Report No. 7662-VAR Yemen Arab Republic Energy Strategy Review January 31, 1990 Industry and Energy Operations Divis;on Country Department IlIl Europe, 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 recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. CURRENCY EOUIVALENT US$1 - 9.75 Yemeni Rials (YR) C9NVERSION FACTORS TOE/Metric Specific Fuel Tonne Gravity Liters/Tonne LPG 1.06 0.56 1,785 Gasoline 1.03 0.72 1,351 Kerosene 1.01 0.80 1,240 ATF (Aviation Fuel) 1.01 0.80 1,240 Diesel/Gas Oil 1.00 5.85 1,176 Fuel 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 net calorific values are 5X less than gross for oil and 9X to 10X less than gross for gas). CONVERSION FACTORS FOR GAS Thousand Cubic Feet (mcf) - 1 Million British Thermal Units ((MMBTU) 38,500 cf - 1 t of fuel oil 0.12 mmcfd - 1 t of fuel oil/year ABBREVIATIONS bbl Barrel bpd Barrels per day cif Cost, insurance and freight ERR Econrmic rate of return ESR Energy Strategy Review fob Free-on-board GDP Gross domestic product GOY Government of the Yemen Arab Republic GUS Gas Utilization Study GVH Gigawatt hour LPG Liquified petroleum gas MEW Ministry of Electricity and Water mmcfd riillion cubic feet per day (gas) MOMR Ministry of Oil and Mineral Resources NPV Net present value PSA Production Sharing Agreement SCOMR Supreme Council for Oil and Mineral Resources stb Stock tank barrel (oil) scf Stock tank cubic foot (gas) TCF Trillion cubic feet TOE Tons of oil equivalent t Metric ton UOP/CS UOP Processes International Inc./Chemsystems YAR Yemen Arab Republic YEPC Yemen Exploration and Production Company YEPIC Yemen Exploration and Productior. Information Center YGEC Yemen General Electricity Corporation YHRC Yemen Hunt Refinery Company YHOC Yemen Hunt Oil Company YOMINCO Yemen Oil and Mineral Resources Corporation YPC 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 ........................................... 1 A. Linkages to the Economy ................................. 1 B. Energy Policy and Planning .............................. 3 C. Sectoral Institutions ................................... 4 D. Demand and Supply Overview .............................. 8 E. Pricir.g, Demand Management and Conservation .... ......... 9 F. Environment . ............................................. 11 II. HYDROCARBON RESOURCES ................... .................... 12 A. Oil Exploration ........... .............................. 12 B. Reseries and Production ................................. 14 C. Gas Resources and Availability .......................... 16 III. PETROLEUM PRODUCTS DEMAND AND SUPPLY ......... .. ............. 19 A. Demand and Supply Balances .............................. 19 B. Marib Refinery ............ .............................. 22 C. Storage Facilities .......... ............................ 23 D. Ras Issa Port and Storage Project ....................... 24 E. Second Refinery Project ................................. 25 IV. POWER DEMAND AND SUPPLY .................. ................... 27 A. Demand . ................................................. 27 B. Generation and Transmission ............................. 29 C. Future Capacity Requirements ............................ 31 U D. YGEC's Management and Financial Situation ..... .......... 34 V. LIQUIFIED PETROLEUM GAS .................. ................... 35 A. Demand ................................................... 36 B. Imports and Potential for Domestic Production .... ....... 37 C. Bottling, Transportation and Distribution .... ........... 38 D. Pricing and Institutions ................................ 40 VI. NATURAL GAS UTILIZATION .................. ................... 42 A. Potential Demand ........... ............................. 42 B. Pipeline Project .......... .............................. 43 C. Economic Evaluation ....................... ........... 45 D. Pricing ......... 46 E. Strategy ......... 49 VII. INVESTMENT OPTIONS, STRATEGY AND RECOMMENDATIONS .48 This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. Table of Contents (Continued) Page I-1 Energy Balance - 1988 ......................................... 57 1-2 Evolution in Gross and Final Energy Consumption (1988 and 2005) 58 1-3 Growth in FLnal Energy Demand (1988 and 2005) .61 1-4 Domestic Unit Prices of Petroleum Products .62 I-5 Petroleum Products - Real Price Index, Consumer Prices and Economic Cost .63 III-1 Historical Consumption of Petroleum Products (1975-88) ........ 64 III-2 Historical Consumption/Supply Balances for Petroleum Products (19R4-1988) .65 III-3 Historical Regional Consumption and Estimated Future Demand for Petroleum Products (1985-2005) .66 III-4 Petroleum Products Demand Projections and Operational Storage Requirements (1990-2005) .67 III-5 Petroleum Product Storage Capacity ............................ 68 rII-6 Ras Issa Product and Crude Storage ............................ 69 III-7 Second Refinery Project - Economic Analysis .... ............... 70 TV-1 YGEC - Power Sales Projections ..... ........................... 83 IV-2 YGEC - System Operating Data Projections - Oil Option ......... 84 IV-3 YGEC - System Operating Data Projections - Gas Option ......... 85 IV-4 YGEC - Inveitment Projections - 1989-2000 .......... ........... 86 nV-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) o~~~~~~~~ I~~~~~~~~~EE ARA NUMA KNUGY STRAT E v Rxecutive Suarv 1. The purpose of this report is to assist the Government of the Yemen Arab Republic (GOY) in analyzing YAR's energy sector, addressing issues related to its development and formulating an appropr:tate strategy. The report includes analyses of and recommendations on energy investments, policy options and operational aspects of the sector, based on information collected by a World Bank mission which visited YAR in February/March 1989- 2. This Energy Strategy Review (ESR) is part of the World Bank's continuing effort to keep abreast of developments in YAR's energy sector. It provides a follow-up to parts of the World Bank's February 1987 report "Yemen Arab Republic: The Impact of Recent Oil and Gas Discoveries on the Macroeconomy and Energy Investment Options" which followed earlier sectoral reviews. Since macroeconomic Rspects of the sector were covered in the Bank's recently issued Country Economic Memorandum,t2 these are not addressed In any detail here. 3. Draving extensively on studies and other work done under the ongoing Technical Assistance to the Petroleum Sector (IDA Credit 1702-YAR of September, 1986), which was in part co-financed by the Governments of the United States of America and the Netherlands, the ESR contains eight chapters. They deal with overall energy sector aspects, YAR's hydrocarbon resources, the demnd and supply of domestic petroleum products, electric power demand and supply, the potential for utilizirng indigenous liquified petroleum gas (LPG) and natural gas resources, a possible sectoral strategy, and a summary listing of the recommendations suggested by the ESR. The report is vritten keeping in mind the GOY policy-makers as its principal audience and places its main emphasis on issues which require GOY's attention in the near future. 4. In our viev, tog oriority should be qiven by GOY to addressinR the following major issues: (i) the availability and deliverability of natural gas which needs to be ascertained with urgency in order to permit its early utilization in place of costly imported fuels in pover generation and cement production; / The mission was composed of Messrs. Burmeister (Senior Operations Officer and Task Manager), Ansari (Senior Petroleum Specialist), Crosetti (Energy Planner), Krishnamurthy (Senior Petroleum Specialist), Maveni (Financial Analyst), 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 Sustainable Grovth during the Oil Era (May 18, 1989). - ii - (iL) design and implementation of a proposed, economically highly attractive gas pipeline project estimated to cost between US$lY) million and US$220 million, together with an appropriate financing strategy; by 1994, gas could replace up to 500,000 tons per year of mostly imported fuel oil, resulting in net annual savings of US$50-80 million; in power generation the use of natural gas could significantly reduce capital and operating costs of the system vis-a-vis fuel oil use; (iii) the need for strengthening the organization, management and finances of YGEC, for increasing tariffs and eliminating costly inefficiencies in the supply of electricity, including high auxiliary consumption and excessive line losses, and for increasing its power sales in order to bring its profitability in line 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, transmission and related areas are estimated at US$661 million if natural gas is available, and in excess of that amount if it is not; (v) the availability for domestic consumption of 120,000 tons/year of LPG that can be produced at the Safer oil and gas fields, to