Report No. 7662-VAR

Yemen Arab RepublicEnergy Strategy Review

January 31, 1990

Industry and Energy Operations Divis;onCountry Department IlIlEurope, Middle East and Africa Regional Office

FOR OFFICIAL USE ONLY

Document of the World Bank

This document has a restricted distribution and may be used by recipientsonly in the performance of their official duties. Its contents may not otherwisebe disclosed without World Bank authorization.

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CURRENCY EOUIVALENTUS$1 - 9.75 Yemeni Rials (YR)

C9NVERSION FACTORS

TOE/Metric SpecificFuel Tonne Gravity Liters/Tonne

LPG 1.06 0.56 1,785Gasoline 1.03 0.72 1,351Kerosene 1.01 0.80 1,240ATF (Aviation Fuel) 1.01 0.80 1,240Diesel/Gas Oil 1.00 5.85 1,176Fuel Oil 0.94 0.96 1,041

1.0 TOE - 10.2 X 106 kcal - 40.5 X 106 BTU - 40,500 cu'. feet;1.0 GWh - 86 TOE, 1.0 kWh - 860 kcals (net calorific values; note that netcalorific values are 5X less than gross for oil and 9X to 10X less than grossfor gas).

CONVERSION FACTORS FOR GAS

Thousand Cubic Feet (mcf) - 1 Million British Thermal Units ((MMBTU)38,500 cf - 1 t of fuel oil0.12 mmcfd - 1 t of fuel oil/year

ABBREVIATIONSbbl Barrelbpd Barrels per daycif Cost, insurance and freightERR Econrmic rate of returnESR Energy Strategy Reviewfob Free-on-boardGDP Gross domestic productGOY Government of the Yemen Arab RepublicGUS Gas Utilization StudyGVH Gigawatt hourLPG Liquified petroleum gasMEW Ministry of Electricity and Watermmcfd riillion cubic feet per day (gas)MOMR Ministry of Oil and Mineral ResourcesNPV Net present valuePSA Production Sharing AgreementSCOMR Supreme Council for Oil and Mineral Resourcesstb Stock tank barrel (oil)scf Stock tank cubic foot (gas)TCF Trillion cubic feetTOE Tons of oil equivalentt Metric tonUOP/CS UOP Processes International Inc./ChemsystemsYAR Yemen Arab RepublicYEPC Yemen Exploration and Production CompanyYEPIC Yemen Exploration and Productior. Information CenterYGEC Yemen General Electricity CorporationYHRC Yemen Hunt Refinery CompanyYHOC Yemen Hunt Oil CompanyYOMINCO Yemen Oil and Mineral Resources CorporationYPC Yemen Petroleum Company

FISCAL YEAR

January 1 to December 31

FOR OMCIAL USE ONLY

YE1 AM REPUBLIC

RERGCY 'ITRAUEGY - sc

Table of Contents

Pwae

EXECUTIVE SUMMARY ................................................. i

I. THE ENERGY SECTOR ........................................... 1A. Linkages to the Economy ................................. 1B. Energy Policy and Planning .............................. 3C. Sectoral Institutions ................................... 4D. Demand and Supply Overview .............................. 8E. Pricir.g, Demand Management and Conservation .... ......... 9F. Environment . ............................................. 11

II. HYDROCARBON RESOURCES ................... .................... 12A. Oil Exploration ........... .............................. 12B. Reseries and Production ................................. 14C. Gas Resources and Availability .......................... 16

III. PETROLEUM PRODUCTS DEMAND AND SUPPLY ......... .. ............. 19A. Demand and Supply Balances .............................. 19B. Marib Refinery ............ .............................. 22C. Storage Facilities .......... ............................ 23D. Ras Issa Port and Storage Project ....................... 24E. Second Refinery Project ................................. 25

IV. POWER DEMAND AND SUPPLY .................. ................... 27A. Demand . ................................................. 27B. Generation and Transmission ............................. 29C. Future Capacity Requirements ............................ 31 U

D. YGEC's Management and Financial Situation ..... .......... 34

V. LIQUIFIED PETROLEUM GAS .................. ................... 35A. Demand ................................................... 36B. Imports and Potential for Domestic Production .... ....... 37C. Bottling, Transportation and Distribution .... ........... 38D. Pricing and Institutions ................................ 40

VI. NATURAL GAS UTILIZATION .................. ................... 42A. Potential Demand ........... ............................. 42B. Pipeline Project .......... .............................. 43C. Economic Evaluation ....................... ........... 45D. Pricing ......... 46E. Strategy ......... 49

VII. INVESTMENT OPTIONS, STRATEGY AND RECOMMENDATIONS .48

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.

Table of Contents (Continued)

Page

I-1 Energy Balance - 1988 ......................................... 571-2 Evolution in Gross and Final Energy Consumption (1988 and 2005) 581-3 Growth in FLnal Energy Demand (1988 and 2005) .611-4 Domestic Unit Prices of Petroleum Products .62I-5 Petroleum Products - Real Price Index, Consumer Prices and

Economic Cost .63

III-1 Historical Consumption of Petroleum Products (1975-88) ........ 64III-2 Historical Consumption/Supply Balances for Petroleum Products

(19R4-1988) .65III-3 Historical Regional Consumption and Estimated Future Demand

for Petroleum Products (1985-2005) .66III-4 Petroleum Products Demand Projections and Operational Storage

Requirements (1990-2005) .67III-5 Petroleum Product Storage Capacity ............................ 68rII-6 Ras Issa Product and Crude Storage ............................ 69III-7 Second Refinery Project - Economic Analysis .... ............... 70

TV-1 YGEC - Power Sales Projections ..... ........................... 83IV-2 YGEC - System Operating Data Projections - Oil Option ......... 84IV-3 YGEC - System Operating Data Projections - Gas Option ......... 85IV-4 YGEC - Inveitment Projections - 1989-2000 .......... ........... 86nV-5 YGEC - Financial Projections ...... ............................ 87

V-1 LPG Project Components and Cost Estimates .................. 91

VI-1 Economic Analysis of Alternatives for Gas Utilization ......... 92

NAP (IBRD 21606)

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I~~~~~~~~~EE ARA NUMA

KNUGY STRAT E v

Rxecutive Suarv

1. The purpose of this report is to assist the Government of the YemenArab Republic (GOY) in analyzing YAR's energy sector, addressing issuesrelated to its development and formulating an appropr:tate strategy. Thereport includes analyses of and recommendations on energy investments, policyoptions and operational aspects of the sector, based on information collectedby a World Bank mission which visited YAR in February/March 1989-

2. This Energy Strategy Review (ESR) is part of the World Bank'scontinuing effort to keep abreast of developments in YAR's energy sector. Itprovides a follow-up to parts of the World Bank's February 1987 report "YemenArab Republic: The Impact of Recent Oil and Gas Discoveries on theMacroeconomy and Energy Investment Options" which followed earlier sectoralreviews. Since macroeconomic Rspects of the sector were covered in the Bank'srecently issued Country Economic Memorandum,t 2 these are not addressed In anydetail here.

3. Draving extensively on studies and other work done under the ongoingTechnical Assistance to the Petroleum Sector (IDA Credit 1702-YAR ofSeptember, 1986), which was in part co-financed by the Governments of theUnited States of America and the Netherlands, the ESR contains eight chapters.They deal with overall energy sector aspects, YAR's hydrocarbon resources, thedemnd and supply of domestic petroleum products, electric power demand andsupply, the potential for utilizirng indigenous liquified petroleum gas (LPG)and natural gas resources, a possible sectoral strategy, and a summary listingof the recommendations suggested by the ESR. The report is vritten keeping inmind the GOY policy-makers as its principal audience and places its mainemphasis on issues which require GOY's attention in the near future.

4. In our viev, tog oriority should be qiven by GOY to addressinR thefollowing major issues:

(i) the availability and deliverability of natural gas which needs to beascertained with urgency in order to permit its early utilization inplace of costly imported fuels in pover generation and cementproduction;

/ The mission was composed of Messrs. Burmeister (Senior Operations Officerand Task Manager), Ansari (Senior Petroleum Specialist), Crosetti (EnergyPlanner), Krishnamurthy (Senior Petroleum Specialist), Maveni (FinancialAnalyst), Mostert (Energy Economist), Sheorey (Senior Power Engineer),Shirazi (Senior Gas Specialisi) and Soncini ( Senior Financial Analyst).Mmes. Csekey and Dennis provided word processing assistance.

2/ Yemen Arab Republic - Country Economic Memorandum - Agenda for SustainableGrovth during the Oil Era (May 18, 1989).

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(iL) design and implementation of a proposed, economically highlyattractive gas pipeline project estimated to cost between US$lY)million and US$220 million, together with an appropriatefinancing strategy; by 1994, gas could replace up to 500,000tons per year of mostly imported fuel oil, resulting in netannual savings of US$50-80 million; in power generation the useof natural gas could significantly reduce capital and operatingcosts of the system vis-a-vis fuel oil use;

(iii) the need for strengthening the organization, management andfinances of YGEC, for increasing tariffs and eliminating costlyinefficiencies in the supply of electricity, including highauxiliary consumption and excessive line losses, and forincreasing its power sales in order to bring its profitability inline with the levels agreed with IDA;

(iv) the need to provide an increased power supply in the mid-1990's;investment requirements up to 2000 in generation, transmissionand related areas are estimated at US$661 million if natural gasis available, and in excess of that amount if it is not;

(v) the availability for domestic consumption of 120,000 tons/year ofLPG that can be produced at the Safer oil and gas fields, toreduce YAR's dependence on increasingly scarce and costlyfirewood (now providing over 50X of YAR's energy requirements),imported LPG currently at a rate of 96,000 t/y (costing aboutUS$20 million) and other petroleum products;

(vi) implementation of other energy related projects including (a) newterminal facilities at Ras Issa, a deep sea port location, toreceive and store imported petroleum products at lover cost; (b)replacement of the floating crude oil export storage facility byon-shore tankage to proviea export coerations with greaterindependence from maintenance and weather-related factors andreduce environmental risks; and (c) a multi-products pipelineup-country from Ras Issa to reduce the cost of petroleum productstransportation; investment requirements for the combined Ras Issafacilities without the pipeline are estimated at US$107 million;

(vii) to ensure that YAR can derive the maximum benefit from itshydrocarbon resources, the enhancement of MOMR's capabilities inorganizing, planning and administering activities in thepetroleum sub-sector;

(viii) a clear definition by GOY of sectoral objectives and theestablishment of a coherent pricing policy;

(ix) the definition of YAR's hydrocarbon prospects and the setting ofa coherent hydrocarbon exploration policy which are requiredbefore GOY can proceed with a long-term exploration program; and

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(x) the proposal to build a second petroleum refinery in YAR at acost in excess of US 350 million, which was found tc beeconomically unattractive and should not be pursued at this time.

5. The following sections provide an overviev of the main findings,conclusions and recommen0ations of the ESR.

6. Sectoral Policies. In order to guide GOY's decisions on sectoralpricing policy, investment alternatives and institutional reforms, and toeliminate and prevent the recurrence of distortions currently found in YAR'senergy sector which resulted from conflicting objectives in the past,priorities need to be established among the mltle objectives in the sector.Basic tools such as data bases and evaluation and planning mechanisms arerequired for strategy formulation, project selection and general programmingin support of proper planning functions the in sectoral ministries.Responsibility for strategy development which is now often split betweensub-sectoral ministries, should be more clearly defined. To permit effectivedecision-making, YAR's institutions and organizations in the energy sectorneed to be made financially viable and their manpower, skills and expertiserequirements must be adequately met.

7. Institutions. The need to improve GOY's institutional capabilities isone of the major issues confronting an effective energy strategy in YAR. SuchImprovements will require (i) the continued use of foreign expertise toenhance the transfer of technology; (ii) the formulation of appropriateorganizational structures at MOMR and its affiliates, subject of a recentUSAID-funded study, and at YGEC; these are needed by virtue of the growingimportance of the energy sector in YAR and its increasing lin'Vs to theinternational economy; and (iii) development of appropriate long- andshort-term manpower planning, including ways to attract and train capableYemeni personnel at all levels of sectoral activities: the public sectorenergy organizations are hampered by civil service payscales which are notcompetitive with those of local, let alone, foreign private sector companies.

8. Pricina. YAR's energy pricing policy has not always provided userswith the correct signals for achieving a rational use of energy and itsconservation. Most energy prices are controlled by GOY and are rarely adaptedto variations in the corresponding economic cost3. This tends to favor theinterest of consumers at the expense of the financial health of the oil andpower companies; consequently, subsidies are needed which must come from GOY'sbudget. Overall, energy prices are above their respective economic costs;however, the prices nf diesel oil and LPG were often lower and should be keptat levels at least otuivalent to their economic costs to preventmis-allocation of resources. Since the major impediment to LPG use is thehigh initial cost incurred by consulers in switching from other fuels,subsidization of LPG is not an effective promotional measure. Although powertariffs appear to be significantly above the economic cost of supply, theyneed to be increased in the short term in order to meet YGEC's financialrequirements.

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9. Hydrocarbon Resources. YAR's hydrocarbon resources have been underexploitation since 1986; crude oil has been exported since late 1987 when apipeline was inaugurated from the Alif Azal oil fields at Safer to the RedSea. Oil operations, including the pipeline and crude shipments, are handledby Yemen Ezploration and Production Company (YEPC) and Yemen Hunt Oil Company(YHOC). Present institutional arrangements within GOY are under review andsome corrective measures are being adopted but have not yet been implemented.Ezisting hydrocarbon operations are ruled by a Production Sharing Agreement(PSA) betwGan COY and YEPC/YHOC which is in need of revision to facilitatecrude oil and gas operations. So far, GOY has not established a well definedDolic! or comprehensive Ieaal framework covering YAR's oil, gas and mineralexploration; these should be developed as soon as possible.

10. Since 1987, proven reserves in the Alif field have been revised frominitial lower estimates to about 1 billion stock tank bbls (stb) of oil inplace. In addition, four other recently discovered smaller fields areestimated to contain about 800 mmstb, increasing YAR's estimated total oilreserves to about 1.8 billion stb; some 50X of this quantity is thought to berecoverable. It is imperative that COY and YEPC reach an early agreement onan oRtimam production program to ensure the efficient exploitation of YAR'soil reserves without damaging the reservoirs.

11. Up to now, natural gas discoveries have not been appraised ordelineated, in part due to the still unresolved gas ownership issue underArticle 27 of the PSA. GOY should take all necessary steps to resolve the gasownershin issue vith YEPC to permit the rapid development and utilization ofthe natural gas resources in order to replace the imported fuel oil now usedIn power generation and cement productior. Estimates for associated andnon-associated gas reserves range from a conservative 6.1 trillion cubic feet(TCF) to an optimistic 15-20 TCF quoted in some trade journals. GOY shouldcommission a brief review of the gas subsecto- to identify the economicallyviable gas discoveries and recommend programs for their development.

12. Petroleum Products Demand and Suuplv. Some 30X of YAR's domesticdemand is currently being satisfied by a small hydro-skimming refinery locatedat Safer, with the remainder being supplied by imports. Although growth indemand has been substantial in recent years, based on our estimate of futuredemand an expansion of YAR's refining capacity would not be economical becauseimported refined products are expected to be available at lower prices thanwhat it would cost YAR to produce them. Our analysis takes into account (i) arecent consultant study on the viability of building a second refinery (with athroughput of about 60,000 bbl/day of mostly domestic crude and an estimatedcost in excess of US$ 350 million) and (ii) reasonable assumptions fordomestic demand growth, international crude/product price ratios, crude oilprices and capital costs. A second refinery project would not be economicallyattractive, even when assuming an adequate domestic crude oil supply, so farnot certain, and an indefinite delay in implementing an economicallyattractive natural gas pipeline.

13. In order to reduce the cost of petroleum product imports, GOY shouldstudy the installation of gort storage and giDelinIn& facilities at Ras Issa.Such an installation would result in freight savings by permitting the use oflarger and on a per-ton basis, less costly tankers and by reducing the needfor costly up-country trucking. At the same time, on-land storage facilitiescould be installed for crude oil exports. On a preliminary basis, we estimatethe Ras Issa facilities (excluding the products pipeline to Bajil or Sana'a)to require an investment of US$107 million. To allow for the proper planningof nev regional storage facilities, current arrangements for gathering andanalXzing regional data concerning petroleum products supply and demand shouldbe strengthened. The sunDly of fuel oil by the Marib refinery to coastalpower plants which does not appear to be economical vis-a-vis imports shouldbe discontinued.

14. Power Demard and Supgly. Electric pover is supplied mainly by twolarge power plants via a pover grid operated by YGEC which also operates anumber of diesel generating stations. In addition, there are privatelyoperated generators supplying industries and rural households. Total 1988pover consumption is estimated at 766/Gwh, of which 545/Gwh was supplied byYGEC. If current demand pro4ections materialize (based on connection to thegrid of major industrial consumers currently generating their own power and a6X annual growth of non-industrial demand), and when alloving for someimprovement in YGEC's low efficiencies, its existing excess generatingcapacity will have been absorbed and additional capacity may be needed asearly as 1994. New as well as the existing power plants should preferably befueled by natural gas, the most economic form of energy. GOY should thereforeascertain with urgency the adequate and timely availability of natural gasvhich could be delivered by pipe-line to the principal pover consumption areas(Sana'a - Mabar, where new generating capacity should be located) and to RasKhatenib where the existing plant could be converted to natural gas use.Completing power plant feasibility studies requires considerable lead time.Therefore, a delay in the decisions beyond early 1990 on the implementation ofthe 8as gipeline could cause a delay in constructing new power plants which inturn could result in the need for pover load shedding in the mid-1990's or innew generating plants having to be designed for costly fuel oil firing. Sinceeach year's delay of the pipeline could cost US$50-80 million in foregonesavings, a delay would clearly not be in YAR's interest. YGEC's overallinvestment requirements in new power generation, transmission and distributionfacilities as well as in the normal development of the system through 2000 areestimated at US$661 million assuming gas-based generation.

15. YGEC's financial condition calls for immediate improvement throughreductions in inefficiencies as well as rationalization and increase ofelectricity tariffs. Most importantly. there must be a reduction in YGEC'shigh auxiliarX consumption in power generation, presently of about 10 in theinterconnected system and 15X in the isolated systems, and the excessivetransmission line losses, presently of 25X (including non-technical losses);the ongoing line loss reduction and other studies should be completed andappropriate recommendations implemented quickly. Frequent shortages of spare

aarts nd mate:?ials also need to be addressed by GOY with urgency in order to

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roduce YGECTs costs and to enhance its financial viability, considering itsimportant role in YAR's groving energy sector. YGEC's oraanization must bestrongthoned, enabling it to cope with an increasingly wide range ofactivities; appropriate planning, budgeting and control functions and othersodern management techniques need to be introduced. Computerization andtraining, particularly in sub-station maintenance, are inadequate and shouldbe addressed.

16. The majority of rural and urban households use electricity. Most ofthem, however, rely on small and costly private power generation. At theappropriate time, GOY should undertake studies to determine an optimal,least-cost rural electrification strategy', taking into account the fullspectrum of possible technological options c..d institrtional arrangements.Such studies should eventually lead to the formulation of a ruralelectrification master plan based on an assessment of the benefits of gridextension vs. continued private autogeneration, which would develop technicalstandards and economic criteria for doing so, assess alternatives toconventional rural electrification, and define the best institutionalarrangements to ensure an effective and economic rural power supply. Sinceconventional electrification of many rural areas would require heavysubsidization, the master plan should keep in mind the rate at which fundingwould be available for this purpose. In the meantime, COY should encouragethe private sector to develop and demonstrate an economicallv viable-ubotoltaic system suited to rural households not reached by YGEC supplies.

17. LPG Demand and Supplv. The depletion of YAR's fuelwood resourcescould occur within 15-20 years if existing patterns of household energyconsumption continue, with serious consequences for welfare particularly amonglower income households and the environment. Apart from COY's efforts toincrease biomass resources which is expected to be supported by IDA's SecondNational Agricultural Development Project planned for 1991, steps mnst betaken to accelerate the substitution of fuelvood use especially with LPG.Such steps include an increase in the availabil .ty of LPG and cylinders aswell as support for the introduction of low-cost and efficient LPG appliancesand bread-ovens; measures such as these could reduce fuelwood consumption by500,000 t/yr.

18. GOY has initiated a "crash program" to substitute LPG from theAlif/Azal and other oil/gas fields for costly LPG imports and fuelwood. ThisLPG, currently being reinjected into the oil fields because of a lack ofstorage and loading facilities, may be adequate to supply YAR's domesticdemand (currently about 96,000 t/year) into the next century.

19. Bottling caRacits is currently being increased from 82,000 to136,000 t/year at the Hodeidah plant. Under the "crash program" and anothernew project, several plants are being or planned to be installed in otherregions. Also bulk truck loading/unloading facilities are to be provided atSafer, as well as road tankers and an additional supplv of LPG cylinders.

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20. Institutional changes, possibly involving the establishment of a newaaencv for LPG production/bottling that can operate as an autonomous entitywithin the confines of well-defined Government policy, would be beneficial.The development, institution and enforcement of safety codes and standards forsafe and smooth LPG operations and handling are important as a prerequisite toassure optimal efficiency in all LPG activitLes. They are essential to permitfostering private sector involvement in the integrated chain from bulktransport to bottling to distribution, with GOY agencies eventually limitingthemselves to planning and control over all private LPG activities.

21. Natural Gas Utilization. As stated earlier, GOY should give toppriority to developing YAR's important natural gas resources and making themavailable for domestic consumption. Gas resources are estimatedconservatively at 6.1 TCF which, if confirmed, would be adequate to providefor much of YAR's energy requirements for many decades. We have reviewed apipeline Droiect study prepared by consultants, focussing particularly cn thetwo most practical and economically beneficial routing alternatives analyzedtherein, namely from the Safer oil/gas fields to Sana'a/Amran and to bothSana'a/Amran and Bajil/Ras Khatenib. The pipeline which is estimated to beeconomically highly attractive, would supply gas principally to existing andfuture power and cement plants, replacing their use of mostly imported fueloil. For the two routing alternatives the project's capital cost is estimatedat USS 139 million and US$ 220 million respectively, excluding financialcharges.

22. As stated in para. 14 above, for any new gas-based power plant to beoperational by 1994, GOY needs to reach decisions on proceeding with the gaspipeline before early-1990. This decision will need to be based or.ascertaining that adeauate quantities of gas are available and can bedelivered by that time. Also, preparation of a coordinated gas developmentplan is needed. Steps towards implementation of the pipeline should becoordinated under an action plan which will need to include institutionalmeasures, such as formation of a qualified project team and coordinationmechanisms with the oil company as soon as pertinent agreements with YEPC arereached.

23. The economic viability of using natural gas as feed-stock forexport-oriented industries (such is fertilizer, petro-chemicals or alumina) isnot attractive at present given YAR's limited raw material base and domesticdemand for such products, unfavourable world market conditions, strongregional competition, the large investment requirements and technologicalconstraints. The viability of such projects, however, should be reviewedcarefully from time to time as conditions may change.

24. Investment Options and Strategy. In summary, the following are theseveral investment options which GOY should pursue with priority, togetherwith order-of-magnitude estimates of their costs and implementation times:

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priority Investment Options

EstimatedCost Estimated

(1126 millionn1 mplementation

LPG Production and Utilization 40-60 1989-1991Natural Gas Development and Pipeline 139-220 1990-1993Rar Issa Petroleum Handling andStorage (including for crude shipment) 107 1990-1993

Petroleum Products Pipeline not available 1990-1993Regional Petroleum Products Storages 35-40 1990Nev Pover Generation, Transmission,Distribution and System Improvements 661 1989-2000

25. The ongoing program to make domestic LPG available to replace importsshould be vigorously pursued. At the same time, the overall hydrocarbonpotential of YAR needs to be assessed; this should result in the fcrmulationof a coherent hydrocarbon exploration strategy to attract private sectorinvestors. Provided sufficient quantities of gas are available ar.ddeliverable, realization of the pipeline project to supply natural gas shouldreceive GOY's priority since it is economically highly attractive and couldresult in tangible savings to the economy at an early time. Studies for theRas Issa petroleum handling and storage facilities, the petroleum productspipeline and regional storages should proceed and resulting projects beimplemented as soon as possible. Investments in power generation,transz.ssion, etc. should proceed as now planned.

26. GOY should develop a core investment plan for prolects in the energysector on the basis of which the World Bank and other international lenderscould be approached for funding. Arrangements for financing merit GOY's earlyattention, as do decisions regardirg the Involvement of the grivate sector inthe structuring, design, implementation and funding of the above projectswhose scope and complexity go well beyond YAR's institutional capabilities.The substantial capital requirements could rapidly absorb YAR's oil revenues,and ways need to be sought to finance them without overly burdening GOY'sbudget; "build-operate-transfer" or similar arrangements with outsideinvestors could be envisaged whereby projects would be implemented andoperated by them for a pre-determined period and then transferred to GOY aftermuch or all of the investment had been amortized and Yemeni staff trained totake over. GOY should seek professional help in exploring such possibilitieson the basis of pre-feasibility studies which could be funded in principlefrom such sources as IDA's Technical Assistance Credit.

YEMEN ARAB REPUBLICENERGY STRATEGY REVIEW

I. THE ENERGY SECTOR

1.01 The Yemen Arab Republic's economy is predominantly rural andcharacterized by low income vith a per capita gross domestic product (GDP) ofabout US$450. Its population of about 9.9 million is videly dispersed overmostly rugged terrain, making the provision of basic services andinfrastructure costly. With the exseption of hydrocarbons, YAR is poorlyendoved vith natural resources. Agriculture which accounts for much of YAR'sdomestic labour force and about 30X of GDP, is constrained by erratic andgenerally low rainfall and the Increasing scarcity ot groundwater as well ascultivatable land. The manufacturing sector (10 of GDP) consists mainly offood processing, building materials and metal working industries. 10% of GDPis accounted for by utilities and construction, leaving 50X in services whichincludes 12 percent in Government.

A. Linkages to the Economy

1.02 Linkages between the overall economy and the energy sector areestablished by both external and internal events. During the 1970s, YARenjoyed rates of GDP growth of nearly 9X fuelled by remittances from Yemeniexpatriates working in the Arab Gulf region: these averaged about US$900million per year and amounted to about half the GDP. Since the expatriateYemenis originated in all regions of the country and typically transferredtheir savings to their home villages, the increase in income benefitted widesegments of the population. As a result, the difference in average incomebetween YAR's rural and urban areas has been modest. This situation ended inthe early 1980s when the lower level of economic activity in the Gulf causedby falling international oil prices led to a fall in expatriate remittances;ttese greatly exceeded the concurrent savings on YAR's petroleum import bill.GOY's adjustment efforts included drastic cuts in investments and imports andresulted in much lower GDP growth which has averaged less than 5X per yearsince 1983.

1.03 The discovery of oil and gas in 1984 improved somewhat YAR's economicprospects. Oil production started in the beginning of 1986 at the level of10,000 barrels (bbl) per day (bpd) to feed a small refinery at the Alif oilfield near Safer, Marib Governorate. Following completion of a 240,000 bpdpipeline, oil exports began in late 1987 at the rate of 130,000 bpd and havemeanwhile been increased to over 180,000 bpd. Assuming future production at aconservative rate of 150,000 bpd and based on the World Bank's current crudeoil price forecasts, GOY's share of oil revenue in the early 1990s could be inthe order of US$700 million per year, representing more than a quarter ofprojected budgetary revenue. The production of hydrocarbons would contributeclose to 15X of GDP, generating more than 90X of YAR's export income. As faras the balance of payments is concerned, the net receipt of foreign exchangefrom oil exports has done little more than to compensate for the US$600million decline in annual private remittances and foreign aid since the early1980s, filling gaps in government revenues and export earnings. Therefore,

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the optima'. depletlon of the oil and gas resources can be defined only withreference to the technically optimal extraction: identified natural gasreserves seem to be large enough compared to potential demand so thatnostretching of output is needed; the oil reserves, on the other hand, are toosmall to justify strategLc limitations on output. Nor is accelerated oildepletion justified: the resulting gains in interest income would more thanlikely be outweighed by the impact of a reduced overall level of extractionand the potential gains from the rise in real crude prices that is likely tooccur in later years.

1.04 Mannower. Employment in the modern energy sector is limited to some(,000 employees, one third of vhich work in the oil sector and two thirds, inthe power sector; this amounts to 0.4X of YAR's labour force. The energysector's demand for scarce specialized technical skills is high, placing greatdemands on YAR's educational system and resources available for fcreigntraining and expatriate assistance. GOY has taken valuable measures toaddress this situation in general, but due to the long lead times needed ined.ucational investments, YAR will have to continue to rely on expatriates formany years. The skills intensity in the energy sector is related to thesector's high investment requirements. During the 1980s, average annualenergy investments amounted to some US$200 million, split about equallybetween the power and hydrocarbon sectors. This represented almost one fourthof gross national investment, a ratio which is likely to recur in the 1990s.Because the investments are import intensive, their effect on the balance ofpayments is large while their impact on local activities is more modest.Since the rate of overall economic growth is related to the productivity ofinvestments, misguided and mismanaged investments in the energy sector canadversely affect the rate of YAR's economic growth; therefore, the rates ofreturn on proper training in the energy sector are particularly high. It isthus recommended that GOY continue to give high priority to skills trainingfor all parts of the energy sector, with particular emphasis on operationsmanagement and project definition, selection and implementation.This will require the continued intensive involvement of outside technicalassistance.

1.05 Industrial promotion. In the absence of a proper definition of YAR'snatural gas reserves (see Chapter II) it is too early to say whether they arelarge enough to permit considering gas export schemes. The gas reserves aresufficient, however, to permit substitution for domestic consumption of oilproducts and thereby replace petroleum product imports and increase crude oilexports. If the potential supply of natural gas should prove to be muchlarger than the foreseeable domestic demand, GOY may eventually wish toidentify additional productive uses for natural gas by attracting energyintensive export industrLes (see para 6.05). However, the prospects for suchindustries if any, need to be evaluated carefully. Contractors are oftenanxious to create work for themselves and may make strong cases for projectswhich are not economlc. Projects that make use of gas as feedstock to producetradeable commodlties are usually characterized by high risks and a highcapital and, correspondingly, low employment intensity. Therefore, it isparticularly pertinent that the Investment appraisals be based on realisteic

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forecasts of international markets and prices and recurrent cost requirements.Also, the potential for beneficial "spill-over effects" of such projects toother domestic industrial activities should not be overrated. Rather thanbeing considered as industrialization projects, these schemes should be judgedas natural gas export schemes.

1.06 Risk Management. The introdiction of natural gas into YAR's economyis favorable from the point of view of risk management: it diversifies thesources of primary energy and improves the economics of small incrementaladditions to power capacity vith the use of combined cycle units. With thedevelopment of exportable hydrocarbon resources, YAR is now even more exposedto the effects of the volatility in international oil prices than it was atthe beginning of the 1980s: firstly, the direct impact of changing oil priceson income from crude exports is added to its indirect effect on temittancesfrom Yemeni expatriates; secondly, in addition to the balance-of-paymentseffect, GOY revenues are directly affected. Prices of GOY-contracted crudeexports averaged US$ 15.9 bbl during the first half of 1988; they fell to USS14.8 bbl during the second half of 1988 and increased to US$ 16.7 bbl for thefirst quarter of 1989; they are expected to increase to around $22.8 bbl (in1989 prices) by the year 2000, according to the World Bank's most recentforecasts. What appears certain is that oil prices vill continue to bevolatile and it is recommended that GOY's policy makers apply appropriate riskmanagement strategies to cope with the variability in international oil pricesto avoid overheating domestic demand or over-investing in projects; this riskmanagement relates not only to the energy sector per se, but is just asrelevant for the setting of macro-economic policies and their effect on allsectors of the economy.

B. Energy Policy and Plannina

1.07 The overriding aim in the energy sector is the maximization ofbenefits to YAR's economy. In practice this translates into multiple specificobjectives, namely (i) to identify and promote least-cost options for theprovision of energy; (ii) to ensure flexibility and security of supply; (iii)to promote the productivity of the tradeables sectors; (iv) to maximizeproductive domestic employment; (v) to maximize foreign exchange earnings andGovernment revenue; (vi) to ensure the sustainability of implemented policiesand investment programs, maintenance of the financial viability of thehydrocarbon and power companies, ability to meet specialized manpoverrequirements, and implementation of an appropriate institutional framework;(vii) to promote social equity which could require the introduction of"life-lira" electricity tariffs (where the consumer pays a low tariff for lowlevels of consumption and a higher tariff for higher consumption),availability of modern forms of energy (e.g. LPG and electricity) to "all"sectors of the population, and an adequate level of taxation on"indispensable" ftels vith a manageable impact on the budgets of thelow-income population; (viii) to promote energy conservation and (ix) tominimize the negative environmental impact of energy production andconsumption.

