial

Despite relatively low per capita household energy consumption and thelack of a space heating requirement, Egypt's large urbanized population andsizeable commercial and services sector provides a substantial potentialdemand base. Current plans calling for extending the grid in Cairo, with

- 47 -

Annex IIIPage 4 of 7

a smaller grid in Alexandria, are likely to lead to a demand of only some 25mmcfd in 2000, which has been taken as the base case forecast. However,actual potential consumption could be far above this level, if funds wereavailable to connect suitable areas in all major cities.

Upper Egvit Demand

All the estimates of potential demand above exclude the demand whichwould arise if Upper Egypt, including the city of Assiut and points furtherSouth, were connected to gas.

Total additional potential demand from connection of Upper Egypt couldbe at least 150 mmcfd by the late 1990s, or an additional 7 percent above thebase case for the rest of Egypt. This potential demand would come from theAssiut power plant (50 mmcfd), Assiut cement plant (40 mmcfd), Kima fertilizerreplacement (40 mmcfd) and miscellaneous demand from the Assiut refinery andother industries (at least 20 mmcfd). If sufficient gas were available, thislevel of demand could justify a pipeline either from the Red Sea coast, orfrom Cairo, at least as far as Assiut.

Gas Production

Estimates of future gas production are based upon discussions with EGPCand published industry sources. Figures are shown by field processing plantand are net of any LPG extracted at the plant (LPG is extracted at all plantsexcept Badr El Din).

Of the established fields, production at Abu el Gharadig, which startedin 1976, is expected to decline steadily from 1994/95 as the reservoir isdepleted. Production from the Abu Madi field is expected to be boosted byaround 25 percent in 1992/93 and to maintain this higher level until 2005.However, this may be optimistic and production could remain steady at around340 mmcfd. Abu Qir production has suffered some well productivity problemsand is not expected to exceed previous production levels. Gulf of Suezassociated gas production is constrained by capacity at the Ras Shukeirprocessing plant and in the pipeline to Suez, and hence no expansion ispossible from the established infrastructure.

The principal increment to production is expected to come from the BadrEl Din (BED) developments and from the El Qara development in the Abu Madiarea. BED 3 came on stream in the second half of 1990 and is expected tobuild a plateau of 150 mmcfd during 1991. BED 2 is expected to contributearound 75 mmcfd from the beginning of 1992. The Abu Senan field will linkinto the BED line to Ameriya, producing an estimated 75 mmifd from 1991onwards. El Qara is expected to produce 120 mmnfd from 1992, which will beprocessed jointly with Abu Madi gas.

Gas from the Khalda area in the Western Desert, which is located too farfrom the main consumption areas for transport to be economic at present, isbeing 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 IUPage 5 of 7

increase with the expansion of power generation capacity. If substantialadditional gas discoveries are made in the area, transport of the gas to theCairo/Alexandria areas may be possible, although it is unlikely that any suchproject will materialize before the late 1990s.

Of the potential developments identified, the most promising is therecovery of additional associated gas from the Gulf of Suez, beginning withthe Trans Gulf Project. This should supply some 70 mmcfd from 1993. It isassumed that an additional increment of this amount is recovered from 1997onwards, 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 assumedto be too small to develop, although additional exploration may prove reservesin the Red Sea that would make development economic, although production isunlikely before 2000.

Port Fouad, El Timsah and some related structures, which lie offshorefrom the Eastern Nile Delta, are currently under evaluation by IOCs andprovide the most substantial longer term development options. It is assumedthat around 1.5 tef of reserves from this area can be developed. However,much additional appraisal drilling is required before a development decisioncan 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 uponexisting identified reserves detailed in the table below, shows an excess ofpotential demand over supply of around 160 mmcfd in 1992/93, rising to700 mmcfd in 2000.

Some of this gap will no doubt be filled by production from newdiscoveries. However, the level of new discoveries needed to sustain self-sufficiency, particularly beyond 2000, is relatively high. Moreover, any newdiscoveries will take at least three years to come into production (probablymuch longer if they are located well away from existing pipelines); henceself-sufficiency is not possible before about 1995, whatever the level offuture discoveries.

The total quantity of reserves required to achieve self-sufficiency, onthe basis of potential demand projections, has been calculated on thefollowing assumptions: that sufficient gas will have to be discovered, onaverage, each year to replace production in that year; and that additionalreserves will have to be discovered to cover the growing gap between potentialdemand and supply. It is assumed that the reserves/production ratio for allnew 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 largerelative to the total discoveries to date of around 13 tcf and would probablyrequire 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 inthe 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 10,365Combined C 0 0 610 610 2,012 3,348 3,348 3,348 3,348 3,348 3,348Gas 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 830Abu Madi (+Qara) 2,619 3,484 3,484 3,484 6,772 5,772 5,772 5,772 5,772 5,772 5,772Abu Qir (+N.A.Q) 2,016 1,959 2,000 2,000 2,000 2,000 2,000 2,000 2,000 2,000 2,000Guff of Suez 1,372 1,313 1,400 1,400 1,400 1,400 1,400 1,400 1,400 1,400 1,400Sinai 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 3,100Khalda 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 3,000Gulf 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

088/89 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 MPage 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 pressuremain from the Nasr City's pressure regulating stations (PRS) toAbbasia to supply gas to industries along the route and to provideadditional supply to Nasr City, El Obour and Abbasia;

2. Installation of one PRS with 60,000 CM/hr capacity in Abbasia toreduce the main feeder's pressure from 30-bar to 7-bar;

3. Installation of some 8-km additional steel mains to supply gas toindustries in the west of Cairo;

4. Construction of a 900-km medium pressure and low pressurepolyethylene (PE) netwotk;

5. Installation of 55 district rAgulating stations and 500 serviceregulators 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 apartmentbuildings, 5,000 (3,000 infill and 2,000 new areas) for commercialconsumers, and 17 for industrial consumers;

8. Installation of 3,720-km carcassing for the apartment buildings andinternal piping for the residential consumer premises;

9. Installation of 235,000 meter and governor kits for residential and5,017 meters and regulator stations for industrial and commercialconsumers;

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 tobe equipped with modern facilities; and training of technicalstaff both in Egypt and in other countries with advanced gasindustry, to maximize operational efficiency; and

(b) computerization of customer services, planning and engineering,emergency centers, and MIS.

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AnanexVPage 2 of 9

The details regarding the number of new customers expected to beserviced by the infrastructure financed under the loan and their location arebased on a series of surveys undertaken by Petrogas and their consultant since1982. In the Garden City area, gas would be supplied to hotels, some of whichare still using costly manufactured gas. In the West Cairo area, which is anew gas development area, a mixed development c.. the west bank of the RiverNile stretching from Madinet El Omal in the north to Giza in the south and thePyramids in the west is planned. There are a number of high-rise apartmentbuildings along the banks of the Nile on the islands of Zamalik and Manial ElRodah, and on the opposite side of the islands in the main banks, that aretargeted for connection to natural gas. Some of these blocks are more than 20stories high. The housing potential along the banks of the Nile and in thecenter of the area designated for the gas network tends to be good. Newhousing and large- and medium-size commercial consumers concentrated aroundthe parallel roads that lead towards the Pyramids are also targeted forconnection to natural gas. The details regarding the expected location of newconsumers are as indicated below:

No. of CustomersA. Cairo West

1. El Haram Area (Pyramid) 110,0002. Giza 15,0003. Imbaba l15.000

Subtotal 140,000

B. Cairo East

1. 15 of May City (Helwan) 10,0002. Emtedad Rameses (Abbasia) 7,0003. Sheraton (Heliopolis) 5,0004. El Eskan El Swesry (N. City) 5,0005. Medinet El Solb (Helwan) 5,0006. El Nozhah (Heliopolis) 3,0007. El Soudia (Zeitoon) 3,0008. New Developments (N. City) 3,0009. El Obour Extension 2,00010. El Obour 2 1,00011. Awel Mayo City (N. City) 1,00012. Eskan El Mohandeseen (N. City) 1,00013. Garden City and Monira 14.000

Subtotal 60,000

C. Commercial and Infill

1. Residential Infill 35,0002. Commercial Infill 3,0003. New Commercial 2,000

Subtotal 40,000

D. Industrial Consumers 17

Total Consumers Under the Proposed Project 240,017

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Annex VPage 3 of 9

The yearly progress for the distribution network and the conversion ofcustomer appliance/burners from their existing fuels to natural gas is shownbelow:

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

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Annex VPage 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 17.04Regulating Stations 0.03 2.45 2.48Service Connections 0.08 2.65 2.73Customer Meters & Regulators 0.19 21.30 21.49Customer 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 12.30Construction Equipment 2.40 9.70 12.10Pipelines & Valves 9.45 3.99 13.43Regulating Stations 0.86 0.18 1.04Service Connections 0.82 0.17 1.00Customer Meters and Regulators 5.08 1.14 6.22Customer 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 10.20Price 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 DisburementEnd of Quarter(US$ 1000)

Calendar Year and Quarter Incremental Cummulative

FY 923rd quarter 0.2 0.24th quarter 0.7 0.9

FY 931st quarter 2.7 3.62nd quarter 2.7 6.33rd quarter 2.7 9.04th quarter 2.7 11.7

FY 941st quarter 2.7 14.42nd quarter 3.0 17.43rd quarter 2.5 19.94th quarter 2.5 22.4

FY 951st quarter 2.5 24.92nd quarter 2.5 27.43rd quarter 2.5 29.94th quarter 3.3 33.2

FY 961st quarter 3.3 36.52nd quarter 3.3 39.83rd quarter 3.3 43.14th quarter 1.4 44.5

FY 971st quarter 1.4 45.92nd quarter 1.0 46.93rd quarter 1.2 48.1

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Page 6 of 9

Key Acto2nPlan

1£MEPA Completion Date

1. Basic design including survey of commercialand 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 toissuance of bid documents) 02/91

5. World Bank review of tender documents (15 days) 02/91

6. Bid documents issued (45 days minimum requiredfor 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 millionand 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

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Annex VPage 7 of 9

Idustrial Consumers Prooosed for Conversion to Natural Gas

Current Consumptionof Petroleum Products Estimated Equiv.