reduce YAR's dependence on increasingly scarce and costly firewood (now providing over 50X of YAR's energy requirements), imported LPG currently at a rate of 96,000 t/y (costing about US$20 million) and other petroleum products; (vi) implementation of other energy related projects including (a) new terminal facilities at Ras Issa, a deep sea port location, to receive and store imported petroleum products at lover cost; (b) replacement of the floating crude oil export storage facility by on-shore tankage to proviea export coerations with greater independence from maintenance and weather-related factors and reduce environmental risks; and (c) a multi-products pipeline up-country from Ras Issa to reduce the cost of petroleum products transportation; investment requirements for the combined Ras Issa facilities without the pipeline are estimated at US$107 million; (vii) to ensure that YAR can derive the maximum benefit from its hydrocarbon resources, the enhancement of MOMR's capabilities in organizing, planning and administering activities in the petroleum sub-sector; (viii) a clear definition by GOY of sectoral objectives and the establishment of a coherent pricing policy; (ix) the definition of YAR's hydrocarbon prospects and the setting of a coherent hydrocarbon exploration policy which are required before GOY can proceed with a long-term exploration program; and - iiL - (x) the proposal to build a second petroleum refinery in YAR at a cost in excess of US 350 million, which was found tc be economically 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 sectoral pricing policy, investment alternatives and institutional reforms, and to eliminate and prevent the recurrence of distortions currently found in YAR's energy 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 are required for strategy formulation, project selection and general programming in support of proper planning functions the in sectoral ministries. Responsibility for strategy development which is now often split between sub-sectoral ministries, should be more clearly defined. To permit effective decision-making, YAR's institutions and organizations in the energy sector need to be made financially viable and their manpower, skills and expertise requirements must be adequately met. 7. Institutions. The need to improve GOY's institutional capabilities is one of the major issues confronting an effective energy strategy in YAR. Such Improvements will require (i) the continued use of foreign expertise to enhance the transfer of technology; (ii) the formulation of appropriate organizational structures at MOMR and its affiliates, subject of a recent USAID-funded study, and at YGEC; these are needed by virtue of the growing importance of the energy sector in YAR and its increasing lin'Vs to the international economy; and (iii) development of appropriate long- and short-term manpower planning, including ways to attract and train capable Yemeni personnel at all levels of sectoral activities: the public sector energy organizations are hampered by civil service payscales which are not competitive with those of local, let alone, foreign private sector companies. 8. Pricina. YAR's energy pricing policy has not always provided users with the correct signals for achieving a rational use of energy and its conservation. Most energy prices are controlled by GOY and are rarely adapted to variations in the corresponding economic cost3. This tends to favor the interest of consumers at the expense of the financial health of the oil and power companies; consequently, subsidies are needed which must come from GOY's budget. Overall, energy prices are above their respective economic costs; however, the prices nf diesel oil and LPG were often lower and should be kept at levels at least otuivalent to their economic costs to prevent mis-allocation of resources. Since the major impediment to LPG use is the high initial cost incurred by consulers in switching from other fuels, subsidization of LPG is not an effective promotional measure. Although power tariffs appear to be significantly above the economic cost of supply, they need to be increased in the short term in order to meet YGEC's financial requirements. - iv - 9. Hydrocarbon Resources. YAR's hydrocarbon resources have been under exploitation since 1986; crude oil has been exported since late 1987 when a pipeline was inaugurated from the Alif Azal oil fields at Safer to the Red Sea. Oil operations, including the pipeline and crude shipments, are handled by Yemen Ezploration and Production Company (YEPC) and Yemen Hunt Oil Company (YHOC). Present institutional arrangements within GOY are under review and some 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 facilitate crude oil and gas operations. So far, GOY has not established a well defined Dolic! or comprehensive Ieaal framework covering YAR's oil, gas and mineral exploration; these should be developed as soon as possible. 10. Since 1987, proven reserves in the Alif field have been revised from initial lower estimates to about 1 billion stock tank bbls (stb) of oil in place. In addition, four other recently discovered smaller fields are estimated to contain about 800 mmstb, increasing YAR's estimated total oil reserves to about 1.8 billion stb; some 50X of this quantity is thought to be recoverable. It is imperative that COY and YEPC reach an early agreement on an oRtimam production program to ensure the efficient exploitation of YAR's oil reserves without damaging the reservoirs. 11. Up to now, natural gas discoveries have not been appraised or delineated, in part due to the still unresolved gas ownership issue under Article 27 of the PSA. GOY should take all necessary steps to resolve the gas ownershin issue vith YEPC to permit the rapid development and utilization of the natural gas resources in order to replace the imported fuel oil now used In power generation and cement productior. Estimates for associated and non-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 should commission a brief review of the gas subsecto- to identify the economically viable gas discoveries and recommend programs for their development. 12. Petroleum Products Demand and Suuplv. Some 30X of YAR's domestic demand is currently being satisfied by a small hydro-skimming refinery located at Safer, with the remainder being supplied by imports. Although growth in demand has been substantial in recent years, based on our estimate of future demand an expansion of YAR's refining capacity would not be economical because imported refined products are expected to be available at lower prices than what it would cost YAR to produce them. Our analysis takes into account (i) a recent consultant study on the viability of building a second refinery (with a throughput of about 60,000 bbl/day of mostly domestic crude and an estimated cost in excess of US$ 350 million) and (ii) reasonable assumptions for domestic demand growth, international crude/product price ratios, crude oil prices and capital costs. A second refinery project would not be economically attractive, even when assuming an adequate domestic crude oil supply, so far not certain, and an indefinite delay in implementing an economically attractive natural gas pipeline. 13. In order to reduce the cost of petroleum product imports, GOY should study the installation of gort storage and giDelinIn& facilities at Ras Issa. Such an installation would result in freight savings by permitting the use of larger and on a per-ton basis, less costly tankers and by reducing the need for costly up-country trucking. At the same time, on-land storage facilities could be installed for crude oil exports. On a preliminary basis, we estimate the 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 planning of nev regional storage facilities, current arrangements for gathering and analXzing regional data concerning petroleum products supply and demand should be strengthened. The sunDly of fuel oil by the Marib refinery to coastal power plants which does not appear to be economical vis-a-vis imports should be discontinued. 