1.08 Objectives such as these have to be used as guiding principles in thedefinition of GOY's energy policies, lncluding decisions on pricing,investment choices and institutlonal reform. At times, some of them may beconflicting in competing policy options. Therefore, the implemented mix ofpolicies depends on political choices between the trade-offs involved ln theachievement of multiple objectives; no policy is optimal in an absolute sense.The trade-off implications of the choices need to be brought out clearly andwhether the proposed policy instruments are more optimal than others infulfilling GOY's preferred policy objectives.

1.09 Conflicting objectives are behind some of the major distortionscurrently found in YARI's energy sector. Military-strategic considerations ofsecurity of supply were one determinant in the installation of the excesspower generating capacity which may have resulted in the limitations ofavailable funding for required pover distribution investments. Decisions madein this regard did not lead to implementation of least-cost options andcontributed to the present high cost of electricity. This in turn, contributedto some of the over-investment in costly autogeneration throughout thecountry, causing a loss of welfcre by domestic consumers, a loss of scarceforeign exchange and a drain on GOY revenues to cover the financial ltases ofYemen General Electricity Corporation (YGEC). Similarly, this policy wentagainst the important objective of rational water manage-iat in agriculture:diesel water pumps used in irrigation are often oversized and run too long,consuming excessive quantities of both water and fuel.

1.10 The above shows that, although the strategic importance of thehydrocarbon sector is clearly recognized by GOY, overall energy issues need tobe addressed more appropriately. It is recommended, therefore, that COYclearly define what its general objectives should be in the energy sector,establishing a priority ranking among them, and that the sectoral ministriesuse this framevork in a coherent manner to evaluate their projects and policyproposals and implement a policy action program to eliminate existingdistortions.

C. Sectoral Institutions

1.11 Overall EnergX Planning. The development of a coherent energystrategy requires an institutional framework capable of carrying out theplanning task, a well-defined division of responsibility between the sectoralinstitutions, and basic tools such as data bases and evaluation and plan'Ingmechanisms. As illustrated in part by the policy inconsistencies noted above,proper energy planning does not presently exist in YAR, neither for strategyformulation, project selection or general programming. The basicresponsibility for formulating and implementing energy policies is essentiallysplit between the Minist-y of Electricity and Water (ME) and the Ministry ofOil and Mineral Resources (MONR). The integration of their policy proposalsis undertaken at three levels, namely the GOY Cabinet, the Central PlanningOrganization (CPO) and the Supreme Council for Oil and Mineral Resources(SCOMR). The Cabinet, by definition, has the ultimate responsibility forenergy policy in YAR.

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1.12 The CPO has both a coordinating and a data collecting responsibility -the latter including information on the energy consumption of major industrialfirms - which is exercised by a small energy planning unit. In principle,GOY's Five-Year Plans prepared by the CPO should spell out the sectoralobjectives and establish comprehensive energy plans for the longer term. Inpractice, however, the energy component of the Five-Year Plan consists of nomore than a series of investment proposals submitted by the two sectoralministries.

1.13 Power Subsector. MN is responsible for the formulation of policiesand plans for the development of the power subsector including the control andlicensing of priva^e and industrial autogeneration. In addition, it isresponsible for the development and exploitation of water resources. Inpractice, NM's small Technical Office keeps track of past activities but isnot involved in any planning, preparation of feasibility studies orsupervision of projects.

1.14 YGEC which reports to MEW as a semi-autonomous entity is responsiblefor the generation and distribution of about 70X of the electricity consumedin YAR through the interconnected public grid and from a number of dieselpower stations; private electricity producers, consisting mainly of householdsand industries, account for the remainder. YGEC has a planning unit whichfunctions only like a statistical office, but intentions are to develop itinto an effective planning tool. In the meantime, YGEC's planning functionsare mostly limited to its projects depar-ment ?itich identifies projects inconnection with the preparation of GOY's Five-Year Plans.

1.15 Several structural factors limit YGEC's efficiency: (i) thesemi-autonomous status of YGEC is a source of friction; NEW does not restrictits own role to the definition of overall policies but tends to play a role inday-to-day management; (ii) the resulting management problems are compoundedby the lack of an overall GOY atrategy for the energy sector; (iii) thepersonnel policy is inadequate for the efficient running of operations: YGECis over-staffed, employing a total of 4,000 people -- to dismiss employees isclose to impossible -- yet under-staffed in terms of highly qualified people;expatriates are needed in key strategic functions; YGEC's salary structure isnot sufficiently flexible for rewarding highly qualified individuals althoughit provides more possibilities for incentive payments than the civil servicesalary structure; (iv) the political structure of YAR with strong localregional influence makes it difficult for YGEC to base investment programs oneconomic considerations (e.g. decisions concerning a balance betweencentralized versus decentralized investments); YGEC is sensitive to chargesof regional discrimination and therefore, each region has its own YGEC unitchaired by a regional representative working almost independently; and (v) inview of YAR's foreign exchange scarcity, COY procedures involved in gettingimport clearances and opening letters of credit are c-.oersome and YGEC isoften unable to procure equipment and spare parts on t5me; as a result,projects are delayed and YGEC has to resort to cannibalizing its temporarilyidle plants for spare parts. It is recommended that appropriate measures be

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implemented to address the above deficiencies and improve YGEC's institutionalstructure and its operational, managerial, personnel and financial policiesvhich should allow YGEC to adequately fulfill its responsibility vithin YAR'seconomy.

1.16 YGEC management is aware that large savings can be achieved withrelatively small investments in improving the efficiency of distribution inurban areas. But the attention of GOY decision makers is more geared toinvestments in expansior than to those in efficiency improvements which arealso blocked because of a lacking data base. YGEC's statistical unit collectsdata on consumer categories, however regional offices do not provide correctand timely data, and meaningful information is often not available in time formanagement to take corrective measures. A high priority therefore is for YGECto develop a data base from a power "system point of view", containinginformation on peak loads, connections, generators and transformers. It isrecommended that (i) YGEC's data collection and interpretation capabilities bestrengthened, (ii) priority be given to strengthening YGEC's existing planningfunction to enable it to develop long-term plans for power generation andtransmission based on valid forecasts of load demands, load shape and loadcenters, to identify the lowest cost options, and to determine appropriatestandards and risk criteria in accordance with YGEC and GOY policy, (iii)operation and maintenance management of generation, transmission anddistribution facilities be improved, and (iv) appropriate training programs beimplemented to help achieve these goals.

1.17 Petroleum Subsector. Prior to the discovery of oil, the supply andmarketing of oil as well as the export of minerals was the responsibility ofthe Yemen Oil and Mineral Resources Corporation (YOMINCO) which alsofunctioned as a public sector holding corporation of its three subsidiarycompanies, YPC, responsible for import and distribution of petroleum products,Yemen Salt Company (YSC), responsible for production and export of salt, andthe National Industrial and Construction Material Company. In 1984, GOYcreated SCOMR to formulate policies for the development and use of YAR'shydrocarbon resources and to conduct negotiations with the operating oilcompanies. It was soon realized that some of these functions could not beperformed collectively, and in 1985, a Presidential Decree established HOMRwith the mandate to manage the petroleum and minerals sectors. nOMR took overmost of the YOMINCO and SCOMR functions and absorbed many of the YOMINCOpersonnel. SCOMR which is chaired by the Deputy Prime Minister and composedof the Ministers of NEW, MOMR, economy and industry, finance and the Chairmanof CPO, continues to have advisory and oversight functions over MOMR and isconsulted on general policy matters while major proposals are taken to theCabinet.

1.18 However, the present relationship between MOMR and SCOMR requiresclarification. Existing legislation appears to place both MOMR and SCOMR atthe highest level to formulate policy, plan sector development, represent GOYin negotiations and manage oil agreements as the functions assigned to SCOMRwere taken over by MOMR after its establishment. Although some division oflabour has developed between the two institutions, their relationship is not

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legally defined and procedures are apt to change as frequently as SCOMR'smembers change. This has veakened the ability of MONR in addressing sectorissues as well as petroleum sector management, particularly its dealings withthe international oil companies. One solution would be to abolish SCONR andtransfer key staff of the SCONR secretariat to a strategic planning unit inMOHR; another vould be to specify that the role of SCOMR should be limited toevaluating the macroeconomic impact of policy and project proposals of NONRand the conformance of the proposals with stated policy priorities in theenergy sector. In any case, SCOMR's role needs to be clarified and careshould be taken to ensure that duplication of functions and of training ofscarce qualified manpower is avoided.

1.19 Under the IDA Technical Assistance Project, a consultant reviewco-firanced by the US Government was undertaken of YAR's petroleum subsectororganizations which was completed in 1988. Its original objective was tofocus on a reorganization of MOMN, but during the course of the study itbecame evident that the policy planning and operational functions of thepetroleum and mineral sectors could not be properly accomplished within MOMR'scivil service structure. Therefore, the study proposed that operationalfunctions of MONR be entrusted to YOMINCO which still exists as a largelydormant legal entity and could be reactivated; MONR in turn would remainresponsible for long range planning and policy formulation. MONR has accepteda revised organizational structure under this concept and plans to implementthe proposal. We believe that a number of issues have not been addressedadequately by the study, including delegation of authority and the mandates ofDeputy Ministers and their links with various Directorates General withinNONR. Presently almost all decisions are taken in the office of the Ministerwith minimal delegation of authority, and other officials feel only littleresponsibility for the management and performance of the petroleum sector.Partly as a result, the efficiency and effectiveness of A'ONR's administrativeand planning functions require improvement. This refers particularly to thesupervision and control of the operations and expenditures of the petroleumoperating company, Yemen Exploration and Production Company (YEPC) and itsprincipal shareholder, Yemen Hunt Oil Company (YHOC). As a first step, MOMNhas commissioned independent audits of YEPC/YHOC's expense statements whichare currently underway. Another study has been completed of the accountingfunctions of NOMR, YPC and YSC. It's recommendations are about to beimplemented with outside help and IDA funding.

1.20 Also under the IDA Technical Assistance Project and with funding fromtha Netherlands Government, the Yemen Exploration and P-aduction InformationCenter (YEPIC) has built up an effective data base on YAR's hydrocarbonresources. The lack of adequate data bases in other areas under MONR'sresponsibility, however, is a serious constraint to policy formulation.MONR's Planning Department is not yet fully functional but intends to set upunits for project evaluation and forecasting.

1.21 YPC which is responsible for the domestic marketing of all petroleumproducts and for: operating the LPG bottling plant and distribution (seeChapter V) has a small statistical unit but no planning capabilities. YPC

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does not have a proven capability to adequately plan and implement investmentprojects.

1.22 It is recommended that GOY follov up the Organization Study vith abrief but comprehensive review of the roles of the various petroleum sectorinstitutions, with the aim of defining linkages between agencies particularlyMONR and SCONR, delineating authority and responsibilities, eliminatingduplication and strengthening personnel policies. This reviev should alsofocus on matters related to personnel remuneration including pay scales andincentives which need to be adequate to attract qualified Yemeni staff for themanagement and operation of this important sector of YAR's economy, and toeventually replace the expatriates currently assisting MOMR under IDA funding.

D. Demand and SUnDIX Overview

1.23 YAR's primary energy production in 1988 was 9.5 million metric tons(t) of oil equivalent (toe), divided between 7.4 mmtoe of crude oil (78X) and2.1 mmtoe of fuelwood (221). After exports of 7.3 mmtoe of crude oil andimports of 1.2 mmtoe of petroleum products, gross energy supply to thedomestic market in 1988 was 3.8 mmtoe, divided between 1.7 mmtoe of crude oiland petroleum products including inventory changes (45X) and 2.1 mmtoe offuelwood (55X).

1.24 Roughly 600,000 t of fuelvood (225,000 toe) were consumed for acharcoal production of 140,000 tons (100,000 toe). 0.5 mmtoe of crude oilwere converted into 0.45 mmtoe of petroleum products in the domestic refinery.Approximately 0.34 mmtoe of diesel and fuel oil were converted into a totalpower generation of 1050 GCH; own consumption of power in the power plants wasaround 100 GUR and line losses accounted for around 190 G'JH, leaving 766 GWH(70,000 toe) for domestic consuwption, 701 of which was supplied by YGEC and301 by private producers (see Chapter IV). YAR's final energy consumption of3.4 mmtoe was dominated by the household sector (61X), followed by thetransport sector (28X), industry (41), commerce (41) and agriculture (31). Asummarized Energy Balance for 1988 is provided in Annex I-1.

1.25 The introduction of natural gas and the continued growth in populationand national income will change the level and struct' J of YAR's energyconsumption. The anticipated shifts in sectoral energy demand up to 2005 areillustrated in Annex 1-2. In the household sector, "useful energy" demandwill continue to grov parallel to the growth in population. As demand forcharcoal and for fuelwood is expected to remain constant, all the growth indemand will be satisfied by the more efficient energy carriers LPG andelectricity. As a result of substantial gains in average energy efficiency,the relative importance of household energy demand in final energy demand isanticipated to drop by a third to 431. Instead, transport will become themajor consumer of final energy (471) as an expected growth in tourismaccelerates the demand for jet-fuel, and road transport continues to increase.The share of industry vill increase only slightly as industrial developmentwill be modest, especially in respect of energy intensive industries. Sinceagriculture already is "overmechanized" and "overirrigated", no growth in

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agricultural energy demand is expected

1.26. The projections used in Chapters III and VI to evaluate the refinerya|nd gas investment options foresee a 47X growth of final energy demand to 5.5itoe by 2005. This is less than the expected growth in population (+65X) orthe growth in national income: GDP is expected to grvw by 78X and non-oil GDPby 56X (see Annes I-3) This low growth in final energy demand is due to thehlgher market share of the more energy efficient commercial fuels which areforeseen to grow by 126X, implying an elasticity of 1.37 compared to thegrowth in population, and of 1.45 compared to the growth in non-oil GDP. As aresult, the relative importance of biomass and petroleum products in finalenergy demand will be reversed from 58/40 to 35/58. Since natural gas is usedprimarily in the generation of electricity, its relative importance in YAR'senergy supply is more apparent iL gross energy consumption (121) than in finalenergy consumption (31). The potential for increasing the share of naturalgas in final energy consumption in the future depend on the future level ofYAR's industrialization.

E. Pricing. Demand Nanagement and Conservation

1.27 Petroleum Products Pricing. A pricing policy providing consumers withthe correct signals is the most powerful policy tool for achieving a rationaluse of energy, and taxation of fuels can be an important source of Governmentrevenue. vhile YGEC is allowed to import fuel oil directly from theInternational market, paying the international price for it, and while noregulation applies to electricity sales by private generators, all otherenergy prices are controlled. Because energy prices on the internationalmarket fluctuate widely, discrepancies between the administered prices andtariffs and the corresponding economic prices develop quickly. Thesediscrepancies may be either reinforced or off-set by changes in the exchangerate. In addition, inflation erodes the real value of fixed prices.Adjustment to changing cost conditions has been slow and normally, prices areonly changed after the financial situation of the affected institution hasdeteriorated: despite fluctuating international energy prices, YAR'selectricity tariffs have remained unchanged since 1981, prices of gasoline,kerosene, aviation fuel and diesel, since 1986, fuel oil, since 1985 and LPGsince 1984. The results of this policy vith regard to the generation ofgovernment revenues, and the development in real and relative prices are shownin the historical trends depicted in Annexes I-4 and 1-5, demonstrating aclear pattern in GOY's policy orientation.

1.28 Firstly, although GOY has avoided to subsidize overall energyconsumption, it has not exploited the potential of energy taxation as animportant source of revenue. The benefit of falling International pricesduring the 1980s were passed on to consumers (see Annex 1-5). The real priceof all petroleum products was allowed to increase in 1981 and afterwards, tofall, reaching by 1987 a level of between 371 (LPG) and 891 (diesel) of theirrespective 1980 prices. The incidence of net taxes on petroleum products(defined as the excess of current prices over economic costs calculated on thebasis of YPC's official cost-plus pricing structure) has been small - on

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average 6-7X during the 1980-1987 period - and fluctuating (see Annex I-4).In 1981 and 1983, GOY incurred overall losses on its prLcing policy; thehighest taz incidence - 19X - came about in 1986 as a result of fallinginternational prices and an overvalued national currency.

1.29 Secondly, although the overall level of taxation has been generallypositive, the tax incidence of individual products has rot: GOY hascross-subsidized the consumption of diesel and of the household fuels,kerosene and LPG, by often pricing them below economic cost, whereas apartfrom 1980, gasoline has alvays been priced above (see Annex I-5). Thepromotional pricing of kerosene can be defended on grounds of social equityand, together with LPG, fuelwood substitution. Yet, as stated in para 5.14, amore effective way of promoting LPG would be to reduce the cost of LPG stovesand increasing the supply of LPG bottles on the market. Black market pricesfor LPG, up to 701 higher than the official price, shov a high willingness topay on the part of consumers; it also should be noted that the average priceof traded fuelwood (YR 1.66 kg) in "useful energy" terms (equivalence 7:1) iscurrently four times the official price of LPG (YR 2.96 kg).

1.30 Diesel oil is one of the most important fuels used in YAR, accountingfor more than a third of the total consumption of petroleum products. Pastunderpricing of diesel has had two major implications. First, it led to aloss of GOY revenue, which in 1987 resulted in a subsidy of about YR 90million. Secondly, it created distortions in the price signals sent toconsumers, as the relative price of diesel compared to the domestic prices offuel oil and gasoline no longer corresponded to their respective opportunitycosts. The underpricing of diesel compared to gasoline promotes investmentsin diesel powered vehicles; although these are more expensive to purchase thanF;asoline povered vehicles, this is no cause of major concern as theirlife-cycle costs may be lower: the international price of diesel during the19809 was on average 4-5X lover than the price of gasoline, mileage per literof diesel engines is usually 5-10 higher, and the cost of maintenance islover. The underpricing of diesel compered to fuel-oil on the other hand,augments YAR's import bill as it encottrages the consumption of higher priceddiesel instead of fuel oil in industry. Finally, a low price of diesel mayslow the process of transferring industrial auto-producers of electricity tothe public grid, even though the cost of auto-production per kWh may still behigher than the industrial pover tariffs. In view of these observations it isrecommended that GOY (i) adopt a full economic cost pricing policy as aminimum requirement for all fuels except kerosene, (ii) align the relativedomestic prices of diesel and fuel oil to their relative international prices,(iii) consider using taxation of petroleum products as a means for raisingGovernment revenues as compared to alternative means of taxation, and (iv)revise petroleum product prices at least once a year in line with movements ininternational prices and the foreign exchange rate.

1.31 Power Pricing. As described in Chapter IV, electricity tariffs areestimated to be above the long-run marginal cost of supply as defined by a1984 study; however, due to internal inefficiencies and delays related tonetwork constraints in connecting major pover consumers to the grid, tariffs

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are not adequate to meet YGEC's revenue requirements. In principle, if YGECwere alloyed to operate efficiently as a truly autonomous entity, the existingtariff level would be sufflcient to cover its costs. As it stands, however,even with a gradual reduction of inefficiencies (see Chapter IV) and increasesin power sales, tariffs need to be revised. It is therefore recommended that,as part of * comprehensive plan to strengthen YGEC's financial performanceincluding through efficiency improvements (Para 4.25), (i) service charges andthe average tariff level be raised in the short- to medium-term, and (ii) thetariff structure be rationalized to better reflect the economic costs of powersupply to different consumer categories. A restructuring f tariffs shouldseek to eliminate cross-subsidies while at the same time meeting social equityobjectives; this should be based on accurate estimates of the economic costsof supply. It is recommended that YGEC update its assessment of long-runmarginal costs of supply (contained in the 1984 Electricity Pricing Studycarried out by the World Bank), and that the results of this update be used asa basis for GOY's future power pricing decisions.

1.32 Demand Management and Conservation. Until now GOY has not establishedspecific energy demand management and conservation policies. GOY should takeup tne conservation of fuelwood as the major demand management issue thatneeds to be addressed; specific recommendations to this effect are made inChapter V. The second priority issue is the need to reduce the auxiliaryconsumption of energy and line losses in the power sector (see Chapter IV),and the third, to promote conservation of energy at the consumer level. Inregard to this last observation it is recommended that GOY facilitate energyaudits with the help of specialized consultants and provide energyconservation investment incentives to 4ndustries whose energy costs amount to,say, more than 10 of their total prodtztion costs, and other major consumers.

F. Environment

1.33 The use of fuelwood is the most serious environmental problemassociated with energy consumption in YAR. As consumption greatly exceedsproductivity, the use of dead wood in the commercial fuel trade has beensupplemented increasingly with economically costly cut live wood. Unlessdirect policy measures to accelerate the substitution of fuelwood by LPG aretaken, national forest resources will be seriously depleted and agriculturalproductivity vill be reduced as a result of impalred nutrient cycling, soilerosion, decreased groundwater recharge and microclimatic deterioration ininteraction with other environmentally degrading activities such as excessivegroundwater pumping and failure to maintain agricultural terraces.

1.34 The introduction of natural gas in power plants and major industrieswould greatly decrease the consumption of heavy fuel oil. This would reduceemissions of S02, CO2 and NO, per unit of energy, while emissions of methanewould increase but cause only an insignificant impact on the environment.Identified oil fields and the pipeline are largely located in arid, sparselypopulated areas, and the environmental risks associated with oil spills aretherefore small. However, maritime loading of crude oil involves risks whichneed to be properly addressed. As detailed in Chapter V. safety standards

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need to be developed, however, for handling of LPG cylinders in thedistribution network to prevent risks to life and property.

1.35 There is currently no legislation in YAR concerning aspects ofenvironmental protection. As part of the Technical Assistance to thePetroleum Sector, IDA has agreed to fund consultants to prepare proposals forsuch legialation which are expected to be completed by 1990. Also, it isanticipated that legislation relating to conservation of forestry measureswill be drawn up and implemented under IDA's Second National AgriculturalDevelopment Project planned for 1991.

II. HYDROCARBON RESOURCES

A. Oil Exploration

2.01 Although large portions of YAR's geology are characterized byextensive volcanic rocks which are void of hydrocarbon accumulation, YAR nowproduces and exports substantial quantities of crude oil. In recent years,international oil companies mounted large scale exploration programs whichhave resulted in significant oil and gas discoveries.

2.02 YAR's petroleum exploration history began in 1961, initially withoutany success. It was in 1981 that a Production Sharing Agreement (PSA) wassigned between YAR and Hunt Oil Company (of the US) to explore the Marib-AlJawf basin covering about 16,800 sq.km. in the East-Central part of thecountry (see W). In 1984, Yemen Hunt Oil Company (YHOC) completed the firstoil discovery well, and the Alif field was declared commercial in 1985. Sincethat time, over one hundred wells have been drilled for development of thisfield whic7a has now been exploited fully; currently, the level of productionis about 140,000 bpd of crude oil, most of which is exported through apipeline with a capacity of 240,000 bpd to the Red Sea. YHOC has meanwhileentered into a partnership with other oil companies, known as YemenExploration and Production Company (YEPC).

2.03 Compagnie Francaise des Petroles (CFP) (Total) signed a concessionagreement vith YAR in 1985 covering about 5,000 sq.km. onshore as well as4,000 sq.km. offshore in the South Tihama region. Exploration work is inprogress, however no discoveries have been reported so far. Similarly in1985, Exxon was awarded a concession covering about 20,000 sq.km. in theCentral Plateau. Exxon carried out geological and geophysical investigationsof its area in 1986 and 1987. Subsequently, the company drilled two wildcatwells which had to be abandoned as non-producers. Having been discouraged bythe results of the two wells drilled, Exxon curtailed its direct exploratoryoperation by selling part of its interest in this concession to Texaco.Lastly, a joint company owned by YAR and th, People's Democratic Republic ofYemen (PDRY) was formed in 1988 to explore and develop the hydrocarbonresources of the Neutral Zone between the two countries.

2.04 Exnloration Policy. YAR has no well defined exploration policy which

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could accelerate attracting private sector investments for high riskezploration. Such a policy could stipulate periodic bid rounds attractinginterested private investt.&s through a transparent exploration promotionexerclse which should address in particular (i) linkages between the entitiesand their respective roles, with a clear statement of prospective investors'needs and the extent of their obligations agreed within the framevork of YAR'slaws pertaining to oil activities, (ii) clear requirements for the treatmentof discoveries as commercial, both for oil and gas, (iii) the logicalgeographic and geologic basis. both in size and prospectivity, of areasoffered for private investors' exploration, and (iv) minimum commitmentsrelated to work programs required for each block, proportional to theprospectivity of an area. It is recommended that GOY establish acomprehensive hydrocarbon exploration policy vhich would (i) clearly definethe role and responsibilities of both th"e private and the public sectorentities vis-a-vis the country's needs, (ii) aim at optimizing YAR'shydrocarbon resource utilization, and (iii) introduce a competitive approachin petroleum industry operations.

2.05 In viev of the international petroleum industry's known interest ininvesting in YAR and the country's objective of attracting competition to itscurrent oil operators, a reliable assessment of YAR's hydrocarbon prospects isneeded to permit formulation of an appropriate policy. Therefore, it isrecommended that GOY carry out an independent comprehensive review of YAR'soverall oil and gas prospects, with the view to preparing a long-termperspective exploration plan for utilization of the country's hydrocarbonresources. This study's aim would be to prepare a synthesis of YAR'shydrocarbon potential within each major geologic province of the country,based on a compilation of all available geological, geophysical andgeochemical data to be analyzed by appropriate modern techniques; onceapproved, the review should take about 24 months to be completed. The WorldBank vould be prepared to consider assisting GOY in such an endeavour.

2.06 Legal Framework. Petroleum agreements in YAR are not related tospecific legislation such as the petroleum and mining laws in effect in mostother countries. Under the terms of the existing PSA, the contractor'soperation in general is "... bound by the laws of Yemen Vnd regulations issuedfor the implementation thereof...." Currently, each ofl agreement must beapproved by YAR's legislative oody on the basis of whi.-h a Presidential Decreeis issued, expressly ratifying the agreement which then becomes an independentlaw. Initially this arrangement might have been satisfactory, both for GOYand a contractor. However, like in any agreement relating to businessarrangements, it is difficult to address the typical problems occurring duringthe normal day-to-day course of business, if agreement changes requirelegislative action and a Presidential Decree. It is thus recommended that GOYprepare and legislate a comprehensive and up-to-date "Hydroc rbon and MineralsAct" on the basis of which all types of petroleum, gas, gas liquids or mineralagreements could be prepared and concluded. This should eliminate thevagueness and problems present in the current agreements with the industry;this would also facilitate contract administration and provide for theflexibility which is needed for granting incentives to attract private

- 14 -

investors, even in less prospective acreages. Such a "Hydrocarbon andMinerals Act" which should include specific reference to the commercializationprocess of natural gas, should be drafted by legal experts acquainted with andexperienced in the evolution of the petroleum laws, particularly in MiddleEastern and North Sea countries.

B. Reserves and Production

2.07 The Alif field is an anticline vith gently sloping flanks. The mainoil reservoir is producing from two distinct sandy intervals which are relatedto rifting phenomena. Both zones have excellent reservoir characteristicswith up to 10 darcies horizontal permeability and up to 23X porosity. TheAlif reservoir rock has a classical seal on the top in form of a thick sectionof interbedded shales and salt deposits.

2.08 Following the initial discovery of oil at Alif in 1984 and subsequentacceptance of commerciality in 1985, proven reserves of the discovery wereoriginally estimated at about 400 million stock tank bbls (stb) of oil inplace. Hove-er, since then considerable additional data have been generated,more than one hundred development wells have been drilled, and wellperformance has been monitored. Based on the new data and a number ofreservoir studi-s both by the contractor and GOY, the oil-in-place reserveestimates of the Alif field have been revised upward to about 1 billion stb.In addition to Alif, a few smaller discoveries have been reported, namely (i)the Azal field with an estimated oil in place of about 200 million stb; and(ii) the Assad Al Kamil field, estimated to have about 400 million stb. Oilreserves in other smaller fields such as Yazan and Nucum are estimated tototal about 200 million stb. Based on more recent information on the basis ofwhich various reservoir studies were carried out by consultants andcontractors, YAR's total oil reserve is currently estimated at about 1.8billion stb, of which 50 or about 900 million stb are thought to berecoverable. The updated data and various reservoir studies (including theone funded under IDA's Technical Assistance to the Petroleum Sector) indicatethat the degree of reliability in YAR's oil reserves estimate is withinacceptable industry standards.

2.09 The estimated gas reserve of YAR has been published in trade journalsas somewhere between 15 to 20 trillion cubic feet (TCF). However, neitheradequate data nor reliable reports were supplied to us to verify the existenceof gas in YAR in such quantities. GOY's reserve estimate is based on dataprovided by the operating oil companies on associated gas, totalling 3.6 TCFof gas in place. MOMR furthermore estimates YAR's potenti'l non-associatedgas reserves to total 3.2 TCF. Greater details are provided later in thisChapter.

2.10 Alif Production and Profiles. The updated reserve estimate of theAlif field is consistent with its production history. For most of 1988, Alifoil production has been about 150,000 stb per day. By September 1988, thelatest month for which data were made available to us, cumulative oil producedwas about 50 million stb and gas about 49 billion stock tank cubic feet (scf)

- 15 -

in place. In order to maintain field pressure at a level required to sustaincrude oil production at about 150.000 bpd, the operator started gas-injectioninto the field for preservation of the gas cap pressure. As of September1988, a total of 28,262 mmscf of gas had been injected. Table 2.1 summarizesAlif production data for the first nine months of 1988, the latest informationavailable to us.

Table 2,1 Alif Field - Cumulative Production/IniectionJanuary - September 1988

Oil Productlon Rate Np Gp R G1month (stb/d) (NNstb) (sef/stb) (mmscf)

1/88 124276 13.367 12073 1074 2322/88 149680 17.708 18367 1447 34783/88 144919 22.200 23293 1097 70804/88 150019 26.701 27461 926 87825/88 149868 31.347 31877 950 127086/88 149929 35.845 35901 b94 161367/88 150006 40.495 40443 977 202218/88 149911 45.142 44740 925 243099/88 149900 49.639 49224 997 28262

Mp - Cumulative Oil ProductionGp- Cumulative Gas ProductionR - Gas Oil Ratio (GOR)GI - Cumulative Gas Injection

Source: NOMR

2.11 Four production scenarios for the Alif field were analyzed by MONR'sreservoir consultant, as summarized in Table 2.2. This analysis did notresult in firm conclusions, except that Scenarios Two and Three were found notto be economically and technically viable and that Scenario Four would bepreferable to Scenario One. MONR is reviewing YHOC's proposed operating

Table 2.2 Alif Field - Oil and Gas Production Scenarios

Oil Production Gas ProductionScenarios (bpd) (GPC in mmscf/day)

One 150,000 600Two 150,000 800Three 180,000 600Four 120,000 600

Source: MONR

production profile submitted in November 1988, as summarized in Table 2.3, butwill avait the results of an ongoing reservoir simulation before reaching a

- 16 -

decision. MOYR's experts' view that Scenario Four (120,000 bpd of oilproduction with a GPC of 600 mmscf of gas) is preferable, does not seemacceptable to YHOC, probably because their economics of oil and gas productionvithin the framevork of the PSA are different from GOY's.

Table 2.3 Alif Field - Operating Production ProfileYHOC's Management Plan of Nov mber 1988

Oil & Condensate CumulativeRate Production GOR Gas Rate

Year (stbZd) (mmstb) (scf/stb) (mmscf/d)

1988 151110 63.54 1200 1801989 165000 123.77 2110 3501990 154550 180.18 2970 4601994- 107680 219.48 5110 5501992 68940 244.64 7950 5501993 52590 263.84 9790 5101994 43260 279.63 12440 5401995 40330 294.35 13500 540

Source: MOIR

C. Gas Resources and Availability

2.12 Recent discoveries in several fields have significantly added to YAR'spotential gas availability. Completion of seven vells indicated that theRaydan field is mainly a gas field. In the Assad Al Kamil field, 17 wellswere completed most of which shoved substantial gas and condensates. Based ondata obtained from MOHK, the total proven and possible gas reserves in theseand other fields are estimated at about 6.8 trillion cubic feet (TCF) whichincludes associated gas, gas cap and non-associated gas. Table 2.4 summarizesMORR's assessment of YAR's proven and possible gas reserves.