DeseriRtio-n Gas Oil Fuel Oil Kerosene LPG Gas ReIuirements-- t/yr .- -----mcm/yr--.-

1. Glass Factory 12,479 14,6882. 7-Up Factory 3,000 80 3,6303. Pencils and Graphite Factory 900 17 1,0804. Ideal Factory 300 4505. Abbassia Industrial Area 1,644 90 1,9356. El Nasr Castings 1,427 5,884 8,4007. Berzy Factory 150 1688. Olympic Electric Company 357 420

9. Wooltex Weaving Factory 735 840

10. Shorbagy Factory 551 63011. El Ahram Beer Factory 700 4,707 1 4,70012. Coca Cola Factory 130 514 56013. Eastern Company for Cigarettes 3,310 4 3,79014. El Nasr Company for Cigarettes 20 147 1 19315. Pepsi Cola Factory 200 507 30 85216. 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 11,7722. Military Factory No. 09 449 200 7633. Helwan Cooperation for

Non-Ferrous Industries (No. 63) 2,923 1,740 5,2304. Factory No. 909 . 1,067 1,2185. 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 MethodICB 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 20regulators (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 3.6fittings a/ (3.6) (3.6)

Engineering & construction 140.4 140.4& procurement services ( - ) ( - )

Consultancy services for 1.3 1.3studies 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 PROJECTPROJECT SCHEDULE

1991 1992 1993 1994 1995 1996 1997ACTIVITY 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 Designand ConsumerSurvey

MaterialProcurement SI ' MR

_ _ _ . __ _ _ _ _ .. . .. . .. _ _ _ . ..._ a'....

NetworkConstruction M M_ MISS

ConsumerConnecton 48,000 4000 i 3 48,000

LEGEND:TP = Tender PreperatlonBi =Bid IssuedMO = Material Ordered xMR = Material Received

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Afxex VIPage 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 theGulf of Suez. During 1990 as much as 873,000 bbl/day of oil and about 1,180million 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, withincreasing demand for natural gas in the country, GOE has declared a policy ofminimizing flaring of associated gas. In order to pursue this objective, EGPChas proposed the Trans Gulf Gas Project to utilize additional associated gasfrom 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 liquidpetroleum products, which could alternatively be exported or utilized in areaswhere 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 beingflared; and

(c) contributing towards environmental protection objectives byreducing CO2 and other emissions in the Gulf of Suez area, thus mitigatingatmospheric pollution and global warming problems.

2. Gas SuDplies and Reserves

Oil and associated gas is currently being produced from over 70 fieldsin the Gulf of Suez. These fields are being produced by 11 operatingcompanie.. In 9 out of 11 of these operating companies, EGPC is 50 percentpartner. Two operating companies --General Petroleum Company (GPC) andGEISUM-- 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 oilproduction from the area. GUPCO operates 24 fields with oil production ofabout 400,000 B/D. Petrobel (AGIP/EGPC) is producing about 200,000 B/Dfollowed by SUCO (ESSO/EGPC) at 100,000 B/D. Under the old oil-productionsharing agreements, all associated gas belonged to EGPC. More recently(1988), EGPC modified production-sharing contracts by including a new gasclause. GUPCO is operating in new contract areas under this clause. Over theyears, EGPC has taken steps to utilize associated gas from various fieldse.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

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Annkez VIPage 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 byGUPCO in 1975 and is currently producing oil and associated gas from 27offshore wells. Some additional production is also being obtained from thenearby North October field from six producing wells. Currently, ubout 45MHSCFD of associated gas from the October field is transmitted through anexisting 30-inch diameter pipeline to Ras Bakr facilities; after processing,dry sales gas is supplied through the 16-inch diameter Ras Shukeir pipeline toSuez. With the increase in oil production from October fields from 100,000B/D to 160,000 B/D, additional associated gas is being produced; this is inexcess of the capacity of the existing facilities being flared. As oilproduction declines, gas oil ratios will tend to increase and associated gasproduction will continue for a longer period than oil production. Theproposed project plans to utilize surplus gas, which is currently being flaredfrom these fields. The nearby North October field is in its early stages ofdelineation and may provide additional gas to the project.

Belavim Fields. The Belayim Fields in the Sinai area cover both onshoreand offshore fields. Belaim (Land) was discovered by Petrobel in '955. Otherareas are Belaim Marine, Rudeis and Sidri (offshore) fields. Originalrecoverable reserves were over two billion bbl from these fields. Remainingrecoverable reserves are estimated at about one billion bbl. Currently, about160,000 b/d oil and 47 MMCFD of associated gas is being produced. The reviewof the production profile indicates an average decline of 8 percent in oilproduction. However, associated gas production is estimated at about 37 overthe first 5 years of the project life and to decline at about six per cent perannum thereafter. Along with the above-mentioned surplus gas, the proposedscheme envisages the utilization of any additional associated gas from thesefields.

3. Status of Project Preparation

Currently, 40 of MMCFD associated gas from the October Field is beingtransmitted to the Ras Bakr facilities through the existing 30-inch diameterpipeline. As discussed above, in order to minimize flaring and optimallyutilize the surplus associated gas of about 30 MMCFD from the October Field,and 37 MMCFD from the LPG recovery plant at Belayim in Sinai, EGPCcommissioned ENPPI, a 100 percent EGPC owned oonsulting services company, toconduct a feasibility study. The objective was to evaluate alternatives anddevelop budgetary cost estimates for optimizing the utilization of surplus-associated gases from the Sinai/Belayim and October Fields. ENPPI completedthis study and submitted its report to EGPC in September 1990. Afterevaluating 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 12inch in diameter to link with the October field;

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Annex VlPage 3 of 16

(c) to add an offshore platform template (a four-legged conventionalsteel jacket structure) to the existing October production platform;

(d) to add two turbine driven compressors and associated facilities tothe platform extension to compress about 70 MMSCFD of associated gas from theOctober field; and

(e) to install additional processing facilities at the existing RasBakr gas processing plant comprising two stage compression, refrigeration anddehydration 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 wasreviewed by the Bank. The mission broadly agreed with the recommendationsmade in this study regarding the project. Further, the mission reviewed withEGPC the reservoir behavior and the production profile for both the Octoberand Belayim fields. The expected production profile for the Belayim andOctober 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 30October 50 60 70 70 70 55 40 30

Based on the above profile, the associated gas feed to the LPG plantswill be in the range of about 50 to 60 MMCFD up to year 2000, yielding about37 MMCFD dry gas for the pipeline and will later follow the natural declinebehavior of the oil reservoirs. While oil production is expected to decline,gas oil ratios will increase resulting in relatively lower decline in gasproduction rates.

Since appraisal, EGPC has awarded a turnkey contract to ENPPI forconsulting services for the Trans Gulf component. These include basic anddetailed 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 thebidding documents in accordance with ICB procedures for the Bank financedcomponents.

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Xnnex. MIPage 4 of 16

4. rtoAect Description

The project would consist of the following:

(i) Fabrication and installation of an extension to the existingoffshore platform of a template (a four-legged conventional steel jacketstructure) about 40 meters northeast of the existing October productionplatform, with a bridge connection to the existing platform; modifications tothe flare hook-up; blowdown systems; topside facilities, the installation oftwo gas compression units; and associated facilities, utilities andinfrastructure.

(ii) Construction of a 12 km extension to the existing 30-inchdiameter Sinai gas pipeline of a new 12-inch diameter submarine pipeline tolink the October field platform.

(iii) Installation of a new gas compression facility at the existingBelayim (within Petrobel's SAGP plant) to compress 37 MMSCFD of Belayim/Sinaigas.

(iv) Expansion of the Ras Bakr Facilities

-Installation of gas processing facilities comprising two gascompressor units, refrigeration and dehydration facilities inorder to process 107 MMSCFD of gas; of this, 40 MMSCFD of gaswould pass through existing unit 104 and 67 MMSCFD would besupplied to the Suez pipeline.

(v) Technical assistance, project management consulting services,surveys, inspection and engineering services.

(vi) Training of EGPC Staff relating to engineering, reservoirevaluation and planning pipeline network and gas processing. The location ofthese facilities are illustrated in Map No. IBRD 22905.

The existing Ras Shukeir gas compression and processing facilities andthe 16-inch diameter Ras Shukeir Suez gas pipeline were constructed under theBank-financed Gulf of Suez Project (No. 1732-EGT). The project componentsrelating to Ras Bakr and the 16-inch diameter loop line are considered anextension of these facilities. At the time of loan negotiations, assuranceswould be sought from EGPC that it would directly finance the Ras Shukeir-Suezpipeline component and complete it by the time the proposed Trans Gulf Gascomponent was commissioned; without this pipeline expansion, it would not bepossible to transmit the additional 67 MMSCFD of sales gas to Suez.