14. Power Demard and Supgly. Electric pover is supplied mainly by two large power plants via a pover grid operated by YGEC which also operates a number of diesel generating stations. In addition, there are privately operated generators supplying industries and rural households. Total 1988 pover consumption is estimated at 766/Gwh, of which 545/Gwh was supplied by YGEC. If current demand pro4ections materialize (based on connection to the grid of major industrial consumers currently generating their own power and a 6X annual growth of non-industrial demand), and when alloving for some improvement in YGEC's low efficiencies, its existing excess generating capacity will have been absorbed and additional capacity may be needed as early as 1994. New as well as the existing power plants should preferably be fueled by natural gas, the most economic form of energy. GOY should therefore ascertain with urgency the adequate and timely availability of natural gas vhich could be delivered by pipe-line to the principal pover consumption areas (Sana'a - Mabar, where new generating capacity should be located) and to Ras Khatenib 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 of the 8as gipeline could cause a delay in constructing new power plants which in turn could result in the need for pover load shedding in the mid-1990's or in new generating plants having to be designed for costly fuel oil firing. Since each year's delay of the pipeline could cost US$50-80 million in foregone savings, a delay would clearly not be in YAR's interest. YGEC's overall investment requirements in new power generation, transmission and distribution facilities as well as in the normal development of the system through 2000 are estimated at US$661 million assuming gas-based generation. 15. YGEC's financial condition calls for immediate improvement through reductions in inefficiencies as well as rationalization and increase of electricity tariffs. Most importantly. there must be a reduction in YGEC's high auxiliarX consumption in power generation, presently of about 10 in the interconnected system and 15X in the isolated systems, and the excessive transmission line losses, presently of 25X (including non-technical losses); the ongoing line loss reduction and other studies should be completed and appropriate recommendations implemented quickly. Frequent shortages of spare aarts nd mate:?ials also need to be addressed by GOY with urgency in order to - vi - roduce YGECTs costs and to enhance its financial viability, considering its important role in YAR's groving energy sector. YGEC's oraanization must be strongthoned, enabling it to cope with an increasingly wide range of activities; appropriate planning, budgeting and control functions and other sodern management techniques need to be introduced. Computerization and training, particularly in sub-station maintenance, are inadequate and should be addressed. 16. The majority of rural and urban households use electricity. Most of them, however, rely on small and costly private power generation. At the appropriate time, GOY should undertake studies to determine an optimal, least-cost rural electrification strategy', taking into account the full spectrum of possible technological options c..d institrtional arrangements. Such studies should eventually lead to the formulation of a rural electrification master plan based on an assessment of the benefits of grid extension vs. continued private autogeneration, which would develop technical standards and economic criteria for doing so, assess alternatives to conventional rural electrification, and define the best institutional arrangements to ensure an effective and economic rural power supply. Since conventional electrification of many rural areas would require heavy subsidization, the master plan should keep in mind the rate at which funding would be available for this purpose. In the meantime, COY should encourage the 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 resources could occur within 15-20 years if existing patterns of household energy consumption continue, with serious consequences for welfare particularly among lower income households and the environment. Apart from COY's efforts to increase biomass resources which is expected to be supported by IDA's Second National Agricultural Development Project planned for 1991, steps mnst be taken to accelerate the substitution of fuelvood use especially with LPG. Such steps include an increase in the availabil .ty of LPG and cylinders as well as support for the introduction of low-cost and efficient LPG appliances and bread-ovens; measures such as these could reduce fuelwood consumption by 500,000 t/yr. 18. GOY has initiated a "crash program" to substitute LPG from the Alif/Azal and other oil/gas fields for costly LPG imports and fuelwood. This LPG, currently being reinjected into the oil fields because of a lack of storage and loading facilities, may be adequate to supply YAR's domestic demand (currently about 96,000 t/year) into the next century. 19. Bottling caRacits is currently being increased from 82,000 to 136,000 t/year at the Hodeidah plant. Under the "crash program" and another new project, several plants are being or planned to be installed in other regions. Also bulk truck loading/unloading facilities are to be provided at Safer, as well as road tankers and an additional supplv of LPG cylinders. - vii - 20. Institutional changes, possibly involving the establishment of a new aaencv for LPG production/bottling that can operate as an autonomous entity within the confines of well-defined Government policy, would be beneficial. The development, institution and enforcement of safety codes and standards for safe and smooth LPG operations and handling are important as a prerequisite to assure optimal efficiency in all LPG activitLes. They are essential to permit fostering private sector involvement in the integrated chain from bulk transport to bottling to distribution, with GOY agencies eventually limiting themselves to planning and control over all private LPG activities. 21. Natural Gas Utilization. As stated earlier, GOY should give top priority to developing YAR's important natural gas resources and making them available for domestic consumption. Gas resources are estimated conservatively at 6.1 TCF which, if confirmed, would be adequate to provide for much of YAR's energy requirements for many decades. We have reviewed a pipeline Droiect study prepared by consultants, focussing particularly cn the two most practical and economically beneficial routing alternatives analyzed therein, namely from the Safer oil/gas fields to Sana'a/Amran and to both Sana'a/Amran and Bajil/Ras Khatenib. The pipeline which is estimated to be economically highly attractive, would supply gas principally to existing and future power and cement plants, replacing their use of mostly imported fuel oil. For the two routing alternatives the project's capital cost is estimated at USS 139 million and US$ 220 million respectively, excluding financial charges. 22. As stated in para. 14 above, for any new gas-based power plant to be operational by 1994, GOY needs to reach decisions on proceeding with the gas pipeline before early-1990. This decision will need to be based or. ascertaining that adeauate quantities of gas are available and can be delivered by that time. Also, preparation of a coordinated gas development plan is needed. Steps towards implementation of the pipeline should be coordinated under an action plan which will need to include institutional measures, such as formation of a qualified project team and coordination mechanisms with the oil company as soon as pertinent agreements with YEPC are reached. 23. The economic viability of using natural gas as feed-stock for export-oriented industries (such is fertilizer, petro-chemicals or alumina) is not attractive at present given YAR's limited raw material base and domestic demand for such products, unfavourable world market conditions, strong regional competition, the large investment requirements and technological constraints. The viability of such projects, however, should be reviewed carefully from time to time as conditions may change. 24. Investment Options and Strategy. In summary, the following are the several investment options which GOY should pursue with priority, together with order-of-magnitude estimates of their costs and implementation times: - viii - priority Investment Options Estimated Cost Estimated (1126 millionn1 mplementation LPG Production and Utilization 40-60 1989-1991 Natural Gas Development and Pipeline 139-220 1990-1993 Rar Issa Petroleum Handling and Storage (including for crude shipment) 107 1990-1993 Petroleum Products Pipeline not available 1990-1993 Regional Petroleum Products Storages 35-40 1990 Nev Pover Generation, Transmission, Distribution and System Improvements 661 1989-2000 25. The ongoing program to make domestic LPG available to replace imports should be vigorously pursued. At the same time, the overall hydrocarbon potential of YAR needs to be assessed; this should result in the fcrmulation of a coherent hydrocarbon exploration strategy to attract private sector investors. Provided sufficient quantities of gas are available ar.d deliverable, realization of the pipeline project to supply natural gas should receive GOY's priority since it is economically highly attractive and could result in tangible savings to the economy at an early time. Studies for the Ras Issa petroleum handling and storage facilities, the petroleum products pipeline and regional storages should proceed and resulting projects be implemented 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 energy sector on the basis of which the World Bank and