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Table 2.4 YAR - Proven and Possible Natural Gas Reserves(billion cubic feet)

Proven Possible Total

Oil Producing FieldsAlif 3,200 3,200Azal 345 345Nacum 8 8Yazan 11 11Assad Al Kamil 2.500 2.500

* ~~~~ ~ ~ ~ ~ ~~6.064 - 6.064

Potential Gas FieldsRaydan, Na'een 300 300Lam 100 100Neem - 300 300

700 700Total 6,064 700 6,764

Source: MONR

.

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2.13 At present GOY does not have a specific natural gas development plan,partly because the ownership of the gas is still a legal issue underdiscussion between GOY and the oil field contractor (see below). Some 250NKCFD of associated gas is being produced from the oil producing fields (Alif,Azal, Nacum and Yazan) and processed in the gas plant which is capable ofprocessing 260 NNCFD associated gas and 140 NNCFD of gas cap for recovery of4,000 bpd of LPG and 5,000 bpd of C5+. Currently about 2,600 bpd of LPG and2,800 bpd of C6+ are being recovered. The LPG together with the dry gas arereinjected back into the reservoir and C5+ is added to the crude oil streamfor export.

2.14 As stated above, the current production plan for Alif adopted by theoperator requires a portion of the gas produced simultaneously with oll to beinjected back into the formation, in order to implement an optimum oil fielddepletion plan. Hovever, it is possible that part of this gas (between 50 to100 mmscf/d) could be released for use in power generation and for otherpurposes, but this needs to be confirmed in connection with GOT's eventualdecision on the production profile. It is recommended that GOY urgently takeall measures necessary to confirm the availability and deliverability of Alifassociated gas, including an agreement with YEPC, and steps be taken to permitits early utilization in substitution of costly imported fuel oil in powergeneration and cement production (See Chapter VI for further discussion).

2.15 Once the oil in the above and other fields currently under productionis depleted, they become gas fields. It is predicted that at Nacum and Yazanthis vill occur as early as 1995. These, plus Lam and Meem, the two confirmedgas fields, will then provide a reasonable source of non-associated gas(approximately 0.4 TCF) for any gas utilization project until other potentialgas fields such as Assad Al Kamil are confirmed or additional oil fields aredepleted and transformed into gas fields.

2.16 Two important issues are apparent in the gas subsector, namely the gasownership under the PSA framework and the extent of YAR's natural gaspotential and reserves. In view of the importance of promoting hydrocarbonexploration and production and of providing adequate incentives to find anddevelop the resources, both of these issues should be addressed as soon aspossible. Although MONR has been actively engaged for some time innegotiatioms with YEPC in relation to provisions under Article 27 of the PSA,a resolution of the ownership issue is not yet apparent. GOY maintains thataccording to the provisions, ".... associated gas not exported in liquid formor used in operation for reinjection or reinjected or flared shall remain theproperty of the State...." The contractor bases his views on the same Articlevhich states also that ".... if gas is produced or is capable of beingproduced from the area, the State and contractor shall study all possibleeconomic alternatives for its use and decide on the best alternative...." andthat ".... production-sharing principles of ArtLcle VII shall apply to thevalue of non-associated gas if it is sold and not used in operation...." Itis recommended that GOY continue and expedite its negotiations on this subjectand, if it becomes clear that a satisfactory agreement cannot be reached,invoke arbitration within the terms of the PSA.

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2.17 Studies related to YAR's gas potential and reserves have not beenpursued as vigorously as those related to oil, due to lack of contractorincentives. An assessment will probably be delayed until the above gasownership issue is resolved. In the meantime, investment decisions for thedevelopment of YAR's natural gas utilization should not be held up and anearly assessment of YAR's gas potential whose development is at a stand-still,is important. It is recommended that GOY coumission a brief review of the gassubsector to identify the next steps required for appraisal and delineation ofthose gas discoveries which appear economically viable, and to establish ayrogram for appraisal and development of the discoveries; close coordinationvith YEPC would be essential. Once competent consultants are hired for thispurpose, the reviev should be completed in about 90 days. I is furthermorerecg=ended that once the above review is completed and after the ownershipquestion is resolved, GO! design and implement a coordinated natural gasdevelopment plan covering both upstream and downstream aspects. The WorldBank would be prepared to consider assisting in these studies under theongoing Technical Assistance Project.

III. PETROLEUM PRODUCTS DEMAND AND SUPPLY

A. Demand and Sunnly

3.01 YPC which is part of MOHR is responsible for imports, transportation,storage and marketing of petroleum products including those produced by theMarib refinery. Sourcing of YPC's imports is generally based ongovernment-to-government negotiations with Saudi Arabia, Kuvait and PDRY,except for LPG imports which are sourced by YPC directly based on competitivetendering procedures.

3.02 We found the statistics available in YAR on historical petroleumproduct imports and the country-wide and regional consumption to be internallyinconsistent. For example, YPC's sales of many products during 1980-84 areshown to be consistently higher than the corresponding year's imports recordedby YPC, although there was no domestic production; differences also cannot bereconciled by inventory variations. It is known that significant unofficialimports, mainly of gasoline, take place across land borders with PDRY andSaudi Arabia; however, estimates of such imports by MOMR, using data fromCustoms authorities, do not provide a valid basis for reconciling theestimates of total consumption, official imports by YPC, and unofficialimports. We also noted that volume measures of YPC imports and sales areconverted to weight measures using different conversion factors. Thehistorical consumption/supply balances for products discussed below aretherefore based largely on our estimates and are approximate.

3.03 Consumption of petroleum products including LPG increased from 202,400tons in 1975 to 969,000 tons in 1984 (or at an annual growth rate of 19X), andto 1,574,000 tons in 1988 (or a rate of 12.4X between 1984 and 1988).Gasoline consumption increased at a steady rate of 21X p.a. whereas that of

- 20 -

diesel oil, while increasing at 20X pa. during 1975-84, appears to havestagnated at a growth rate of 1X during 1984-88. Therefore, correlating roadtransport fuel consumption with vehicle fleet population, average distancetravelled, and specific fuel consumption by type of vehicle is difficult dueto the lack of reliable data. Fuel oil and aviation turbine kerosene (ATK)consumption figures are reasonably accurate since thelr end-users are readilyidentifiable Our estimate of YAR's hLstoric consmption of petroleumproducts is shown in Anngz III-1 and summarized in Table 31.

Table 3.1 TAR - Historic ConsumutLon of PetrolrMM Produqts(in '000 t)

i97 1980 i96 198-4

Gasoline 49.5 203801 257.0 568.1Diesel Oil 94.4 399.L 477.0 495.0ATK 5.1 24.5 33.9 62.0LPG 4.6 19.5 54.0 96.0Kerosene 38.8 77.6 70.7 63.9Fuel Oil 10.0 _6.0 76.4 289.0

Total 202.4 734.8 969.0 1,574.0

3.04 Supplies of refined products consist of imports by YPC through theports of Hodeidah and Al-Mukha, direct fuel oil imports by YGEC for its twocoastal power plants, net supplies of products from the Marib Refinery sinceApril 1986, and unofficial imports across land borders with Saudi Arabia andPDRY. Unofficial imports of gasoline are believed to have been verysignificant during 1984-86, far exceeding YPC's official imports, but appearto have been reduced to insignificant levels since then, which is ascribed tothe devaluation of YAR's currency relative to Saudi Arabia's. Theproduct-wise consumption/supply balance during 1984-88 is shown in AnnexIII-2. indicating that in 1988, 68X of domestic demand for petroleum wassupplied by imports. The operations of the Marib refinery are described inParas. 3.08 - 3.11.

3.05 Projections of products demand vere prepared as part of thefeasibility study for a second refinery (see par&. 3.20) and reviewed by us inthe light of current macroeconomic growth projections. Future demand for roadtransport fuels - gasoline and diesel oil - was estimated on the basis ofanticipated vehicle fleet growth, average annual mileage and specific fuelconsumption by type of vehicle. The fleet growth appears to provide the bestbasis for this estimate even though there have been significant additions ofunregistered passenger cars to YAR's fleet. For gasoline, the study's impliedgrowth rate of 8.3X/p.a. during 1988-95 and 5.2X during 1995-2005 isconservative in comparison to the historic 1980-88 growth rate of 13.4X,reflecting the normal reduction after rapid initial growth from low

- 21 -

consumption levels as vell as increased user efficiency. We consider thedLesel oil consumption growth assumed at 4.42 during 1988-1995 and 3.0X during1995-2005 reasonable. Demand estimates for jet fuel ezhlbit a similarphenomenon of lover growth in the future than in the past and have been basedon Yemenia Airlines' growth targets, correlated with projected generaleconomic growth. Kerosene demand is projected to decrease gradually,reflecting substitution by LPG. We consider that the study's demandprojection methodology and the estimates themaalves for the above mentionedfuels are acceptable. But we have carried out independent projections forfuel oil and LPG based on our assessment of growth in YAR's power sector andof gas development and utilization. Our demand projections using base caseassumptions are shown in Table,3.2.

TIale 3.2 YAR -s for Petrol brdacs. 1920-2005(in '000 t)

Actual - Prolected Growth Rates X p.a.

1988 1990 129 2000 200S 1980-88 1988-95 1995-2005

Gasoline 568 650 990 1,275 1,650 13.4 8.3 5.2Diesel oil 495 545 670 786 902 2.7 4.4 3.0ATK 62 70 100 140 189 12.0 7.1 6.6LPG 96 114 193 268 331 16.3 16.3 5.5Kerosene 64 60 60 55 50 (2.4) (0.1) (1.8)Fuel Oil 289 482 587 152Lg 185Sa - 10.7 (10.9)/a

/A Reflects the anticipated substitution of fuel oil by natural gas.Otherwise, fuel oil demand is projected at 1.0 million t in 2000 and 1.2million t in 2005 (see para 6.03).

3.06 Distribution of products is carried out by YPC through regionalstorage installations at Sana'a, Hodeidah, Taiz, Narib and Al-Mukha. Theregions served by Sana'a, Bodeidah and Taiz account for 90-95% of YAR's totalconsumption of gasoline, kerosene and diesel oil, and for 1002 of ATK and fueloil. The regional shares mentioned above take into consideration YPC's salesonly and do not take into account the distribution of unofficial imports amongthe regions for which there are no statistics, or those by YGEC for its powerplants. Historical regional consumption shares during 1985-88 and ourprojections of these shares for the future (YPC sales only) are shown in AnnexIII-3 and regional demand projections in absolute terms, in Annex III-4. Theyreflect the impact of increasing natural gas use expected for the 1990's andaccelerated demand growth expected for the Narib and Al-Nukha areas.

3.07 YPC's and 0M1R's organizational capabilities are weak vith regard tothe systematic gathering and interpretation of data on supply and consumptionby product and by major user-sectors. There is no adequate coordination withthe Transport Ministry, YGEC and with Customs authorities, and unofficial

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imports are not adequately tracked and documented. It is recommended thatMOMR/YPC engage specialized services to establish adequate systems forassembling country-wide petroleum sector statlstics, including data gathering,interpretation and demand projections, and provide training for a core ofYemeni personnel for this purpose.

B. Marib Refinery

3.08 Presently 22X of YAR's demand for gasoline, 36X of diesel oil and 57%of fuel oil is supplied by the 10,000 bpd hydro-skimming refinery at Safer(Marib Governorate) which vas commissioned in April 1986. The refinery isjointly owned by Yemen Hunt Refining Company (YHRC) and YPC under the terms ofthe PSA. The plant was originally intended to refine part of Alif crude oilto provide only diesel oil for crude oil and gas production operations butlater designed to also produce gasoline; it was constructed as a skid-mounted,modularized unit with self-supporting utilities and infrastructure facilities.

3.09 The refinery yield pattern averages about 31.5 vol X gasoline, 34.8%diesel oil and 28.7X fuel oil, with the remainder representing internal fuel(in addition to some natural gas) and losses. Part of the production ofgasoline and diesel oil is used by YHOC for crude and gas productionoperations and the rest is sold to YPC under a refined products productionsharing agreement. The overall refinery balance for the period April 1986 toDecember 1988 is shown in Table 3.3. This refinery does not produce keroseneor ATK because of the high paraffinic nature of the Alif crude oil, requiringall kerosene fractions to be cut back into diesel oil to conform to the pourpoint specification of 250F. Because of low sulfur content of Alif/Azal crudeoil, the distillates and fuel oil do not require treatment facilities.

Table 3.3 Marib Refinerv Material BalanceAnril 1986-December 1988

(in '000 bbls)

Total Delivered to YPC duringProduction X 1986 1987 1988

Gasoline 3,071 30.8 805.3 1,089.9 1,114.7Diesel Oil 3,497 35.1 868.6 1,159.2 1,098.3Fuel Oil 2.954 22.7 793.9 1,109.5 1,050.5Subtotal 9,522 95.6

Fuel Losses 435 .4,Crude Charged 9,957 100.0

3.10 The refinery is operated under a "comfortable" operating regime, andthere are possibilities for optimizing its yield pattern and increasing theproduction of higher-value distillates possibly by up to 5X through moredynamic operations control. To increase the benefits of refinery operations,it is recommended that NONR launch a program of improved training of Yemeni

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personnel in refinery operations, and to adjust refinery operations tooptimize its yield pattern.

3.11 Information on the accounts for the refinery proper, anddisaggregation of refining costs in sufficient detail including for operationsby the foreign partner, were not made available to us. However, indicationsare that the total refining costs incurred during the last three years ofUS$1.8-2.3 bbl, are acceptable although somewhat on the high side. In ourestimation, refining at Narib is an economically attractive alternative tosupplying YAR's main consumption areas with imported products. The cost ofproducts supply from the refinery, comprising the opportunity value of crudecharged to it (at FOB export price minus cost of pipeline transport from Saferto the Red Sea), plus refining cost and road transport cost of products fromthe refinery to Sana'a, is likely to be less than cif products import costs atHodeidab plus road transport costs to Sana'a. It is recommended that MOMRconduct a brief study to confirm the economic benefits of continued operationof the Marib refinery, including of the desirability of relocating thefacilities to Mabar along the crude pipeline route and closer to the mainproduct consumption areas.

3.12 Currently the bulk of the fuel oil produced at the Marib refinery istransported by road to the power plants on the Red Sea coast. In our view itcould be economically more beneficial to spike the fuel oil into the crude forexport, and to import the fuel oil required for power generation. Thequantity of fuel oil so spiked (about 3,000 bpd) would be too small relativeto the crude quantity (about 140,000 bpd) to significantly affect the crudeoil quality. Even alloving for some discount on the FOB export price of crudeoil, this alternative is most likely to be more beneficial. It is recommendedthat fuel oil spiking into the export crude be commenced as soon as possible.

C. Storage Facilities

3.13 Hodeidah is the main port for imports of refined products. Due tolimitations of draft, the port can admit only small tankers of a maximum15,000 DWT with loads of up to 10,000 DWT. The tank farm adjoining the porthas a total capacity of some 52,000 t of liquid products storage, excludingLPG, which is planned to be expanded to about 60,000 t by 1990 by refurbishingthree gasoline tanks and constructing additional tanks for kerosene and dieseloil. Most of the current tankage which was built in 1974, is in fairly goodphysical condition. However, a system for maintenance through periodicinspection is lacking. Facilities for product loading into tank trucks alsoappear to be in good working order but require an improved system for quantitymeasurement through tank-truck calibration besides the current method whichrelies on meters. It is recommended that YPC strengthen its tank farmmaintenance arrangements and measurement systems with the help of specializedassistance and increase the training of its operations personnel for allstorage terminals.

3.14 Based on our demand projections, the planned 60.000/t storage capacitywill not be sufficient to provide a 21-days stock of YAR's white products

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demand. Based on future demand growth assumptions (para 3.05), YAR's storagerequirements would amount to 87,000 t by 1995, 130,000 t by 2000 and 160,000 tby 2005. The current facilities at Hodeidah cannot be expanded to such levelsbecause the resulting road congestion would be excessive, and because oflimitations in additional land availability as well as draft limits in theport. NONR/YPC are therefore considering to install new products port andstorage facilities at Ras Issa (see below). If and vhen such new facilitiesare installed, the current Hodeidah tank farm could be used as operationalstorage for supplies to the Bodeidah region.

3.15 Regarding the current storage capacities at Sana'a (excludingstrategic storage capacities) and Taiz, on the basis of 30-day consumptionthese are already inadequate and require expansion. Annex III-5 summarizescurrent storage capacities by location and product. Arnex III-4 referred toearlier also summarizes the incremental white products storage needed to beinstalled at each location in order to provide adequate capacities on aregional basis in the future; this is based on our projections for totalcountry and regional demand; as an order-of-magnitude, we estimate that up to2005, required investments for this purpose total US$35-40 million. It isrecommended that YPC increase its petroleum products storage to ensure anuninterrupted supply to all parts of the country.

D. Ras Issa Port and Storage Proiect

3.16 In addition to replacing the Hodeidah petroleum products port andstorage facilities with new ones as mentioned above, COY is beginning toconsider relocating YAR's crude export facilities to Ras Issa, a thinlypopulated area on the coastline about 65/km north of Hodeidah; it has deepdraft close to the coastline and is thus approachable by large tankers andpotentially a good site for installation of tanker receiving/loadingfacilities through offshore single-buoy-mooring (SBN) and for storages forcrude oil and products.

3.17 After separation in the central processing unit located at the Saferoil field, crude oil is presently transported by pipeline over about 430 km tothe Ras Issa receiving station, from which it is pumped by subsea pipeline toa COY-owned tanker (T.S. "Safer") moored about 20 km offshore, which acts as afloating storage. From this 500,000 DWT tanker which has an effective storagecapacity of about 3 million bbls of crude oil, the oil is pumped into exporttankers moored alongside from time to time. According to information receivedfrom MOHR, the operating costs (excluding capital-related costs) for thetanker amount to about US$10 million per year, without allowing for the costsof periodical overhauls and tanker lease during the periods the T.S. "Safer"is out of commission.

3.18 According to our preliminary assessment of its economic justification,implementing the Ras Issa project could be attractive. The base case economicrate of return (ERR) of the project is estimated at about 22X and the netpresent value (NPV) (at a 12X discount rate), at US$36 million when assuming(i) installation of 240,000 t of on-land crude storage capacity replacing the

- 25 -

TS "Safer"; (ii) 160,000 t of vhite products storage capacity to be builtduring 1992-2005; (LiL) estimated total capital costs of US$68 illion forstorage, US$20 million for mooring facilities and other infrastructure, andannual operatLng costs of US$7 million; (iv) freight savings on productimports at US$9 t of white products (as compared with importing products insmall vessels at Hodeidah); and (v) operating cost savings on the crude oilstorage vis-a-vis continuing operation of TS "Safer". Our preliminarycalculations are shown in Menx 111-6. Fuel oil imports for supply to the twocoastal pover plants are expected to continue being handled through their ownfacilities and therefore, no major fuel oil storage vould be needed at RasIssa.

3.19 It is recommended that a detailed study be carried out to define thephysical facilities required, develop the engineerLng, estimate the capitaland operating costs, confirm the econowic/financial justification of theinvestments, aud develop a master plan for this project; the same study shouldalso reconsider the justlifcation of investments in a multi-products pipelinefrom Ras Issa to Bajil and/or Sana'a and its implicatlons on the scope ofproducts storage facilities to be installed at Ras Issa. This was originallyrevieved by a 1983 consultant study which recommended construction of such apipeline vith marine facilities at the Red Sea port of Salif, but GOY has notdecided on its implementation or routing. This study should be up-dated aspart of the new Ras Issa study. It is evident that the economic viability ofthis project is closely related to YAR's storage, supply and distributionnetwork, and it should be treated as an lntegral part thereof.

E. Second Refinerv Proiect

3.20 The feasibillty of establishing a second refinery in YAR was esaminedby an IDA-financed study conducted by UOP Processes InternatlonalInc./Chemsystems (UOP/CS); the study was commissioned by GOY in 1986 andcompleted in 1989Y. In llne with lts terms of reference, the study took theadequate availabllity of domestic crude oll for granted; it assessed fivepotentlal locatlons for the new reflnery - Ras Khatenib, Ras Issa, Bajil,Narlb and Nabar - resultlng ln the conclusion that Ras Issa would be the bestlocation. Also, several refinery configurations were evaluated, resulting inthe finding that a fluid catalytic cracking configuration would be the mostappropriate and largely consistent with projected trends of domestic productsdemand. The study analyzed the economic justifLcatLon for the investment,taking into account several scenarlos concerning future demand, crude oilslate, products yield profile, market prices and capital costs.

3.21 The analysls conducted by us of the project justLfLcation ln economlcterms is based on the above study, wLth our assessment of domestlc productdemand, a modlfled capital cost estimate (US$350 mllion, excludlng financial

"Feasibllity Study for a New Refinery" by UOP Processes International Inc.,of March 10, 1989.

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costs), and the Vorld Bank's current projections for international prices ofcrude oil and products. We have also assumed that, based largely on nevdiscoveries, domestic crude of Xarib-type specification will be available tosupply 73S of the refinery's requirements. Tble 3.4 presents our "Base Case"assessaent comparing the co t of supply of imported products net of the valueof exported crude if the refinery project is not iaplemented, with the costunder the situation where the refLnery were built. Our finding is that,except in the outer years, the total net cost of products supply isconsistently higher wLth the refinery in place thank without. This shows thatit would be more economical for YAR to continue to export its crude and importthe needed refined products. Annex 1I1-7 describes in detail the calculationsand assumptions used in our economic analysis of the project. Therefore, andalso in view of the macroeconomic impact of undertaking such a majorinvestment, Jt i8rco ended that GOY not pursue the project further at thistime.

Table 3.4 YAR - Second Refinery ProtectNot Cost of Products SuDDlV

(in million constant Us Dollars of 1988)

Without Refinery With Refinerv1994 19 Z000 2005 194 1995 2000 2005

Cost of product imports (cif) (27a.5) (291.8) (496.4) (777.5) (20.1) (14.0) (0.4) (126.1)Revenues from product exports /a - - - - 37.1 74.3 35.3 24.0Feedstock imports (heavy stock) - - - - (51.7) (61.6) (91.7) (115.9)Rev.nua from equivalent crudeoil exports (fob) 206.9 256.5 377.8 476.0 - - - -

Operating costs - - - - (19.4) (20.5) (18.0) (18.0)Capital recovery jb - - - - (63.0) (63.0) (63.0) (63.0)Interest on working capital LI - - - (0.7) (0.7) (0.7) (0.7)Salvage value of capital - - -Total net cost of supply ( 716) ( 35.3) (116.6) (301.5) (117.8) (85.5) (138.5) (258.4)

_ Consists of exports of: i) gesoline at 181,000 in 1994. increasing to 456,000 by 1996, and decreasing to zeroby 2001; (ii) marginal exports of kerosene of 1-2 thousand tons during 1996-2005; (iii) Jet fuel of 1,000 in1994. increasing to 28,000 in 1996. and decreasing to zero by 2000; (iv) diesel oil at 82,000 in 1994,increasing to 267,000 in 1996, and decreasing to zero by 2000; and (v) bitumen at 14,000 in 1994. increasing to29,000 in 1996, and decreasing to zero by 2000.

/b At 12S interest over 12 years on capital cost of US$390.2 million (including interest during construction ofUS$49.1 million).

LI At 12S on US$6 million.

3.22 Based on the costs and benefits assumed for our Base Case, the projectwould have an only marginal ERR of 3.2X, confirming the above conclusion.Besides the Base Case, ve assessed eight other less likely scenarios (seeAnnex III-7), representing combinations of differring assumptions for demand,prices, crude and product slate, and capital/operating costs. Of all the

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scenarios analyzed, only those corresponding to the more optimistic UOP/CS andNOHR's sets of demand assumptions and our scenario assuming increasedinternational product prices ("Refmis VI") show positive NPV's of theproject's economic costs and benefits. The "Refmis VI' scenario assumes thatthe international product-to-crude price ratio would increase from 1996onwards, reflecting a hypothesis that the world-wide demand and supply wouldequilibrate by 1995 and consequently, refining margins would increase to allowcovering full cost recovery of new refinery investments coming on stream by1995. However, until such time as product prices in relation to crude pricesshow a definite and substantial increase approaching the levels assumed inthis scenario, a decision to invest in a new refinery would be very risky. Itshould also be noted that if domestic crude is not available in sufficientquantities for an estimated 12-year refinery operation and the resulting crudedeficit has to be made up entirely by imported crude, the ERR would fallconsiderably.

3.23 Concerning the scenario termed "UOP/CS Base Case", our re-evaluationresults in a 12.4X ERR compared to UOP/CS's analysis with an ERR of 18.6X.UOP/CS' higher return is due to (i) lower assumed capital costs, Xii)inclusion in the production slate of LPG which is assumed to have a valueequal to its present high import cost, (iii) higher FOB realization values forthe export of surplus production which are not fully consistent withassumptions on freight costs on imports used for valueing refinery outputs,and (iv) what we consider over-optimistic assumptions for future crude andproduct prices that are much higher than those forecast by the World Bank.The scenarios corresponding to MOMR's set of assumptions show ERRs in excessof 18X because of even higher product prices assumed and a higher productsdemand growth rate, both of which in our view are not realistic. As afurther variant, we tested the impact of delaying the substitution of fuel oilby natural gas: the assumption that gas would not be available to power andcement plants before 2005 resulted in an only small increase of our Base CaseERR from 3.22 to 4.72; in essence, the greater fuel oil demand as a result ofa delayed gas pipeline implementation would not make the refinery project anymore attractive.

IV. POWER DEMAND AND SUPPLY

A. Demand

in YAR, a total 1988 consumption of 766 Gwh is estimated. 462 of thisconsumed by households, 272 by industrial users, and 142 by commercial users,with the remainder attributable mainly to the military, agriculture, watersupply, hotels and street lighting.

La Conducted by the UNDP/World Bank Energy Sector Management AssistanceProgram (ESMAP) and co-financed by the Government of the Netherlands.

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4.01 YAR's power sector consists of (i) the interconnected power gridlocated in the western part of the country and numerous isolated systems, alloperated by the public utility, Yemen General Electricity Corporation (YGEC),and (ii) a large number of private autogeneration units among industries andhouseholds throughout the country. Given the lack of reliable data, YAR'soverall power demand cannot be assessed with certainty; but based oninformation availatle from YGEC and the ongoing Household Fuel Marketing StudyA which will complement the ESR in providing details on many of the ouseholdenergy users

4.02 In order to project YAR's future power demand, we have made certainassumptions. Given YAR's historic power demand growth and currentmacroeconomic growth projections, and in view of the World Bank's experiencein similar developing countries, we have assumed a 6% normal annual growth inmaximum demand (on a straight-line basis) for YGEC's interconnected system.This demand is expected to increase from 128 MW in 1987 to 374 MW in 2000 and660 MW in 2015. If major industrial loads (such as cement plants and foodprocessing industries) are included as now expected, the maximum demand in2000 would rise to 464 MW. The maximum demand for YGEC's isolated systemswhich represent generation in YGEC's branches remote from the interconnectedsystem and which was about 17 NW in 1988, is estimated to decrease to 12 MW in2000. Household demand, including from non-YGEC systems, is assumed to growat a compound annual rate of about 71.

4.03 Industrial power demand growth will have a critical impact on thepower sub-sector. If this materializes as now expected, the share ofindustrial in total demand would i:.crease from presently 23X to 511 in 2000.At that time the industrial loads would account for 90/MW out of the estimatedmaximum demand for the inter-connected system of about 464/MW. If they don'tmaterialize, the need for expanding YGEC's power supply could be delayed. Themajor addition in the industrial loads would be on account of the existing twocement plants of Amran and Bajil, now generating their own power, and theproposed cement plant at Al Barh (Mafraq), which eventually will account for atotal cement production of about 2.6 million t/yr. However, if plans forinstallation of the Mafraq plant are delayed or cancelled, there would be areduction of about 25 MW in the maximum demand.