5. Project Implementation

EGPC would have the overall responsibility for implementing the proposedproject. However, various components of the project would involve otherentities: GUPCO would be involved in modifications at the October platformand other facilities; Petrobel would be involved with the Sinai/Belain

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AnmpxPage 5 of 16

components; PPC would implement pipeline components; and ENPPI would handleconsulting services, etc.

In order to speedily and efficiently implement the project, EGPC wouldform a Project Implementation Unit (PIU) headed by a project manager, whowould be responsible to the Head of Planning and Projects in EGPC. PIU wouldcoordinate and supervise various implementation functions necessary todesign, procure, construct and commission the project facilities. The otherentities would support PIU's program as follows:

(i) ENPPI, a 100 percent owned subsidiary of EGPC, would beresponsible for detailed design, procurement, project management andconstruction supervision; and

(ii) The construction and commissioning phase of the project wouldbe assigned - the following operating companies: (a) GUPCO for the Octoberfield offshore facilities and the Ras Bakr facilities; (b) Petrobel for gascompression and associated facilities at Belain/Sinai; and (c) PetroleumPipeline Company (PPC) for the offshore pipeline and the Ras Shukeir-Suezpipeline loop to the existing 16-inch diameter Ras Shukeir-Suez pipeline.

ENPPI. ENPPI has vast experience with the design, management andsupervision of similar projects in Egypt. ENPPI was actively involved insimilar projects under the two previously financed Bank projects, i.e., theGulf 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 forma project management team who would be fully responsible to PIU for thisproject in all its phases.

Proiect Implementation Unit (PIU). EGPC would staff the ProjectImplementation Unit (PIU) from the experts working on similar projects and, ifnecessary, from other operating companies with the requisite experience.Additional technical assistance requiring skill/equipment not available withinEGPC organizations would be obtained from local and expatriate consultingservices whose qualifications, experience and conditions of employment wouldbe satisfactory to the Bank and EGPC. During negotiations, the compositionand qualifications of the PIU unit would be reviewed by the Bank and the PIUteam would be agreed upon with EGPC.

Implementation Schedule. EGPC plans to complete the Ras Shukeir-SuezPipeline component by June 1992. The implementation issues relating to theremaining components would be discussed and finalized with EGPC duringnegotiations. In order to speedily complete the project, it would ')eessential to conduct offshore route surveys and finalize a detailedengineering 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'sprocurement guidelines. During negotiations agreement would be sought withEGPC on (a) the finalization of procurement and contracting tasks; (b)planning the project activities including preparation of a critical path plan

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Annex VIPage 6 of 16

of its activities leading to the award of contracts for onshore/onshoreactivities; (c) the quarterly review of the progress of the project with theBank; and (d) the appointment of independent third party inspection services.

6. Project Costs

The project is estimated to cost US$62.6 million equivalent includingcontingencies. of which US$50.5 million or 80 percent represents the foreignexchange component. A physical contingency of 10 percent was applied to allproject costs. The price contingencies are estimated based on a forecast offoreign inflation of 3.4 percent per annum and local iiZlation of 16.7, 11.1and 8.7 percent for FY92, FY93 and FY94, respectively.

The cost of material, equipment and installation is estimated at US$49.0million. Detailed engineering, project management, procurement andconstruction supervision costs are estimated at US$5.7 million. As discussedin para. 3, ENPPI has been designated by EGPC for the above-mentionedservices, to be financed by EGPC through their ongoing arrangements. ENPPIwould be assisted by some expatriate personnel. The average man-month costfor expatriates is estimated at US$15,000 per man-month and US$4,000 for localpersonnel. Other project related services, e.g., inspection, are estimated atUS$2.0 million and these would be procured by EGPC in accordance with the Bankprocurement guidelines. These estimates are based on current rates forsimilar services.

Duties and taxes on goods and materials are not included since EGPC isexempt from such payment. The estimated project costs, excluding interestduring construction, is summarized in below.

7. Financing Plan

The proposed Bank loan of US$35.9 million for the Trans Gulf Projectcomponent would finance about 60 percent of the total project cost, net ofduties and taxes, and would meet about 72 percent of foreign costs. All localcurrency expenditures, including duties and taxes, if any, would be financedby EGPC. EGPC would also finance, through its own resources, the totalexpenditures, both foreign and local for (i) an on-going contract with ENPPIfor the study, design, project management, procurement and constructionsupervision of the proposed Trans Gulf Project and the Ras Shukeir-Suez gaspipeline expansion component; (ii) and all expenditures, both local andforeign, for the Ras Shukeir-Suez gas pipeline component.

The proposed financing plan is summarized in Table 1.

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Annex VPage 7 of 16

Table 1

Prolect Financing PlaUSS million

Source of Funds LQcagj Total X -of Financing PlaI

IBRD - 35.9 35.9 597.6EGPC 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-drivencompressor package and offshore facilities on the October Platform.

- Supply, installation and commissioning of two gas-engine-drivencompressor packages and associated facilities in the Sinai/Belaim area.

- Supply, installation, and commissioning of two gas-turbine-drivencompressor packages and associated facilities at Ras Bakr.

- Supply, installation and commissioning of gas processing facilities atthe 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 13.4related services (4.4) (4.0) (2.0) (10.4)

Construction and consulting 8.9 8.9services

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.

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Amex VIPage 9 of 1 6

All Bank-financed procurement for goods and services would be inaccordance with the Bank's procurement guidelines. Detailed procurementarrangements and list of packages proposed for Bank financing are given inTable 2.

All major packages of material, equipment and services for EGPC and itsimplementing agencies would be procured in accordance with the Bank'sInternational Competitive Bidding (ICB) procedures except for the following:

(a) Contracts for equipment and inspection and similar services neededfor offshore operations, e.g., specialized equipment, instrumentsand specialized services (inspection and similar services), whichare available only from a limited number of suppliers, and whichdo not exceed an aggregate of US$3.0 million, may be awarded inaccordance with the Bank's procurement guidelines for LimitedInternational Bidding (LIB).

(b) Contracts for the equipment and material that are proprietary, orneeded to ensure standardization and compatibility witn theexisting equipment and facilities, which do not exceed in valuethe equivalent of US$200,000 each, and do not exceed in aggregatethe equivalent of US$2.0 million may be procured by directcontracting under the terms and conditions acceptable to the Bank.

All bid packages having a value of US$300,000 equivalent or greaterwould be subject to prior Bank review. Other contracts would be subject toselective post award review by the Bank.

In order to expedite procurement, all bid packages would be prepared byEGPC in accordance with the Sample Bidding Documents prepared by the Bank.Retroactive financing to the extent of US$5.0 million equivalent would bepermitted to cover advance contracting for the materials and equipmentprocured in accordance with ICB procedures, if acceptable to the Bank.

9. Disbursement

Disbursement of the Bank loan would be made against (a) 100 percent ofthe foreign exchange components of the imported equipment and material; and(b) 100 percent of the ex-works cost of equipment and materials manufacturedlocally and procured under ICB procedures, and 80 percent of the totalexpenditures procured locally off-the-shelf.

The disbursement profile essentially conforms with the statisticalprofile for Bank/IDA energy projects (e.g., oil, gas, refinery, energyconservation), excluding power projects. It is generally in line with thedisbursement profile of past Bank-financed projects in Egypt. Thedisbursement profile is based on (i) a three-month lag between the timeexpenditures have been incurred (according to the project implementationschedule) and the time funds are disbursed against this expenditure; and(ii) the loan becoming effective in November 1991.

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Annex VIPage 10 of 1 6

10. =WnLtoring and Renorting

Satlsfactory procedures for monitoring the progress of the project interms of physical executlon and financial reporting would be agreed with EGPCduring negotiations.

PIU would furnish to the Bank quarterly progress reports in a format tobe agreed wlth EGPC and the Bank. In additLon, EGPC would submLt monthlyprogress report to the Bank. Any major issues that are likely to hamper ordelay project implementation would be tmmediately communicated by EGPC to theBank.

11. Environmental IMRact

By minimlzing the flaring of associated gas in the Gulf of Suez, theproject would directly contribute toward the abatement of global warming andthe reduced emission of CO. in the atmosphere; it would indirectly contributeby displacing fuel oil, the additional associated gas from the Gulf of Suezarea, which would reduce the emlssion of CO, ln the area, particularly wherepower and chemical/industrial plants are located. The natural gas pipelines,both offshore and onshore, would not create any environmental problems, asoffshore lines would be laid on seabed and adequately protected, and onshorelines would be buried. Adequate monitor-ng arrangements would be installed onthese plpellnes to safeguard agalnst lea" and ruptures due tooverpressurization, corrosion and third-party damage.

Standard international petroleum industry practices and codes would befollowed for Gulf of Suez offshore installations, offshore and onshore naturalgas plpelines, and at Ras Bakr gas processing facilities. Safety distancesand appropriate safety codes would be applied for all gas processlng plants.The operations, maintenance, flre preventlon and pollution control measurestaken by EGPC ln the existing Ras Bakr gas processing facilities and by itsoperating companies (GUPCO and PETROBEL) ln offshore Gulf of Suez operationsare satisfactory. As a condltion of negotlations, EGPC would be requlred tofurnish to the Bank an updated quarterly environmental report lndlcating theircompliance wlth the standards satisfactory to the Bank. During negotiations,EGPC agreement would be sought that prior to construction, an environmentalreview of the proposed construction details would be furnished to the Bank forreview to ensure that all necessary environmentally mitigative features havebeen addressed.