other international lenders could be approached for funding. Arrangements for financing merit GOY's early attention, as do decisions regardirg the Involvement of the grivate sector in the structuring, design, implementation and funding of the above projects whose 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's budget; "build-operate-transfer" or similar arrangements with outside investors could be envisaged whereby projects would be implemented and operated by them for a pre-determined period and then transferred to GOY after much or all of the investment had been amortized and Yemeni staff trained to take over. GOY should seek professional help in exploring such possibilities on the basis of pre-feasibility studies which could be funded in principle from such sources as IDA's Technical Assistance Credit. YEMEN ARAB REPUBLIC ENERGY STRATEGY REVIEW I. THE ENERGY SECTOR 1.01 The Yemen Arab Republic's economy is predominantly rural and characterized by low income vith a per capita gross domestic product (GDP) of about US$450. Its population of about 9.9 million is videly dispersed over mostly rugged terrain, making the provision of basic services and infrastructure costly. With the exseption of hydrocarbons, YAR is poorly endoved vith natural resources. Agriculture which accounts for much of YAR's domestic labour force and about 30X of GDP, is constrained by erratic and generally low rainfall and the Increasing scarcity ot groundwater as well as cultivatable land. The manufacturing sector (10 of GDP) consists mainly of food processing, building materials and metal working industries. 10% of GDP is accounted for by utilities and construction, leaving 50X in services which includes 12 percent in Government. A. Linkages to the Economy 1.02 Linkages between the overall economy and the energy sector are established by both external and internal events. During the 1970s, YAR enjoyed rates of GDP growth of nearly 9X fuelled by remittances from Yemeni expatriates working in the Arab Gulf region: these averaged about US$900 million per year and amounted to about half the GDP. Since the expatriate Yemenis originated in all regions of the country and typically transferred their savings to their home villages, the increase in income benefitted wide segments of the population. As a result, the difference in average income between YAR's rural and urban areas has been modest. This situation ended in the early 1980s when the lower level of economic activity in the Gulf caused by 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 and resulted in much lower GDP growth which has averaged less than 5X per year since 1983. 1.03 The discovery of oil and gas in 1984 improved somewhat YAR's economic prospects. Oil production started in the beginning of 1986 at the level of 10,000 barrels (bbl) per day (bpd) to feed a small refinery at the Alif oil field near Safer, Marib Governorate. Following completion of a 240,000 bpd pipeline, oil exports began in late 1987 at the rate of 130,000 bpd and have meanwhile been increased to over 180,000 bpd. Assuming future production at a conservative rate of 150,000 bpd and based on the World Bank's current crude oil price forecasts, GOY's share of oil revenue in the early 1990s could be in the order of US$700 million per year, representing more than a quarter of projected budgetary revenue. The production of hydrocarbons would contribute close to 15X of GDP, generating more than 90X of YAR's export income. As far as the balance of payments is concerned, the net receipt of foreign exchange from oil exports has done little more than to compensate for the US$600 million decline in annual private remittances and foreign aid since the early 1980s, filling gaps in government revenues and export earnings. Therefore, -2- the optima'. depletlon of the oil and gas resources can be defined only with reference to the technically optimal extraction: identified natural gas reserves seem to be large enough compared to potential demand so that nostretching of output is needed; the oil reserves, on the other hand, are too small to justify strategLc limitations on output. Nor is accelerated oil depletion justified: the resulting gains in interest income would more than likely be outweighed by the impact of a reduced overall level of extraction and the potential gains from the rise in real crude prices that is likely to occur 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, in the power sector; this amounts to 0.4X of YAR's labour force. The energy sector's demand for scarce specialized technical skills is high, placing great demands on YAR's educational system and resources available for fcreign training and expatriate assistance. GOY has taken valuable measures to address this situation in general, but due to the long lead times needed in ed.ucational investments, YAR will have to continue to rely on expatriates for many years. The skills intensity in the energy sector is related to the sector's high investment requirements. During the 1980s, average annual energy investments amounted to some US$200 million, split about equally between the power and hydrocarbon sectors. This represented almost one fourth of gross national investment, a ratio which is likely to recur in the 1990s. Because the investments are import intensive, their effect on the balance of payments is large while their impact on local activities is more modest. Since the rate of overall economic growth is related to the productivity of investments, misguided and mismanaged investments in the energy sector can adversely affect the rate of YAR's economic growth; therefore, the rates of return on proper training in the energy sector are particularly high. It is thus recommended that GOY continue to give high priority to skills training for all parts of the energy sector, with particular emphasis on operations management and project definition, selection and implementation. This will require the continued intensive involvement of outside technical assistance. 1.05 Industrial promotion. In the absence of a proper definition of YAR's natural gas reserves (see Chapter II) it is too early to say whether they are large enough to permit considering gas export schemes. The gas reserves are sufficient, however, to permit substitution for domestic consumption of oil products and thereby replace petroleum product imports and increase crude oil exports. If the potential supply of natural gas should prove to be much larger than the foreseeable domestic demand, GOY may eventually wish to identify additional productive uses for natural gas by attracting energy intensive export industrLes (see para 6.05). However, the prospects for such industries if any, need to be evaluated carefully. Contractors are often anxious to create work for themselves and may make strong cases for projects which are not economlc. Projects that make use of gas as feedstock to produce tradeable commodlties are usually characterized by high risks and a high capital and, correspondingly, low employment intensity. Therefore, it is particularly pertinent that the Investment appraisals be based on realisteic - 3 - forecasts of international markets and prices and recurrent cost requirements. Also, the potential for beneficial "spill-over effects" of such projects to other domestic industrial activities should not be overrated. Rather than being considered as industrialization projects, these schemes should be judged as natural gas export schemes. 1.06 Risk Management. The introdiction of natural gas into YAR's economy is favorable from the point of view of risk management: it diversifies the sources of primary energy and improves the economics of small incremental additions to power capacity vith the use of combined cycle units. With the development of exportable hydrocarbon resources, YAR is now even more exposed to the effects of the volatility in international oil prices than it was at the beginning of the 1980s: firstly, the direct impact of changing oil prices on income from crude exports is added to its indirect effect on temittances from Yemeni expatriates; secondly, in addition to the balance-of-payments effect, GOY revenues are directly affected. Prices of GOY-contracted crude exports averaged US$ 15.9 bbl during the first half of 1988; they fell to USS 14.8 bbl during the second half of 1988 and increased to US$ 16.7 bbl for the first quarter of 1989; they are expected to increase to around $22.8 bbl (in 1989 prices) by the year 2000, according to the World Bank's most recent forecasts. What appears certain is that oil prices vill continue to be volatile and it is recommended that GOY's policy makers apply appropriate risk management strategies to cope with the variability in international oil prices to avoid overheating domestic demand or over-investing in projects; this risk management relates not only to the energy sector per se, but is just as relevant for the setting of macro-economic policies and their effect on all sectors of the economy. B. Energy Policy and Plannina 1.07 The overriding aim in the energy sector is the maximization of benefits to YAR's economy. In practice this translates into multiple specific objectives, namely (i) to identify and promote least-cost options for the provision of energy; (ii) to ensure flexibility and security of supply; (iii) to promote the productivity of the tradeables sectors; (iv) to maximize productive domestic employment; (v) to maximize foreign exchange earnings and Government revenue; (vi) to ensure the sustainability of implemented policies and investment programs, maintenance of the financial viability of the hydrocarbon and power companies, ability to meet specialized manpover requirements, 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 low levels 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 the low-income population; (viii) to promote energy conservation and (ix) to minimize the negative environmental impact of energy production and consumption. 