4.04 Table 4.1 provides an overview over YAR's current and projected demandestimates. Annex IV-1 provides further details as to YGEC's sectoral salesprojections through 2000, expressed in Gwh as well as YR at current tarifflevels.

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Table 4.1:. YAR - Power Consumution Estimates(in Gwh)

1988 a/ 1995 2000Power Generated by: YGEC Other YGE Othe: YGEC Other

Households 217 139 402 201 538 266Industrial 125 82 707 - 1,019 -Commercial 107 - 215 - 285Other 96 - 136 - 165

Total 766 1,.661 2.273

A/ Actual

4.05 Data provided by the Household Fuel Marketing Study indicate thewidespread use of electricity in both rural and urban households: about 70X ofall households in YAR use electricity. Given the large amount of electricityconsumed by households and its associated costs, the household electricitysupply strategy is an important part of YAR's overall energy strategy for bothsocial and economic reasons.

4.06 Currently there are nearly 1.3 million rural households. However,only 49,000, or 4X are connected to the YGEC system while some 700,000, or541, use electricity from other sources. Assuming that the number of ruralhouseholds will increase by 2% annually over the next 15 years, there will benearly 1.8 million rural households by 2004. If implementation of the currentand proposed power projects as well as the Earthquake Reconstruction Projectproceed as planned, there will be approximately 370,000 rural householdsconnected to YGEC, suggesting that the portion of rural households soconnected will increase to only 211 by 2004. If the fraction of ruralhouseholds using their own generators or purchasing power from privateproducers remains constant at 451 of all rural households, there will be over800,000 rural households using electricity generated from sources other thanYGEC. Paras 4.19 - 4.21 provide a detailed discussion of the issues involvedin rural electrification.

B. Generation and Transmission

4.07 This section discusses YGEC's operations only. Its system consists oftwo parts, namely the interconnected grid (comprising the thermal powerstations at Ras Khatenib and Al-Mokha and the major diesel stations in theurban areas of Sana'a, Hodeidah and Taiz, all connected to the 132-kVnetwork), and about 33 isolated systems throughout the country, comprisingdiesel units and associated distribution networks. The interconnected systemhas an installed capacity of 372 MW, of which 310/MW in the two thermal plantsand 62 MW in the city diesels. In 1988 the grid accounted for about 931 ofYGEC's electricity sales and generation. According to current plans, by 2000this system would increase its generating capacity to 590 MW, while thecapacity in the isolated systems would gradually fall from presently 26/MW to18 MW as more of the areas now served by the diesel units get connected to thegrid.

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4.08 At present the interconnected system has an excess generatingcapacity. In 1988, the maximum demand of the interconnected system was143/MW, leaving a reserve of 160%. However given general demand growth, andif the Amran and Bajil cement plants and other industrial users are linked tothe interconnected system during the next few years, this margin is expectedto disappear in 1993; additional capacity would have to be installed then tomeet demand. As discussed below, natural gas is the preferred energy forpower plants. If natural gas is not available, YGEC would have to installadditional fuel oil fired thermal plants instead of the more efficientcombined cycle gas based power plants, or would have to take load managementmeasures (including load shedding) as may be required to contain the demandfor power within the available capacity. Either option would mean financialloss to YGEC (see para 4.13).

4.09 YGEC's auxiliary consumption in the existing power plants and linelosses are high. In 1988 the percentage of auxiliary consumption at RasKhatenib was 11.5% and that at Al Mokha, 9.5%. Moreover, the auxiliaryconsumption in the diesel plants of the isolated systems stands at a high 15%.YGEC so far has not analyzed in detail the causes for these high levels.Similarly, 1988 line losses of the interconnected system are estimated at 25%and for the isolated systems, at about 21%. As regards our projections, wehave assumed that with installation of more efficient gas-based combined cycleplants in the future and better management of existing oil fired thermal powerplants, the auxiliary consumption for the interconnected system would bereduced from about 10% in 1988 to about 6% in 2000; in case of continued oilfiring, the auxiliary consumption was assumed to be reduced to about 8% in2000. It is recommended that the causes for YGEC's high auxiliary consumptionbe investigated rigorously and appropriate action be taken to reduce it.

4.10 YGEC is concerned about its high line losses of 25% out of which 6%could represent non-technical losses. For its financial recovery plan, YGEChas already appointed consultants (under IDA-Credit 1361-YAR) who areassisting in the streamlining of billing procedures and in reducingnon-technical losses. About 4% of the remaining line losses could beattributed to the inadequate sub-transmission and distribution network whichneeds to be rehabilitated. UNDP/OPEC Fund are likely to support YGEC incarrying out a power system loss reduction study, strongly recommended by theWorld Bank, which could provide a rehabilitation and line loss reductioncomponent for the urban areas of Sana'a, Hodeidah and Taiz under IDA'sproposed Fifth Power Project. In our projections we have assumed that linelosses would be reduced from 25% ir. 1988 to about 15% in 2000. In case such areduction is not achieved. YGEC would have to generate a total of about 2816GWH in 2000 instead of the 2485 GWH as assumed by us under the gas option,meaning that an additional generating capacity of 54 MW would have to beinstalled. It is therefore recommended that the line loss reduction study becompleted with urgency and that recomended measures be strictly enforced toreduce losses to a targeted 15% by 2000.

4.11 As a result of YAR's foreign exchange shortage, and since YGEC'sexisting thermal plants are under-utilized, requirements of power plant spare

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parts have often been met by cannibalizing unused generating units. With anincreasing power demand, all existing units will soon be required inoperation. To permit this to happen, it is recommended that GOY makeavailable adequate foreign exchange to allow YGEC to acquire full spare partssupplies, especially for all units in its two thermal plants, and to installappropriate spare parts management and maintenance control systems to ensurethat efficient operations are not jeopardized in the future.

4.12 GOY had earlier initiated studies to explore prospects for geothermalpower generation. These however, were abandoned as uneconomical in light ofthe recently discovered hydrocarbon resources. We agree with GOY that nofurther work be undertaken on this subject at this time.

C. Future Capacity Reguirements

4.13 Based on current demand projections, additional generating capacitywill need to be available by 1994. The type of additioral plants to beinstalled depends basically on GOY's decision regarding the availability ofnatural gas (see Chapter VI). In our analyses we have therefore focussed onYGEC's projected operations under two scenarios, namely (i) the "Oil Option"under which no natural gas would become available and all future powergeneration would continue to be fuel-oil based, and (ii) the "Gas Option"under which adequate quantities of gas would be available for use by new powercapacity to be installed beginning in 1994 as well as for the converted RasKhatenib plant; due to the less attractive economics of extending the gaspipeline further, it is assumed that the Al Mukha plant would continue to beoil fired. Since no details are available as yet for implementation of thegas pipeline, we considered three sub-options, namely (i) that gas would beavailable for the projected up-country combined cycle plants but the pipelinewould not extend to the Red Sea Coast and that Ras Khatenib would continue tobe oil-fired; and (ii) that the pipeline would extend to both Sana'a and RasKhatenib. Annexes IV-2 and IV-3 provide projections up to 2000 for YGEC'spower generation and sales as well as fuel requirements for the interconnectedsystem under these options.

4.14 Under the Oil Option we assumed that the additional thermal generatingcapacity would be installed along the Coast. Fuel oil requirements in powergeneration would thus rise from about 210,000 mt in 1988 to about 720,000 mtin 2000 (see Table 3.2). With the ongoing strengthening of the Northerntransmission loop, no difficulties are expected in transferring the additionalpower to the major load centers of Sana'a/Amran which in 1988 was responsiblefor 52X of the interconnected system demand and is estimated to still accountfor 40% of demand in 2000. In case of the Gas Option, additional generatingcapacity requirements would be based on combined cycle modules of 90/NW, eachconsisting of two-30 KW gas turbines and one-30 MW steam turbine. The firsttwo modules would likely be located in the Amran/Sana'a/Mabar corridor and thethird, in the Bajil/Hodeida area whicn is technically feasible since make-upwater requirement of the modules is relatively modest (about 4,500 kg/hr permodule) and no difficulty is expected in meeting requirements at theselocation.

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4.15 The Governments of YAR and PDRY are considering installation of a132-kV interconnection linking the Aden system to YGEC's grid. The nature ofoperation of this interconnection is so far not known. Therefore, for thepurposes of this review, we have assumed that there would be no economicexchange of power.

4.16 Investment Requirements. Annex IV-4 provides an estimate of theinvestment requirements for YGEC's new generation, transmission anddistribution facilities as well as for normal system development/improvementsto meet projected load growth through 2000. For the Oil Option, investmentsare estimated to total US$ 703 million, and under the Gas Option, US$661million. The difference of about US$42 million is based on the less costlyand more efficient combined cycle modules. Utilizing gas rather than fuel oilis advantageous and economical. Income projections for YGEC under the oil andgas options are attached as Annex IV-5. In view of the greater generatingefficiency, the use of natural gas at YGEC's plants would have a clearlypositive impact on the company's financial situation. Provided that r-turalgas is available (see Chapter II), it is recommended that gas use and combinedcycle plant technology be introduced as soon as possible to meet YGEC's futurecapacity requirements and that the existing fuel oil based plant at RasKhatenib be converted to gas.

4.17 In view of the favourable economics of gas-based power generation,considering that under current demand projections new plants need to be inoperation by 1994, and keeping in mind the lead time required to complete thenecessary power plant feasibility studies and financing arrangements prior tocommencement of their construction, it is recommended that GOY reach an earlydecision to proceed with implementation of the gas pipeline to avoid having toinstall additional fuel oil based capacity or the need for loan managementmeasures (see para 4.08).

4.18 The investment requirements shown in Annex IV-4 take into accountongoing or committed projects of a network control center, the Northern loop132-kV transmission line, and the YAR-PDRY 132-kV interconnection. Inaddition, provision is included for the reinforcement to the transmissionsystem required to meet the projected load growth up to 2000. Estimatedinvestment requirements in distribution include IDA's ongoing or agreed Thirdand Fourth Power Projects as weli as the Earthquake Villages Project. It alsoreflects the proposed Fifth Power Project as currently under considaration.Although so far YGEC has made no provisions for reinforcement of distributionlines, replacement of overloaded transformers by others of adequate capacity,and replacement of old service connections and meters, we have assumedinvestment requirements of US$105 million for these purposes.

4.19 Rural Electrification. Except where electricity is put to productiveuse, it is often not possible to justify rural electrification on quartifiableeconomic grounds alone. Because of the high financial costs involved and thecomparatively meagre financial benefits from rural electrification, utilitycompanies are normally reluctant to extend supplies to rural areas. Thus,

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historically in most developing countries, the generation, transmission anddistribution of electricity has been concentrated in the urban areas.However, governments often consider extension to rural areas of infrastructurefacilities such as electricity necessary for socio-political reasons and to(i) provide incentives for industries to locate in less economically developedareas; (ii) disperse industry and avoid concentration in a few places and therelated pollution effects; (iii) counteract tendencies of populations tomigrate to urban areas and overstraining infrastructure facilities there: (iv)provide better security and health services; and (v) achieve perceived socialequity objectives. In practice it is difficult to quantify the benefitsassociated with fulfillment of these objectives. Therefore, the rate at whichrural electrification is to be introduced has to take into account both thefinancial burden it imposes on the utility company and possibly the governmentbudget, as well as the need to meet other government objectives.

4.20 A strategy most often adopted is for a proper analysis of theeconomics of rural electrification to be carried out from the nationalperspective, based on data on rural incomes and populations, alternativeenergy sources and their economic costs, and on the nature and incidence ofproductive activities. Such an analysis provides a starting point forformulation of a strategy which takes into account other non-quantifiablebenefits from rural electrification. A rural electrification masterplan isthen developed spelling out the strategy and criteria for selecting areas tobe electrified, methods of financing and of providing compensation to theutility company for losses arising from its supplying power to uneconomicareas.

4.21 YAR's circumstances are typical of most developing countries in thatthe costs of rural electrification are high (about US$1,500 per ruralhousehold connected), rural incomes and per capita consumption are low, andpopulation concentrations are thin. Considering costs such as mentioned, thefinancial resources necessary to accelerate the rate of rural electrificationare immense. The additional cost of connecting 1 million rural households forexample, which would result in the connection of nearly 80X of all ruralhouseholds in YAR, is estimated at US$ 1.5 billion. Given the difficulty ofmobilizing such resources, small-scale autogeneration by the private sector islikely to remain a dominant mode of power supply for rural households for theforeseeable future. In the short term, encouragement should be given to theprivate sector to supply the outer areas and to develop pilot projects toexperiment with unconventional methods of power provision such asphotovoltafes (solar energy), described below. It is recommended that in themedium term, GOY carry out a study to determine the benefits of ruralelectrification either through grid extension or autogeneration, developtechnical standards, and formulate a master plan as described above. Carryingout a proper analysis of the economics of rural electrification would requiredata on rural incomes and populations, alternative energy sources in ruralareas and their economic costs, the nature and incidence of productiveactivities, and others; the ongoing Household Fuel Marketing Study willprovide much of the needed data. In the meantime, our investment estimatesassume that the rural electrification programs included under IDA's proposed

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Fifth Power Project will be implemented at a cost of about US$126 million.

4.22 Private Generation and Photovoltaics. There are alternatives to thedecentralized power supply currently found in YAR. Analyses carried out aspart of the Household Fuel Marketing Study indicate that, under certainconditions which exist on a widespread basis in YAR, decentralizedphotovoltaic systems can provide electricity for basic needs at less economiccost than small autogeneration or grid extension. Specifically, forsettlements of less than 35 to 60 electrified households located at least 3 kmfrom existing grid supply, household photovoltaic systems appear to be theleast-cost electricity supply option for typical YAR rural household needssuch as lighting, radio and small television. Such systems might cost on theorder of US$500 per household and provide power at annualized costs 25X-50Qbelow the costs of grid extension or small autogeneration, depending on localcircumstances. It is recommended that GOY carry out further work for thedevelopment, demonstration and testing of household photovoltaic systems toestablish a basis for its decision on the use of this system in a wide-spreadand systematic manner, and to determine how private sector participation inthis effort can be mobilized most effectively. Results of this work couldprovide a useful input to the broader rural electrification study recommendedabove.

D. YGEC ManaLement and Financial Situation

4.23 Until 2000, YGEC is expected to increase about threefold itselectricity output; this will involve adding 240 MW of generating capacity andis expanding operations in transmission and distribution to cover more of therural areas. It is, therefore, essential that YGEC's organization be bettertuned to enable it more to efficiently manage its operations. Outsideconsultants are expected to continue assisting in developing YGEC's manpowerplan and training programs and to make recommendations about changes in YGEC'sorganization structure to reduce costs and meet its future needs. Under theprevious IDA projects, YGEC supported long-term overseas academic training andabout 40 students are currently being trained in the UK and USA; however, YGEChas yet to finalize placement of these trainees when they return to YAR. YGECalso needs to implement on-the-job training for its middle management with thehelp of foreign experts; this is specially needed for improving its operatingperformance and maintenance of generation, transmission and distributionfacilities. It is recommended specifically that YGEC (i) complete the ongoingprograms and implement their recommendations; (ii) introduce appropriatedelegation of power and responsibility to enable top management time forplanning and addressing policy issues; (iii) strengthen its planning functionto appropriately carry out short and long term planning ;(iv) improve thebudgetary system recently introduced and initiate procedures for establishinga comprehensive cost accounting and management reporting system to bringoperating costs under tighter control and (v) implement hands-on training inequipment maintenance.

4.24 YGEC is currently implementing various computer applications, the mostimportant of which are the billing system, financial accounting and job

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costing. Since most of these systems will not have been extended to allregions by the expiry of the current consultancy contract, it is recommendedthat YGEC make immediate plans for a follow-on phase to its financial recoveryplan consultancy. particularly with regard to the extension of thecomputerization of billing to cover more than the 231 of consumers whosebilling is now in the process of being computerized.

4.25 As shown on Annex IV-5, YGEC's financial condition continues to beweak and will continue so unless important steps are taken. The main causesare the above-mentioned excess generating capacity and high levels of systemlosses as well as diseconomies arising from numerous organizational unitswhich can be rationalized, the high price to YGEC in recent years ofdomestically produced and imported diesel oil (which in 1988 was 29% above itseconomic cost), and a level and structure of power tariffs that has not beenadjusted since 1981 to take account of inflation (see Chapter I). As aresult, the projected rates of return on revalued assets for the oil and gasoptions mentioned in para 4.14 are substantially below the rates agreed withIDA under ongoing projects (31 in 1989/1990 and 51 in 1991 and beyond). Inorder to re-establish YGEC's financial viability, it is recommended that acomprehensive plan consisting of both revenue enhancement and cost reductionmeasures be instituted as a matter of urgency; on the cost side, the planshould include reduction of auxiliary and system losses to appropriate levels,rationalization of YGEC's organizational and management arrangements, andstrengthening of budgetary and cost control procedures; on the revenue side,efforts should focus particularly on improving the billing system andcollection of accounts receivable, on increasing power sales by connectingseveral major industrial consumers, and on increasing the level and adjustingthe structure of tariffs (see para 1.31).

4.26 According to the World Bank's 1984 Electricity Pricing Study, YGEC'stariff structure contains cross-subsidies between consumer categories:subsidized are most industrial consumers (with the exception of some sz-qllerones), some hotels and agricultural enterprises. Although changes may haveoccurred since 1984 in the prices of oil as well as in power plant costs, itis most likely that both financial and economic distortions in power tariffsremain (see para 1.31).

V. LIOUIFIED PETROLEUM GAS

5.01 GOY has targeted LPG as a primary substitute fuel in its efforts todecrease fuelwood demand and thereby slow the depletion of YAR's woodresources which would occur if existing patterns of residential and commercialenergy consumption continue, with serious effects on welfare particularlyamong lower income households. Strong demand for LPG cannot be satisfied dueto constraints in supply. Logistical bottlenecks, particularly in bottlingand transportation, have led to severe demand/supply imbalances which in turnhave spawned an active black market for LPG and cylinders. LPG producedlocally from associated gas is now reinjected into the oil field reservoir dueto lack of storage, loading and transportation facilities, while demand has

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been met to a limited extent by costly imports. Two primary and interrelatedissues arise from this situation, namely. (i) how to bring LPG productionon-line as rapidly as possible in order to reduce both the cost of supply andthe import bill, and (ii) how to relieve the logistical bottlenecksconstraining consumption and interfuel substitution.

A. Demand

5.02 Total LPG consumption in YAR increased from an estimated 27,000 t in1982 to about 84,000 t in 1987 and 96,000 t in 1988. In 1987, the last yearfor which detailed information was available to us, approximately 70,000 twere consumed by households and most of the balance, by poultry farms. Withimprovements in the av-ilabtlity and delivery of LPG and other measures whichGOY should take, we estimate that household demand could increase threefoldand reach 240,000 t by 2000; in addition, a potential demand of nearly 30,000t year could be tapped in other sectors such as by poultry farms and largecommercial consumers. In 1987 approximately 43X of all households in YAR usedLPG (371 of rural and 89X of urban households) according to the ongoingHousehold Fuel Marketing Study; average consumption for users was 125 kg/yr(109 kg/yr for rural and 179 kg/yr for urban households). While urbanhousehold penetratiozA in different areas ranged from 671 to over 95A, it wasonly about 361 in rural areas, leaving significant potential for consumptiongrowth there. We therefore believe that once LPG becomes available moreeasily, demand for this form of energy will increase significantly.

5.03 A 1987 survey of YAR households indicated that for only 12X of allhouseholds not using LPG, the primary reason for not using it was lack ofaccessibility; 611 cited the high initial costs of fuel switching as well asthe lack of bottles as the major reason. Of whose who were using LPG, about431 indicated that lack of cylinders represer sd a major difficulty with LPGuse. Although YPC officially charges a deposit of only YR150 per cylinder,the average household cost of an empty cylinder was about YR400, with somecases reported as high as YR1,000.

5.04 With the planned alleviation of supply constraints, policies andprograms will become the critical factor in promoting LPG demand to reducefuelwood consumption. In this regard we have analyzed two scenarios resultingfrom possible GOY strategies, namely:

(i) "Natural Substitution" of fuelwood consumption, where no GOY action istaken beyond making domestically produced LPG available in anaccelerated way. In this case, and should the current trends inhousehold energy consumption continue, YAR's total fuelwood stockswould be depleted in about ten years to the level currently found infuelwood deficit areas such as Dhamar. This scenario assumes that atthat time, national household LPG consumption would also reflect thepatterns currently found in Dhamar where it is relatively intensive.Non-household LPG demand growth is assumed at 51 annually and includesthe demand by commercial users such as poultry farms which isestimated to grow to 29,000 t by 2000.

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(ii) "Managed Transition' where additional actions are implemented by GOYat an early stage to promote LPG use, including (a) an increase in theavailability of LPG cylinders, to ensure their adequate supply at anaffordable price, (b) mobilization of and providing incentives for theprivate sector to participate in LPG bottling, marketing anddistribution, including in bulk, (c) development and dissemination oflow-cost LPG bread-ovens and other appliances, (d) formulation andenforcement of codes and standards to help ensure product safety andthe smooth operation of bottling and distribution, and (e)establishment of a separate agency or unit within NOMR that would beresponsible for LPG production and code enforcement (see below).

5.05 We compared the two scenarios with a theoretical "Maximum Potential"which establishes what could be considered as the upper bound for futuregrowth in domestic LPG consumption. This is characterized by steady growth inLPG demand, such that, at the end of 15 years, all households in YAR consumeLPG at the average 172/kg/yr rate of those who today use only LPG and nokerosene or wood. Non-household demand is assumed to grow at 10 annually.The estimated LPG demand under the two scenarios and the maximum potential areshown on Table 5.1.

Table 5.1 LPG Demand Estimates(in '000 t)

1988-2000Projected Growth Rate

1990 20 (X)

Natural Substitution 108 144 193 6.0Managed Transition 114 193 268 8.9Maximum Potential 119 201 340 11.1

5.06 Clearly, GOY actions can make a significant difference in LPG demandgrowth: according to our estimation the difference in consumption under thetwo scenarios after 12 years is estimated at 75,000/t/yr, which is equivalentto about 500,000/t of fuelwood or 10 of present fuelwood demand. It isrecommended that GOY take adequate measures needed for a managed transition toincreased LPG use, undertaking the appropriate investments and implementingpolicies and programs to encourage LPG substitution of fuelwood and petroleumfuels.

B. Imports and Potential for Domestic Productio.

5.07 Of the 96,000/t of LPG consumed in 1988, approximately 82,000/t wereimported by sea in bulk and bottled in Hodeidah by YPC. Bulk importationthrough the Hodeidah port is limited by the capacity of off-loading, storageand bottling facilities, and is costly due to high ocean freight because LPGmust be imported in small tankers. The cif price for LPG is now aboutUS$200/t, resulting in an annual cost to the economy of nearly US$20 million.

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The remaining 14,000/t of LPG consumed in 1988 were imported in cylinders fromPDRY.

5.08 Approximately 2,600/bpd (80,000 t/yr) of LPG is being recovered fromassociated gas at the C5 + gas plant at the Safer Alif/Azal oil fields.However, in the absence of storage, transportation and loading facilities, theLPG is reinjected back to the reservoir. Production of this LPG, whosequality is in conformity with standard commercial specifications, could beeasily increased to 4,000 bpd (120,000 t/yr) by processing additional gas.Further quantities of LPG (up to 6,000 bpd or 180,000 t/yr) can be producedfrom Alif/Azal gas by installation of cryogenic processing units. Based onthe presently proven gas reserves (see Chapter II) and assuming (i) the samegas composition for all new fields as found at Alif, (ii) a 75X reservoirrecovery factor and (iii) an 851 recovery of propane and 1001 butane,approximately 16 million tons of LPG could be available in total; inprinciple, this would be sufficient to meet an annual demand of 300,000/t forover fifty years.

5.09 GOY decided recently to proceed with an "LPG crash program" toexpedite the utilization of this indigenous LPG. This program is beingassisted by IDA under its Technical Assistance Project. Specifically, theprogram includes (i) preparation of an optimum and long-term LPG developmentplan for YAR, supported by the necessary economic justifications, (ii)installation of LPG storage and loading facilities at Safer, (iii) review ofthe feasibility of installing optimum size bottling plants in cities with mainLPG distribution depots, (iv) procurement of LPG road tankers to transport upto 120,000 t/yr from Safer to bottling plants, and (v) implementation of abulk delivery system to commercial and poultry farm consumers. Negotiationsbetween GOY and YEPC to agree on a joint venture framework for making the LPGavailable have been underway for a prolonged period, so far without reaching aconclusion. It is recommended that the "crash program" which is estimated tocost about US$5 million, be pursued vigorously, that the YEPC negotiations beconducted as soon as possible, and that this be followed by the implementationof adequate institutional arrangements for planning the future development ofLPG resources.

C. Bottling. Transportation and Distribution

5.10 Bottling. The extension of the Hodeidah bottling plant which iscurrently under way will increase its capacity from 82,000 t/yr to 136,000t/r; i.nstallation of facilities for bulk loading of road tankers is *.derstudy. The capacity expansion is expected to be sufficient for meetingdomestic LPG demand until 1991 and should obviate the need for YGEC's importsof bottled LPG. Once demand growth warrants it, additional bottling capacityshould be installed at optimum locations, supplemented by facilities to handlebulk deliveries. Apart from the "crash program" mentioned above, GOY has beenconsidering a larger project the centerpiece of which is a 170,000 t/yr 0bottling plant near Sana'a; the cost of this and other components is estimatedat about US$50 million for a first phase, as shown on Annex V-1. Our reviewindicates that this project may be over-ambitious for YAR's requirements and

I