12. Project RLsks

The offshore associated gas production from the October and Sinal/Belaimoil fields carry the normal geological and operatlonal risks inherent topetroleum production and process operations. Offshore gas operations poseadditional safety risks. However, the international oil and gas industry hasdeveloped sophisticated techniques and standard safety, operations andmaintenance codes that are being stringently followed by EGPC and itsoperating companies in the Gulf of Suez areas, both offshore and onshore. Asa result of this, EGIC operating companies have demonstrated a satisfactory

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Amrex MIPage 11 of 16

operating record in terms of safety and environmental impact. Therefore, thephysical risks in the proposed project are minimal. During the last Bank-financed project (LN 2103-EGT), stringent safety codes were followed and foundsatisfactory. 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 beenprovided.

The commercial risks for this project are minimal, as the associated gassupply is expected to be adequate over the project life, and the availAbilityof additional dry natural gas, LPG and natural gas liquids would significantlybenefit Egypt in terms of minimizing the cost of energy supply and reducingthe environmental impact of hydrocarbon fuel use.

H: %gbaed%agy%am*x6 . oar

TRANS GULF GAS COMPONENTDetailed Cost Flow

FY92 FY93 FY94 Total CostLoc. 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 0.3Basic 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 0.8Sinai/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 3.5Offshore 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 18.5Belaim/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 2.1West Bank FacilitiesGas Compressors 0.1 1.0 1.1 0.7 7.6 8.3 0.2 0.4 0.6 1.0 9.0 10.0Dehydration Unit 0.1 0.2 0.3 0.6 0.4 1.0 0.1 0.1 0.2 0.8 0.7 1.5Refrigeration Package 0.1 0.5 0.6 0.5 4.0 4.5 0.1 0.5 0.6 0.7 5.0 5.7Bulk 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 2.8Construction 0.2 0.3 0.5 0.6 2.0 2.6 0.2 0.4 0.6 1.0 2.7 3.7Consulting 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 52.2Physical 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 xPrice Contingency 0.3 0.9 1.3 0.7 3.7 4.4 0.2 0.7 0.9 1.2 5.4 6.6Base 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 0Total 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_yPage 13 of 16

Producton Data(as of 1/1/91)

Estimated Proven Oil Reserves . 4,500 MM BarrelsEstimated Proven Gas Reserves : 12,400 BCFNo. of Producing wells . 896Estimated 1990 Daily Production 873,000 B/DPercent Change From 1989 : +2.6 percent

R£eLnin

No. of Refineries .8Crude Refining Capacity : 523,153 BOPDThermal Operations : 16,470 BOPDCatalytic Reforming : 33,540 BOPDCatalytic Cracking . Nil

Gas Processing CaRacity(as of 1/1/91)

A. Summary

Total No.of Gas Processing Plants : 8Gas Capacity : 1320 MHSCFDAvg Gas Throughput During 1989 : 1188 MMSCFD S

Production (Average based on past 12 months

L.P.G. mix : 691,700 gallons/dayOther NGL : 1,158,500 gallons/dayTotal Products : 1,1850,200 gallons/day

1 To be verified with EGPC

B. Gas Processing U_its(Data us of 1/1/91)

Process ProductionComoanv 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 .... 84.9Dahshour, Abu Gharadig stabilizerDesert, Block 30

Egyptian General 132.0 124.0 Absorption/stabilizer .... .... 210.9Petroleum Corp. -Abu Gharadig field,286 km west of Cairo,Western Desert

Abu Nadi LTS plant and 242.0 236.0 Absorption/Cryogenic .... .... 203.0field, 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 .... 206.2offshore, 60 km eastof Alexandria

Dahshour, Abu Charadig 124.0 118.0 Cryogenic Expander 132.0 .... ....field, 65 km west ofCairo, Giza

Ras-Shukeir 177.0 131.0 Refrigeration/absorption/ 283.2 .... 190.7stabilizer

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 VIPage 15 of 16

Gas Com2ogitions/Plouct

Strea BelaYXLmLinai 9Sx8L:r mixed

Composition (NOL X)

H120 0.01 1.63 1.07C02 0.83 3.37 2.50N2 0.78 0.87 0.84CH4 65.74 57.24 60.14C2H6 19.57 14.43 16.19ONH 12.56 12.07 12.24I'4110 0.18 1.77 1.23tAH10 0.29 4.48 3.05C5H12 0.02 1.26 0.84C5H12 0.02 1.44 0.95C5H14 + I JA4 0.95Q.2

H2S (parts per million) 11 10 10

Design flows NMSCFD (dry basis)

EGYPTIMPLEMENTATION SCHEDULE

FOR TRANS GULF GAS PROJECT

DURATIONDESCRIPllON IN MONTHS

_ 1 2 3 4 5 _ 7 8 9 10 1112 13 14 15 11617 1819201211222 1N 2526 27 2 0031312 33ONSHO(EI OFFSHORE SURVEY

WF-4U4IET & DEWVERY

SStdB~AYtM AREAH 1IGASCOMPRESSOR 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 FACILITIEGAS 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 FOSBARCTOBID EVAWLATION *DEUVERY AT SrrEINTLAO

-PLACING FORMAL P.O. oceecc CONSTRUCTION WORK

S.umw ENPPl wpIAmlAw49097a

- 77 -

Ann-- VilPage 1 of 2

EGYPT

GAS INVESTMENT PROJECT

Gas Market DeveloRment

The Cairo gas distribution network consists of a relatively lowproportion of gas sales to commercial and industrial consumers. As the costof distribution to residential consumers is relatively high, primarily causedby cost of piping installation, and consumption is low, residential supply isless commercially viable than sales to other sectors. These issues need to beaddressed along wfth pricing so that a rational market development strategycan evolve. The market development strategy was discussed with Petrogas, andit was agreed that a study be initiated with the objective of reviewingstrategies to increase the penetration of gas sales to the commercial andindustrial market as well as to develop new markets, such as for gas-based airconditioning. The study should also identify the areas where the cost ofdistribution could be reduced or the operational capabilities of Petrogas beenhanced. For example, a building construction code should be developed andratified so that the new buildings in the existing or foreseeable gas areasare equipped with one gas piping installation during the buildingconstruction. Furthermore, the study should provide a training component tostrengthen 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 ofabout five engineers who would be trained in sales promotion inthe commercial and industrial markets. The members of this coreshould be capable of negotiating gas sales contracts withindustrial and large commercial consumers involving inter-fuelsrelationships, conversion costs and economics of gas use from thestandpoint of consumers. The unit should also include a womanwho would focus on the cooking aspects of natural gas use, payiugparticular attention to the changes in cooking practices thatwould 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 inAlexandria;

4. the improvement of emergency maintenance operations and customerservices;

5. the identification of cost reduction measures such asincorporating the installation of gas piping in the buildingconstruction codes;

- 78 -

Annex VIIPage 2 of 2

6. a study of the uses of supervisory control and data acquisitionsystem in maximizing gas distribution efficiency in Cairo;

7. the establishment of a computerized design and cost estimatecenter;

8. the improvement of safety engineering practices and thedevelopment of a modern reporting system; and

9. the identification of training requirements and the preparationand 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 refineriesare managed by boards of directors and operate the facilities for a refiningfee, ixed annually by EGPC. The refineries, except for three lube productionand one delayed coking facilities, are of simple hydro-skimming or toppingconfiguration and process domestic crude oils. Refined products are marketedby Misr Petroleum Company and the Cooperative Petroleum Company, both fullyowned subsidiaries of EGPC, as well as by Mobil, Esso and Caltex at the retaillevel.

2. There are significant mismatches between the production of refinedproducts from domestic refining and demand, resulting in significant exportsof fuel oil and naphtha and imports of gas oil and LPG. The surplus of fueloil is expected to increase with the increased substitution of fuel oil bynatural gas. EGPC has been planning to install secondary processingfacilities to convert surplus fuel oils to higher value distillates, includinga hydrocracker.

3. In order to develop a rational investment program over the next 5to 10-year time frame for the refining and distribution subsector, EGPCintends to carry out a consultant study, as well as acquire in-houseinstitutional capabilities in the methodologies and techniques for medium tolong-term investment planning. The objectives of the investment program wouldbe to minimize the cost of products supply, consistent with future demandgrowth and with the product specification changes over time.

4. Consistent with the above-mentioned objectives, the consultantwould carry out the following tasks.

a) Future demand estimates: The consultant would analyzehistoric consumption, by major energy and non-energyproducts, with reference to the major factors that affectdemand such as GDP growth, prices of competing products,automobile fleet growth, population etc. and would developappropriate equations to explain historic consumption and toproject demand over the period up to the year 2005. Thedemand projections would take into account the increase ofgas use.

- 80 -Annex VIIIPage 2 of 3

b) grices: The consultant would develop scenarios forpetroleum and product prices translated to each refinerylocation and to each major distribution storage point in thecountry, for purposes of economic comparison of variousinvestment options as inputs to investment planning model.

c) Matbematical model for investment planning: The consultantwould develop a mathematical model (suitable for EGPCcomputing systems) that would be capable of analyzing theimpact of investment options on the cost of product supplythrough a combination of domestic refining, imports andexports. For this purpose, the consultant would considerall domestic crude oils and an agreed list of four foreigncrude oils for refining at each existing refinery location.