1.08 Objectives such as these have to be used as guiding principles in the definition of GOY's energy policies, lncluding decisions on pricing, investment choices and institutlonal reform. At times, some of them may be conflicting in competing policy options. Therefore, the implemented mix of policies depends on political choices between the trade-offs involved ln the achievement of multiple objectives; no policy is optimal in an absolute sense. The trade-off implications of the choices need to be brought out clearly and whether the proposed policy instruments are more optimal than others in fulfilling GOY's preferred policy objectives. 1.09 Conflicting objectives are behind some of the major distortions currently found in YARI's energy sector. Military-strategic considerations of security of supply were one determinant in the installation of the excess power generating capacity which may have resulted in the limitations of available funding for required pover distribution investments. Decisions made in this regard did not lead to implementation of least-cost options and contributed to the present high cost of electricity. This in turn, contributed to some of the over-investment in costly autogeneration throughout the country, causing a loss of welfcre by domestic consumers, a loss of scarce foreign exchange and a drain on GOY revenues to cover the financial ltases of Yemen General Electricity Corporation (YGEC). Similarly, this policy went against 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 the hydrocarbon sector is clearly recognized by GOY, overall energy issues need to be addressed more appropriately. It is recommended, therefore, that COY clearly define what its general objectives should be in the energy sector, establishing a priority ranking among them, and that the sectoral ministries use this framevork in a coherent manner to evaluate their projects and policy proposals and implement a policy action program to eliminate existing distortions. C. Sectoral Institutions 1.11 Overall EnergX Planning. The development of a coherent energy strategy requires an institutional framework capable of carrying out the planning task, a well-defined division of responsibility between the sectoral institutions, and basic tools such as data bases and evaluation and plan'Ing mechanisms. As illustrated in part by the policy inconsistencies noted above, proper energy planning does not presently exist in YAR, neither for strategy formulation, project selection or general programming. The basic responsibility for formulating and implementing energy policies is essentially split between the Minist-y of Electricity and Water (ME) and the Ministry of Oil and Mineral Resources (MONR). The integration of their policy proposals is undertaken at three levels, namely the GOY Cabinet, the Central Planning Organization (CPO) and the Supreme Council for Oil and Mineral Resources (SCOMR). The Cabinet, by definition, has the ultimate responsibility for energy policy in YAR. - 5 - 1.12 The CPO has both a coordinating and a data collecting responsibility - the latter including information on the energy consumption of major industrial firms - which is exercised by a small energy planning unit. In principle, GOY's Five-Year Plans prepared by the CPO should spell out the sectoral objectives and establish comprehensive energy plans for the longer term. In practice, however, the energy component of the Five-Year Plan consists of no more than a series of investment proposals submitted by the two sectoral ministries. 1.13 Power Subsector. MN is responsible for the formulation of policies and plans for the development of the power subsector including the control and licensing of priva^e and industrial autogeneration. In addition, it is responsible for the development and exploitation of water resources. In practice, NM's small Technical Office keeps track of past activities but is not involved in any planning, preparation of feasibility studies or supervision of projects. 1.14 YGEC which reports to MEW as a semi-autonomous entity is responsible for the generation and distribution of about 70X of the electricity consumed in YAR through the interconnected public grid and from a number of diesel power stations; private electricity producers, consisting mainly of households and industries, account for the remainder. YGEC has a planning unit which functions only like a statistical office, but intentions are to develop it into an effective planning tool. In the meantime, YGEC's planning functions are mostly limited to its projects depar-ment ?itich identifies projects in connection with the preparation of GOY's Five-Year Plans. 1.15 Several structural factors limit YGEC's efficiency: (i) the semi-autonomous status of YGEC is a source of friction; NEW does not restrict its own role to the definition of overall policies but tends to play a role in day-to-day management; (ii) the resulting management problems are compounded by the lack of an overall GOY atrategy for the energy sector; (iii) the personnel policy is inadequate for the efficient running of operations: YGEC is over-staffed, employing a total of 4,000 people -- to dismiss employees is close to impossible -- yet under-staffed in terms of highly qualified people; expatriates are needed in key strategic functions; YGEC's salary structure is not sufficiently flexible for rewarding highly qualified individuals although it provides more possibilities for incentive payments than the civil service salary structure; (iv) the political structure of YAR with strong local regional influence makes it difficult for YGEC to base investment programs on economic considerations (e.g. decisions concerning a balance between centralized versus decentralized investments); YGEC is sensitive to charges of regional discrimination and therefore, each region has its own YGEC unit chaired by a regional representative working almost independently; and (v) in view of YAR's foreign exchange scarcity, COY procedures involved in getting import clearances and opening letters of credit are c-.oersome and YGEC is often unable to procure equipment and spare parts on t5me; as a result, projects are delayed and YGEC has to resort to cannibalizing its temporarily idle plants for spare parts. It is recommended that appropriate measures be - 6 - implemented to address the above deficiencies and improve YGEC's institutional structure and its operational, managerial, personnel and financial policies vhich should allow YGEC to adequately fulfill its responsibility vithin YAR's economy. 1.16 YGEC management is aware that large savings can be achieved with relatively small investments in improving the efficiency of distribution in urban areas. But the attention of GOY decision makers is more geared to investments in expansior than to those in efficiency improvements which are also blocked because of a lacking data base. YGEC's statistical unit collects data on consumer categories, however regional offices do not provide correct and timely data, and meaningful information is often not available in time for management to take corrective measures. A high priority therefore is for YGEC to develop a data base from a power "system point of view", containing information on peak loads, connections, generators and transformers. It is recommended that (i) YGEC's data collection and interpretation capabilities be strengthened, (ii) priority be given to strengthening YGEC's existing planning function to enable it to develop long-term plans for power generation and transmission based on valid forecasts of load demands, load shape and load centers, to identify the lowest cost options, and to determine appropriate standards and risk criteria in accordance with YGEC and GOY policy, (iii) operation and maintenance management of generation, transmission and distribution facilities be improved, and (iv) appropriate training programs be implemented to help achieve these goals. 