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that a system of smaller, decentralized bottling plants to complement theHodeldah plant may be more appropriate. It i8 recommended that this projectbe re-evaluated in light of the conclusion of the recently completed studyundertaken as part of the "crash program".

5.11 Cylinders and Appliances. Under current supply-constraints,approximately 1/million LPG cylinders (or bottles) are in use by householdsand another 100,000, by commercial establishments; 300,000 are in circulationin the transport/filling system. Implementation of bulk LPG distribution toabout 1,500 identified commercial units and poultry farms and by the privatesector vhich has already shown interest, is likely to release some 125,000cylinders. Since many of the bottles in use are damaged and should berepaired or replaced, it is estimated that there are currently some 1.0million bottles in acceptable condition in circulation. Assuming that thenumber of LPG-using households increases by 30X over the next three yearsthere could be a total requirement of 1.7 million bottles by 1992, requiringthe importation of about 300,000 additional cylinders per year. It isrecommended that implementation of bulk distribution of LPG be expedited andthe stock of useable cylinders be increasei to eliminate shortages which coulddampen the benefits of the planned increase in L?G production and bottlingcapacity.

5.12 Cylinders cause only part of the initial cost of fuel switching. Ahousehold must also buy LPG appliances which can be costly: a burner ring,for example, may sell for only YR150, however, the largest share of householdenergy is consumed in bread baking which requires bread-oven. Their price ofYR1500 to YR2500 make them unaffordable to many. Therefore, to helpfacilitate fuel switching and to increase interfuel substitution inhouseholds, an affordable LPG bread-oven and/or retrofitting of wood ovensshould be developed and promoted. Some work in this regard has commencedunder the Household Fuel Marketing Study. It is recommended that further workbe undertaken towards the development and more widespread use of low cost LPGappliances.

5.13 TransRortation and Distribution. The transportation of LPG cylindersto distribution depots in urban centers is being contracted to privatetruckers which are reimbursed according to transport tariffs established byYPC. From these depots, cylinders are distributed through fifty YPC-ownedurban retail distribution centers and 501 contracted agents; thus the marketis highly fragmented. YPC arranges for transport of cylinders from itsdistribution depots to retail centers; there, consuimers puxchase LPG (at theofficial price of YR37 per filling of a cylinder of nominally 12.5/kg; actualfilling average however, is 10.7/kg) and return empty cylinders; these centcrsare operated generally at a loss to YPC. In the case of the agents who areselected under procedures overseen by local village and town councils theseare responsible for the transport of cylinders from YPC's depots to theirshops and are refunded YR1.5 per cylinder to cover transport costs. There isno system in place allowing for government control over retailer activities;safety standards in bottle handling have not been established, entailing risksto life and property. It is recommended that the GOY develop, with assistance

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from appropriate experts, national safety codes and standards and implementthem to assure safe operations within the LPG supply network.

D. Pricing and Institutions

5.14 The import, bottling and transportation of LPG is handled entirely byYPC; this operation is not profitable. Given the high cif cost of importedLPG, the current official price of YR37 per filling of a cylinder entails asubsidy which is absorbed by YPC. Since the major impediment to LPG use isthe high initial cost to consumers of switching from using other fuels (para5.03), subsidization of LPG is not an effective promotional measure. In ourview the LPG subsidy is higher than indicated by YPC's official pricestructure since (i) YPC's method of calculating the operating costs of thebottling plant as a percentage of the LPG cif price understates the true costsand (ii) the low LPG cost calculated by YPC does not reflect the economiccosts of present bottlenecks in the distribution network and in particular,the almost total absence of bottle storage (empty or filled) at the plant. Toremedy the above and to enable YPC to amortize anticipated investments in theexpansion of the Hodeidah and other future plants, in new loading and storagefacilities at Safer, in transportation equipment and in new cylinders, the LPGsales price needs to be revised teking into account all real costs. Our roughestimate, based on the present cif price of imported LPG of over US$200 t,indicates a realistic cost of YR52 per cylinder filling of 12.5/kg, that is,YR15 above the present official price. Since cylinders are filled on averagewith no more than 10.7/kg of LPG, the official price is 21X below the economiccost of supply. Indigenous production of LPG will in the best of cases reducethe economic cost to about YR40 per 12.5 kg cylinder, as it saves the cost ofocean freight on imported LPG of about US$ 105/t.

5.15 As noted earlier, because of supply constraints the actual average LPGretail price is currently about YR60 per cylinder (71X above the officialprice, with individual prices varying from YR40 to YR78) illustrating thewillingness of consumers to pay a high price for this preferred form ofenergy. It is recommended that GOY revise current LPG pricing and ensure thatit will fully cover YPC's costs and provide a reasonable return on theinvestments in rationalizing and expanding LPG production and distribution;ex-processing-plant prices should accurately reflect the economic cost ofprocuring and processing LPG, thereby encouraging least cost supply, andretail prices should reflect the economic cost of supply and the relativevalue of LPG vis-a-vis substitutes.

5.16 Development of the domestic LPG is the responsibility of a recentlyformed project team within IOMR/YPC, which may eveatually evolve into acompany devoted solely to LPG. For the short to medium term, this entitycould also have responsibility for bulk transport and bottling; once anappropriate pricing policy is in place, these functions, should be assumed byprivate operators. In the future, the principal role of GOY in LPG supplywould therefore be limited to its production and to monitoring and controllingall LPG sector operations, ensuring safe, efficient and economic delivery ofthe product to the consumer, and encouraging private sector operation of all

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other functions. It is recommended that COY (i) eazmine whether in the sediumterm these activities can effectively be assumed by YPC or whether a separateautonomous agency would prove more appropriate, (ii) establish a separateagency, or a new department within NONR, to oversee LPG regulatory and controlfunctions, develop, implement and enforce safety codes and standards, andmonitor the impact of pricing and other policies on safe and efficient supply,(iii) within the framevork of the long-term plan for developing LPG resources,implement policy, pricing and institutional measures to improve the economicsand operational efficiercy of the LPG distribution network, and (iv) provideincentives for the private sector to assume responsibility for an Integrateddistribution network encompassing all aspects of LPG supply, from bulktransport from Safer to bottling and distribution. This should include anexamination of options for joint ventures, innovative private/publicpartnerships (such as "build-operate-transfer" arrangements for bottlingplants), and direct private investment in and operation of small- andmedium-scale plants.

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VI. NATURAL GAS UTILIZATION

6.01 As described in Chapter II, nev recent discoveries have furtherstrengthened the prospects for natural gas utilization in YAR. Our economicevaluation of the potential investments for utilizing the gas indicates thatthese could be highly attractive and should be considered with priority. Thepurpose of this Chapter is to review the poteatial demand prospects, and toprovide a prelidinary assessment of the principal investment options.

A. Potential Demand

6.02 A long-range natural gas demand forecast has not yet been prepared byGOY; this should be the object of future studies. In the meantime, ye haveattempted to estimate YAR's potential gas demand based on experience in otherdeveloping countries vith more mature gas markets, and on the replacement offuel oil in YAR's power generation and the cement industry.

6.03 According to our projections shown on Table 6.1, YAR's fuel oil demandwill increase from 290,000 t in 1988 to 1.2 million t in 2005 unless naturalgas is made available. Fuel oil consumption in the power sector is estimatedto grow from 210,000 t in 1988 to 920,000 t in 2005; these quantities would beused in the existing steam power plants at Ras Khatenib and Al Mukha and infuture additional power plants (Chapter IV). Fuel consumption in the cementsector, which presently consists of plants at hAran and Bajil, is estimated togrow from 80,000 t in 1988 to 300,000 t by 2005, based on a projected growthof YAR's cement production from 800,000 t to 3.0 million t and assuming thatone ton of fuel oil is needed per 10 t of cement produced.

Table 6.1 YAR - Projected Fuel Oil Consumptionin Power and Cement Production /a

('000 t)

Cement Power TotalAmran Balil Other Ras Khatenib Al Mukha Other

1988 50 30 - 105 105 - 2901994 100 80 90 239 239 43 7912000 100 90 90 239 239 242 10002005 100 100 100 239 23c 442 1220

Za Assuming no availability of natural gas.

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6.04 Substitution for LPG and kerosene could provide another but limitedpotential market for natural gas in YAR's residential and commercial sectors;this is a premium market since gas can substitute petroleum products andimprove the cities' environment by reducing road traffic supplying petroleumproducts and air pollution. However, natural gas networks can only bedeveloped economically in cities with high concentrations of commercialconsumers and well developed residential sectors, leaving substantial parts ofthe urban and the rural markets for other forms of energy. We thus estimatethat by 2005 the potential natural gas substitution for LPG and kerosene couldbe about 10 of country-wide demand, or about 40,000 t of these products.Overall, and based on the above, natural gas could potentially substitute forabout 1.3 million t of petroleum products; this would be equivalent to morethan 120 million standard cubic feet per day (mmcfd) of natural gas. Tosatisfy this potential gas demand presumes the implementation of specificinfrastructure investments, discussed later in this Chapter. In view of theclear potential which natural gas has as an economic source of energy, andgiven its potential availability in adequate quantities in the early 1990's,it is recommended that GOY expedite its ongoing efforts to finalize the legalaspects of making gas available and to develop dnd implement a coordinated gasdevelopment plan covering both, upstream and downstream aspects.

6.05 In principle there are other potential uses for natural gas, includingthe production of fertilizer, methanol, automotive fuels such as compressednatural gas, and liquified natural gas. However, both the World Bank's 1987study on the impact of hydrocarbon discoveries and consulcants' "GasUtilization Study" (GUS)W conclude that in view of the limited domesticmarket for these products, unfavourable world market conditions, theparticularly strong regional competition, the large investment requirementsand technological constraints, these options are presently unlikely to beeconomically rewarding for YAR. It is recommended, therefore, that anynatural gas utilization plans in YAR for the short and medium term focus onlyon the use of gas as a source of energy for the domestic market.

B. Pipeline Proiect

6.06 GOY commissioned the GUS in 1987 to assess possibilities forcommercialization of indigenous natural gas and LPG. The study's terms ofreference were based on the assumption that adequate supplies of gas would beavailable. For natural gas, it evaluated six pipeline options, covering thecosts of transmission, service connections to the power stations and cementplants, and conversion of existing consumers' facilities from fuel oil use.All of the options were shown to be economically attractive, except onewhereby electricity would be generated at or near the gas fields in Marib,then transmitted over power lines to Sana'a and other parts of YAR; this

J "Yeam-n Arab Republic - Gas Utilization Study" by Gasunie Engineering B.V.of January 1989, co-financed by the Government of the Netherlands under theWorld Bank's Technical Assistance to the Petroleum Sector.

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option was not considered further since it vas found to be uneconomicalbecause (1) it would eliminate the large benefits from fuel oil substitutionby cement plants and other potential non-power consumers, and (ii) it vouldrequire ezcess generating capacity to compensate for power transmission lossesover the long distances involved. We carried out further analyses of two ofthe five remaining options vhich GUS found to have the highest economicbenefits; their routing to Sana'a, Amran and to Ras Rhatenib is shown on theMap. We did not analyze further the other three options which includeextensions of the pipeline to Taiz and Al-Mukha and were found by the GUS tobe economically less attractive.

6.07 The options analyzed by us consist of the following:

(i) Option I comprises a 224 km pipeline from the gas fields at Narib toNabar; this stretch vould be of telescopic design of which 124 km of22-inch diameter and the remaining 100 km, of 20-inch diameter; an 80km, 18-inch pipeline from Mabar to Sana'a; and a 60 km, 8-inchpipeline from Sana'a to Amran. The primary objective of this optionis to supply future combined cycle power plants in theNabar-Sana'a-Amran "corridor" and the existing cement plant at Amran.Demand under this scenario is forecast to grow from 12 macfd of gas in1994 to about 61 mmcfd in 2005. This option provides sufficientcapacity to supply other industries and, eventually, urban commercialand residential consumers in the corridor and in Narib. TotalInvestments are estimated at US$193 million, of which US$139 millionfor the pipeline and US$54 million for compressor units to be builtafter 2010.

(ii) Option II's components are a 224 km, 22-inch pipeline from Narib toNabar; an 80 km, 16-inch pipeline from Nabar to Sana'a; a 60 km,8-inch pipeline from Sana'a to Amran; and a 208 km, 16-inch pipelinefrom Nabar to Bajil and Ras Khatenib, where the existing cement andsteam power plants would be converted to gas use and where futurecement plants could be served by the pipeline. Investments in thepipeline would total US$220 million, and in compressor stations to beinstalled in 2.3 NW, 3.7 NW and 6 Mg increments from 2008 to 2015,US$47 million. The gas demand under this scenario is expected to growfrom 48 mmefd in 1994 to 102 mmcfd in 2005. With additionalcompressors to be installed in the future, the proposed pipeline forthe portion Narib-Nabar could be enlarged to handle future extensionsto Taiz and other southern regions if desirable.

6.08 The projected demand for gas under the two options is summari!ed inTable 6.2.

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! Table 6.2 YAR - Projected Natural Gas Demandj (mmcfd)

Pipeline Option I Plieline Option II

Cement Yovr Total Cement Power Total

1994 11 1 12 14 34 481997 11 14 25 18 48 662005 11 50 61 21 81 102

C. Economic Evaluation

6.09 Our economic evaluation vhich is based on a comparison of the costsand benefits accruing to YAR with and without the pipeline, concludes that thegas pipeline project is highly attractive in economic terms. This assessmentis based on the quantification of the value of substituting natural gas forother fuels, and the difference in investment costs and efficiency betweengas-based and oil-based power generation. Annex VI-1 provides details onassumptions used in our analysis and economic rate of return calculations.All costs and benefits are expressed in constant end-1988 prices and areexclusive of financial costs.

6.10 Benefits. The project's main benefits consist of the value of fueloil which would be replaced by natural gas, improvements in power and cementplant fuel efficiency, and in the savings resulting from the investment costdifferential between future gas-based and oil-based power generation. Usingnatural gas would allow any excess fuel oil produced by the Narib refinery tobe exported at the margin or permit reductions in fuel oil imports.Consequently, the benefits of using gas are based on the cif price of importedfuel oil plus the cost of domestic transport where applicable (to Bajil andAmran). Prices are estimated based on current World Bank projections of crudeoil prices and of the differential between crude oil and fuel oil prices.

6.11 Costs. Project costs consist of three main components, namely (i)/thecapital cost of pipeline and compressors (para 6.07) as well as the small costto convert boilers of steam turbines at the power station and cement plants,(ii) operation and maintenance costs, and (iii) the cost of supplying gas fromthe fields to the pipeline. The estimates of the first two components arebased on the GUS. Since the cost of gas, one of the main elements of theanalysis, will depend on the outcome of GOY's negotiations with the oil fieldcontractor, we have assumed three price scenarios, namely US$0.50, US$1.00 andUS$2.00 per mcf, in line with natural gas prices customary in other countries.

6.12 Economic Rate of Return. The focus of our analysis of the twopipeline options was to determine the most economic meaus for substitutingnastral gas for fuel oil. The results are summarized in Table 6.3 whichcompares the NPV's and ERR's for the two options, with variations inassumptions. The table demonstrates the significant economic benefits, even

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Table 6.3 YAR - Natural Gas Utllization ProjectEconomic Beneflts

OptLon I ODntion IIEl! A/ zl NPV la ERR

Cost of Gas US$0.50/amcf (Base Case) 275.7 24.9 536.4 30.5US$1.00/macf 235.2 23.2 455.0 27.9US$2.00/macf 154.1 19.7 292.2 22.5

Capital Cost Increase from Base Caseby 251 242.2 22.0 483.9 26.6by 50X 208.6 19.8 438.4 23.6

Oil Price Scenariolower than Base Case 162.9 20.6 325.9 24.4

./ at a 12X discount factor.

under adverse assumptions, which YAR can derive from utilizing natural gas inpower generation and cement production. In both options analyzed, the ERRsare significantly greater than 12X, the estimated opportunity cost of capitalin YAR. The benefits associated with gas use are evident particularly inOption II vhich extends the pipeline to Ras Khatenib. Sensitivity testsindicate that even with real capital cost increases of 25X and 50%, or with ahigher gas price, or with a fall in the international price of crude oil by251 in real terms from our forecast, the ERR would remain well aboveacceptable levels. It is therefore recommended that, subject to theavailability and deliverability of adequate gas volumes, GOY initiatepreparations vithout delay for proceeding with the gas pipeline project, toenable the economy to benefit at an early time from this important naturalenergy resource.

D. Pricina

6.13 As shown in our economic analysis, we assume that the economiccost of production and distribution of natural gas will be below the cost ofalternative fuAls presently used by potential gas consumers. Therefore, GOYhas to determine how to divide this "rent element", i.e. the differencebetween the cost of the gas and its value to the economy, among energyconsumers, the oil field contractor, the gas distributors and, finally, thaGovernment. The decision will inter alla, depend on an evaluation of GOY'sneed for revenue on the one hand, and the effectiveness of promotingindustrial development through provision of a cheap energy source on theother. In most industries, expenditures on energy amount to no more than 2-4Xof total manufacturing costs. Therefore, increasing energy prices will notsignificantly affect their competitiveness. The objective of GOY's strategyfor natural gas development is the maximization of net benefits to YAR fromthe use of its hydrocarbon resources. This objective has three importantdimensions, each of which implies certain pricing principles: firstly, theremust be an incentive to promote efficient use of gas; gas prices must neitherbe so high as to inhibit consumption, nor so low as to encourage wasteful use.

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Secondly, because of the high front-end costs of natural gas development andits pronounced economies of scale, the growth rate of demand should be rapid.Thirdly, there must be adequate incentives to explore for and produce the gas.This establishes the outer bounds for natural gas consumer prices. The upperbound is defined by the cif value of the substituted fuel oil and diesel oil.Since in the short run, the bulk of demand will come from enterprises thathave to convert existing boilers from oil to gas, the price of gas has to beset at a level below the price of oil to make the conversion investmentsattractive; this price differential should allow a recuperation of theseinvestments within a reasonably short time. The lower bound is determined bythe long run marginal economic cost (LRC) of supply of gas which comprisesthe costs of exploration, development and production, transmission anddistribution. Since the LRNC falls once the basic infrastructure is in place,this principle has to be qualified: revenue flows to both production andtransmission distribution companies should be high enough to cover their fullcosts including depreciation and sufficient returns on capital, to keep themfinancially viable. Producer prices can be based either on the "cost plus"method which relates the price of gas to the costs incurred by the producingcompany, with an additional element to provide the company with a return onthe capital invested, or the "market-related" approach which involvesidentifying the border price of substitute fuels and deducting the costelements form the point of use back to the well-head (mainly costs ofconversion at user level, distribution and transmission).

6.14 Few general guidelines for the optimal structure of consumer pricescan be given beyond the very broad principles stated above. Normally,consumers are charged a fixed annual monthly fee for the gas, the so-called"demand rate", to cover part or all of the fixed distribution costs, and avariable rate, often called the "commodity rate", to cover the variable,mostly fuel costs.

6.15 In view of the above, it is recommended as a first step towardsthe definition of a rational pricing policy for natural gas, that (i) insetting price terms for the natural gas producers, GOY ensure that theyencourage gas exploration efforts and the future involvement by foreigninvestors operators in the gas pipeline project, and (ii) cost studies beundertaken to define the upper and lower bounds of possible natural gasconsumer prices which should be sufficiently below the price of fuel oil toencourage its substitution, as inputs for the final prices to be adopted andfor the more basic discussion of distributing the rent from gas utilization.

E. Strategy

6.16 Given the attractiveness to YAR of developing its potential forutilizing natural gas, it is recommended that GOY's preparation forimplementing the project be based on an action plan aiming at completion ofthe project before 1994 when new power plants are required to come on stream;this action plan would require setting up an adequate institutioiial frameworkfor an integrated program of gas development and utilization and theassignment of a qualified engineering firm to design an optimum gas project.

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The elements of an institutional framework should include:

(i) a joint coordination comittee between the oil/gas field operatorsand GOY which will oversee both upstream and downstream aspects ofproject development;

(ii) a gas project team to plan the implementation of the gas projectand to monitor the future development of gas resources; the leaderof such a team should be a member of the JCC; experienceelsewhere shovs that this group would eventually evolve into anational gas company to handle the planning and operation of thegas industry in YAR; and

(iii) a market survey group to be formed vithin the gas project team toexamine the natural gas market potential including eventuallysmaller industries and residential and commercial consumerslocated along the planned pipelines.

6.17 Using the GUS as a point of departure, the joint coordinationcommittee should develop an integrated gas project, incorporating all upstreamand downstream components--gathering, treating, processing, transmissiondistribution, and conversion of consumers' facilities--into the developmentplan and the project design. Following completion of an agreement with theoil/gas field operators for supplying YAR's future gas requirements, includingon the estimated gas availability and cost of production, the principal stepis the assignment of an engineering firm to design an optimum gas projectwhich should be fully integrated, encompassing all upstream and downstreamcomponents, and estimate investment requirements for gathering, treating,transmission and distribution, as vell as conversion of consumer facilitiesfrom liquid fuels to gas. This plan will need to be followed by theacquisition of the needed land and pipeline construction. We estimate thatfrom the time GOY decides to proceed vith the project, implementation villtake about three years. In order for the pipeline to be completed by the timeadditional power generating capacity is required by 1994, G(Y's decision onproceeding vith the pipeline would have to be reached by early 1990.

VII. INVESTMENT OPTIONS. STRATEGY AND RECOMMENDATIONS

7.01 The preceding chapters have provided detailed descriptions ofdifferent aspects of YAR's energy sector and presented our observations andrecommendations for action. This final chapter is meant to briefly summarizewhat currently are the principal options and a strategy which GOY may want tofollow, together vith a summary of all the recommendations made in this EnergyStrategy Reviev.

7.02 Table 7.1 lists the principal investment options in YAR's energysector, together vith order-of-magnitude estimates of capital cost andestimated time required for implementation. The "crash program" to makedomestic LPG available to replace imports, the design and implementation ofwhich has been initiated, should be vigorously pursued. Preparations for the

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realization of the project to supply natural gas as fuel for power generation,cement plants and potentially other users, should be initiated without delay;to implement this option will require firstly, reaching agreement with theoperating oil company as to the availabilLty and deliverability of associatedor non-associated gas, and secondly, assessing the overall hydrocarbonpotential of YAR with the help of outside experts, resulting in theformulation of a coherent hydrocarbon exploration strategy and in attractingprivate investors for exploration and the gas pipeline project.

Table 7.1 YAR - Enerwv Sector Investment Options

InvestmentRequirements Estimated

Proiect (US$ Million) Implementation

LPG Production and Utilization 40-60 1989-1991Natural Gas Development and Pipeline 139-220 1990-1993Ras Issa Petroleum Handling andStorage (including crude shipment) 107 1990-1993

Petroleum Products Pipeline n.a 1990-1993Regional Petroleum Products Storages 34-40New Power Generation, Transmission,Distribution and System Improvements 661 1989-2000

n.a.: not available

7.03 With regard to the potentially attractive investments in the Ras Issapetroleum handling and storage facilities and the petroleum products pipeline,studies should proceed as soon as possible to determine their viability,duration, cost and implementation. - The installation of new power generatingfacilities, possibly as early as 1994, may be required regardless of thesource of energy, i.e. natural gas or imported fuel oil. Other investments inpower transmission, distribution and normal development should be implementedas nov planned. - Concerning the second refinery, this project is economicallynot attractive, also, sufficient oil reserves have not been proven in YAR toensure an adequate availability of domestic feedstock for an extended period.Therefore, this project should not be pursued.

7.04 Financing for investment projects such as the above is an aspectmeriting GOY's early attention. It is recommended that adequate provisions bemade in the planning for domestic public financing of such projects, and thatcontacts be initiated with bilateral and multilateral sources of public andprivate funds; early decisions by GOY as to the involvement of the privatesector, possibly in the form of "build-operate-transfer" or similar schemes,would help in structuring, designing, implementing and funding these projectswhich in their scope and complexity go beyond YAR's institutionalcapabilities; consideration should be given to obtaining the services ofspecialized consultants or international banks for this purpose.

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7.05 To the extent funds are available under the IDA Credit for TechnicalAssistance to the Petroleum Sector, these can be allocated to financing someof the studies recommended in the preceding chapters. The World Bank standsready also to consider supporting separately the development and implemen-tation of any economicall- attractive investment project in YAR's energysector, such as the natural gas pipeline and the Ras Issa storage and pipelinefacilities, or additlonal hydrocarbon exploration. It is recommended that GOYdevelop with urgency a core investment plan for the energy sector on the basisof which discussions could take place at an early stage with the World Bankand other international agencies to review possibilities for fundting, and withthe Bank regarding its possible role in project promotion and the coordinationof funding from other sources.

7.06 This section lists in summary form the recommendations made in thisreport (with references to the paragraphs where each is discussed in detail),where possible in order of priority as perceived by us and classified by theministry or agency likely to be charged with considering and implementingthem, as follows:

(i) Ministry of 0.l1 and Mineral Resources

1- Hydrocarbon Availability

(a) MONR should continue and expedite its negotiations with YEPC on theavailability of gas, and if it becomes clear that a satisfactoryagreement cannot be reached, invoke arbitration under the terms of thePSA. (Paras 2.16 and 6.04)

(b) If possible under the Alif field production profile, the availabilityand deliverability of Alif associated gas should be confirmed andsteps be taken to permit its early utilization in substitution forcostly imported fuel oil in power generation and cement production.(Para 2.14)

(c) MONR should commission a brief review of the gas subsector to identifythe next steps required for appraisal and delineation of thosenon-associated gas discoveries which appear economically viable, andto recommend a program for appraisal and development of thediscoveries in close coordination with YEPC; a coordinated natural gasdevelopment plan should be designed and Implemented. (Para 2.17)