(d) Investment Program: The consultant would run the developedmodel to determine the effects on costs of product supply,consistent with the demand projections, of the followingoptions: (i) import all products to meet demand withoutdomestic refining (for the purposes of establishing areference case); (ii) supply products while operating therefineries 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 newinvestments; (iv) supply products under optimized crudeslate and imports and exports, and use new process unit andenergy conservation investment options at each refininglocation. The model's logic and structure should be capableof handling variations in input data, and of expressing thedefined objective functions as discrete output. Capitalcosts used for investment options inputs should have anaccuracy 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 modelsoftware;

(iv) capital and operating cost estimates for investmentoptions;

(v) recommendations on future investments at any or alllocations, capital cost estimates and a time schedulefor the implementation of such investments; and

- 81 -Annex VIII

Page 3 of 3

(vi) a data base on the crude oil analyses used for modelsoftware generation and on investment optionsanalyses.

f) Two representatives of EGPC would participate with theconsultant for the duration of this study. The consultantwould submit a draft report six months after the effectivedate of the contract, for review, comments and discussionswith EGPC and the World Bank. Following the receipt of suchcomments, the consultant would submit the final study reportwithin six weeks. Concurrently, t'"e consultant wouldinstall the model at EGPC and train EGPC personnel in thehands-on use of the model.

M: \ubared\say\arwex9. sar

- 82 -

Annex TXPage 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 inEgypt. Currently, over 85 percent of the total oil production comes from over50 oilfields in the Gulf of Suez area. Associated gas is produced with oil invarying quantities, dependent on gas oil ratios and other reservoircharacteristics.

Egyptian General Petroleum Corporation (EGPC) is currentlyutilizing some of the associated gas to supply Egyptian consumers. However,some associated gas is being flared. As the oilfields are depleted, the gasoil ratios tend to increase, whilst oil p.oduction declines and increasingrelative quantities of associated gas continue to be produced. In addition,EGPC and other international oil companies (IOCs) operating in the Gulf ofSuez area have been exploring and have discovered new oil and non-associatedgas fields. With continued exploration, there is a high probability offinding additional oil and gas reserves in the near future.

Obiective

The objective of the proposed study is to update the previousstudies and:

(i) to evaluate the present and the prospective gas supply potentialof the Gulf of Suez area with a view to maximize the utilizationof associated and nonassociated gas and minimize the flaring ofassociated gas;

(ii) to develop an optimal transmission and distribution systemintegrating the existing gas transmission and distribution systemwith the medium- and long-term gas development and utilizationplans; and

(iii) to provide EGPC with the economic evaluation of various investmentscenarios based on a phased-gas development strategy to meet themedium- and long-term gas demands of Egypt.

ScoRe of Wo-rk

In order to achieve the objectives of this study, the consultantor the entity undertaking the task would:

- 83 -

Annex IX

Page 2 of 2

(i) review the geological, reservoir and production data on the oiland gas fields in the Gulf of Suez and Sinai area;

(ii) collate and integrate the data relating to the availability ofrecoverable gas reserves (both associated and nonassociated) anddevelop gas deliverability profiles for the next twenty years;

(iii) review the gas prospects from the fields discovered but not yetdeveloped, as well as evaluate potential gas reserves in the Gulfof Suez area;

(iv) review past and present development costs for the existing fieldswith a view to prepare investment plans to optimize theutilization of (a) associated gas from existing fields; (b) thedevelopment of gas discovered from new fields, both oil andnonassociated gas in the Gulf of Suez and Sinai areas; and (c)est:imate the costs for discovery and for the development of newgas prospects;

(v) review the existing gas gathering, transportation compression anddistribution system;

(vi) review the gas demand forecast of EGPC for the medium and longterm;

(vii) evaluate transmission and distribution options with a view tooptimize the existing system and develop least-cost options forinvestment in gas transmission and distribution systems;

(viii) make recommendations that would enable EGPC to prepare itsinvestment plans to maximize gas development and utilization fromthe Gulf of Suez and Sinai area; and

(ix) prepare an environmental assessment consistent with the guidelinesof the Government and the Bank.

U: %dw*\aqvmz1O. seg

- 84 -

Annex XPage 1 of 2

GAS INVESTMENT PROJECT

Cost of Gas Distribution

Terms of RefeLrnce

Thie current tariffs charged by Petrogas have remained unchangedsince 1981 and bear little relation to the costs of distribution or toalternate fuel costs. In order to achieve the anticipated financial andeconomic benefits from the GCGDEP, it is important that a new and moreappropriate tariff structure for residential and commercial consumers is putin place.

In addition, the contractual and regulatory environment fornatural gas distribution shoutld be examined and appropriate changesimplemented. This is particularly important if Petrogas is to extend naturalgas distribution to a substantial number of larger commercial consumers (e.g.,hotels, hospitals etc.). For these consumers, a proper framework of contractsand obligations is essential.

The study would:

1. assess the current level of tariffs in relation to the pattern ofconsumption and costs of alternative fuels (both current andexpected);

2. calculate the appropriate fixed and variable costs to be allocatedto gas distribution;

3. advise on practices adopted by other gas utilities both indeveloped and developing countries;

4. address the particular aspects of gas distribution in Egypt thatcall for specific tariff structures;

5. determine the best practice for offering incentives to commercialand small industrial consumers to convert to natural gas;

6. formulate a set of contracts for Petrogas sales to commercial andsmall industrial consumers;

7. assess the status of gas distribution within the legal frameworkprevailing in Egypt and advise on any changes to ensure properregulation of gas distribution; and

- 85 -Annex XPage 2 of 2

8. formulate a complete tariff structure and contractual frameworkfor all classes of consumers to address the requirements ofeconomic efficiency in fuel Oistribution and financial viabilityfor Petrogas.

This study should be carried out with the assistance ofconsultants as soon as possible, preferably prior to the commencement of gasconsumption under the project. There should be a very close link between thework 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 actualachievements and supplied to the Bank at agreed intervals on the followingaspects:

(a) procurement action by bid packages (bid specifications, bidinvitation, opening of bids, bid evaluation, award of contract,signing of contract and contract price as amended from time totime);

(b) physical progress according to project components and contracts(highlighting critical activities and bottlenecks);

(e) actual project costs and expenditures (local and foreign) andestimated remaining expenditure (local and foreign) projectedquarterly through project completion;

gd) disbursement schedule (for the Bank loans and other loans);

(e) information on problems encountered during implementation (includingmajor 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 asfollows:

miaeLLQ COMpositi2D Proposed Dates

Project launch mission Gas (upstream) Specialist September 1991Gas (downstream) SpecialistFinancial Analyst

Project supervislon and Gas (upstream) Specialist March 1992Study revLew Gas (downstream) Specialist

Energy EconomistFinancial Analyst

Project supervisLon Gas (upstream) Specialist Twice/yearGas (downstream) Specialist 1992-1994Financial Analyst

Project supervision Gas (downstream) Specialist Twice/yearFinancial Analyst 1995-1997

N:%dienAs*&7%=e1Leet

- 87 -

Annex XIIPage 1 of 9

CAS INVESTHENT PROJECT

EGPC Financial Performance

1. Domestic Energy Prices: assumed to reach 100 percent of internationalprices by FY96 including alignment of the petroleum and official exchangerates by the start of FY91.

2. Crude Oil Output: assumed to maintain current output levels of 870,000bbls/day until FY93 then decline by 4 percent per annum thereafter.

3. E=yvt's Share of Oil Production: residual after assumed foreign oilcompany cost recovery of US$1,600 million, to a minimum of 70 percent and amaximum of 85 percent.

4. Condensate: assumed to be 15 percent of equivalent natural gasproduction, with 50 percent available for petroleum product production.

5. Refinery OutRut: current capacity of 21.4 million metric tonnes assumedto be increased by 10 percent in both FY92 and FY94, with the same productslate.

6. Crude Oil Exports: residual after refinery requirements and 5 percentrefinery losses.

7. Petroleum Product Demand: product demand growth based on assumed priceelasticities (-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 percentof equivalent natural gas sales to the power sector, 67 percent of equivalentgas sales to industry, and 100 percent of gas sales to construction andcement. Gas-oil demand reduced by 33 percent of equivalent natural gas salesto industry.

9. Product ExVorts: difference between refinery output and domestic demand.

10. Product Exnort Revenues: increased from FY90 base by assumed changes ininternational crude oil prices.

11. Gas Production Cos;s: based on assumed output from "old" versus "new" gasfiel' . and an assumed price of 40 percent of fuel oil equivalent for "new"gas.

12. Domestic Product Sales: based on estimated sales and assumed domesticprice changes (see point 1) for petroleum produczs and Petrogas purchases ofnatural gas (see Petrogas asstumptions).

- 88 -

Annex XIIPage 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 averagepetroleum product purchase costs, which are assumed to increase with inflationand output.

15. 2natin&--Costs: asstmed to increase directly with inflation andproduction.

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 taxassumed as per historic average.