1.17 Petroleum Subsector. Prior to the discovery of oil, the supply and marketing of oil as well as the export of minerals was the responsibility of the Yemen Oil and Mineral Resources Corporation (YOMINCO) which also functioned as a public sector holding corporation of its three subsidiary companies, YPC, responsible for import and distribution of petroleum products, Yemen Salt Company (YSC), responsible for production and export of salt, and the National Industrial and Construction Material Company. In 1984, GOY created SCOMR to formulate policies for the development and use of YAR's hydrocarbon resources and to conduct negotiations with the operating oil companies. It was soon realized that some of these functions could not be performed collectively, and in 1985, a Presidential Decree established HOMR with the mandate to manage the petroleum and minerals sectors. nOMR took over most of the YOMINCO and SCOMR functions and absorbed many of the YOMINCO personnel. SCOMR which is chaired by the Deputy Prime Minister and composed of the Ministers of NEW, MOMR, economy and industry, finance and the Chairman of CPO, continues to have advisory and oversight functions over MOMR and is consulted on general policy matters while major proposals are taken to the Cabinet. 1.18 However, the present relationship between MOMR and SCOMR requires clarification. Existing legislation appears to place both MOMR and SCOMR at the highest level to formulate policy, plan sector development, represent GOY in negotiations and manage oil agreements as the functions assigned to SCOMR were taken over by MOMR after its establishment. Although some division of labour has developed between the two institutions, their relationship is not - 7 - legally defined and procedures are apt to change as frequently as SCOMR's members change. This has veakened the ability of MONR in addressing sector issues as well as petroleum sector management, particularly its dealings with the international oil companies. One solution would be to abolish SCONR and transfer key staff of the SCONR secretariat to a strategic planning unit in MOHR; another vould be to specify that the role of SCOMR should be limited to evaluating the macroeconomic impact of policy and project proposals of NONR and the conformance of the proposals with stated policy priorities in the energy sector. In any case, SCOMR's role needs to be clarified and care should be taken to ensure that duplication of functions and of training of scarce qualified manpower is avoided. 1.19 Under the IDA Technical Assistance Project, a consultant review co-firanced by the US Government was undertaken of YAR's petroleum subsector organizations which was completed in 1988. Its original objective was to focus on a reorganization of MOMN, but during the course of the study it became evident that the policy planning and operational functions of the petroleum and mineral sectors could not be properly accomplished within MOMR's civil service structure. Therefore, the study proposed that operational functions of MONR be entrusted to YOMINCO which still exists as a largely dormant legal entity and could be reactivated; MONR in turn would remain responsible for long range planning and policy formulation. MONR has accepted a revised organizational structure under this concept and plans to implement the proposal. We believe that a number of issues have not been addressed adequately by the study, including delegation of authority and the mandates of Deputy Ministers and their links with various Directorates General within NONR. Presently almost all decisions are taken in the office of the Minister with minimal delegation of authority, and other officials feel only little responsibility for the management and performance of the petroleum sector. Partly as a result, the efficiency and effectiveness of A'ONR's administrative and planning functions require improvement. This refers particularly to the supervision and control of the operations and expenditures of the petroleum operating company, Yemen Exploration and Production Company (YEPC) and its principal shareholder, Yemen Hunt Oil Company (YHOC). As a first step, MOMN has commissioned independent audits of YEPC/YHOC's expense statements which are currently underway. Another study has been completed of the accounting functions of NOMR, YPC and YSC. It's recommendations are about to be implemented with outside help and IDA funding. 1.20 Also under the IDA Technical Assistance Project and with funding from tha Netherlands Government, the Yemen Exploration and P-aduction Information Center (YEPIC) has built up an effective data base on YAR's hydrocarbon resources. The lack of adequate data bases in other areas under MONR's responsibility, however, is a serious constraint to policy formulation. MONR's Planning Department is not yet fully functional but intends to set up units for project evaluation and forecasting. 1.21 YPC which is responsible for the domestic marketing of all petroleum products and for: operating the LPG bottling plant and distribution (see Chapter V) has a small statistical unit but no planning capabilities. YPC -8- does not have a proven capability to adequately plan and implement investment projects. 1.22 It is recommended that GOY follov up the Organization Study vith a brief but comprehensive review of the roles of the various petroleum sector institutions, with the aim of defining linkages between agencies particularly MONR and SCONR, delineating authority and responsibilities, eliminating duplication and strengthening personnel policies. This reviev should also focus on matters related to personnel remuneration including pay scales and incentives which need to be adequate to attract qualified Yemeni staff for the management and operation of this important sector of YAR's economy, and to eventually 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) and 2.1 mmtoe of fuelwood (221). After exports of 7.3 mmtoe of crude oil and imports of 1.2 mmtoe of petroleum products, gross energy supply to the domestic market in 1988 was 3.8 mmtoe, divided between 1.7 mmtoe of crude oil and petroleum products including inventory changes (45X) and 2.1 mmtoe of fuelwood (55X). 1.24 Roughly 600,000 t of fuelvood (225,000 toe) were consumed for a charcoal production of 140,000 tons (100,000 toe). 0.5 mmtoe of crude oil were 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 total power generation of 1050 GCH; own consumption of power in the power plants was around 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 and 301 by private producers (see Chapter IV). YAR's final energy consumption of 3.4 mmtoe was dominated by the household sector (61X), followed by the transport sector (28X), industry (41), commerce (41) and agriculture (31). A summarized Energy Balance for 1988 is provided in Annex I-1. 1.25 The introduction of natural gas and the continued growth in population and national income will change the level and struct' J of YAR's energy consumption. The anticipated shifts in sectoral energy demand up to 2005 are illustrated in Annex 1-2. In the household sector, "useful energy" demand will continue to grov parallel to the growth in population. As demand for charcoal and for fuelwood is expected to remain constant, all the growth in demand will be satisfied by the more efficient energy carriers LPG and electricity. As a result of substantial gains in average energy efficiency, the relative importance of household energy demand in final energy demand is anticipated to drop by a third to 431. Instead, transport will become the major consumer of final energy (471) as an expected growth in tourism accelerates the demand for jet-fuel, and road transport continues to increase. The share of industry vill increase only slightly as industrial development will be modest, especially in respect of energy intensive industries. Since agriculture already is "overmechanized" and "overirrigated", no growth in -9- agricultural energy demand is expected 1.26. The projections used in Chapters III and VI to evaluate the refinery a|nd gas investment options foresee a 47X growth of final energy demand to 5.5 itoe by 2005. This is less than the expected growth in population (+65X) or the growth in national income: GDP is expected to grvw by 78X and non-oil GDP by 56X (see Annes I-3) This low growth in final energy demand is due to the hlgher market share of the more energy efficient commercial fuels which are foreseen to grow by 126X, implying an elasticity of 1.37 compared to the growth in population, and of 1.45 compared to the growth in non-oil GDP. As a result, the relative importance of biomass and petroleum products in final energy demand will be reversed from 58/40 to 35/58. Since natural gas is used primarily in the generation of electricity, its relative