(d) MONR should carry out an independent comprehensive review of YAR'soverall hydrocarbon prospects, with a view to preparing a long-termperspective exploration plan for utilization of the country'shydrocarbon resources. (Para 2.05)

(e) MOHR should establish a comprehensive hydrocarbon exploration policywhich would (i) clearly define the role and responsibilities of boththe private and public sector entities vis-a-vis the country's needs,(ii) aim at optimizing YAR's hydrocarbon resource utilization, and

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(iii) introduce a competitive approach to petroleum industryoperations. (Para/2 .04)

2- Natural Gas Utilization

(a) MONK should develop and implement a coordinated natural gasdevelopment plan covering both upstrem and downstream aspects. (Para6.04)

(b) Subject to the avallabilLty and deliverabllity of adequate natural gasquantities, GOY should proceed with the development and implementationof a gas plpeline project at an early stage to enable YAR to benefitfrom lts important natural gas resources end to avoid having toinstall additivonal fuel-oil based power generating capacity. (Paras4.17 and 6.12)

(c) Preparations for implementing the natural gas pipeline project shouldbe based on an action plan aiming at completion of the project before1994 when new power plants are required to come on stream; this actionplan would require setting up an adequate institutional framework foran integrated program of gas development and utilization, and theassignment of a qualified engineering firm to design an optimumproject. (Para 6.16)

(d) MOKR should ensure that price terms to be set for natural gasproducers encourage exploration efforts and the future involvement byforeign investors/operators in the gas pipeline project; cost studiesshould be undertaken to define the upper and lower bounds of naturalgas consumer prices, to serve as a basis for distributing the rent tobe derived from gas utilization. (Para 6.15)

(e) For the short and medium term, natural gas utilization plans shouldfocus only on the use of gas as a source of energy for the domesticrequirements. (Para 6.05)

3- Liquified Petroleum Gas

(a) Since it may be over ambitious, the larger LPG bottling project shouldbe re-evaluated in light of the results of the recently completedstudy under the LPG "crash program". (Para 5.10)

(b) MOHR should (i) examine whether bottling and distribution of LPG caneffectively be assumed by YPC inT the short to medium term or whether aseparate autonomous agency would be more appropriate, (ii) establish aseparate agency, or a new department vithin MONK, to oversee LPGregulatory and control functions, and monitor the impact of pricingand other policies on safe and efficient supply, (iii) within theframework of the long-term plan for developing LPG resources,implement policy, pricing and institutional measures to improve theeconomics and operational efficiency of the LPG distribution network,

- 52 -

and (iv) provide incentives for the private sector to assumeresponsibility for an Integrated distribution network. (Pars 5.16)

(c) NONR should develop national safety codes and standards and implementthem to assure safe operations within the LPG supply network. (Para5.13)

(d) MONR should undertake further work towards the development and morewidespread use of low cost LPG appliances. (Para 5.12)

(e) MOHR should take adequate measures in support of a managed transitionto higher LPG consumption, undertaking appropriate investments andimplementing policies and programs which encourage the substitution offuelvood and petroleum fuels. (Para 5.06)

4- Petroleum Products

(a) MOIR should carry out a detailed study to develop a master plan forthe Ras Issa project, define the physical facilities required, developtheir engineering, estimate their capital and operating costs, andconfirm the economic/financial justification of the requiredinvestments; it should also update the analysis of the multi-productspipeline project developed in 1983. (Para. 3.19)

(b) MOHR should conduct a brief study to confirm the economic benefits ofcontinued operation of the Marib refinery. (Para 3.11)

(c) MONR should launch a program of improved training of Yemeni personnelin refinery operations, and to adjust operations to optimize its yieldpattern. (Para 3.10)

(d) MOMR/YPC should engage specialized services to establish adequatesystems for assembling country-wide petroleum sector statistics,including data gathering, interpretation and demand projections, andprovide training of a core of Yemeni personnel for this purpose. (Para3.07)

(e) Since it is not economically viable, the Second Refinery Projectshould not be pursued further at this time. (Par.. 3.21)

(ii) Yemen Petroleum Companv

(a) The LPG "crash program" should be pursued vigorously and be followedby implementation of adequate institutional arrangements for planningthe future development of LPG resources. (Para 5.09)

(b) YPC should expedite implementation of bulk distribution of LPG andincrease the stock of usable LPG cylinders to eliminate shortageswhich could dampen the benefits of the planned increase in LPGproduction and bottling capacity. (Para 5.11)

- 53 -

(c) Spiking of fuel oil from the larib rofinery into the export crudeshould be considered as soon as possible since supplying lt as fuel tocoastal power plants does not appear econosical. (Para. 3.12)

(d) With the help of specialized assistance, YPC should strengthen itstank farm maintenance arrangements and measurement systems andIncrease the training of Lts operations personnel for *11 of itsstorage terminals. (Para 3.13)

(e) YPC should increase its petroleums products storage capacity to ensurean uninterrupted supply to all parts of the country. (Para 3.15)

(iii) Ministrv of Electricity and Vater

(a) MEW should take appropriate measures to address YGEC's existingstructural deficiencies and improve its operational, managerial,personnel and financial policies. (Para 1.15)

(b) In the medium term, NEW should carry out a study to determine thebenefits of rural electrification either through grid extension orautogeneration, and develop technical standards; it should alsoformulate a strategy and master plan for rural electrification,including methods of mobilizing resources and mechanisms forcompensating YGEC for financial losses associated with providing powerto unprofitable reas. (Para 4.21)

(c) NEW should carry out further work on the development, demonstrationand testing of household photovoltaic systems, and to determine howprivate sector participation can be mobilized most effectively. (Para4.22)

(iv) Yemen General Electricity Corooration

(a) YGEC should design and institute a comprehensive plan to improve itsprofitability and bring it in line with the levels agreed with IDA;such a plan should consist of both revenue enhancements and costreduction measures. (Para 4.25)

(b) YGEC snould make arrangements for a follow-on phase to its financialrecovery consultancy, particularly with regard to the extension of thecomputerization of billings. (Para 4.24)

(c) The line loss reduction study should be completed, and recommendedmeasures should be strictly imposed to reduce losses to a targeted 15Xby 2000. (Para 4.09)

(d) YGEC should investigate rigorously the causes for high auxiliaryconsumption and take appropriate action to reduce it. (Para 4.09)

(e) YGEC should (i) strengthen its data collectlon and interpretation

- 54 -

capabilities, (ii) strengthen existing planning functions to enablethem to develop long-term plans for power generation and transmission,identify the lowest cost options and determine appropriate standardsand risk criteria in accordance with YGEC and GOY policy, (iii)improve rhe budgetary system recently introduced and initiateprocedures for establishing a comprehensive cost accounting andmanagement reporting system to bring operating costs under tightercolAtrol, (iv) introduce appropriate delegation of power andresponsibility to enable top management increased time for planningand addressing policy issues, (v) improve operation and maintenancemanagement of generation, transmission and distribution facilities,(vi) complete the ongoing training programs, and (vii) implementhands-on training in equipment maintenance. (Paras 1.16 and 4.23)

(f) YGEC should install appropriate spare parts management and maintenancecontrol systems to prevent jeopardizing efficient operations in thefuture. (Para 4.11)

(g) Subject to the availability of natural gas, YGEC should introduce gasuse and combined cycle power plant technology to meet futuregenerating capacity requirements and convert the existing fuel oilbased plant at Ras Khatenib to gas. (Para 4.16)

(h) YGEC should up-date its assessment of long-run marginal costs of powersupply, the results of which should be used to provide a basis forfuture power pricing decisions (Para 1.31).

(v) YAR's Government in General

1- Sectoral Management

(a) GOY should clearly define its general objectives in the energy sector,establishing a priority ranking among them; the sectoral ministriesshould use this framework in a coherent manner to evaluate theirprojects and policy proposals and implement a policy action program toeliminate existing distortions. (Para. 1.10)

(b) GOY should follow up the MOHR Organization Study with a brief butcomprehensive review of the roles of the various petroleum sectorinstitutions, with the aim of defining linkages between agencies,delineating authority and responsibilities, eliminating duplicationand strengthening personnel policies including on pay scales andincentives. (Para. 1.22)

(c) GOY should apply appropriate risk management strategies to cope withthe variability in international oil prices; this risk managementshould relate not only to the enetgy sector per se, but is just asrelevant for macro-economic policies and their effect on all sectorsof the economy. (Para 1.06)

- 55 -

(d) GOT should prepare and legislate a comprehensive and up-to-date"Hydrocarbon and Minerals Act" on which all oil, gas and mineralagreements should be based. (Para 2.06)

(a) GOT should facilitate energy audits with the help of specializedconsultants and provide energy conservation investment icentives toindustry and other major consumers. (Para 1.32)

(f) GOY should continue to give high priority to skills training for theenergy sector. (Para 1.04)

2- Pricing

(a) GOY should (i) adopt full economic cost pricing as a min!mumrequirement for all fuels except kerosene, (ii) align the relativeprices of diesel and fuel oil to their relative international prices,(iii) consider using taxation of petroleum products as a means forraising Government revenues, and (iv) revise petroleum product pricesat least once a year in line with movements in international pricesand the foreign exchange rate. (Para. 1.30)

(b) GOY should allow YPC to revise current LPG pricing and ensure that itfully covers costs and provides a reasonable return on the investmentsin rationalizing and expanding LPG production and distribution;ex-processing-plant prices should accurately reflect the economic costof procuring and processing LPG, thereby encouraging least costsupply; retail prices should reflect the economic cost of supply andthe relative value of LPG vis-a-vis substitutes. (Para 5.15)

(c) YGEC should be alloved to raise service charges and average tariffs inthe short-to medium-term and rationalize its tariff structure tobetter reflect the economic cost of power supply to different consumercategories. (Para 1.31)

3- Investments and Funding

(a) Adequate provisions should be made in GOY's budgetary planning fordomestic public financing of energy investment projects, and contactsbe initiated with bilateral and multilateral sources of public andprivate financing. (Para 7.04)

(b) GOY should develop a core investment plan for the energy sector on thebasis of vhich discussions could take place at an early stage with theWorld Bank and other international lending agencies to reviewpossibilities for funding, and vith the Bank regarding its possiblerole in project promotion and the coordination of funding from othersources. (Para 7.05)

- 56 -

(c) GOT shouU. make available adequate foreign exchange to allow YGEC toacquiro full spare parts supplies, especially for the units In its twothermal plants (Para 4.11)

The World BankEN3IEJanuary 1990

- 57 -

Annex 1-1YAR - Energy Strategv Review

Eneray Balance 1988

(physical quantities, thousand tons nd GUN1

Priesry Cnergy Petroleum Products

Fuel Wood ;Crude o;i Chareoal Eleetricity LPG Gasoline Kerosene jet-Fuel Diesel Ful o;iGross Supply YGEC Priv.

Production 5600 7404Imports 96 444 64 62 372 149Primary xports -7342Stock changes 390

Total available 5600 452 96 444 64 62 372 149

ConversionPetroleum Reftntng -430 127 144 159Charcoal Production -600 140Electrie Pover Generation 811 252 -21 -11 -210Own consumption -22 .87 -STrana./diatrib. loss -179 -12

Set Supply Available 1000 140 545 235 96 550 64 62 401 98

Consumption by SectorIndustry 121 82 2 111Comerce 80 94 10 3Transport 550 62 281Households 5000 60 194 143 80 64Public/Other 111 3Agriculture 7 8 56

Source: Mission *sttmtee

(thousand cons of oil equivalent)

Primary Energy Petroleum Products

Fuel Wood Crude OiL Charcoal Electricity LP¢ Gasoline Kerosene Jet-Ful Diesel Fuei Oil Totals TotalsGross Supply YGEC Prtv.

Production 2070 7404 9474i yports 102 471 65 63 372 140 1217 1217

Primar Exports -7342 -7342Stock Chsnges 390 340

Total availablo 2070 412 102 471 65 63 372 140 1217 3739........................................................................................................................... ....................Conversion

Petroleum Refining -430 136 144 150 430 0Charcoal Production -222 114 -108Electric Power Generation 221 112 -22 -I1S -197 -312 -IConversion lossess Own Cons. -22 -160 .92 -274Trsnsm./distrib. logs -15 -I -16

Net Supply Available 1848 0 114 46 19 102 189 61 63 401 93 133 3340

Consumption by SectorIndustry 11 7 2 64 93 159 177Comerce 61 8 1 3 3 77Transport 589 63 281 933 933Households 1848 49 17 12 85 65 150 2076Public/Other 10 3 3 13Agriculture 1 9 85 94 95

......................................................... .......................................................................................

Source: tission *esiaes

- 58 Annex I-2YAR - ENERGY STRATEGY REVIEW page 1 of 3

EVOLUTION IN GROSS AND FINAL ENERGY CONSUMPTION

GROSS ENERGY CONSUMPMON 1988Stbuetum of Pnmwy ErnW Dwnard

3.8 toe

GROSS ENERGY CONSUMPilON 2005Sbrct, arf Pumwy E&W Ownatd

Natuai rmos (i i7%)

Fudw=W (t3Dr.) Oil (55.4Z)

6.3 mmtoe

- 59 - Annex I-2page 2 of 3

YAR - ENERGY STRATEGY REVIEW

FINAL ENERGY CONSUMPTION 1988Wwtumtw of Piwot Owiand

Ebctiw-iri (I SX)

Petaleum Prducts (40A%)

Fueiw=Wd/chwcl (57.7X)

3.8 mtoe

FINAL ENERGY CONSUMPTION 2005Stnxtuz d Find Eavy Ownd

Ekbd*rAl (4AXl)

FuimIwodelchomll (35DX)

Pebt aIum Prnducu (C7-9%)

a*wI Ga5 (2%).6 toe

- 60-

Annex I-2

page 3 of 3YAR - ENERGY STRATEGY REVIEW

FINAL ENERGY CONSUMPTION 1988

Airtulture)1%j m rfuUt (InK)

T.nqx,t (2885%)

Indusby (419%)k/z (W2S%)

FINAL ENERGY CONSUMPTION 2005

Agr-ultue (2D%) vuwnncPubIic (2.1X)

Hou-toehol (43.0%)

lianwt (47AX)

-ncusy (as)

- 61 -

Annex 1-3

YAR - Energy Strategy Review

GROWTH IN FINAL ENERGY DEMAND (1988 - 2005)COMPARED TO GROWTH IN POPULATION AND GDPRATIOS (in parantheses: % change 2005/1988)

Population Growth Non-oil GDP GDP(65%) (56%) (78%)

Final EnergyDemand 0.89 0.94 0.83

(47%)

CommercialEnergy Demand 1.37 1.45 1.27

(126%)

Fuelwood/Char-coal Demand 0 0 0

(0%)

EfficiencyAdjusted Fi- 1.07 1.13 1.0nal EnergyDemand (76%)1)

1) 1 too of fuelwood - 0.4 efficiency adjusted toe

- 62 -

Annex 1-4

YAR - ENERCY STRATEGY REVIEW

DOMESTIC UNIT PIICESOF PETROLEUM PRODUCTSPtYR /l it re )

1980 1981 1982 1983 1984 1985 1986 1987

Gasoline, current price 2.30 2.60 2.60 2.60 2.60 2.60 3.00 3.00real price (1980) 2.30 2.55 2.48 2.36 2.10 1.65 1.46 1.20real gaso. price index 1.00 1.11 1.08 1.03 0.91 0.72 0.64 0.52cf, US$/tonne 390 406 383 307 307 247 141 176cf, YR/liter 1.79 1.87 1.76 1.41 1.66 1.80 1.33 1.80economic consumer pr. 2.34 2.45 2.32 1.91 2.21 2.41 1.90 2.49net revenue -0.04 0.15 0.28 0.69 0.39 0.19 1.10 0.51

Xerosene, current price 1.50 2.06 2.06 2.06 2.06 2.06 2.30 2.30real price (1980) 1.50 2.02 1.96 1.87 1.66 1.30 1.12 0.92real kero. price index 1.00 1.35 1.31 1.25 1.11 0.87 0.75 0.62cf, US$/tonne 393 418 385 286 286 265 156 180fc, YR/liter 1.81 1.92 1.77 1.32 1.54 1.93 1.47 1.84economic consumer pr. 2.22 2.36 2.18 1.64 1.92 2.41 1.88 2.35net revenue -0.72 -0.30 -0.12 0.42 0.14 -0.35 0.42 -0.05

Jet-Fuel, current price 1.98 2.41 2.29 2.29 2.29 2.29 2.41 2.41real price (1980) 1.98 2.36 2.18 2.08 1.85 1.45 1.18 0.97real Jet-f.price index 1.00 1.19 1.10 1.05 0.93 0.73 0.59 0.49cf, US$/tonne 306 424 386 313 313 265 156 180cf, YR/liter 1.41 1.95 1.78 1.44 1.69 1.93 1.47 1.84econ.cons.pr. 1.74 2.39 2.18 1.79 2.10 2.41 1.88 2.35net revenue 0.24 0.02 0.11 0.50 0.19 -0.12 0.53 0.06

Diesel Fuel, current pri 0.90 1.65 1.50 1.50 1.50 1.75 2.00 2.00real price (1980) 0.90 1.62 1.43 1.36 1.21 1.11 0.98 0.80real dies. price index 1.00 1.80 1.59 1.52 1.34 1.23 1.08 0.89cf. US$/tonne 350 380 347 347 260 268 138 168cf, YR/liter 1.61 1.95 1.60 1.60 1.40 1.96 1.30 1.67economic consumer pr. 1.98 2.15 1.97 1.97 1.76 2.4 1.68 2.16net revenue -1.08 -0.50 -0.47 -0.47 -0.26 -0.69 0.32 -0.16

Fuel Oil, current price 1.23 1.62 1.50 1.50 1.50 1.72 1.72 1.72real price (1980) 1.23 1.59 1.43 1.36 1.21 1.09 0.84 0.69real fuelo. price inde 1.00 1.29 1.16 1.11 0.98 0.89 0.68 0.56cf, US$/tonne 208 264 242 212 212 172 126 109cf, YR/liter 0.96 1.21 1.11 0.98 1.14 1.26 1.18 1.11economic consumer pr. 1.21 1.51 1.40 1.24 1.45 1.60 1.55 1.49net revenue 0.02 0.11 0.10 0.26 0.05 0.12 0.17 0.23

LPG (12.5 kg). curr. pr. 40.00 42.00 4.00 47.00 37.00 37.00 37.00 37.00real price (1980) 40.00 41.18 41.90 42.73 29.84 23.42 18.05 14.86real LPG price index 1.00 1.03 1.05 1.07 0.75 0.59 0.45 0.37cf, US$/tenne 448 448 352 254 189cf, YR/12.5kg 25.76 30.24 32.12 29.85 24.10

WEIGHTED NET REVENUE -0.04 0.06 0.11 0.32 0.16 0.06 C.45 0.21W.N.Rev. in k of av.pr. -2.31 2.68 5.51 16.08 7.79 3.00 19.50 9.30

Consumer price index 100 102 105 110 124 158 205 249Exchange rate YR/US$ 4.60 4.60 4.60 4.60 5.40 7.30 9.40 10.20

- 63 -

YAK - NtfKjY bhTAIkGY REVIEW Annex I-5PETROLEUM PRODUCTS

REAL PRICE INDEX

1.2

1.8

cis6-41~~1.

asI

Q7

19aE 19w 19E2 19&3 1984 198e 1988 19Z7

t kla'are O jet-fuud A desd X fuel aila gasoline v LPG

CONSUMER PRICES AND ECONOMIC COSTYR /liter surplus or deficit

1.5

I -~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~

01

-0.5

1980 '981 1982 1983 1984 1985 1986 1987

gasoline --+- kerosene *w Diesel-fuel fuel-oil

- 64 -

Annex 111-1

YAR - Energy Strategy ReviewHistorical Consumptionof Petroleum Products (1975-88)

(in '000 tons)

Diesel FuelGasoline Kerosene ATK Oil Oil

1975 49.5 38.8 5.1 94.4 10.01976 74.2 50.1 8.9 131.3 10.01977 119.6 54.5 15.3 183.7 10.01978 139.2 59.2 11.2 200.1 8.01979 191.7 53.1 10.2 314.0 9.01980 208.1 77.6 24.5 399.1 6.01981 207.9 55.0 24.3 365.0 5.21982 240.6 73.3 25.8 416.3 24.41983 297.4 74.8 23.5 469.8 37.91984 257.0 70.7 33.9 477.0 76.4

1985 316.6 77.4 49.0 503.2 216.71986 381.0 69.9 51.3 509.7 320.81987 459.0 68.1 53.0 544.0 270.61988 568.1 63.9 62.0 495.0 289.0

Growth Rate, % p.a.

1975-84 20.1 6.9 23.4 19.7 25.31984-88 21.9 (-)2.5 16.3 0.9 39.5

Note: We have converted some of the data in volumes using following

barrels/ton: Gasoline: 8.5; Kerosene/ATK: 7.8; Diesel Oil: 7.4; andFuel Oil: 6.5

Source: MOMR, YPC, and Mission estimates

EMTIE4187P/12

- 5 6Annex III-

YAR EEneray $ra1egy QtviowH-_-ricAl CanIsUmoion/SUR1_y Balances fQr rit1Qly A ProductC1 l19214 "ii

(in '000 tons)

1984 M5y 198 12IL7 1988

Gasoline

A. SUDO1YYPC Imports 72.62 107.13 61.08 283.94 444.08

'Other' tmports Jlfi.93 228.59 177.18 44.92 __

Total Imports 242.55 335.72 238.26 328.86 444.08

Refinery Supply _ _ 95.?7 12g.63 1]3257Total Supply _42.55 l3S.Z_ 334.0 458.2 S76.65

S. ConsumptionYPC Sales 87.82 90.04 194.75 415.74 568.10

'Other' Sales A/ 169.17 226.60 186.24 43.26Total Consumption _i.99 3164 38Q.99 459.00 / 568.1Q

Kerosene

A. SUDD1YYPC Imports 63.83 66.50 60.30 136.89 Q/ 139.19 Q/

'Other' Imports I1.04 7.5Q 4.30 _._7 __Total Imports 82.87 74.00 64.60 137.76 139.19

Refinery Supply _ _ _ - - _Total Supply 82.87 74.0Q 64.60 137.76 / 139.19 Q/

B. Con5umotion'YPC Sales 53.83 71.90 57.20 67.19 63.90

'Other' Sales a/ 16.82 5.47 12.6S 0.87Total Consumption 70.65 77.37 69.8i5 68 Q / 63.90

ATK

A. SuplyYPC Imports 23.58 57.10 28.27 / /

'Other' Imports 10.32 _ 1.9 __Total Imports 33-90 57.10 30.20 _

Refinery Supply - _ _ _ _ _Total Supply 33.90 57.10 30.20 117.76 C/ 139.19 r/

S. _onsumt ionYPC Sales 33.89 46.32 50.47 53.01 62.00'Other' Sales A/ - 2.68 0.83

Total Consumption 33.93 49.QQ S1.3 5DA1 b/ 62.QQ

Diesel Oil

A. SupplyYPC Imports 483.73 549.49 303.41 402.45 363.75'other' Imports __.Q7 4,38 - 3.42 _ 2.13 - 8.25

Total Imports 492.80 553.87 306.73 404.58 372.00Refinery Supply - 116.i2 115.64 147.5Q

Total Supply 492.U 5S3.87 423.35 5a6022 5!9.50B. Consuml tjgn

YPC Sales 479.74 520.12 510.02 528.95 485.50'Other' Sales j/ N.A. N.A. N.A. N.A. N.A.

Total Consumption 477.02 50 24 509.69 544.00 b/ 495OQ

Fuel Oil

A. 5yuQlYPC Imports 161.72 69.52 5.28 107.21 149.40'Other' Imports 4_ 14.8Q d/ 1825.0 d/ ANA.. N.A.

Total Imports 161.72 204.32 187.78 107.21 149.40Retinery Supply _-- - 124.52 L74Q1 164.75

Total Supply 161.72 204.32 312.1 211.52 314.15

B. Conumt5jljionYPC Sales 77.54 81.89 140.74 167.03 148.40

'Other' Sales _/ - 134.83 180.09 103.57 140.60Total Consumption Z7._-54 t672 12Q083 _7Q.6Q 89.0Q

a/ By difference betw-ecn totil co^ ufiption ard YPC sales. Compare with 'OtheOr import,II/ UOPiCSCl Kero,cr.e and ATrd/ B. VGE

EM'IEi'1q8 P-

-66 -Annex I I 1

YAR Energy Strateg g RyiwHistorical Reoioal 1ConsvmAgion apo EILimAted future Oemand

for Petrolem PrVQducts (1985i Z 5)(in percent of YAR totals)a/

Sana'a HodeidA Taiz Marfe Al Mukha

Gasoline

1985 (Actual) 44.2 20.3 34.3 1.21986 " 47.7 17.3 32.7 O.S 1.81987 " SO.9 15.1 29.2 2.6 2.21988 " 49.0 20.7 24.5 3.6 2.2

1990 (Projected) SO.0 20.0 24.0 4.0 2.01995 " 48.0 22.0 23.0 S.0 2.02000 n 49.0 20.0 23.0 6.0 2.02005 " 48.0 22.0 22.0 6.0 2.0

Kerosene

1985 (Actual) 18.7 41.7 37.0 2.61986 n 22.8 39.2 35.2 2.81987 n 23.9 38.8 34.7 0.2 2.41988 a 24.2 37.7 34.5 O.S 3.1

1990 (Projected) 24.0 38.0 34.0 1.0 3.01995 a 20.0 30.0 41.0 S.0 4.n2000 a 20.0 30.0 37.0 8.0 S.02005 a 20.0 30.0 34.0 10.0 6.0

ATK

1985 (Actual) 62.2 21.7 16.11986 a 62.7 22.0 15.31987 a 63.7 16.7 19.61988 a 62.3 19.5 18.2

1990 (Prajected) 63.0 20.0 17.01995 a 65.0 20.0 15.02000 a 67.0 20.0 13.02005 69.0 21.0 10.0

pResP Qil

1985 (Actual) 45.1 31.6 19.9 3.41986 a 45.2 29.4 19.8 2.0 3.61987 a 44.7 29.6 18.3 4.9 2.51988 " 47.3 24.7 20.6 4.9 2.5

1990 (Projected) 45.0 25.0 22.0 5.0 3.01995 a 45.0 25.0 22.0 5.0 3.02000 " 45.0 25.0 22.0 5.0 3.02005 n 45.0 25.0 22.0 S.0 3.0

Fuel Oil

1985 (Actual) 49.0 S. 01986 n 26.8 73.21987 " 24.2 75.81988 28.7 71.3

1990 (Projected) 29.0 71.01995 a lS.O 85.02000 1S.0 85.02005 a is.0 85.0

A/ On YPC's sales only

SourCC. MOMR

EM' IEa.tI

YAR ENERGY STRATEGY REVIEWPetroleum Products

Demand Prolections and Operational Storaae Reauirements (1990-2005

Total Country Sana,a ogdeidah Ta1M Mareb Al-*ikha12990 1995 ZOQO 2005 1990 19.5 2000 2001 1190 1221 2000 2005 1120 1122 20002z00 1120 1121 2000 2001 1121 1995 2091 _ Um

Gasoline 650 990 1,275 1.650 325 475 625 792 130 218 255 363 156 228 293 363 26 50 77 99 13 20 26 33

Kerosene 60 60 SS S0 14 12 11 10 23 18 17 15 20 25 20 17 1 3 4 5 2 2 3 3

ATK 70 100 140 189 44 65 94 130 14 20 28 30 12 1S 18 19 - - - - - - - -

Diesel Oil 545 670 786 902 245 302 354 406 136 168 197 226 120 148 173 198 27 34 39 45 16 20 24 27

Total 1325 1820 2256 2791 628 854 1,084 1,338 303 424 497 634 308 416 504 597 53 87 120 149 31 42 53 63

Retuirod (30 days) 110 152 188 233 52 71 90 112 25 35 41 53 26 35 42 S0 4 7 10 12 3 4 5 S

Cumulative Incremental 61 31 29 32 52 19 19 22 - - - - 18 9 7 8 1 3 3 2 - - -Storage Required WJ

Cost @US$250/ton of .15.3 ;.8 7.3 8.0 10.5 4.8 4.8 5.5 - - - 4.5 2.3 1.8 2.0 0.3 0.8 0.8 0.5 - - -Storage (USSmillion)

ai ExisLing operational storage capacity, including planned expansion at Hodeldah:(white Products only)

Lon

Sana a 10,000Hodeidah 60,0001aiz 8,200Kireb 2,800Al Mukha 14.100

tz

- 68 -

Annex 111&

YAR - Energv Strategy ReviewPetroleum Product Storaae Capacity

(as of end-1988)

SANA'A a/ HODEIOAN TAIZ HAREB AL-MUKHADays Days Days Days Daysof of of of of

cu .m. m. co/ cu.m. Cns, b/ cu.m. Cons, h/ cu.m. Cons, / cu.m. Cons, /

Gasoline 4.260 5.6 18.900 / 58.7 4.000 10.5 1.750 31.3 8.600 251.5

ATK/Kerosene 2.040 8.2 11.300 _/ 114.0 -

Diesel Oil 6.350 9.9 28,100 _/ 83.9 6,000 21.5 1,750 4/ 8.600 129.5

JP-4 - - 5.000 - - - -

Fuel Oil - - - - - 1.750 3.1 2.000 4/

Total 12.650 63.300 10.000 S,250 19.200

Total (tons)g,/ 10,400 S1.900 8.200 4,300 15.700

_/ Excludes strategic storage for: gasoline: 1,540 cu.m.; kerosene: 1.020 cu.m.; anddiesel oil: 2,560 cu.m.

_/ Days of consumption for region.

c/ Tankage under expansion. to be completed by 1990 by: gasoline: 7,300 cu.m.:kerosene: 3,000 cu.m.; and diesel oil: 6,300 cu.m. Storage expressed in number ofdays of consumption is for Hodeidah regional consumption only.

4/ Denotes *very high".

_/ Average density for all products- 0.82

Source: YPC, MOMR

EMTIE4187P/pl3

- 69-YAR - ENERGY STRATEGY REVIEW

RAS ISSA PRODUCT AND CRUDE STORAGEi POMUCT STORAGE AT RAS ISSA AM 111-I

Proucts Origiatting at Ras lisa ITotal Dea0d - Narib Refinery Prodetiolm - Projection

(000 tons 199 1 13 19"1 19 1M7 193 1t9 2000 2001 2002 200 200 2005

Prue.6asoline 20 23 26 30 35 40 44 4U 53 5 4 47 11 75 79 83Re.6amoline 4U8 542 600 64 733 9 655 9S 957 1,012 1,211 1,275 1,342 1,414 1,40 1,547DOntic Kero 60 60 60 60 60 60 59 58 57 54 55 54 53 52 51 50Jet Futl 70 75 81 a7 93 100 107 M4 122 131 140 149 158 I4 178 189Dincl 372 395 411 443 469 497 519 541 54 583 78 9 90 854 878 902Fuel Oil 297 34 404 449 402 407 374 38 12 12 152 158 14 171 178 185LI 114 19 28 0 0 0 0 0 0 0 0 0 0 0 0 0Bitum 30 35 41 48 54 65 71 77 94 92 00 104 113 120 127 135

1,451 1,517 1,658 1,801 1,948 1,977 2,029 1,781 1,849 1,90 2,501 2,617 2,731 2,854 2,979 3,111

Total White Products 1,010 1,095 1,184 1,294 1,390 1,505 1,584 1,647 1,754 1,845 2,254 2,353 2,455 2,542 2,474 2,791Total Storage

Rqured 0 21 days 58 63 69 74 80 87 91 94 101 104 130 135 141 147 154 161Incr. Storage 58 5 5 4 4 7 5 5 5 5 24 6 4 6 6 7Invtstent 4SN

at UJ1ton 100 11.40 0.98 1.05 1.13 1.22 1.32 0.91 0.9 1.00 1.05 4.73 1.12 1.17 1.23 1.29 1.35at USSItas 250 14.50 1.22 1.31 1.41 1.52 1.65 1.14 1.19 1.25 1.31 5.91 1.40 1.4, 1.54 1.41 1.48

Ilntent - lntrast. 20 40S 401and Port 20 4.0 8.0 0.0

Opmr.Costs 0.00 0.00 3.00 3.00 3.00 3.00 3.00 3T U 3.00 3.00 3.00 3.00 3.00 3.00 3.00 3.00Cap Cost + Op Cost

east Case 15.40 9.98 12.05 4.13 4.22 4.32 3.91 3.9 4.00 4.05 7.73 4.12 4.17 4.23 4.29 4.35Test Case 18.50 9.22 12.31 4.41 4.52 4.65 4.14 4.19 4.25 4.31 9.91 4.40 4.47 4.54 4.41 4.68

Freiqht Savingsper ton 9.00 0.00 0.00 10.67 11.54 12.51 13.55 14.26 15.00 15.79 16.61 20.30 21.18 22.10 23.06 24.07 25.12per ton 5.00 0.00 0.00 5.93 6.42 6.95 7.53 7.92 8.34 8.77 9.23 11.28 11.77 12.28 12.81 13.37 13.96

Base CaseCast 15.60 8.98 12.05 4.13 4.22 4.32 3.91 3.94 4.00 4.05 7.73 4.12 4.17 4.23 4.29 4.35Benefit 0.00 0.00 10.47 11.54 12.51 13.55 14.24 15.00 15.79 14.41 20.30 21.19 22.10 23.04 24.07 25.12

llt Benetit -15.40 -9.99 -1.37 7.43 8.29 9.22 10.35 11.05 11.78 12.54 12.57 17.06 17.92 18.93 19.78 20.77IRR 2t.5S

Tnt CaseCeet 18.50 9.22 12.31 4.41 4.52 4.45 4.14 4.19 4.25 4.31 9.91 4.40 4.47 4.54 4.41 4.68llnoftit 0.00 0.00 5.93 6.42 6.95 7.53 7.92 8.34 8.77 9.23 11.28 11.77 :2.28 12.81 13.37 13.96

11t Benefit -18.50 -9.22 -6.38 2.01 2.43 2.87 3.79 4.14 4.52 4.92 2.37 7.37 7.91 8.27 8.76 9.27

I CRUDE STRMSE AT RAS ISSA

19 1991 1992 1 1 1995 19 1997 199 1999 2000 2001 2002 2003 2004 2005Total Storage…… - -

Required 240000 tonsInvestent - Stare 20? 40 40?USt/ton 150 3 7.2 14.4 14.4

200 48 9.4 19.2 19.2

Oper.Costs 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0Use Case

Cost 7.2 14.4 18.4 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0Befit 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0llt Benefit -7.2 -14.4 -9.4 4.0 6.0 4.0 6.0 6.0 4.0 4.0 6.0 6.0 6.0 6.0 6.0 6.0IRA 14.51eVY 3.5

Test CaseCost 9.4 19.2 23.2 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0Bnetit 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0Ibt 8 nefit -9.6 -19.2 -13.2 6.0 6.0 6.0 6.0 4.0 4.0 6.0 6.0 U4. 6.0 6.0 4.0 6.0

1"-5.8

III C118INED CRUOE I PFR0OIIT STOR1E

Base CaseCost 22.9 23.4 30.4 8.1 9.2 8.3 7.9 8.0 8.0 8.0 11.7 8.1 8.2 9.2 8.3 8.3Benefit 0.0 0.0 20.7 21.4 22.5 23.5 24.3 25.0 25.8 24.6 30.3 31.2 32.1 33.1 $4.1 35.1Ibt Benefit -22.8 -23.4 -9.8 13.4 14.3 15.2 14.3 17.0 17.8 18.4 18.4 23.1 23.9 24.8 23.9 26.8IRI 21.61WV 34.0

Tnt CaseCast 28.1 28.4 35.5 8.4 8.5 8.7 8.1 8.2 8.3 8.3 12.9 9.4 9.3 8.5 9.4 8.7Bmfit 0.0 0.0 15.9 14.4 17.0 17.5 17.9 19.3 18.0 19.2 21.3 .8 22.3 22.3 23.4 24.0et Beeit -28.1 -28.4 -19.4 8.0 9.4 9.9 9.9 10.1 10.5 10.9 8.4 13.4 13.3 14.3 14.8 15.3a

- 70 -

Annex ILUPage 1 of 6

YAR - Energy Strategy ReviewSecond Refinery Proiect

Economic Analysis

Introduction

1. Following the discovery of commercially exploitable crude oilreserves in YAR, GOY commissioned UOP Processes International,Inc./ChemSystems (UOP/CS) to study the possibilities of establishing asecond petroleum refinery in the country. We have reviewed this IDA-financed study entitled "Feasibility Study for a New Refinery" of February1989 which serves as a basis for our analysis.

2. The assessment of the proposed new refinery investment is afunction of projections/assumptions concerning: (i) domestic demand forpetroleum products; (ii) economic prices of crude and products;(iii) refinery crude slate and products slate; and (iv) economic capitaland operating costs of the refinerv. In addition to UOP/CS's sets ofassumptions concerning each of the abovementioned parameters, the WorldBank and MOMR generated independent or modified projections concerningdomestic demand and prices of crude and products. In our analysis of theeconomic justification of the proposed investment, discussed below, thevarious sets of assumptions concerning the four main parameters have beencombined to generate a number of scenarios for assessing the impact ofvariations in estimates of demand, prices, crude slate, product yield, andcapital investment on the project economic rate of return (ERR). The datasets attached to this Annex summarize the bases and assumptions made byUOP/CS, the Bank, and MOMR; they are discussed below.

Domestic Demand for Petroleum Products

3. Demand projections for products by UOP/CS in their Study arebased on a detailed analysis of historic consumption trends, end-useanalyses, and correlations with general economic and sectoral growthtrends. Our projections are essentially based on those by UOP/CS, exceptin the case of fuel oil and LPG, which are based on our independentassessments. The UOP/CS base case demand scenario assumes that in the caseof fuel oil demand, natural gas will be made available well before 1994 fora proposed new power station near Sana'a, as well as to the cement plant atAmran, resulting in reduced fuel oil demand commencing 1992-1993. Our"Base Case" demand estimates for fuel oil are based on gas availability tothe proposed Sana'a power and the Amran cement plants by 1994 andsubsequently to the Ras Khatenib power and the Bajil cement plants by 1997,and on our independent assessment of power demand. The impact of fuel oilsubstitution by gas on the project has been assessed by a separate variantto our Base Case in which it has been assumed that natural gas will not be