21. Surplus Payout: set to 75 percent of income after tax as per historicaverage.

22. Working Capital: set to maintain current ratio of 1.1 excluding cash usedas balance item in projections.

H: \shared\gry\annexl3 . ar

- 89 -hab RFmbrie of EgYM Annex XII

ILvem-mog Page 3 of 9Actual mid DriecteV FG Sfor-EGPC

01-Apr-91 AsswmqIr

EY-88 Y yn FY91 FY92 FY94 FY95 fY96 FY97Price Assumoticna Ys 9Local 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 188Foreign Pr.Andex (FY91=10 86.4 93.8 97.1 100 105 105 106 109 113 118Real Exchange Rate Devaluation 0% 0% 0%/0 0% 0% 096Petroleum Exchange Rate 0.70 0.70 1.03 2.31 3.95 4.67 5.20 5.50 5.62 5.66Exchange Rate (LEI$) 2 2.38 2.65 2.91 3.95 4.67 5.20 5.50 5.62 5.66

International Crude Oil PricesBank 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 ForecastCrude Oil (S/bbl) 15.4 15.0 18.8 20.9 18.9 17.9 19.1 20.3 21.8 23.6Crude Oil ($/bbl 1990 price 17.8 15.9 19.3 20.9 18.0 17.0 18.0 18.6 19.2 19.9Annual 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% 100oLPG 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%hGas 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 478LPG(p/litre) LEtbottle 1.5 2.0 3.3 4.3 6.2 8.5 9.3Gasoline (p/litre) 56 72 97 96 99 107 117Kerosene (plitre) 10 20 33 43 62 84 91Gas Oil (p/litre) 10 20 34 44 65 89 97Other 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 478LPG (LEtmt) 120 160 262 343 499 682 744Gasoline (LEtmt) 783 1012 1360 1340 1391 1504 1642Kerosene (LEImt) 126 252 412 537 776 1053 1150GasOil(LE/mt) 120 240 407 533 778 1064 1161Other Products (LE/mt) 100 200 224 265 298 327 357

- 90 - Annex XIIAlabReoub&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 FY6E9fyj~~ ____~ 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 739Pecent 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 27,613In 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 M0LPG 280 285 285 0 0 0 0 0 0 0GasolineTN~ha 3,380 3,400 3,400 3.400 3,400 3,740 4,114 4,114 4,114 4,114Kerosene 2,447 2,530 2,530 2,530 2,530 2,783 3,061 3,061 3.061 3,061Jet Fuel 170 170 170 170 170 187 206 206 206 206Gasliesel Oi 3,613 3,600 3,600 3,600 3,600 3,960 4,356 4,356 4,356 4,356Fuel il 10,380 10,450 10,450 10,450 10,450 11,495 12,645 12,645 12,645 12,645AspthsX 583 651 651 651 651 716 788 788 788 788Lube 00 185 208 206 206 206 227 250 250 250 250Othem 307 343 343 343 343 378 416 416 416 416Total 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 1,420ratio actual to est. exports 124% 119% 91% 100%

Petroleum Product 0e0 mt)LPG (70) (60) (20) 0 0 0 0 0 0 0Butane Gas (79) 28 41 0 0 0 0 0 0 0Naptha/Gasoline 1,106 1,270 1,428 1,210 1,178 1,537 1,814 1,751 1,711 1,675Kenosene 92 66 318 563 1,437 1,416 1,337Jet Fuel (30 (52) 224 237 255) (2457 (258) (278) (300) (322)Gas OWDiese (676 (779) 774 968) 827) 245) 34 312 297 134Fuel OI 636 884 1,022 77 1 140 4,687 6,210 5,494 4,876 3,887Bunker Fuel 1,378 1,716 1,952 1,834 1,834 1,834 1,834 1,834 1,834 1,834Other 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 8588Total Expowts 3,151 3,944 4,494 3,213 4,218 8,450 10909 10966 10226 8910Total Imports 1,125 1,091 1,018 1,230 1,108 802 258 278 300 322

-91 - Annex XIIPage 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 2,896Fuel Oil Power 4,144 3,993 4,143 4,535 3,712 1,676 1,656 2,422 3,136 4,027Gas Oi 1,022 1,043 1,012 1,060 987 895 826 804 788 819Gas Oi Tmnspont 3,065 3,128 3,361 3,518 3,441 3,310 3,226 3,240 3,271 3,402Kerosene 2,406 2,422 2,358 2,438 2,464 2,465 2,498 1,624 1,645 1,724Gasoline 2,121 2,096 2,174 2,190 2,222 2,203 2,300 2,363 2,403 2,439Jet Fuel 390 390 390 407 425 444 463 484 505 527Lube Oils 185 206 206 208 206 227 250 250 250 250Other A 1020 1 0201. 1.020 1.02 1.020 1j065 1.112 1.161Petroleum Products 87497 11 1619368 18241 15538 1518 15146 15908 17246

Natural ¢as §aeLmilKncubic meters)Domestic 60 65 70 73 76 85 97 110 123 138Commercial 0 1 2 2 2 6 14 22 31 40FertiTcer 1,147 1,161 1,251 1,147 1,323 1,530 1,612 1,864 1,685 1,706Constr/Petrol 719 710 922 1,726 1,768 1,933 2,078 2,098 2,202 2,305Industry 743 828 931 2,129 2,212 2,305 2,398 2,491 2,594 2,698Power CC/CT 4,105 4,377 2,580 2.801 2,532 3,204 3,918 3,918 3.918 3,918Power 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 1,504Commercial 140 158 193 199 204 207 207 207 206 205Investment Companies 3 6 6 6 6 6

Total 759 792 846 847 824 840 852 1,709 1,721 1,715

Revenues from PetroasGas Revenues 192 232 315 412 662 1,595 2,428 3,843 5,741 6,295LPG Revenues 7 8 9 39 78 104 162 647 9866 1,435

Average Increase ofPetroleum + Gas Supply 6%Y 1% 5% 6% 1% 0% 1% 3% 3% 4%

Annex XIIPage 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 1,091Avg Rev (LEln mid 1990 pr 132 99 137 277 336 327 355 377 394 410Avg. Rev. ($mt mid 199 pr $128 $101 $111 $120 $104 $96 $103 $107 $111 $115Avg Rev. Wbbl current $14.9 $12.7 $14.5 $16.2 $14.7 $13.9 $14.8 $15.7 $16.9 $18.3Discount 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 0Naptha 162 182 224 211 186 230 289 296 311 330Kerosene 23 15 67 126 341 362 370Jet Fuel 3E) (2) (28 ((33) (32 (30) (32) (37 (43) (50)Gas OiVDiesel (97) (109 (137 (190) (147 41 54 59 61 30Fuel Oil 57 63 84 7 94 367 518 487 465 401Bunker Fuel 146 164 203 212 192 182 194 206 222 240Other 4 15 20 I f 28 73 59 42 21

Total (mln. $) 221 285 366 219 298 802 1,222 1,412 1,418 1.341Total (min. LE) 155 200 378 506 1,179 3,745 6,352 7,763 7,966 7.594Tal 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 3.312Gas Oi Transport 548 1,063 1,711 2,162 3,144 4,317 4,902Kerosene 307 621 1,016 1,340 1,260 1,733 1,983Gasoline 1,716 2,248 2,997 3,082 3,286 3,615 4,006Jet Fuel 51 107 183 249 376 532 607Other 123 245 279 337 392 446 -4Total Petroleum Products 2006 2152 2271 517 42 6861 8 10046 13243 15314

osts an uRevenuesFuel Dcosi( lmi) 74 72 90 101 91 a6 92 98 105 114Gas 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 6,295NetGasRevenues(LE) 182 217 278 311 395 824 1,387 2.620 4,325 4,687

-93 Annex XIIAra Rob of E Page 7 of 9G-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 FY97Domesi Sales

Petroleum Products 2,006 2,152 2,271 3,172 4,882 6,861 8,048 10,046 13,243 15,314Crude Oil 248 338 175 0 0 0 0 0 0 0Natural 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 SalesCrude Oil 913 763 922 3,078 4,352 3,578 2,293 1,943 1,542 1,091Net Petrol Products 120 2 378 506 1..79 3.74S 6.352 7.763 7.96fi -594Sub-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 30,957Share 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 EXpenSeSCost 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 692DePreCiatiOn 140 119 154 205 260 360 478 610 754 907ROYaltieS 120 100 187 215 332 471 571 714 864 929FOreinr Exchange Losses 0 0 0 17 50 83 90 92 88 81IntereSt & 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 3,994Distr;bUted to Govemment 1,033 864 780 2,064 3,516 5,231 6,333 8,679 11,155 11,983Reserves 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 XIIPage 8 of 9

01-Apr-9101-Apr-91 -(~~~~~est) lest) (Zm (estl (est) lest) lest)

ASSETS _88 FY89 FY90 M91 FY9 £9i FY94 FY9_ F-96 f

Net Cash 950 815 746 864 1,017 1,621 2,501 4,165 6,688 9,580Current Assets 1,100 1,200 1,890 2,604 3,650 4,"5 6,030 6,990 7,982 8,547Ivestments in Affiliates 2,925 3,135 3,135 3,135 3,135 3,135 3,135 3,135 3,135 3,135Propelty, Plant & EquipmentAt Cost 1,528 1,830 2,005 2,273 2,889 3,996 5,308 6,780 8,378 10,073Less 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 7,770Long-terrn Debt

Foreign Banks 268 239 309 593 900 929 814 626 401 163Domestic Sources 124 128 108 95 83 71 58 46 33 21

Equity 300 300 300 300 300 300 300 300 300 300Reserves 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 28,955EQUITY

- 95

Arab Reo"bib d E Annex XIIGas!rivestnientLoaii Page 9 of 9

Actual and DrojectF tteets for EGPCSource 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 21,282Depreciation 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 0Local Debt 45 8 0 0 0 0 0 0 0 0Equity 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 FundsIncome Taxes and 395 333 321 869 1,514 2,277 2,766 3,809 4,909 5,277Social BankDebt ServiceInterest 25 23 20 48 70 72 69 57 43 28Repayment 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 79.3Operating 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 1.1Current 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 XIIIPage 1 of 7

GAS INVESTMENT PRQJECT

Pet. gas. Financia. Proiection Assumptions

1. Domestic Energy rices: assumed to reach 100 percent of internationalprices by FY96 including alignment of .he petroleum and official exchangerates by the start of FY91.