importance in YAR's energy supply is more apparent iL gross energy consumption (121) than in final energy consumption (31). The potential for increasing the share of natural gas in final energy consumption in the future depend on the future level of YAR's industrialization. E. Pricing. Demand Nanagement and Conservation 1.27 Petroleum Products Pricing. A pricing policy providing consumers with the correct signals is the most powerful policy tool for achieving a rational use of energy, and taxation of fuels can be an important source of Government revenue. vhile YGEC is allowed to import fuel oil directly from the International market, paying the international price for it, and while no regulation applies to electricity sales by private generators, all other energy prices are controlled. Because energy prices on the international market fluctuate widely, discrepancies between the administered prices and tariffs and the corresponding economic prices develop quickly. These discrepancies may be either reinforced or off-set by changes in the exchange rate. In addition, inflation erodes the real value of fixed prices. Adjustment to changing cost conditions has been slow and normally, prices are only changed after the financial situation of the affected institution has deteriorated: despite fluctuating international energy prices, YAR's electricity tariffs have remained unchanged since 1981, prices of gasoline, kerosene, aviation fuel and diesel, since 1986, fuel oil, since 1985 and LPG since 1984. The results of this policy vith regard to the generation of government revenues, and the development in real and relative prices are shown in the historical trends depicted in Annexes I-4 and 1-5, demonstrating a clear pattern in GOY's policy orientation. 1.28 Firstly, although GOY has avoided to subsidize overall energy consumption, it has not exploited the potential of energy taxation as an important source of revenue. The benefit of falling International prices during the 1980s were passed on to consumers (see Annex 1-5). The real price of all petroleum products was allowed to increase in 1981 and afterwards, to fall, reaching by 1987 a level of between 371 (LPG) and 891 (diesel) of their respective 1980 prices. The incidence of net taxes on petroleum products (defined as the excess of current prices over economic costs calculated on the basis of YPC's official cost-plus pricing structure) has been small - on - 10 - 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; the highest taz incidence - 19X - came about in 1986 as a result of falling international prices and an overvalued national currency. 1.29 Secondly, although the overall level of taxation has been generally positive, the tax incidence of individual products has rot: GOY has cross-subsidized the consumption of diesel and of the household fuels, kerosene and LPG, by often pricing them below economic cost, whereas apart from 1980, gasoline has alvays been priced above (see Annex I-5). The promotional pricing of kerosene can be defended on grounds of social equity and, together with LPG, fuelwood substitution. Yet, as stated in para 5.14, a more effective way of promoting LPG would be to reduce the cost of LPG stoves and increasing the supply of LPG bottles on the market. Black market prices for LPG, up to 701 higher than the official price, shov a high willingness to pay on the part of consumers; it also should be noted that the average price of traded fuelwood (YR 1.66 kg) in "useful energy" terms (equivalence 7:1) is currently 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, accounting for more than a third of the total consumption of petroleum products. Past underpricing of diesel has had two major implications. First, it led to a loss of GOY revenue, which in 1987 resulted in a subsidy of about YR 90 million. Secondly, it created distortions in the price signals sent to consumers, as the relative price of diesel compared to the domestic prices of fuel oil and gasoline no longer corresponded to their respective opportunity costs. The underpricing of diesel compared to gasoline promotes investments in diesel powered vehicles; although these are more expensive to purchase than F;asoline povered vehicles, this is no cause of major concern as their life-cycle costs may be lower: the international price of diesel during the 19809 was on average 4-5X lover than the price of gasoline, mileage per liter of diesel engines is usually 5-10 higher, and the cost of maintenance is lover. The underpricing of diesel compered to fuel-oil on the other hand, augments YAR's import bill as it encottrages the consumption of higher priced diesel instead of fuel oil in industry. Finally, a low price of diesel may slow the process of transferring industrial auto-producers of electricity to the public grid, even though the cost of auto-production per kWh may still be higher than the industrial pover tariffs. In view of these observations it is recommended that GOY (i) adopt a full economic cost pricing policy as a minimum requirement for all fuels except kerosene, (ii) align the relative domestic prices of diesel and fuel oil to their relative international prices, (iii) consider using taxation of petroleum products as a means for raising Government revenues as compared to alternative means of taxation, and (iv) revise petroleum product prices at least once a year in line with movements in international prices and the foreign exchange rate. 1.31 Power Pricing. As described in Chapter IV, electricity tariffs are estimated to be above the long-run marginal cost of supply as defined by a 1984 study; however, due to internal inefficiencies and delays related to network constraints in connecting major pover consumers to the grid, tariffs - 11 - are not adequate to meet YGEC's revenue requirements. In principle, if YGEC were alloyed to operate efficiently as a truly autonomous entity, the existing tariff level would be sufflcient to cover its costs. As it stands, however, even with a gradual reduction of inefficiencies (see Chapter IV) and increases in power sales, tariffs need to be revised. It is therefore recommended that, as part of * comprehensive plan to strengthen YGEC's financial performance including through efficiency improvements (Para 4.25), (i) service charges and the average tariff level be raised in the short- to medium-term, and (ii) the tariff structure be rationalized to better reflect the economic costs of power supply to different consumer categories. A restructuring f tariffs should seek to eliminate cross-subsidies while at the same time meeting social equity objectives; this should be based on accurate estimates of the economic costs of supply. It is recommended that YGEC update its assessment of long-run marginal costs of supply (contained in the 1984 Electricity Pricing Study carried out by the World Bank), and that the results of this update be used as a basis for GOY's future power pricing decisions. 1.32 Demand Management and Conservation. Until now GOY has not established specific energy demand management and conservation policies. GOY should take up tne conservation of fuelwood as the major demand management issue that needs to be addressed; specific recommendations to this effect are made in Chapter V. The second priority issue is the need to reduce the auxiliary consumption of energy and line losses in the power sector (see Chapter IV), and the third, to promote conservation of energy at the consumer level. In regard to this last observation it is recommended that GOY facilitate energy audits with the help of specialized consultants and provide energy conservation 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 problem associated with energy consumption in YAR. As consumption greatly exceeds productivity, the use of dead wood in the commercial fuel trade has been supplemented increasingly with economically costly cut live wood. Unless direct policy measures to accelerate the substitution of fuelwood by LPG are taken, national forest resources will be seriously depleted and agricultural productivity vill be reduced as a result of impalred nutrient cycling, soil erosion, decreased groundwater recharge and microclimatic deterioration in interaction with other environmentally degrading activities such as excessive groundwater pumping and failure to maintain agricultural terraces. 1.34 The introduction of natural gas in power plants and major industries would greatly decrease the consumption of heavy fuel oil. This would reduce emissions of S02, CO2 and NO, per unit of energy, while emissions of methane would increase but cause only an insignificant impact on the environment. Identified oil fields and the pipeline are largely located in arid, sparsely populated areas, and the environmental risks associated with oil spills are therefore small. However, maritime loading of crude oil involves risks which need to be properly addressed. As detailed in Chapter V. safety standards - 12 - need to be developed, however, for handling of LPG cylinders in the distribution network to prevent risks to life and property. 