- 71 -Annex III-Zpage 2 of 6

estimates made by MOMR staff, but modified by us in that the rate of growthfrom 1996 will be slower than MOMR's implied growth rates, so that it willcoincide by 2005 with the level of demand projected by us for each product.This modification to MOMR's estimates is based on the consideration thatMOMR's estimates is based on the high, perhaps transient increases inconsumption of gasoline and jet fuel which occurred during 1987, andextrapolated to the long-term. Even though MOMR's original long-termprojections in our view lack validity, the demand projections as modifiedby us have been considered as one of the three scenarios to test thesensitivity of the ERR to demand growth.

Prices of Crude and Products

4. Our forecasts of economic prices of products t-t Hodeidah/Salifhave been built from international crude oil price projections in the ArabGulf (AG, Light Arab), applying (i) the historical relationships (ratios)between crude and individual products at refining source, and (ii) freightrates for transport of products to Hodeidah/Salif. Two crude pricescenarios have been considered: the first based on the World Bank'sprojections at $15.4 per barrel in 1990 increasing to $21.8 per barrel in2000 (all in constant 1988 terms), and the second based on UOP/CS's basecase projections which are significantly higher. Concerning product pricesat source, our projections are based on the average 1983-1987 ratiosbetween crude and individual products in AG, applicable till 2005 as theBase Case, and as a variant, the ratios changing upwards from 1996reflecting an assumption that the world-wide supply/demand for productswill equilibrate by 1995; thereafter the prices and price ratios will besuch as to enable full cost recovery of the most efficient new refinerycoming on stream by 1995. The latter assumption implies that the currenteffective refining over-capacity worldwide, which results in refineriesrecovering only their rash operating costs, will change when, as nowpostulated, the worldwide demand outstrips supply by 1995.

5. The price relationships (ratios) between crude and products, atsource, projected by UOP/CS are essentially similar to ours; thoseprojected by MOMR are the same as those of UOP/CS. Concerning the economicCIF prices: (i) UOP/CS' projections are based on product prices in theMediterranean market plus a freight rate of about US$14 per ton toHodeidah/Salif reflecting transport in small (less than 10,000 DMT) tankersbecause of restrictions in port facilities at Hodeidah; and (ii) ourprojections are based on the assumption that the Ras-Issa port developmentand storage facilities to accommodate larger tankers (up to 80,000 DWT)will be justified and will have been implemented before the proposedrefinery is commissioned in early 1994; as a consequence, the source ofproducts would be Arab Gulf, with lower freight rates for transport ofproducts to Ras-Issa. Our estimates of CIF prices thus result in lowereconomic values for imported products, compared to those of UOP/CS, as wellas those of MOMR.

Crude Slate and Crude Throughput

6. The Feasibility Study is based on a refinery capacity ofapproximately 60,000 bpd, processing about 75X domestic Alif crude and 251imported reduced crude from the Arab Gulf areas. There are major

- 72 -Annex III-7page 3 of 6

uncertainties about availability of Alif crude in adequate quantities tillthe year 2005 (12-year refinery operation commencing 1994). Currentindications are that the Alif crude availability may fall below 45,000 bd(i.e. below 75% of the 60,000 bpd refinery capacity) by 1996. AlthoughMOMR have indicated the possibility of additional crude oil production fromother fields yet to be defined, credible estimates of production rates andmore importantly, the quality of crude oil, are uncertain.

7. It is thus not possible at this time to estimate with certaintythe crude slate beyond 1996 to be used by the refinery. If, in fact, Alifcrude availability declines as currently expected, the deficit of crude forrefining will need to be supplemented by suitable imported crude. Theimpact of this situation has been bracketed by the two separate Bank-developed scenarios where the refinery prou-;-es either Alif crude plusreduced crude or imported crude plus local cundensate, each processedthroughout the life of the investment. Thus, two crude slate scenarioshave been assumed: (i) UOP/CS' where 75X Alif and 25% imported reducedcrude are assumed to be processed; and (ii) our alternative case where 75%Light Arab imported crude and 25% domestic :ndensate from other fields yetto be confirmed, are used. Product yields trom the abovementioned twofeedstock slates are as estimated by UOP.

8. Capacity buildup is assumed at 701 during first year of operation(1994), 85% during second year, and 100% during third year and thereafter.Concerning the yield pattern from the refinery, UOP/CS assumed productionof 100,000 tpy (at 100% throughput) of LPG on the consideration that therewill be no production of LPG from Alif field associated gases. Theopportunity value of refinery LPG is very high since the freight fortransport of imported LPG from source to Hodeidah is about US$100 per ton.Since it is now reasonably certain that investments for LPG recovery fromAlif associated gases as well as from other non-associated gas fields willhave been justified and implemented before 1994, our Base Case assumes thatthe refinery will not produce any LPG, and the refinery yield pattern hasbeen adjusted accordingly. However, the impact of having to produce LPG atthe refinery on ERR has also been tested as a variant to our Base Case.

Capital Costs

9. UOP/CS's estimates of cepital costs are based on U.S. Gulf Coasterected costs (the normal benchmark) in constant 1986 US$; the erectedcosts at Ras Issa are estimated from the above, using a locationtranslation factor of 1.5. It is further assumed that the proposed RasIssa product storage facilities will be justified and implemented,resulting in a reduction in refinery capital cost on account of avoidedcrude and product storages at the refinery. At 7-day crude storage and 15-day product storage, the avoided refinery capital cost is estimated atabout US$35 million for grass-roots location at Ras Issa. Taking also intoaccount the additional investment required for linking the refinery withRas Khatenib power station by a power tranumission line (which is notrequired in case the refinery is not built), the net reduction in refinerycapital cost is estimated at about US$10 million. Road linkages and otherinfrastructures will be required in either the with- and the without-refinery cases. " our 1 r " a 'vl - , r 1 -9 I

- 73 -Annex-III-7page 4 of 6

ERR has been tested by assuming variation of +101 over the Base Casecapital cost estimates. Operating costs as estimated by UOP/CS for thevarious crude slates and capacity throughputs have been adopted with someadjustments, particularly arising out of changes in LPG productiondiscussed in para 3 above. Although there would be some differences in thecapital costs when based on the two different crude slates, these would berelatively minor and have been ignored for the present analyses. For theeconomic analyses, capital related costs and charges have been excluded.

Economic Evaluation

10. Our Base Case is defined by the combination of the followingassumptions: (i) demand, corresponding to UOP/CS estimates except for fueloil and LPG where our higher projections were used; (ii) crude oil pricescorresponding to the Bank's crude oil price projections, expressed inconstant 1988 terms; (iii) product to crude price ratios based on1983-87 average spot price ratios in the Arabian Gulf, remaining constantthroughout the 12 years of refinery operation; (iv) lower freight rates forArab Gulf crude to Ras Issa in large tankers; (v) crude slate consisting ofAlif (75X) and imported reduced crude (25%); (vi) no production of LPG atthe refinery, with adjustments to gasoline and fuel oil production on thebase refinery yield pattern as in the UOP/CS Study; and (vii) capital costbased on US Gulf Coast erected cost, using a location multiplier of 1.5,but reduced by US$30 million representing net avoided expenditure whencompared with the "no refinery" scenario. The ERR and NPV estimates forthe various scenarios and variants are summarized in Attachment 1. Cost-Benefit streams, ERR and NPV's for the Bank's Base case, and one of thetest cases (RefMisVl), as well as for UOP Base Case (REUOPBa) are shown onpage 6 of Attachment 2 to this Atnex.

11. The impact of variations on demand, product prices, crude slate,production slate with and without LPG manufacture, and capital costs areestimated as follows: First, demand variations as represented by thedifference between our Base Case and the MOMR Case (equivalent to about 30Xin the initial years of operation, gradually declining to about 91 by 2000and to nil by 2005, comparisons of RefIis 2 and RefMis 3 scenarios) accountfor about 0.6% in the ERR. Second, the scenario ReMinMo, which has an ERRof 20.11, reflects the combined effect of higher demand, higher opportunity(CIF) values for products, and the effect. of making LIG at the refinery,when compared with our Base Case. The effect on the ERR of higher demandis estimated at 0.61 as mentioned above, and the effect of making LPG, at1.31 (comparison of ReMinMo and ReMinVl). Thus, by difference, theresidual effect of product price assumptionu on ERR is estimated at about171. The implied price variations as measured by the difference in CIFHodeidah/Salif prices between MOMR estimate and our Base Case estimate, isabout 451 in the initial years of operation declining to about 301 by theyear 2005. The ERR is thus highly sensitive to price assumptiousexemplified further by comparison between our Base Case and RefHis 2, wherean 8Z variation in prices results in about 6 percentage point difference inthe ERR. Third, regarding the impact of variations in capital costassumptions, a 101 variation ir capital costs results in a change of about1 percentage point in the ERR. In summary, while it is very difficult todisa regate the 4' act of -i v' vI' * V ' ' * , , I , C. In

- 74 -

Annex IIl-7page 5 of 6

parameters on the ERR, it is clear that it is sensitive mainly to prices,and less sensitive to demand variations and production slate.

12. The proposed project investment would result in negative netpresent values (NPV) at a discount factor of 12X for all of the Bank'sscenarios, except RefMisVl. The primary reason for the high positivo NPVand ERR for the MOHR cases is the product price assumptions. As mentionedabove, the very high product to crude price ratios and high freight rateson top of high base crude prices assumed by MOMR result in 30-45X higheropportunity values for the refinery output. In our view, such highopportunity values are untenable in a responsible economic analysis, and donot form a valid basis for a sound investment decision. The ERR/NPVcalculation corresponding to the scenario termed "UOP/CS base case" arebased on our calculations using UOP/CS assumptions on demand, and CIFprices but with our adjustments to the capital costs on end-1988 terms andremoving inconsistencies in UOP's own calculations concerning CIF importcosts and FOB revenues from export product surpluses. The scenario termed"UOP/CS base case" in our analysis thus includes some adjustments to someof the assumptions made by UOP/CS in their own analysis. The ERRcalculated by UOP/CS is about 18.61, whereas our analysis shows an ERR of12.4X due to the adjustments referred to above, and discussed below.Firstly, UOP/CS' latest crude oil price projections in 1988 constant dollarterms is $27.4 per barrel in 1995 increasing to $33.3 in 2000 and to $39.3by 2005, which are much higher than our projections of $17.2, $21.8, and$27.6, respectively, all in constant 1988 terms. As a consequence, theopportunity value imputed to refinery products in UOP/CS scenario isunacceptably high, and these price assumption variations account for themajor part of the difference in the ERR calculations. Secondly, UOP/CSassume that Alif crude will carry a price premium of 51 over the Arab Lightmarker crude. We have conservatively assumed that there will no pricepremium which would result in lower imputed feedstock price te the refinerywith a small consequent improvement in the ERR. Thir,y y, the importedheavy residue, a part of the refinery feedstock, has been assumed by UOP/CSas having the same price as fuel oil price in the Mediterranean area,whereas we have assumed that the price will be higher by the amount offreight from the AG area. The difference is relatively small and will havemarginal impact on project ERR. Fourthly, UOP/CS assume that the export ofsurplus fuel oil will have a value of 1X sulfur fuel oil (rather than 3.51sulfur fuel oil), and that the export of gasoline will have a valuecorresponding to premium gasoline (rather than regular gasoline). We haveassessed the impact of these assumptions on the ERR as 0.6, and 0.3percentage points. Fifthly, UOP/CS have assumed that surplus exports ofkerosene and gas oil will be to nearer-by markets with no freightpenalties, that the production of bitumen will correspond to domesticdemand each year with export of surplus in the form of fuel oil, and thatthe refinery will achieve 1001 capacity utilization from the first year.We find it difficult to accept these assumptions: In summary, the impactof all of UOP/CS assumptions in their evaluation of the ERR, other than theproduct prices, is relatively small and not likely to exceed about 2percentage points. Basically, UOP/CS's crude oil and consequent productsprice assumptions are unacceptable to us.

13. Our scenario RefMis Vl, differs from our Base Case in that theproduct in crude price ratios will increase from 1996 reflecting a

- 75 -Annex III-7page 6 of 6

hypothesis that the world-wide demand and supply of products willequilibrate by 1995 and consequently product prices will increase to permitfull cost recovery by new capacity investments. RefMis VI scenario showsour ERR of 13.31. It should be borne in mind that this scenario alsoassumes that Alif crude will be available in adequate quantities for 12years of refinery operating life. If in fact Alif crude availability isnot sufficient, resulting in having to import deficit crude, the ERR willreduce considerably. The magnitude of processing local or imported crudesis reflected by comparison of Base Case (RefMis 0), and RefKis 1. To theextent that the refinery has to import crude oil to supplement or replaceAlif crude, the ERR will drop below the threshold level of 121.

14. The Attachment 1 to this Annex sets out the ERR and NPV's of thevarious scenarios analyzed. Attachment 2 sets out the data sets on demand,prices, crude and product yields corresponding to various sets ofassumptions.

15. In conclusion, we assess that the proposed new refinery is noteconomically justified, and should not be proceeded with at this time. Theproject justification may be reassessed in the future, when theinternational crude prices increase at rates significantly higher thanthose projected by the Bank now to the levels approaching those projectednow by UOP/CS.

ja - EnerYv Strateav ReviewEstimated ERRs for Refinery Investment

(Codes refer to data in Data Sets at Enclosure)

V A R I A B L E SP r I ca a Crude Slate RefineryProduct Product Alif/ Arab Ligbt/ LPG Production NmDogd Crudo Ogi Ratio Freight Red Crude Condensate Witlout a

I.'

a) R*mix 0 (BaesC"e w/ 1.5 CP) D2 PCI PO1 PR2 Fl CS3 - - x 3.2 -131.6b) Refmis VI D2 PCI PO1 In V1 CS3 - - x 13.3 +26.0C) Rofmis V2 D2 PCI PO1 FR2 F1 C03 - 2.2 -144.6d) Refala 1 D2 PC1 PO1 PR2 F1 - CS2 - x -8.1 -237.0*) Retini 2 DZ PCI PO2 PR2 CS3 - - 9.2 -47.6f) R*fmis 3 D3 PCI PO2 PR2 CS3 - - x 9.8 -37.1

xx. WrUCS

a) ReUOPBa(Base Case) Di PC7 P07 PR7 F4F2 CSi - x - 12.4 7.0

a) RoMinHo D3 PC6-PC7 P06-PO7 PR6 F3-F4 CS1 - x - 20.1 159.8b) RelinVI D3 PC6-PC7 P06-P07 PR6 F3F4 CS1 - - 1s8. 131.9

Notes:

1. With reference to our Base Case (a) (Refais 0): (b) Refmis VI measures the impact of hypothesis of increased product to crude priceratios from 1996 onwards; (c) Refmis V2 measures impact of producing LPG from refinery, in turn based on assumption that LPG dma.d willnot be met in full by recovery from natural gas; td) Refmis 1 measures impact of change in crude slate; (e) Refmis 2 measures impact ofbiaher import CIP price reflected by sourcing supplies from Mediterranean area and transport in small ships. with Implied assumption thatthe proposed Alif port development and storage project will not come about; and (f) Refmis 3 measures impact of higher domestic productdemand growth coupled with higher import CIF prices as in te) above.2. JP/CS base case (RaUOPBa), reflects lower demand growth rates for fuel oil and LPG relative to ESR Base Case, and assumes higher crudeprice growth rates, somewhat higher product to crude price ratios, higher freights, and 100,000 tpy production of LPG from refinery. Thecombined effect of price assumptions (crude. ratios, source, and freight) results in significantly higher CIF prices at Hodeidah, wbichtranslate to about 140-1662 higher by 1995. and 122-1602 higher by 2000 relative to those based on the Base Case. Comparison of this casewith Rofmie 2, masures the impact of price assumption changes on ERR for the magnitude of price differences mentioned above.3. ERR estimates following MOM's assumptions of high demand growth (modified by the Bauk for the years beyond 1995, on the considerationthat FOM's original estimates of growth rates beyond 1995 did not appear to be tenable), even higher product to crude price ratios Itresulting in the highest CIF Bodeidah prices. The impact of not producing LPG at the refinery is measured by the variant case ReMinVirelative to RuMinMo.

I,4. Variable that has been changed with reference to respective base cases are underlined. 0S. Capital cost estimates in 1988 prices for all our scenarios are US$347 million (including US$6.0 million of working capital); for WP/CSscenario: US$347 million (including working capital); and for MOM scenarios: US$347 million (including US$6.0 million of workingcapital).

- 77 - Attachment 2 to Annex III-7Page 1 of 6

YAR - ENERGY STRATEGY REVIEW

OIL PRODUCTS DEMNUD FORECAST

('000 tons/yr)

Est.DI) 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Prem.Gasoline 15 20 23 26 30 35 40 44 48 53 58 64 67 71 75 79 83Reg.Gasoline 559 630 684 742 806 875 950 997 1047 1099 1154 1211 1275 1342 1414 1488 1567Domestic Kero 63 60 60 60 60 60 60 59 58 57 56 55 54 53 52 51 50Jet Fuel 64 70 75 81 87 93 100 107 114 122 131 140 149 158 168 178 189Diesel 544 545 568 591 616 642 670 692 714 737 761 786 808 830 854 878 902Fuel Oil * 316 418 401 385 369 354 340 333 327 320 314 308 301 295 288 282 276LPG 81 86 99 114 132 152 175 186 199 212 225 240 251 262 274 287 300Bitumen 26 30 35 41 48 56 65 71 77 84 92 100 106 113 120 127 135

Total 1669 1859 1945 2041 2148 2266 2400 2489 2584 2685 2791 2904 3011 3125 3244 3370 3502* of which:Fuel OilPower Plants - 312 284 259 235 214 195 175 158 142 128 115 - - - - 115Other Industry - 106 113 120 128 136 145 154 - 193 - - - 161

Est.D2) 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Prem.Gasoline 16 20 23 26 30 35 40 44 48 53 58 64 67 71 75 79 83Reg.Gasoline 560 630 684 742 806 875 950 997 1047 1099 1154 1211 1275 1342 1414 1488 1567Domestic Kero 64 60 60 60 60 60 60 59 58 57 56 55 54 53 52 51 50Jet Fuel 64 70 75 81 87 93 100 107 114 122 131 140 149 158 168 178 189Diesel 544 545 568 591 616 642 670 692 714 737 761 786 808 830 854 878 902Fuel Oil * 350 482 553 589 654 587 587 559 223 197 173 152 158 164 171 178 185LPG 96 114 139 148 163 178 193 208 2234 238 253 268 280 292 304 317 331Bitumen 26 30 35 41 48 56 65 71 77 84 92 100 106 113 120 127 135

Total 1719 1951 2137 2279 2464 2525 2665 2737 2505 2587 2678 2776 2897 3024 3156 3296 3442* of which:Fuel OilPower Plants 263 354 414 449 478 496 480 446 208 153 116 134 139 144 149 154 160other Industry 87 128 139 140 176 91 107 113 15 44 57 18 19 21 22 23 25

Est.D3) 1989 199 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Prem.Gasoline 16 24 28 32 37 43 50 53 55 58 61 64 68 71 75 79 83Reg.Gasoline 560 771 842 920 1005 1098 1200 1232 1266 1300 1335 1371 1408 1446 1486 1526 1567Domestic Kero 64 60 60 61 61 62 62 61 59 58 57 56 54 53 52 51 50Jet Fuel 64 74 82 91 101 113 125 130 136 142 147 154 160 167 174 181 189Diesel 544 545 585 628 675 725 778 790 801 813 825 838 850 863 876 889 902Fuel Oil 316 418 451 486 524 566 610 559 223 197 173 152 158 164 171 178 185LPG 96 86 99 114 132 152 175 188 201 215 231 229 242 255 2f" 284 300Bitumen 26 30 35 41 48 56 65 70 75 81 87 94 101 108 1 125 135

Total 1686 2008 2183 2374 2584 2813 3065 3074 3091 3116 3149 3189 3236 3291 3352 3420 3494

01) BANK ESTIMATE (Base Case) - Gas to Sana$a/Amran In 1994 and Ras Katenib in 1997.D2) MOMR - (modified), 1996-2005 a Bank Estimate.D3) UOP/cS - Base Case, (Feb 1989).

Jan-90

- 78 - Attachment 2 to Annex III-7

Page 2 of 6

YEMEN - ENERGY SECTOR REVIEW

CRUDE PRICES (in constant 1988 US#)

BANK ESTIMATE:Base Case - P1 a)

1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

FOB AG S/bbl 14.7 15.4 15.7 1S.1 16.5 16.8 17.2 18.0 18.9 19.8 20.8 21.8 22.9 24.0 25.1 26.3 27.6 (PCI)FOB AG S/ton 107 112 115 118 120 123 126 132 138 145 152 159 167 175 183 192 201 (Po1)CIF Ned.S/ton 113 118 121 124 126 129 132 138 144 151 158 165 173 181 189 198 207Alif S/ton 113 118 121 124 126 129 132 138 144 151 158 165 173 181 189 198 207Imp.Heavy S/t 86 90 92 94 96 98 96 100 105 110 115 121 127 133 139 145 153

PRODUCT RATIOS (PR2)

Prem.Gasotline 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33Reg.Gasotine 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27Domestic Kero 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31Jet Fuel 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31Diesel 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17F. Oil (3.5%S 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73LPG 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14Bitumen 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78

a) In the variant scenario REFMISV1, Product Ratios are assumed from 1966 as foLLows:Prm.Gas.:1.49; Reg.Gas.:1.4; Kero&Jet Fuel: 1.43; Diesel:1.28;Fuel Oil: 0.72; LPG: 1.14; and Bitumen: 0.78.

BANK ESTIMATE: CRUDE PRICESRCFMIS1 -'''(Lower Freight Rates)

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

FOB AG S/bbl 14.7 15.4 15.7 16.1 16.5 16.8 17.2 18.0 18.9 19.8 20.8 21.8 22.9 24.0 25.1 26.3 27.6 (PC1)FOB AG S/ton 107 112 115 118 120 123 126 132 138 145 152 159 167 175 183 192 201 (Po1)CIF Ned.S/ton 113 118 121 124 126 129 132 138 144 151 158 165 173 181 189 198 207Light Arab S/ 112 117 120 123 125 128 131 137 143 150 157 164 172 180 188 197 206Condensate S/ 113 118 121 124 126 129 132 138 144 151 158 165 173 181 189 198 207 (CS2)

PRODUCT RATIOS

Prem.Gasoline 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33Reg.Gasoline 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27Domestic Kero 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31Jet Fuel 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31Diesel 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.1 1.17 1.17 1.17F. OiL (3.5XS 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73LPG 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14Bitumen 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78

BANK ESTIMATh: CRUDE PRICESREFMIS2 & REFMIS3 ------------(High Freight Rate)

1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

FOS AG S/bbl 14.7 15.4 15.7 16.1 16.5 16.8 17.2 18.0 18.9 19.8 20.8 21.8 22.9 24.0 25.1 26.3 27.6FOB AG S/ton 107 112 115 118 120 123 126 132 138 145 152 159 167 175 183 192 201CIF Ned.S/ton 113 118 121 124 126 129 132 138 144 151 158 165 173 181 189 198 207Alif S/ton 113 118 121 124 126 129 132 138 144 151 158 165 173 181 189 198 207Imp.Heavy S/t 89 92 95 97 99 101 103 107 112 117 122 128 133 139 145 152 160

PRODUCT RATIOS

Prem.Gasotine 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33Reg.Gasoline 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27 1.27Domestic Kero 1.31 1.31 1.31 1.31 1.31 1.31 1.31 *.3 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31Jet Fuel 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.3i 1.31 1.31 1.31Diesel 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17 1.17F. Oil (3.52$ 0.7S 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73 0.73LPG 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14Bitumen 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78

- 79 - Attachment 2 to Annex III-7Page 3 of 6

YEMEN - ENERGY SECTOR REVIEW

CRUDE PRICES (in constant 1988 USS)

UOP/CS ESTIMATE Of:Base Case - P7

1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

FOB AG S/bbt 14.7 18.0 18.9 19.9 20.9 21.9 23.0 23.9 24.9 25.9 26.9 28.0 28.9 29.9 30.9 31.9 33.0 (PC7)FOB AG S/ton 107 131 138 145 152 160 168 175 182 189 197 204 211 218 226 233 241CIF Med.S/ton 113 137 144 151 158 166 174 181 188 195 203 210 217 224 232 239 247 (P07)Alif S/ton 120 144 151 158 165 173 184 191 198 205 213 224 231 238 246 253 264Imp.Heavy S/t 89 104 109 114 119 125 130 135 140 145 151 148 154 158 163 168 168

PRODUCT RATIOS (P07)

Prem.Gasotine 1.33 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.36 1.36 1.36 1.36 1.36 1.37Reg.Gasoline 1.27 1.28 1.28 1.28 1.28 1.28 1.28 1.28 1.28 1.28 1.28 1.29 1.29 1.29 1.29 1.29 i.30Domestic Kero 1.31 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.34 1.34 1.34 1.34 1.34 1.33Jet Fuel 1.31 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.34 1.34 1.34 1.34 1.34 1.33Diesel 1.17 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.19 1.19 1.19 1.19 1.19 1.18F. Oil (3.5%S 0.73 0.71 0.71 0.71 0.71 0.71 0.71 0.71 0.71 0.71 0.71 0.67 0.67 0.67 0.67 0.67 0.64LPG 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14Bitumen 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78

MOHR ESTIMATE CRUDE PRICESRENINMOD - P6 -----------

1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

FOB AG S/bbl 15 18 19 19 21 21 23 24 24 26 26 28 29 29 31 31 33 (PC6)FOB AG S/ton 107 131 138 145 152 160 168 175 182 189 197 204 211 218 226 233 241CIF Med3./ton 113 137 144 151 158 166 174 181 188 195 203 210 217 224 232 239 247 (P07)ALif S/ton 120 144 151 158 165 173 184 191 198 205 213 224 231 238 246 253 264Inp.Heavy S/t 90 91 95 99 104 108 115 119 123 128 133 136 141 145 149 154 159

PRODUCT RATIOS (PR6)

Prem.Gasoline 1.33 1.53 1.53 1.53 1.53 1.53 1.53 1.53 1.53 1.53 1.53 1.53 1.53 1.53 1.53 1.53 1.53Reg.Gasoline 1.27 1.38 1.38 1.38 1.38 1.38 1.38 1.38 1.38 1.38 1.38 1.38 1.38 1.38 1.38 1.38 1.38Domestic Kero 1.31 1.39 1.39 1.39 1.39 1.39 1.39 1.39 1.39 1.39 1.39 1.39 1.39 1.39 1.39 1.39 1.39Jet Fuel 1.31 1.39 1.39 1.39 1.39 1.39 1.39 1.39 1.39 1.39 1.39 1.39 1.39 1.39 1.39 1.39 1.39Diesel 1.17 1.21 1.21 1.21 1.21 1.21 1.21 1.21 1.21 1.21 1.21 1.21 1.21 1.21 1.21 1.21 1.21F. Oft (3.5XS 0.73 0.61 0.61 0.61 0.61 0.61 0.61 0.61 0.61 0.61 0.61 0.61 0.61 0.61 0.61 0.61 0.61LPG 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14 1.14Bitumen 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78 0.78

Jan-90

- 80 - Attachment 2 to Annex III-7

YAR - ENERGY SECTOR REVIEW Page 4 of 6.......... ..................

PRODUCT PRICES CIF HODEIDAN............. ....................

(in 1988 US#/ton)BANK ESTIMATE

Est.------------- EtBASE CASE 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005em soi. .... .... .... .... .... .... .... .... .... .... .... .... .... .... .... .... ....276

Prem.Gasoline 156 163 166 169 16 176 173 181 190 199 208 219 229 240 251 263 276ReD.Gasotine 149 156 159 167 170 174 175 173 181 190 199 215 219 229 240 251 264Doestic Kero 154 160 164 167 170 174 170 178 187 196 205 215 226 236 247 259 272Jet fue: 154 160 164 167 170 174 170 178 187 196 205 215 226 236 247 259 272Diesel 139 145 147 150 154 157 153 160 168 175 184 193 202 212 222 232 244Fuel Oil(3.5X) 86 90 92 94 96 98 96 100 105 110 115 121 127 133 139 145 153LPG 207 213 216 219 222 225 183 190 197 205 213 226 235 244 254 264 280Bitumen 154 158 160 162 164 166 138 143 148 153 158 169 175 181 188 195 207

REFMtS1------- Est.

1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005e.a e 163 166 169 173 176 1-3 181 190- 199 208 219- 229- 240 25- 23 2

Prem.Gasoline 156 163 166 169 173 176 173 181 190 199 208 219 229 240 251 263 276ReD.Gasotine 149 156 159 167 170 174 170 178 181 190 199 215 219 229 240 251 264Domestic Kero 154 160 164 167 170 174 170 178 187 196 205 215 226 236 247 259 272Jet Fuet 154 160 164 167 170 174 170 178 187 196 205 215 226 236 247 259 272Diesel 139 145 147 150 154 157 153 160 168 175 184 193 202 212 222 232 244Fuel Oi(3.5X) 86 90 92 94 96 98 96 100 105 110 115 121 127 133 139 145 153LPG 207 213 216 219 222 225 183 190 197 205 213 226 235 244 254 264 280Bitumen 154 158 160 162 164 166 138 143 148 153 158 169 175 181 188 195 207

REFMIS2------- Est.

1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005_G i 1 170 174 17- 181 185- 189 197 206- 215- 225- 235- 245- 256- 268- 280- 292-

Prem.Gasoline 162 170 174 177 181 185 189 197 206 215 225 235 245 256 268 280 292ReD.Gasotine 155 168 166 170 179 177 181 189 1970 21 215 235 235 245 256 267 279Domestic Kero 159 168 171 175 179 182 186 194 203 212 221 231 241 252 264 276 288Jet Fuet 159 168 171 175 179 182 186 194 203 212 221 231 241 252 264 276 288Diesel 144 152 155 158 161 165 168 175 183 191 199 208 217 227 237 248 259Fuel Oilt(3.5X) 89 94 96 98 100 103 105 110 114 119 125 130 149 172 197 227 261LPG 211 220 225 230 235 240 245 255 265 276 287 298 310 322 335 348 362Bitunen 138 162 167 171 176 181 186 193 201 209 217 225 234 242 252 261 271

UOP/CS------ ~Est.

Base Case 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005---------. .. ..... .... .... .. ... .... . .... ... I--- .---- ---- . ..... ---- . ---- ---- ---- . ---- ---- . ..----. .. .

Prem.Gasoline 162 196 206 216 226 236 247 256 265 275 285 299 308 318 328 338 351Reg.Gasoline 155 187 196 205 215 224 235 243 252 262 271 285 293 302 312 321 335Domestic Kero 159 197 206 216 226 236 248 256 265 275 285 295 304 314 323 333 342Jet Fuel 159 197 206 216 226 236 248 256 265 275 285 295 304 314 323 333 342Diesel 144 177 185 193 202 211 222 229 237 246 255 263 272 280 289 298 304Fuel Olt3.5X) 89 104 109 114 119 125 130 135 140 145 151 148 154 158 163 168 167LPG 211 246 246 254 262 271 304 312 320 328 337 360 368 376 384 393 419Bitumen 138 157 162 168 173 179 192 197 202 208 214 221 226 232 238 244 256

REMINMOD

1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Prem.Gasoline 162 221 232 243 254 266 279 289 300 311 323 335 345 356 367 379 394Reg.Gasoline 155 201 211 220 230 241 253 262 272 282 292 303 313 323 333 343 354Domestic Kero 159 202 212 222 232 243 255 264 274 284 294 305 315 325 335 345 356Jet Fuel 159 202 212 222 232 243 255 264 274 284 294 305 315 325 335 345 356Diesel 144 177 186 195 203 213 223 232 240 249 258 268 276 284 293 302 312Fuel 0il(3.5X) 90 91 95 99 104 108 115 119 123 128 133 136 141 145 149 154 159LPG 214 246 253 261 269 278 304 312 320 328 337 360 368 376 384 393 419Birumen 138 157 162 168 173 179 192 197 202 208 214 221 226 232 238 244 256

Jan-90

- 81 - Attachment 2 to Annex III-7Page 5 of 6

YAR - ENERGY STARTEGY REVIEW

HEW REFINERY PRWUCTION FORECAST

CRUDE SLATE #1

('0CO tonsuyr)1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Total Crude Charge:Alif 1606 1950 2294 2294 2294 2294 2294 2294 2294 2294 2294 2294|lported Heavy 530 643 757 757 757 757 757 757 757 757 757 757

Capacity Utilization: 70X 85K 100X 100K 100X 100X 100K 100 100 100K 100 100