2. LPG Retail Prices: fuel component assumed to reach international pricesby FY96, plus distribution costs assumed to reach 30 percent of the economiccost of US$150/mt by FY96 and 100 percent by FY98.

3. Retail Domestic Gas Prices: set to an average of 19.8 piasters/cubicmeter in FY92 and thereafter set to the fuel oil equivalent, plus a marginsufficien to cover operating costs and the average incremental cost ofnetwork 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 300additional commercial customers in both FY91 and FY92, thereafter as perproject 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 valuedassets.

7. Foreign Exchange Losses: amortized at 5 percent per annum.

8. Wazes and Salaries: increased by local inflation and an el.-ticity of0.75 with respect to gas sales.

9. Income,Tax: effective tax rate on income before tax of 25 percentassumed.

10. LPG Sales: assumed to be supply driven and equal to the historic averageof 13 percent of equivalent gas production.

11. Cost of LEG Sold: set to 15 percent of the distribution cost component ofLPG sales.

12. Surplus Payout: by law 2 percent of income before taxes is paid to theNasser Social Bank plus 85 percent of after-tax-income; however, to achieve a25 percent self-financing level, the retention of almost 90 percent of incomeafter taxes under current depreciation rules is necessary.

13. Cash: used as balance item in projections and as a proxy for requiredequity 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 domesticcustomer and LE 400 per additional commercial customer.

H: \sharad%\\a=exzt . ser

Annex XIII- 97 -ageTof7

Arab Reoubhc of EgvytGas Investment Loan

Achal and Prolected PetDoass Financial SummaryIncome Statement

(LE million)01-Apr-91 (eat) (est) (est) (est) (est) (est)

FY87 FY88 FY89 FY90 FY91 FY92 E93 FY94 FY95 FY96Natural Gas SalesDomestic 5.0 5.3 5.7 6.3 8 12 18 28 46 70Commercial 0.1 0.2 0.3 0.5 1 1 2 4 9 18Industrial 178.0 234 396 726 1,078 1,733 2,636PowerStations 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 59Total 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 5,741Sales Margin 16.7 28.0 32.3 39.1 15.6 138.0 139.4 145.7 167.6 187.7Margin 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 51.5Foreign Exchange Losses 0.0 2.1 4.5 5.3 6.2 6.7wages & Salaries 5.0 7.2 8.3 8.9 12.1 17.4 24.3 27.6 29.1 30.8Other Faxed Coats 0.9 0.1 0.1 0.0 2.4 3.5 4.9 5.5 5.8 6.2Other Costs 1.5 1.3 1.5 1.6 2.2 3.3 4.9 5.7 6.0 6.3Total 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 86.2Interest Expenses 2.6 2.4 2.2 3.0 6.6 10.3 10.5 10.2 9.2 7.9Income 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 78.3Surplus 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 RevenuesDomestic 36.5 40.9 43.2 55.5 84.8 105.5 163.9 218.9 747 1,029Commercial 28.2 35.1 54.3 71.1 103 140Investment Companies 1.4 1.3 1.7 1.7 U 44 _5. 6.0 7 4Total 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 73Appliance Sales 17.6 26.2 25.6 28.9 35.6 44.3 51.9 57.4 122 129Services Revenues 3.4 3.3 6.9 11.6 13.9 17.3 20.3 22.4 48 50EGPC Subsidies 7 06 0.0 .0. 0 0.0 0 2Total 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 1Cost of LPG 7.1 6.7 7.6 9.0 39.3 78.4 104.4 162.2 647 966Cost of Cyclinders 15.6 10.9 9.3 11.0 19.1 23.8 27.8 30.8 65 69Cost of Appliances 9.5 2.6 3.8 4.5 33.8 42.0 49.3 54.5 116 123Total Cost of Sales 32.2 41.1 47.8 56.6 92.2 144.2 181.5 247.5 829 1158Sales 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 96Wages & Salaries 17.7 19.9 23.3 26.7 32.9 41.0 48.0 53.1 113 119Other Fixed Costs 5.9 9.9 10.2 12.3 14.8 18.4 21.6 23.9 51 54Other Costs 3.8 5.3 5.9 6.9 8.5 10.5 12.4 13.7 29 31Total 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 -32Interest Expenses 0.0 0.0 0.0 0.0income 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 -32Combhned Gas & LPG Operatio sNon-Operating Revenues 7.1 8.5 12.7 14.5 18.4 24.5 30.1 33.2 35 37Non-Operating Expenses 4.3 5.4 10.0 11.3 14.4 19.2 23.5 26.0 28 29Nasser Social Bank 0.1 0.2 0.3 0.3 0.1 2.0 2.6 1.9 1 1Net 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 54W/C Subsidy Reserve 0.6 0.7 1.0 0.0 0.6 0.0 0.0 0.0 0 01st DivWiends 4.4 5.5 7.3 7.8 4.8 7.8 0.0 0.0 0 0Govt. Admin Charges 0.0 0.0 0.0 0.3 0.0 7.3 0.0 0.0 0 02nd Dividend Shareholders 0.0 0.0 0.0 2.2 0.0 49.2 0.0 0.0 0 02nd 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 0DlstrlbutedtoEmployees 1.1 1.4 1.8 2.7 1.2 18.4 0.0 0.0 0 0Reservs Retfaned 1.5 1.9 2.5 2.0 1.6 14.8 126.1 92.4 67 54

Annex XIII99 Page 4 of 7

Aab Peot of EgyrA

Actual and Proiected PetMras Financial SuMmaryBlabne Sheet

(l.E mooinOl-Apr-91 (est) (od) (eat) (eat) (eat) (et)

FY87 FY88 FY89 FY90 FY91 FY92 FY93 FY94 FY95 FY96ASSETSGros Historic Fxed Assets 255.7 26.1 288.7 339.9 388.1 417.1 461.3 1,018 1,624 1,V'1Less: 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 0Gross Rb alued FiXed Assets 255.7 269.1 288.7 339.9 388.1 417.1 481.3 1,018 1,624 1,991Less: 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 521Other Long Tern Assets 4.6 4.9 6.9 6.6 8.1 10.5 12.2 13 14 15

Current AssetsCash 42.0 59.4 73.1 47.4 68.1 5.8 (352.6) -728 -860 -1,145Accounts Receivable 26.2 58.4 51.0 63;5 64.9 120.9 368.1 480 760 1,083Others (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 EQUITYCapital 146.1 148.7 151.2 156.5 156.5 156.5 156.5 157 157 157Total Reserves 50.9 71.9 80.8 93.8 95.5 110.3 236.4 329 396 450Reval 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 33CoInswer 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 862Others 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 Eavotnas Invedment Loan

Actual and Projected Petroaas Finarcial SummaivSource 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 FY96SOURCES OF FUNDS - - -

Net Income Before Interest 9.4 11.2 14.8 19.4 13.0 105.9 1386.6 102.7 76.7 61.5Depreciation 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 96.4 101.8EGPC Contribution 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Consumer 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 0.0Payments 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 XIIIPage 6 of 7

Arab eubc of Eavts Inestment Loan

Actual and Proecd Petraas Financial SummavNatural 3asBalance Sheet

(LE rrIllign}(est) (est) (esl) (eel) (est) (esl)

FY87 FY8B FY89 FY90 FY91 FY92 FY93 FY94 FY95 FY96ASSEISGross Historic Fixed Asss 165.5 173.3 190.0 240.5 281.7 302.8 337.4 549 777 1,031Less: 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 0Gros Revalued Fixed Assets 165.5 173.3 190.0 240.5 281.7 302Q8 337.4 549 777 1.031Less: 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 266Other Long Term Assets 2.5 3.9 4.1 2.6 3.3 4.2 4.9 5 6 6

Cufrern AssetsCash 41.6 40.8 53.2 34.4 65.0 (9.4) (84.2) -152 -232 -334Accoudts Receivable 20.3 49.2 44.2 51.6 53.4 105.0 347.1 467 678 957Others (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 EQtUITYCapita 100.7 103.2 105.7 111.0 111.0 111.0 111.0 111 111 111Total Reseves 35.4 39.0 58.6 85.9 66.1 81.1 156.6 223 299 380Reval 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 26Consumfe 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 718Otder 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 XIIIPage 7 of 7

OnInvedm Loan

A" mW Pr LEd mEdmmFnni uatuval 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 89.6Depecio 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 96.4 101.8EGPC Contbb. Gas 0.0 2.6 2.5 5.4 0.0 0.0 0.0 0.0 0.0 0.0Consurrw 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 0.0Paymets 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 connectionsat the time of laying pipelines in new areas produces a high and historicallypredictable 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 priceof gas, and to Petrogas's marketing efforts. It is assumed that pricingreforms and an improved marketing performance by Petrogas (promoted bytechnical assistance under the project) would result in the target number ofcustomers being achieved.

Gas Consumptio

Residential Consumption

Average gas consumption in the residential sector is estimated on thebasis of average consumption on the current distribution system. Since 1987,consumption has been relatively stable at around 240 cm/yr. This level ofconsumption is below the levels expected at the time of the first phase ofGreater Cairo gas distribution. Two factors appear to be acting to depressapparent usage:

(i) A substantial proportion of the Egyptian housing stock isunoccupied, and these customers are registered as having used no gas,which lowers recorded average consumption. The opinion of Petrogas isthat between 5-10 percent of apartments are unoccupied in lower incomeareas but that in upper income areas, the proportion is 20-25 percent.When average consumption figures are adjusted to exclude unoccupiedresidences, the average usage per household rises to 279 cm. WhilePetrogas endeavors not to connect unoccupied apartments (at its ownexpense) during the coverage of a new area, it is likely that theproportion of unoccupied apartments will be about the same in the nextphase of Cairo gas distribution.

(ii) The relative prices of gas and LPG, and the structure of gasprices, have create a substantial incentive to limit gas consumption tothe first slab (22.5 cn/month) and to use LPG for any additionalrequirements. Some consumers may have been using gas for cooking andLPG for water heating. The increase in LPG prices in May 1990 removedthe incentive to use LPG in place of gas, but it is too early to assessthe 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 remainingLPG appliances to gas, and the elimination of the incentive to restrictconsumption to the first slab, which should increase averageconsumption.

Trend growth in average household consumption of 1 percent per annum isanticipated, mainly due to the LPG substitution referred to above and to theincreased use of gas for water heating as living standards rise (currentappliance density per household is about 1.6). It is assumed that the priceelasticity of demand is very low, since gas cooking and water heating areessential services. There is, thus, likely to be little response to theanticipated long term raising of prices to economic le-els.

Commercial Consumgtion

The average consumption of commercial users is also estimated on thebasis of current consumption. However, there were only 363 commercialcustomers in FY90, compared with the 5000 expected to be connected under theGCGDEP. The average of 4900 cm/yr may not be fully representative ofconsumption potential, due to the following reasons:

(i) Gas to commercial consumers is, at present, priced well above thecost of LPG and gas oil. Hence, commercial consumers have the sameincentive as residential consumers to limit gas consumption and use LPGor gas oil where possible.

(ii) Few sizeable consumers (hotels, hospitals, large restaurants) areconnected to gas, and none are using it to its full potential.Incorporation of these consumers wouldl raise the average consumptionlevel.

Based upon experiences in other cities, an average of 6000 cm/yr percustomer is considered reasonable for the start of the project (FY93), wheninitial LPG and petroleum product pricing reform will have created a greaterincentive 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 theservice 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 ofelectric heaters leadL to their substitution by gas heaters where consumershave 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 befor LPG. with 10 percent for gas oil, which is used by larger consumers forwater heating.

- 105 -

Annex XIV

Page 3 of 7

Industrial substitution is based upon surveyed fuel use in the targetedfactories, 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 pricesand the economic costs of transportation and delivery.

Although Egypt's modest imports and exports are in balance, there is anexcess of potential demand over supply for LPG. Despite future growth insupply as more gas is utilized, in the long run the LPG requirements ofEgypt's rapidly growing population can only be met by imports. Hence the cifprice of LPG is used to value the LPG displaced by gas. This is taken as theMediterranean LPG price, adjusted for freight to Egypt (US$20/ton).

Allowance is also made for the substantial transport, bottling anddistribution costs of LPG. This has been estimated at US$150/ton, based uponeconomic costs provided by Petrogas. The main cost components are as follows(capital and operating costs):

USSZton

Port Handling and Transport to Bottling Plant 20Bottling Plant 25LPG Cylinders 85Transport and Distribution of Cylinders 20

TOTAL COST 150

The capital intensive nature of LPG means that most of this costrepresents imported capital equipment.

For gas oil, the cif price is taken, reflecting Egypt's substantialcurrent deficit in middle distillates. This price is adjusted for freight toEgypt, 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 priceforecasts.

Base Fuel Values and Costs (USS/ton)

Transport, Storage &1990 Price and Basis Distribution Adjustment

LPG 219 (cif) 150Fuel Oil 80 (fob) 15Gas 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 tradeablepetroleum products with lower cost gas, natural gas distribution yields abenefit to consumers due to its convenience and security of supply. It isgenerally recognized that consumers are willing to pay a premium for naturalgas over LPG, reflecting its superior qualities in use. In the absence ofdirect market data in Egypt, this willingness to pay has been approximated bythe costs borne by consumers to obtain a quality of service from LPG thatapproximates 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 totheir apartments; and (b) the imputed rent of the space occupied byLPG cylinders.

- The security of supply benefit of natural gas has been approximatedby the holding cost of a spare LPG cylinder (which is held by mostconsumers to guarantee availability of LPG).

Using average costs observed in Cairo, the value of these consumerbenefits for the purposes oi economic analysis has been estimated at US$30 perton of LPG displaced for residential consumers and US$15/ton displaced forcommercial consumers.

It should be mentioned that industrial consumers benefit in a similarmanner from the replacement of fuel oil and gas oil with natural gas, sinceconversion to gas reduces working capital requirements (for stored oilproducts) and usually lowers the operating and maintenance costs of boilers.Since these benefits will vary widely between users, no attempt has been madeto value them, and, in this sense, the valuation of the benefits of gassubstitution to industry is conservative.

MA: \hared\gary\annex5. sar

EGYPr GAS INVESTMENT LOAN IOREATER 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 5000Industrial 2 8 13 1a 22 22 22 22 22 22 22 22 22 22 22 22 22 22CONSUMPTlN PER UNIT (an

Resudtal 245 247 250 252 255 257 280 262 265 288 270 273 276 279 281 284 287 290Commenc 6000 6300 6815 6948 7293 7658 6041 d443 8865 9308 9773 10000 10000 10000 10000 10000 10000 10000Industtbt (mIr) 3050 3080 3111 3142 3174 3205 3237 3270 3303 3338 3389 3403 3437 3471 3508 3541 3578 3812GAS SALES (nEcm)

ResdntIal 5753 17433 29345 41494 53883 60468 61073 61634 62301 62924 63553 64188 64830 8547s 66133 6870s 67463 88137Commewdal 3000 9450 18538 24310 32819 38288 40203 42213 44324 46540 48867 50000 50000 50000 SOO0 50000 s5ooo 500S0Industiral 3050 15402 32867 48704 63473 70518 71224 71936 72855 73382 74118 74857 75605 76361 77125 77898 78675 79462Total 11603 42284 78549 114508 150174 16927S 172S00 175833 179280 182845 186535 189045 190436 191840 193256 194891 196138 197599FUELSWJ9SWtUTEOOns)

ULF 6796 20928 35760 51261 67469 76757 78627 00571 82583 84695 88883 86215 80738 69285 69796 00336 90870 91428Fuel 06 1357 6851 14531 21664 2t233 31367 31681 31998 32318 32641 32967 33297 33030 33986 34306 34649 34996 35346ri0 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 21.4LPG (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.? 369.7 369.7 369.7 369.7 389.7Fuel 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 95.3GMON o0(t Tamsp.& DIaL) 193.7 168.7 195.1 202.1 210.4 218.7 227.0 235.3 236.5 236.5 234.5 232.5 230.5 230.5 230.5 230.5 230.5 230.5Tampoet Dstdabn Coa OUaIMut LPG Sub efts

UIlon USln of IPOLP 1SO Realda" 30Fudl 0 1s CommterIal 1SGo0 (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 33.60Fud 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 3.37amON 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

uXWEEFITS 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 20.2O4M * 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 2.00oa 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 14.60Tdl 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 4.22GM 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 XIVPage 7 of 7

ARAB REULCOFEGP

GAS INVESTMENT LA Trn u Gas O

Cagital Cost AssumDtionsLocal Cost = 25%Foreign Cost = 75%

Product Mix AssumptionsFeed Gas = 70 MMSCFDProducts = 60 MMSCFD Gas

35 Tons/Day LPG900 BbVday Condensate

Capdal Cost O&M Production Revenue (US$ million) NetYear TGGC Ploeline Cost Profile 1/ Gas LPG Condensate Revenue

FY91/92 10.3 15.0 8.34 -33.64FY92193 38.1 15.0 8.34 42 24.16 1.12 3.48 42.68FY93/94 7.5 5.0 8.34 52 29.06 1.45 4.18 13.84FY94/95 8.34 62 35.97 2.05 5.17 34.86FY95/96 8.34 62 37.35 2.20 5.37 36.58FY96/97 8.34 62 38.97 2.21 5.60 38.44FY97/98 8.34 45 29.51 1.61 4.24 27.02FY98/99 8.34 28 19.15 1.00 2.75 14.57

FY99/2000 8.34 15 10.70 0.54 1.54 4.44FYOQ(01 8.34 14 9.91 0.48 1.43 3.47FY01/02 8.34 13 9.18 0.42 1.32 2.58FY02/03 8.34 12 8.50 0.39 1.22 1.77FY03104 8.34 11 7.87 0.38 1.13 1.02FY04/06 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> ~ /

AIRPORTRAS ABU RUDEI$' P

OctoberField12

ToSuez - 1 2Km Poin

o Rasker a r169 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~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~1ew E S T F acial, ens

BANK BELAYI

MEOITfRAtN SEGAS ARAB REPUBLIC OF EGYPTGAS INVESTMENT PROJECT

TRANS GULF COMPONENT___ ~~~~~~~~~Proiec Existi ng:

OFMA A ON LAND PIPELINESARABIA OFFSHORE SUBMERGED PIPELINES

LBA ARABREPULIBLYIC AA \NJ MEASURINGANDCONTROLSTATIONSOF E GYP T * COMPRESSION STATIONS

BUL-ROADS

SUDAN BU ILT- UP AREAS

ARAB REPUBLIC OF EGYPT

GREATER CAIRO GAS DISTRIBUTION PROJECT

' ks Nos' Cay< i1th 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