Prem.GasoLine 45 54 64 64 64 64 64 64 64 64 64 64Reg.Gasoline 848 1029 1211 1211 1211 1211 1211 1211 1211 1211 1211 1211Domestic Kero 122 148 175 182 189 197 294 211 218 226 233 241Jet Fuel 14 17 20 13 6 -2 9 -16 -23 -31 -38 -46Diesel 550 668 786 786 786 786 786 786 786 786 786 786FuelOil (3.5O) 216 262 308 308 308 308 308 308 308 308 308 308LPG 70 85 100 100 100 100 100 100 100 100 100 100Bitumen 70 85 100 100 100 100 100 100 100 100 100 100

Total Products 1935 2349 2764 2764 2764 2764 2764 2764 2764 2764 2764 2764

CRUDE SLATE #2

('000 tons/yr)1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Total Crude Charge:Arab Light 1700 2065 2429 2429 2429 2429 2429 2429 2429 2429 2429 2429Condensate 438 531 625 625 625 625 625 625 625 625 625 625

Capacity Utilization: 70K 85K IOOX lK lOOK 100X 1OOK 100K 100X 100K 100l 100l

Prem.GasolIne 45 54 64 64 64 64 64 64 64 64 64 64Reg.Gasoline 904 1097 1291 1291 1291 1291 1291 1291 1291 1291 1291 1291Domestic Kero 42 51 60 60 59 58 57 56 55 54 53 52Jet Fuel 95 115 135 135 136 137 138 139 140 141 142 143Diesel 550 668 786 786 786 786 786 786 786 786 786 786Fuel Oil (3.52S) 228 277 326 326 326 326 326 326 326 326 326 326LPG 0 0 0 0 0 0 0 0 0 0 0 0Bitumen 70 85 100 100 100 100 100 100 100 100 100 100

Total Products 1933 2348 2762 2762 2762 2762 2762 2762 2762 2762 2762 2762

CRUDE SLATE #3

(' 000 tons/yr)1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Total Crude Charge:Alif 1606 1950 2294 2294 2294 2294 2294 2294 2294 2294 2294 2294Imported Heavy 530 643 757 757 757 757 757 757 757 757 757 757

Capacity Utilization: 70K 85K lOOK 10OX 100 100 100: 1002 100K 100K 100 100l

Prem.Gasoline 45 54 64 64 64 64 64 64 64 64 64 64Reg.Gasoline 904 1097 1291 1291 1291 1291 1291 1291 1291 1291 1291 1291Domestic Kero 0 0 0 0 0 0 0 0 0 0 0 0Jet Fuel 137 166 195 195 195 195 195 195 195 195 195 195Diesel 550 668 786 786 786 786 786 786 786 786 786 786Fuwl Oit (3.52S) 228 277 326 326 326 326 326 326 326 326 326 326LPG 0 0 0 0 0 0 0 0 0 0 0 0Bitumen 70 85 100 100 100 100 100 100 100 100 100 100

Total Prodchts 1934 2348 2762 2762 2762 2762 2762 2762 2762 2762 2762 2762

Jan-90

- 82 - Attachment 2 to Annex III-7Page 6 of 6

YAR - ENERGY STRATEGY REVIEW

Cost-Benefit Strem for Economic Rate of Return

(miltions of US$ in constant end 198 term)

Production Costs Sales

Capital Working Crude Other NetYear Costs Capital Domest. Iwport. Variable Fixed Domest Exports Benefits BANK ESTIMATE - BASE CASE

1990 34.1 (34.1)1991 102.3 (102.3)1992 136.4 (136.4) Economic Rate of Return: 3.2%1993 51.2 (51.2)1994 17.1 6.0 206.9 51.7 2.7 16.7 243.2 51.4 -6.5 Net Present Value1995 256.5 61.6 3.8 16.7 263.2 88.4 13.0 S 12X Discount Rate: (131.6)1996 315.8 75.8 4.5 16.7 293.0 137.7 17.91997 330.4 79.3 4.5 16.7 293.0 157.4 19.41998 345.8 83.0 4.5 16.7 322.5 150.8 23.31999 361.9 86.9 4.5 13.5 355.7 141.8 30.62000 378.8 91.7 4.5 13.5 482.2 48.4 42.02001 396.5 96.0 4.5 13.5 522.2 34.2 46.02002 415.0 100.4 4.5 13.5 553.4 29.3 49.42003 434.3 105.1 4.5 13.5 582.6 27.5 52.72004 454.7 110.0 4.5 13.5 613.6 25.2 56.22005 (34.1) (6.0) 476.0 115.9 4.5 13.5 649.3 22.5 102.0

Production Costs Sales

Capital Working Crude Other NetYear Costs Capital Domest. Import. Variable Fixed Domest Exports Benefits BANK ESTIMATE REFNIS Vl

-- -- - - - - -- - - - - - - - - - - - -- - - - - - - - - - -- - - - ------ = = s= = = = =_ = = =

1990 34.1 (34.1)1991 102.3 (102.3)1992 136.4 (136.4) Economic Rate of Return: 13.3%1993 51.2 (51.2)1994 17.1 6.0 206.9 51.7 2.7 16.7 251.2 44.4 (5.4) Net Present Value1995 256.5 61.6 3.8 16.7 272.2 79.9 13.5 a 12% Discount Rate: 26.41996 315.8 74.8 4.5 16.7 322.4 145.9 56.51997 330.4 78.3 4.5 16.7 344.4 146.9 61.41998 345.8 81.9 4.5 16.7 372.0 143.8 66.81999 361.9 85.8 4.5 13.5 404.9 136.6 75.92000 378.8 93.8 4.5 13.5 557.6 40.1 107.02001 396.5 98.0 4.5 13.5 600.2 25.3 113.12002 415.0 102.4 4.5 13.5 632.4 21.6 118.72003 434.3 107.0 4.5 13.5 661.9 21.7 124.32004 454.7 111.8 4.5 13.5 693.0 21.8 130.32005 (34.1) (6.0) 476.0 117.6 4.5 13.5 728.4 21.8 178.7

Production Costs

Capital Working Crude Other Revenues NetYear Costs Capital Domest. Import. Variable Fixed Benefits UOP ESTIMATE

1990 34.4 (34.4)1991 103.2 (103.2)1992 137.6 (137.6) Economic Rate of Return: 12.4%1993 51.6 6.0 (57.6)1994 17.2 277.6 66.1 2.7 16.7 400.4 20.1 Net Present Value1995 358.6 84.0 3.8 16.7 506.2 43.1 a 12% Discount Rate: 7.01996 437.3 102.4 4.5 16.7 611.5 50.61997 453.4 106.2 4.5 16.7 636.9 56.21998 470.1 110.1 4.5 16.7 663.4 62.01999 487.5 114.1 L.5 :3.5 691.0 71.42000 514.8 112.0 4.5 13.5 732.9 88.12001 530.4 116.2 4.5 13.5 754.1 89.42002 546.6 119.8 4.5 13.5 776.9 92.42003 563.4 123.5 4.5 13.5 800.4 95.62004 580.6 127.3 4.5 13.5 824.8 98.82005 (34.4) (6.0) 605.4 126.4 4.5 13.5 852.4 143.0 Jsn-90

YEMEN ARAB REPUBLICENERGY STRATEGY REVIEW

YGEC - POWER SALES PROJECTIONS

YR 1987 1/ 1988 1/ 1989 1990 1995 2000Average _Price YR YR YR YR YR YR

Per KWH GWH Millions GWH Millions GWH Millions GWH Millions GWH Millions GWH Millions

Households 1.10 183 208.6 217 247.0 238 261.8 273 300.3 402 442.0 538 592.0Commercial (100 KW 1.10 55 62.1 57 64.4 63 69.3 68 74.8 91 100.0 120 132.0Commercial >100 KW 1.10 45 49.5 50 55.0 56 61.1 65 71.5 124 136.0 165 182.0Industrial (100 KW 1.10 38 42.5 43 48.1 49 53.3 50 55.0 74 81.0 99 109.0Industrial )100 KW 1.10 20 22.0 22 24.2 26 28.6 29 31.9 44 48.0 59 65.0Industrial (100 KW 0.65 30 19.5 60 39.0 77 50.5 117 76.0 228 148.0 305 198.0Amran Cement 0.60 - - - - 30 18.0 70 42.0 85 51.0 140 84.0Bajil Cement 0.60 - - - - 40 24.0 50 30.0 105 63.0 140 84.0Al Barh Cement 0.60 - - - - 35 21.0 140 84.0Yemani - Hodeidah 0.65 - - - - - - 20 13.0 40 - 40NAB/8isc. Taiz 0.65 - - - - - 22 14.3 60 88.4 60 88.4Red Sea Flour, Hod. 0.65 - - - - - 36 23.4 36 36 1Hotels (100 KW 1.10 5 4.9 3 3.3 3 3.8 4 3.8 6 6.6 8 8.8 wHotels 100 KW 0.65 4 2.6 12 7.8 12 7.8 12 8.4 18 12.0 22 14.0 wMilitary 1.10 21 23.1 24 26.4 26 28.6 28 30.8 32 35.0 38 42.0 1Mosques 1.10 1 1.6 2 1.7 2 1.9 2 2.0 2 2 4 2.7 3.0Water (NWSA) 1.10 17 18.7 20 22.0 21 23.1 22 24.2 27 30.0 32 35.0Agriculture 0.75 15 11.3 18 13.5 20 15.0 22 16.5 28 21.0 33 25 0Street Lighting 1.10 16 18.2 17 19.4 18 19.8 19 20.9 23 25.0 29 31 o

TOTAL 450 484.6 545 571.8 641 666.6 909 838 8 1,460 1,310.4 2,007 1777 2e _- == - = = _=

1/ Actual

EM3IEJM

YEMEN ARAB-REPUBLICENERGY STRATEGY REVIEW

YGEC - SYSTEM OPERATING DATA PROJECTIONS

OIL OPTION

1988 I/ 1989 1990 1994 1995 200 200

L Units Sold (GWh)Interconnected System 506 642 870 1296 1445 1977 2608Isolated Systems 39 39 39 36 35 30 30

Toal iflW In 18

1I Units Sent OtlILgWblInterconnected System 674 856 1145 1620 1784 2326 3033Isolated Systems SO SO SO 46 45 38 38

QALa1 ili 9i0 15b I ' j364 3071

III Units Generated (GWh.Interconnected System 752 950 1270 1794 1967 2544 3294Isolated Systems 59 59 59 54 53 4C 45

IV Maximum Demand tMW)Interconnected System 143 181 224 32T 352 475 595Isolated Systems 17 17 17 1S 15 12 12

TLal 160 1 7 la 3 4Q bo

V Installed Capacity ._M9ja) Interconnected System

-Thermal 310 310 310 350 390 550 730-Diesel 62 62 80 80 80 40 -

Subtotal 372 372 390 430 470 590 730

b) Isolated Systems 26 26 26 23 23 18 18

Total 646 0 83 2AI

VI fuel Consumed by Tvoe

-Fuel Oil (mt) 210,033 264,373 353,559 520,917 568,246 720.118 920,010-Diesel Oil (mt) 22,824 25,502 28,516 27,129 '3.150 19.073 13.756

1/ ActualKS/yhEM3IE I

I

IEMEN ARAB _REPUBLIENERGrYSTRAjEQY REVjL.,

YGEC - SYSTEM OPERATING DATA PROJECTIONS

GAS OPTION

1988 I/ 1989M 1990 1994 _J1as 2000 2005

I Units S Id (GWh)Interconnected System 506 642 870 1296 1445 1977 2608Isolated Systems 39 39 39 36 35 30 30

!TQ$ 5i5 6 209 1332 1480 2Q7 2618

II Units Sent Out IGWhIInterconnected System 674 856 1145 1620 1784 2326 3033Isolated Systems 50 50 50 46 45 38 38

Total 724 9 06 1 J5 18 2 9 2364 3071

1l Units_Ge3rAted-AGwh)Interconnected System 752 950 1270 1795 1952 248S l'q2Isolated Systems 59 59 59 54 53 "5 45

law flU 1009 1329 1849 ZMfl AlQ U37

Ia Maximum Demand tMW)Interconnected System 143 181 224 321 350 46" 588Isolated Systems 17 '7 17 15 15 '2 '2

IgLai 160 98 21 336 2 4976 9o0

V Installed Capacity (MW)(a) Interconnected System

Thermal 310 310 310 310 310 310 310Combined Cycle/CombustTurbine - - 30 30 240 438Diesel 62 62 so 80 8D 30

Subtotal 372 372 390 420 420 580 748

(b). Isolated Systems 26 26 26 23 23 18 18

Inlai 3gs 398 416 443 4A3 S9 7

VI Fuel CLonsumed by TvDeA. No Gas Firing for Ras Khaterc,b

-Fuel Oil (t) 210.033 264,373 353,559 496,314 480,478 403,494 359,400-Diesel Oil (t) 22.824 25,502 28 516 26.346 22,297 17,981 12.515Natural Gas (MMCFT ) - 464 2,977 9.536 16,750

b. With Gas FirinQ for Ras Khatenib from 1994Fuel Oil (t) 210,033 264,373 353,559 235.706 210,883 133,899 93,000 m

-Diesel Oil (t) 22,824 25,502 28,516 26,346 22,297 17,981 12,515-Natural Gas (MMCFT) 11,966 14,866 21,425 2e,480

C. With Gas Firing for Ras Khatenib from 1997Fuel Oil (t) 210,033 2b4,373 353,559 19b.314 480,478 133.899 93,000Oiesel Oil (tJ 22,824 25,502 28,516 26,346 22,297 17,981 12,515-Natural Gas )MMCFT) 464 2.977 21 425 2f,.480

1/ ALtualKS/yhEM3IE

- 86 - Annex IV-4

Yemen Arab ReputlieEnergy_Strategy Rev>-w

YGEC Investment Ptojections 1989 - 2000('000US - -)

Local Foreign Total

I Generation - Gas Option 17,676 159,665 177,341

Oil Uption 21,853 197,255 219,111

II Transmission 33,150 125,673 158,823

III Distribution 33,769 186,545 220,314

IV Normal Development 24,000 81,000 105,000(incl. system improvement)

Total - Gab Option 108,595 552,883 661,478Total - Oil Option 112,,72 5902496 703,248

Annex IV-5- 87- Page I of 4

YAR Energy Strategy Review

YGEC Financial Projections

The attached projections are based on the following importantassumptions:

(a) Fuel Oil Prices are based on crude oil estimates of US$15/bbl in1989 gradually increasing to US$24/bbl in 1999/2000. Theseprices translate to prices of YR800/ton (includingtransportation costs) in 1989 and YR1,400/ton in 1999/2000.Diesel oil prices to YGEC have been assumed to remain at thecurrent level of YR2,317/ton throughout the period since thisprice would still be higher than the internationial price in 2000.

(b) Timely Connection of Major Industrial Consumers. The share ofelectricity consumption by industrial consumers is expected toincrease substantially from 23Z in 1988 to 51% in 2000 largelyas a result of expected new consumers and expansion of theirproduction facilities. Major industrial consumers, Amran andBajil Cement plants are expected to be connected on May I andApril 1, 1989 respectively. To the extent that industridlconsumers are not connected at the projected rate salesforecasts would not be achieved, Section III (Attachment 4).

(c) YGEC would take measures to reduce system losses by about 1 p.a.

(d) Existing electricity tariffs would not be charged.

-88 - Annex IV-5

Page 2 of 4

YEMEN ARAB REPUBLIC

YEMEN rENERAL ELECTRICIT' CORPORATICN

!St!wArE- 4eu _DnTETEZ ttnm '.raur eoc -

Estaaatf…----------------------------------------------…---Projt--------------------------------------------SCEIMIO I 1998 MOw 1:99e 1991 1992 I199 1994 IQ95 19§6 1999 iccq °° iOO

No. of Coasers ICOOsi 271 316 '58 386 4: 444 466 49) 513 54' Se? 56ross 6eneration (61M) 9Ell 1,009 :.29 1,549 1,672 i,7' 1,949 2,005 2.109 2.251 2,'7 2 4 2Energy Sent Out (6lIMI 724 906 1,195 1,392 1,504 1,595 1,666 1,829 1,93r 2,070 2.17: : Z,364

Energy Solod IUI 545 682 910 1,074 1.191 1,2:6 I.332 1.460 1,598 1.716 1,8.:2 :.71 2., Line Loses 2 24.? 24.7 :3.8 22.8 21.5 :1.0 20.0 0.2 1s., 17.1 16.1 1'.1 :.

…-___-_-_- _ _---- - ------- - ----------------- -R Nillion…-----------…-------------------Operating Incone

Electricity S.l.s 5e6 667 8?9 9?9 1,072 1.149 1,214 1,311 1,41: 1,517 1,609 1,711 1Service Charges 76 94 9! 105 11; 120 ;15 131 138 144 15; i59 16-Capacity C6argsn ° 12 1? 19 :5 27 29 52 '5 .7 AO 4? 46Other lnctn 13 14 15 17 la 20 22 24 27 28 31 33 ':

TOTAL IhNCW 661 777 966 1,119 1,226 1,316 1,390 1,499 1,613 1,726 1,9.1 1.946 2,024

Owatia Espne

Ful 212 280 393 474 533 59 653 731 806 986 969 1,038 1,071Salaries and Alle cen 200 220 .24 266 292 327 A60 396 443 487 536 590 649Mauntenance, materials, etc. 58 B2 92 100 110 120 132 145 160 176 193 213 234Oeprecisti±n 130 161 209 220 316 374 4*9 497 542 620 O6 745 835

TOTAL OPERATINI EXPENSES 600 743 935 1,060 1,251 1,U40 1,584 1,769 1,971 2,169 2,394 2,586 2,789

Surplus/lDeficit) Before Interest 61 34 'I 59 (25) !(t' '194) (271) (3581 (443) 1553) (640) (7t5Internt 116 111 101 92 79 65 95 104 1"0 125 130 135 14JSurplusl(Deficit) After Interst (55) (77) (70) (33) (1031 (158J (299) (375) (4789 (568) 1693) (775! 105)Required Surplus Befre Interet - 111 133 m 2 531 445 507 565 620 673 724 786 8ICRevenue Shortfall - 76 102 233 406 539 701 936 979 1,116 1,277 1.426 1.6164Airagre Net Revalued Assets - ',717 4,439 5,931 7,613 8,906 10,134 11.300 12,402 1,,460 14,470 15,?29 17,061Actual Rate of Return (2) - 0.9 0. 1.0 (0.3) (1.01 (1.9) (2.4) (2.9! (3.2' !3.9 '4.1) ;4'.5Target Rate of Rturn 3 - 5 5 5 5 5 5 5 5 5 5Required Average Tariff Increase (2! - 10.6 - 10.4 11.2 6.7 1,7 '.2 '-0 2.3 ' .8 2.4 4.1

FILENAME: YECISI

- 89 - Annex IV-5Page 3 of 4

YEMEN ARAB REPUBLIC

YEMEN GENERAL ELECTRICITY CORPORATION

ESTIMATED AND PROJECTED IhCOhE STATEMENTS (YEARS IeS9 - 2000'

Estieate- ___- --__…---------- --…-…------------… -roJ-ctet----… - … ------ …

SCEIIC 11 I9 1989 1990 I9! 192 1993 1'04 19°5 1990 19? !99 1990 7mr.. . .. .

No. of Conmers IOOOs) 273 319 ,59 396 422 444 466 490 51 s40 5s0 i°Gros 60neration (6N) 911 1,009 1,329 9.f1SE 1,672 1,'!3 1,349 2.005 2,109 2,25; 2,339 2,434 :.53^Energy Srnt Out (6H) 724 906 1,195 1,392 1.504 1.595 1,6 1,29 1.939 2,070 2,172 ,274 .,364Energy Sold 19M1 545 692 910 1,074 1.191 1.2b0 1,332 1,460 1.587 1,71o 1,92: 1.;9! 2,f!"7Line Losses t 24.7 24.7 23.9 22.3 :1.S 21.0 20.0 20.2 19.! 1 I,.! .! !.1 15.!

…______________________-…________________---… ------- -Y - - -ilions-----------------------------------

Operating Inem.

Electricity Sales 563 667 639 970 1,072 ;.149 1,214 .,V11 1,413 1,51? 1.609 1,711 1:.'7Strvice Charges 76 94 95 105 it. 120 125 131 139 144 151 !9 167Capacity Charge 9 12 17 IS 25 27 29 32 S5 ;7 40 43 *eOther lnto 13 14 15 17 19 20 22 24 27 2t 31 33 34

TOTAL INCOIE 661 777 966 1,119 1,226 1,316 1,390 1,499 1,613 1,726 1,931 1,9te 2,024

Operating Espenss

Ful 212 280 393 474 533 5"8 646 641 634 701 6b4 645 672Salaries and Alloancn 2C0 220 242 266 292 327 360 396 443 487 536 590Mointenance, MIterials, etc. 59 92 92 1O 110 120 132 143 160 176 193 213DeprKiaton 3O 161 209 220 316 374 439 434 55t 616 669 749 914

TOTAL OPERATING EXIPSES 600 743 935 1,060 1,251 1,409 1,557 1,66 1,796 1,990 2,062 2,197 2.369

Surplusi(Deticit) beore Interest 61 34 31 59 (25) 93) (167) (168) 1193) (254) 231) (212; i3451Interest 116 111 101 92 79 65 95 104 110 110 120 125 129Surplus/lDeficitl After Interest (55) (77) (70) (33) (103) (15) (262) (2172! (293) (364) (351) (376) (4731Reuired Surplus Befre Interest - 111 133 292 391 445 503 55q 616 660 71e 7' 927Revenut Shortfall - 76 102 233 406 539 670 727 799 914 94! 1,029 1.170Average Net Revalued Assets - .,717 4,439 5,831 7,613 3,906 10,056 11,179 12,312 13.196 14,327 15,54 l.531Actual Rate of %eturn (1) - 0.9 0.7 1.0 (O.;) (1.0) (1.7) (1.5) (1.5) (1.7) (1.6) (1.6) (2.11Target Rate of Return tl(l -3 5 5 5 5 5 5 5Required Average Tariff Ircren;e 1tI 10.6 - 10.4 11.2 6.' 5.0 - - 1.9 - O e .5

FILENE: YGECIS2

- 90 - Annex IV-5Page 4 of 4

YENE MAUD RIflLIC.. _- ----------.

YEIIM SaEmUL ELECTRICITy CORPORATION

ESTIMATED AN P*OJECTE0 IICOHE STATEMENTS (TEAlS 1999 - 2000)

Estiut ---------------- -- --------*------_-------- ------te-------------------------

SCEImIII III 1m I9 19O 1"91 12 1993 1994 I15 196 1"7 1999 i99 "0C

ll. ot Crnsa lh000l 273 319 35 3166 422 444 466 490 513 0 567 595Gross S"eratim liIINI #11 1,009 1,329 1,548 1,672 1,773 1,849 2,005 2.108 2,251 2,339 2,434 2,530Energy Sot Ot (SUI 724 906 1,195 1,392 1,504 1,595 1,646 1,929 1,91 2,070 2,172 2,274 2. 44Energy Sold (611) 545 692 910 1,074 1,161 1.260 1,32 1,460 1,597 1,716 1,922 :,931 ,,00?LiUn Losss 2 24.7 24.7 23.9 22.9 21.5 21.0 20.0 20.2 184. 17.1 16.1 15.1 1!.1

------------------------- _ -,- _--_-------rR ft±IIions--------- --0eraating lnco

Electricity Sales 563 667 839 979 1,072 1,149 1,214 1,311 1,413 1,517 1,609 1,711 1,"7Service Chargn 76 94 95 105 111 120 125 131 139 144 151 159 16lCawcity Chargs 9 12 17 I 25 27 29 32 35 37 40 43 4bote lnci IS 14 15 17 19 20 22 24 2 29 31 33 34

TOTAL INIWME 661 m 966 1,119 1,226 1,316 1,3S9 1,498 1,613 1,726 1,931 1,946 :,024

Fel 212 290 393 474 533 5" 626 641 634 414 361 325 353Wlarin ad Olluaen 200 22 242 266 m 327 360 396 443 487 536 590 649.fawtaae, Materials, etc. 6 9 92 92 100 110 120 132 145 160 176 - 193 213 274krcaitim 130 161 206 220 316 374 439 484 559 616 670 750 915

TOTAL rAtIU EPEIS 6C0 743 935 1,060 1,251 1,409 1,557 1,466 1,796 1,693 1,760 1,979 2,051

Surplusl(keciti efore Interest 61 34 31 59 (251 (93) (167) (1681 (103 33 71 66 I 7(Intrst 116 111 101 92 79 65 95 104 110 110 120 125 129Surplus(kticit3 After Interet (553 (17) (70) (331 (103) 1150) 1262) (272 (2M) (771 1491 1571 (1553Revired Surplus Bfore Interest - 11 133 m 391 445 503 559 616 660 '71 778 827Re"Ue Shortfall - 76 102 233 406 53 670 727 ?99 627 646 710 852Awage et Revolued Aisets - 3,717 4,439 5,831 7,613 6,906 10,056 11,179 12,312 13,203 14,341 15,559 16,54?Actul Rate of Return 171 - 0.9 0.7 1.0 (0.3) (1.01 (1.7) (1.5) (1.5) 0.4 0.5 0.4 10.^!

target Rate of Return(11 - 3( 5 5 5 5 5 5 5 S 5Required Average Tariff Increase (1) - 10.6 - 10.4 11.2 6.7 5.9 - - - - - -

FILEMNAE: YSECIS3

- 91 - ANNEX V-1

YAR Energy Strat3gy ReviewLPG Project Components and Cost Estimates

(in UsS '000)

Additional compression equipment (Safer) 1,000Storage and Truck Loading (Safer) 9,976Sava'a Bottling Plant 17,000Infrastructure 1,680Unloading facilities (Hodeidah) 1,300Trucks and semi-trailers: 30 5,380Land 1,000Site survey/soil investigation 110Bottles 350,000 8,400Spares 410Training/Initial Operations 1,100Overall Project Management 2,530

49,886

Source: Fluor Daniel N.V. and MOMR

MS/yh

EMTIE

- 92 - Annex VI-1Page i of 6

YAR - Energy Strategy Review

ECONOMIC ANALYSIS OF ALTERNATIVES FOR GAS UTILIZATION

Assumptions

1. OPTION I

Economic Costs

(a) Pipeline Capital Costs. Ca2ital costs of the pipeline was based onconsultant's estimate. The sizes and costs assessed for the pipelines are onthe basis of capacities required to provide gas from the gas fields at Maribto Sana'a to Amran, as follows:

US$ MillionPipeline (1993-1994) 1988 Prices

124 km and 22" and 100 km 20" from Maribto Mabar, 80 km 18" from Mabar to Sana'aand 60 km 8" from Sana'a to Amran 161.4

Compressors (2010-2013) 35.1

(b) Conversion of Amran Cement. Conversion of kilnburners for gas firing 0.4

(c) Operation and Maintenance of Pipeline. Annualfixed 0 and M costs estimated at 1.5% ,f the pipeline cost 2.4

(d) Compressors fuel cost. Annual cost 2012through 2013 0.1

Economic Benefits

(a) Fuel oil equivalent. The incremental quantities of fuel oil thatwould be substituted by gas in the Amran cement plant and the estimated gasconsumption of the proposed new power plant in the Sana'a area. The price offuel oil shown below, has been computed on the basis of World Bank projectionsof the international price of crude oil through the year 2000. A real increaseof 4.81 per annum in international oil price was assumed after 2000. Priceswere converted to December 1988 pric s.

- 93 - Annex VI-iPage 2 of 6

Proiected Prices(US$/ton)

1990 1995 2000 2005 2013

Crude 117 126 159 207 296Product Ratios .73 .73 .73 .73 .73Freight 4 4 5 6 7Fuel Oil 90 96 121 153 223

(b) Investment Differential. DifferEnce in capital costs. betweenoil-based and gas-based power gereration over the period 1993-2013.

(c) Fuel Efficiency. Reflects the savings in fuel on account of thegreater efficiency of the combined-cycle plant over the fuel-based steam powergeneration.

2. OPTION 2

Economic Costs

(a) Pipeline Capital Costs. The sizes and costs assessed by theconsultants under this alternative are on the basis of capacities required todeliver gas to the Ras Khatenib steam power station and the Bajil cementplant, in addition to the Sana'a-Amran extension, as follows:

US$ MillionPipeline (1993-1994) 1988 Prices

224 km 22" from Marib to Mabar and Sana'a60 km 8" from Sana'a to Amran and288 km 16" from Mabar to Bajil and Ras Khatenib 256.04

Compressors (2010-2013)

(b) Conversion of Amran and Bajil cement plants andRas Khatenib power si ;ion 1.80

(c) Operation and Maintenance. Annual 0 and M costsestimated at 1.5% of pipeline cost 3.83

(d) Compressors fuel cost. Annual cost 2012through 2013 0.30

Economic Benefits

Benefits were measured as in Option I with the addition of fuelsubstitution in the Bajil cement plant and the Ras Khatenib power station.

- 94 - Annex VI-1- 94. -_____

Page 3 of 6

YEMEN - ENERGY STRATEGY REVIEW

OPTION 1 Gas Distribution PrLject

COSTS BENEFITS

6as Value atCement Operat. Cost FO Equivalent

Invest Plants Coepr. and of -- Invest. Fuel NetCosts Conv. Fuel Naint. 6as Power Cement Oiff. Effic.Benefi

1992 96.8 0.0 -96.81993 64.6 13.0 -51.61994 0.4 2.4 2.2 1.5 12.5 -6.8 0.4 2.61995 2.4 3.4 9.4 12.2 0.0 2.3 18.11996 2.4 4.2 14.9 12.8 13.0 3.7 37.81997 2.4 4.4 17.2 13.4 -4.8 4.3 21.31998 2.4 5.7 27.1 14.0 32.8 6.8 72.61999 2.4 6.5 34.3 14.7 -6.8 8.6 41.82000 2.4 6.7 37.9 15.4 -18.6 9.5 35.12001 2.4 7.3 45.0 16.2 50.4 11.3 113.22002 2.4 7.3 47.2 17.0 15.7 11.8 81 92003 2.4 8.5 59.5 17.7 -34.7 14.9 46.62004 2.4 9.6 72.8 18.5 -50.4 18.2 47.12005 2.4 10.7 88.0 19.5 0.0 22.0 116.42006 2.4 11.3 98.4 20.4 0.0 24.6 129.72007 2.4 11.3 103.3 21.4 9.9 25.8 146.72008 2.4 12.4 121.2 22.5 9.9 30.3 169.02009 2.4 13.5 141.0 23.6 9.9 35.2 193.82010 10.5 2.4 14.7 162.1 24.8 0.0 40.5 199.82011 7.0 2.4 15.3 177.6 25.9 0.0 44.4 223.22012 10.5 0.1 3.8 15.3 186.4 27.2 9.9 46.6 240.32013 7.0 0.1 3.8 16.4 211.5 28.5 9.9 52.9 275.4

Econosic Rate of Return: 24.9%Net Present Value at 12%: 275.7

ENTIENay-89

_ 95 - ANNEX VI-IPage 4 of 6

YEMEN - ENERGY STRATESY REVIEW

OPTION 2 Gas Distribution Project

COSTS 9ENEFITS

6as Value atCement Operat. Cost FO Equivalent

Invest Plants Ccepr. and of -------------Invest. Fuel NstCosts Conv. Fuel Naint. 6as Power Cement Diff. Effic. Benefit

1992 153.6 0.0 -153.61993 102.4 13.0 -89.41994 1.8 3.8 8.5 38.6 15.9 -6.8 9.7 43.31995 3.8 9.9 46.9 15.6 0.0 11.7 60.41996 3.8 11.4 53.9 20.9 13.0 13.5 86.11997 3.8 11.6 58.2 21.9 -6.8 14.6 72.51998 3.8 13.1 70.1 24.2 32.8 17.5 127.81999 3.8 14.2 79.2 26.0 -6.8 19.8 102.12000 3.8 14.4 85.1 29.5 -18.6 21.3 99.02001 3.8 15.7 100.1 30.9 50.4 25.0 186.92002 3.8 16.1 109.3 32.4 15.7 27.1 163.52003 3.8 16.6 117.6 33.9 -34.7 29.4 125.82004 3.8 17.6 132.0 35.3 -50.4 33.0 128.52005 3.8 17.9 141.2 36.8 0.0 35.3 191.52006 3.8 17.9 149.7 39.0 0.0 37.4 2C4.32007 3.8 17.9 157.1 40.9 9.9 39.3 225.52008 3.8 17.9 164.6 42.9 9.9 41.2 236.82009 3.8 17.9 173.0 45.1 9.9 43.3 249.52010 3.8 17.9 181.5 47.3 0.0 45.4 252.32011 10.8 3.8 17.9 189.9 49.4 0.0 47.5 254.22012 7 0.3 3.8 17.9 199.2 51.9 9.9 49.8 281.52013 7.2 0.3 3.8 17.9 208.6 54.3 9.9 52.1 295.7

Economic Rate of Return: 30.5.Net Present Value at 12%: 536.4

ENTIEfay-89

OPTION I YENEN - ENERGY STRATEGY REVIEW=~~~~~~~~~~~~~~~~~~~~~~--- -- :J-- - --No Gas for Rlas Xatenib Gas Distribitian Project

Project StArt-up~ 1994 ------------Load Growth forecast (NW) 1994 1995 1996 1997 199 1999 2000 2001 2002 2d103 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Intercrwoete Systm321 352 363 412 436 4.56 475 494 513 532 551 595 431 669 709 751 796 844 89 948IsnttedoSystmdysin15 15 14 14 13 13 12 12 12 12 12 12 - - - - - -

Gwwratiris C.36 37 9742644p49 47 06525 544 563 607 631 669 709 751 796 844 89 948-Eistins: Therom NW 310 310 310 310 310 310 310 310 310 310 310 310 310 310 310 310 310 310 310 310-NeW: Thermalt - - - - - - - - - - - - - -

Codblned Cycle 30 90 90 120 180 180 240 27 270 326 382 438 468 468 524 580 636 646 666 722Diesel 80 80 80 80 80 60 40 30 20 - - - - --

ToUta Interconneced 40 80 80510 570 550 590 610 600 636 692 748 778 77 8 34 890 946 976 976 1032Totatlsotated 23 23 21 21 20 20 18 18 18 18 18 18 18 18 18 18 18 18 18 18INKMSTUTS - Powe Stations 39.6 - 19.8 39.6 - 39.6 18.6 - 34.7 34.7 34.7 - 34.7 34.7 34.7 - 34.7 34.7

-Cemr0E03t MM0.46 2.98 4.54 5.00 7.51 9.07 9.54 10.80 10.80 13.04 1S.28 17.52 18.7 18.72 20.96 23.:0 25: " f 2t:88 385-Cement ~~~~~3.88 3.88 3.883 3.88 3.88 3.88 3.88 33.88.88 3.881 3.88 3.88 3.88 3.88 3.88 38 :03138 .Total 4.3 668.42 8.88 11.40 12.96 13.42 14.68 14.68 16.92 19.16 21.40 22.60 22.60 24.84 27.0 29.32 30.52 30.52 32.76

Fuel Casit Using Gas US$1 0.50 ICF (in US$ sillion)-Power 0.23 1.49 2.27 2.SO 3.76 4.54 4.77 5.40 5.40 6.52 7.64 8.76 9.36 9.36 10.48 11.60 12.72 132 13.32 14.44-Cemet 1.94 1.94 1.94 1.94 1.94 1.94 1.94 1.94 1.94 1.94 1.94 1.94 1.94 1.94 1.94 1.94 1.94 1.9 1.94 1.94

Gas Into Fuel Oil Equiv.8 0.96 (in $000 NT)-Power 12.6 80.9 123.3 135.9 204.2 246.6 259.2 2M.6 29.6 354.5 415.4 476.3 508.9 508.9 569.8 630.7 691.6 724.2 72.2 75.1-cement 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6fuelfactor 1.0 Cin 115/tan)Price of Fuel Oft C CIF Nodeldah) 98. 96 .0 100.0 105.0 110.0 '15.0 121.0 127.0 133.0 139.0 145.0 153.0 160.0 168.0 176.0 185.0 194.0 203.0 213.0 223.0LocaL Freight Nadeidmh/Pm-a 20.4 20.0 20.8 21.9 22.9 23.9 25.2 26.4 27.7 289 30.2 31.8 33.3 35.0 36.6 38.5 40.4 42.3 44.3 46.4Cost of Delivered Fuel 1181.4 116.0 120.8 126.9 132.9 138.9 146.2 153.4 160.7 167.9 175.2 184.8 193.3 203.u 212.6 223.5 234.4 245.3 257.3 269.4Gas Cast 8 Fuel O1Il Equi valent Cin..US$ miltion)-Power 1.5 .4 1.9 17.2 27.1 34.3 37.9 45.0 47.2 59.5 72.8 88.0 98.4 103.3 121.2 141.0 162.1 177.6 186.4 211.5-Cement 12.5 12.2 12.8 13.4 14.0 14.7 15.4 16.2 17.0 17.7 18.5 19.5 20.4 21.4 22.5 23.6 24.5 25.9 27.2 28.5

PROJECT CONIC COSTS.- 1992 199 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013.-- - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - - - - - - - - - - - - - - - - - - - - - - - -Gas Project lo-westment Cost (in 1988 USS million)-Pipeline 1.162 96.8 64.6 - - - . . . - . . . - . . - . 10.5 7.0 10.5 7.0Ceiwnt Ptwit Conversion 0.4

-Comprebrsm FueL Cast . - . . - . - . - . 0.0 0.0 0.1 0.1-0 1 N 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 3.8 3.8-Cost of Gas US5$ 0.50 - 2.2 3.4 4.2 4.4 5.7 6.5 6.7 7.3 7.3 8.5 9.6 10.7 11.3 11.3 12.4 13.5 14.7 15.3 15.3 16.4

Total Casts 968 6.6 5.0 5.8 6.6 6.9 8.1 6.9 9.1 98 9.8 10.9 12.0 13.1 13.7 13.7 14.8 16.0 27.6 2'.? 29.7 27.3 .PROJECT ErCONONIC ENEFITS

GasValer S ulOlE1.5 9.4 14.9 17.2 27.1 34.3 37.9 45.0 47.2 59.5 72.8 88.0 98.4 103.3 121.2 141.0 162.1 177.6 186.4 211.5 x-Cement ~~~~~~~~12.5 12.2 12.8 13.4 14.0 14.7 15.4 16.2 17.0 17.7 18.5 19.5 20.4 21.4 22.5 23.6 24.8 25.9 27.2 28.5

Power Ptmnts CGas vs Oil)-Investment Differentialt 13.0 -6.8 0.0 13.0 -6.8 32.8 -6.8 -18.6 50.4 15.7 -34.7 -50.4 0.0 0.0 9.9 9.9 9.9 0.0 0.0 9.9 9.9 -Incre.edEfficiency 25.0% - 0.4 2.3 3.7 4.3 6.8 8.6 9.5 11.3 11.8 14.9 16.2 22.0 24.6 25.8 30.3 35.2 40.5 44.4 46.6 52.9 ~

Total Beniefits 0.0 13.0 7.6 240 4.4 28.1 80.8 50.7 44.2 122.9 91.6 57.4 59.1 129.6 143.4 160.5 183.8 209.7 227.4 247.9 270.0 302.8Not Bciefits -96.8 -51.6 2.6 18.1 37.8 21.3 72.6 41.8 35.1 113.2 81.9 46.6 47.1 116.4 129.7 146.7 169.0 193.8 199.8 22.2 240.3 275.4

OPTION I EROR 24.9k 20-year aperation (1994-2013)=== NPV 8 12% 275.7

OPTION 2 YEMEN - ENERGY STRATEGY REVIEWGas for las Katenib in 1994 Gas Distribution ProjectProject Start-up 1994 ........................

Load Growth Forecast (NW) 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 m00l 2008 2009 2010 2011 2012 2013Interconnected System 321 352 383 412 436 456 475 494 513 532 551 595 631 669 709 751 796 844 895 948Isotated SpSts 15 15 14 14 13 13 12 12 12 12 12 12

336 367 397 426 449 469 487 ~506 525 544 563 607 631 669 709 751 796 844 895 948Generating Cpcity (NW) 30 60 0 30 60 0 60 30 0 56 56 56 0 56 56 56 0 56 56 56-Existirg: Therml 310 310 310 310 310 310 310 310 310 310 310 310 310 310 310 310 310 310 310 310-mew: Theril - - - - - - - -- - - - . . .- -Combined Cycle 30 90 90 120 180 180 240 270 270 326 382 438 436 494 550 606 606 662 71i 774Diesel 80 80 80 80 80 60 40 30 20 - - - - - - - - -

Total Intercomected 420 480 480 510 570 550 590 610 600 636 692 748 748 804 860 916 916 972 1028 1064Total Isolated 23 23 21 21 20 20 18 18 18 18 18 18 18 18 18 18 18 18 18 18INVESTNENTS - Power Stations 39.6 - 19.8 39.6 - 39.6 18.6 - 34.7 34.7 34.7 - 34.7 34.7 34.7 - - 34.7 34.7Gas Conmtion (000 UICF)-Power 0.0353 ft3/3 12.00 14.87 16.43 16.89 19.40 20.96 21.43 24.00 24.80 25.77 27.n 28.48 28.48 28.48 28.48 28.48 28.48 28.48 28.48 28.48-Cement * 4.94 4.94 6.36 6.36 6.71 7.42 7.42 7.42 7.42 7.42 7.42 7.42 7.42 7.42 7.42 7.42 7.42 7.42 7.42 7.42

TotaL 16.94 19.81 22.78 23.25 26.11 28.38 28.84 31.41 32.21 33.18 35.13 35.90 35.90 35.90 35.90 35.90 35.90 35.90 35.90 35.90Fuel Cost Using Gas US$0.50 NNCF (in U# million)-Power 6.00 7.43 8.21 8.44 9.70 10.48 10.71 12.00 12.40 12.88 13.86 14.24 14.24 14.24 14.24 14.24 14.24 14.24 14.24 14.24-Cement 2.4. 2.47 3.18 3.18 3.35 3.71 3.71 3.71 3.71 3.71 3.71 3.71 3.71 3.71 3.71 3.71 3.71 3.71 3.71 3.71Gas into Fuel Oil Equiv 0.96 (in g000 MT)Power 0.3 0 .4 0.4 O.S 0.5 0.6 0.6 0.7 0.7 0.7 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 u,-Cement 0.1 0.1 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 *fuetfactor 1.0 (in USSIton)Price of Fuel Oil (CIF Nodeid h) 98.0 96.0 100.0 105.0 110.0 115.0 121.0 127.0 133.0 139.0 145.0 151.0 160.0 168.0 176.0 185.0 194.0 203 0 213.0 2.0Local Freight Nodefdmh/A*ran 20.4 20.0 20.8 21.9 22.9 23.9 25.2 26.4 27.7 28.9 30.2 31.4 33.3 35.0 36.6 38.5 40.4 42.3 44.3 46.4Cost of Delivered Fuel 118.4 116.0 120.8 126.9 132.9 138.9 146.2 153.4 160.7 167.9 175.2 182.4 193.3 203.9 212.6 223.5 234.4 245.3 257.3 269.4Gas Cost 8 fuel Oil Equivalent (in US# million)Power 38.6 46.9 53.9 58.2 70.1 79.2 85.1 100.1 108.3 117.6 132.0 141.2 149.7 157.1 164.6 17.0 181.5 189.9 199.2 208.6-Ceent 15.9 15.6 20.9 21.9 24.2 28.0 29.5 30.9 32.4 33.9 35.3 36.8 39.0 40.9 42.9 45.1 47.3 49.4 51.9 54.3PROJECT ECONONIC COSTS 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013Gas Project Investment Cost (in 1988 USS million)-Pipeline 1.16 153.62 102.42 - - - - - - - - - - - - - - 10.8 7.18 7.18-Cement *nd Power Plants Conv. 1.80-Coreusors Fuel Cost - * - - - - - - - - - - - - - - - - - 0.31 0.31-0 & N - - 3.83 3.83 3.83 3.83 3.83 3.83 3.83 3.83 3.83 3.83 3.83 3.83 3.83 3.83 3.83 3.83 3.83 3.83 3.83 3.83-Cost of Gas USS 0.50 - - 8.47 9.91 11.39 11.62 13.06 14.19 14.42 15.71 16.11 16.59 t7.57 17.95 17.95 17.95 t7.95 17.95 17.95 17.95 17.95 17.95

Total Costs 153.6 102.4 14.1 13.7 15.2 15.5 16.9 18.0 18.3 19.5 19.9 20.4 21.4 21.8 21.8 21.8 21.8 21.8 21.8 32.6 29.3 29.3PROJECT CNUIC BENEFITSGas Value 8 Fuel Oil Euivatent

-power - 38.6 46.9 53.9 58.2 70.1 79.2 85.1 100.1 108.3 117.6 132.0 141.2 149.7 157.1 164.6 173.0 181.5 189.9 199.2 20A.6-Cement - 15.9 15.6 20.9 21.9 24.2 28.0 29.5 30.9 32.4 33.9 35.3 36.8 39.0 40.9 42.9 45.1 47.3 49.4 51.9 4*.3Power Plants (Gas vs 011) 9-Investment Differential 13.0 -6.8 0.0 13.0 -6.8 32.8 -6.8 -18.6 50.4 15.7 -34.7 -50.4 0.0 0.0 9.9 9.9 9.9 0.0 0.0 9.9 9.9-Fuel Effic!ency 25X 9.7 11.7 13.5 14.6 17.5 19.8 21.3 25.0 27.1 29.4 33.0 35.3 37.4 39.3 41.2 43.3 45.4 47.5 49.8 S2.1

Total hneffits 0.0 13.0 57.4 74.2 101.3 87.9 144.7 120.2 117.3 206.4 183.5 146.2 149.9 213.3 226.0 247.2 258.5 271.3 274.1 286.8 310.8 325.0 0Net Benefits -153.6 -89.4 43.3 60.4 86.1 72.5 127.8 102.1 99.0 186.9 163.5 125.8 128.5 191.5 204.3 225.5 236.8 249.5 252.3 254.2 281.5 295.7OPTION 2 EROO 30.5X 20-year (1994-2013).- -- NPV 8 12X 536.4

MAP SECTION

YEMEN ARAB REPUBLICV S A U D I A R A B I A ENERGY STRATEGY REVIEW

Ah U DI A R A B I APETROLEUM, GAS AND POWER FACIUTIES

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