1.35 There is currently no legislation in YAR concerning aspects of environmental protection. As part of the Technical Assistance to the Petroleum Sector, IDA has agreed to fund consultants to prepare proposals for such legialation which are expected to be completed by 1990. Also, it is anticipated that legislation relating to conservation of forestry measures will be drawn up and implemented under IDA's Second National Agricultural Development Project planned for 1991. II. HYDROCARBON RESOURCES A. Oil Exploration 2.01 Although large portions of YAR's geology are characterized by extensive volcanic rocks which are void of hydrocarbon accumulation, YAR now produces and exports substantial quantities of crude oil. In recent years, international oil companies mounted large scale exploration programs which have resulted in significant oil and gas discoveries. 2.02 YAR's petroleum exploration history began in 1961, initially without any success. It was in 1981 that a Production Sharing Agreement (PSA) was signed between YAR and Hunt Oil Company (of the US) to explore the Marib-Al Jawf basin covering about 16,800 sq.km. in the East-Central part of the country (see W). In 1984, Yemen Hunt Oil Company (YHOC) completed the first oil discovery well, and the Alif field was declared commercial in 1985. Since that time, over one hundred wells have been drilled for development of this field whic7a has now been exploited fully; currently, the level of production is about 140,000 bpd of crude oil, most of which is exported through a pipeline with a capacity of 240,000 bpd to the Red Sea. YHOC has meanwhile entered into a partnership with other oil companies, known as Yemen Exploration and Production Company (YEPC). 2.03 Compagnie Francaise des Petroles (CFP) (Total) signed a concession agreement vith YAR in 1985 covering about 5,000 sq.km. onshore as well as 4,000 sq.km. offshore in the South Tihama region. Exploration work is in progress, however no discoveries have been reported so far. Similarly in 1985, Exxon was awarded a concession covering about 20,000 sq.km. in the Central Plateau. Exxon carried out geological and geophysical investigations of its area in 1986 and 1987. Subsequently, the company drilled two wildcat wells which had to be abandoned as non-producers. Having been discouraged by the results of the two wells drilled, Exxon curtailed its direct exploratory operation by selling part of its interest in this concession to Texaco. Lastly, a joint company owned by YAR and th, People's Democratic Republic of Yemen (PDRY) was formed in 1988 to explore and develop the hydrocarbon resources of the Neutral Zone between the two countries. 2.04 Exnloration Policy. YAR has no well defined exploration policy which - 13 - could accelerate attracting private sector investments for high risk ezploration. Such a policy could stipulate periodic bid rounds attracting interested private investt.&s through a transparent exploration promotion exerclse which should address in particular (i) linkages between the entities and their respective roles, with a clear statement of prospective investors' needs and the extent of their obligations agreed within the framevork of YAR's laws pertaining to oil activities, (ii) clear requirements for the treatment of discoveries as commercial, both for oil and gas, (iii) the logical geographic and geologic basis. both in size and prospectivity, of areas offered for private investors' exploration, and (iv) minimum commitments related to work programs required for each block, proportional to the prospectivity of an area. It is recommended that GOY establish a comprehensive hydrocarbon exploration policy vhich would (i) clearly define the role and responsibilities of both th"e private and the public sector entities vis-a-vis the country's needs, (ii) aim at optimizing YAR's hydrocarbon resource utilization, and (iii) introduce a competitive approach in petroleum industry operations. 2.05 In viev of the international petroleum industry's known interest in investing in YAR and the country's objective of attracting competition to its current oil operators, a reliable assessment of YAR's hydrocarbon prospects is needed to permit formulation of an appropriate policy. Therefore, it is recommended that GOY carry out an independent comprehensive review of YAR's overall oil and gas prospects, with the view to preparing a long-term perspective exploration plan for utilization of the country's hydrocarbon resources. This study's aim would be to prepare a synthesis of YAR's hydrocarbon potential within each major geologic province of the country, based on a compilation of all available geological, geophysical and geochemical data to be analyzed by appropriate modern techniques; once approved, the review should take about 24 months to be completed. The World Bank vould be prepared to consider assisting GOY in such an endeavour. 2.06 Legal Framework. Petroleum agreements in YAR are not related to specific legislation such as the petroleum and mining laws in effect in most other countries. Under the terms of the existing PSA, the contractor's operation in general is "... bound by the laws of Yemen Vnd regulations issued for the implementation thereof...." Currently, each ofl agreement must be approved by YAR's legislative oody on the basis of whi.-h a Presidential Decree is issued, expressly ratifying the agreement which then becomes an independent law. Initially this arrangement might have been satisfactory, both for GOY and a contractor. However, like in any agreement relating to business arrangements, it is difficult to address the typical problems occurring during the normal day-to-day course of business, if agreement changes require legislative action and a Presidential Decree. It is thus recommended that GOY prepare and legislate a comprehensive and up-to-date "Hydroc rbon and Minerals Act" on the basis of which all types of petroleum, gas, gas liquids or mineral agreements could be prepared and concluded. This should eliminate the vagueness and problems present in the current agreements with the industry; this would also facilitate contract administration and provide for the flexibility which is needed for granting incentives to attract private - 14 - investors, even in less prospective acreages. Such a "Hydrocarbon and Minerals Act" which should include specific reference to the commercialization process of natural gas, should be drafted by legal experts acquainted with and experienced in the evolution of the petroleum laws, particularly in Middle Eastern and North Sea countries. B. Reserves and Production 2.07 The Alif field is an anticline vith gently sloping flanks. The main oil reservoir is producing from two distinct sandy intervals which are related to rifting phenomena. Both zones have excellent reservoir characteristics with up to 10 darcies horizontal permeability and up to 23X porosity. The Alif reservoir rock has a classical seal on the top in form of a thick section of interbedded shales and salt deposits. 2.08 Following the initial discovery of oil at Alif in 1984 and subsequent acceptance of commerciality in 1985, proven reserves of the discovery were originally estimated at about 400 million stock tank bbls (stb) of oil in place. Hove-er, since then considerable additional data have been generated, more than one hundred development wells have been drilled, and well performance has been monitored. Based on the new data and a number of reservoir studi-s both by the contractor and GOY, the oil-in-place reserve estimates 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. Oil reserves in other smaller fields such as Yazan and Nucum are estimated to total about 200 million stb. Based on more recent information on the basis of which various reservoir studies were carried out by consultants and contractors, YAR's total oil reserve is currently estimated at about 1.8 billion stb, of which 50 or about 900 million stb are thought to be recoverable. The updated data and various reservoir studies (including the one funded under IDA's Technical Assistance to the Petroleum Sector) indicate that the degree of reliability in YAR's oil reserves estimate is within acceptable industry standards. 2.09 The estimated gas reserve of YAR has been published in trade journals as somewhere between 15 to 20 trillion cubic feet (TCF). However, neither adequate data nor reliable reports were supplied to us to verify the existence of gas in YAR in such quantities. GOY's reserve estimate is based on data provided by the operating oil companies on associated gas, totalling 3.6 TCF of gas in place. MOMR furthermore estimates YAR's potenti'l non-associated gas reserves to total 3.2 TCF. Greater details are provided later in this Chapter. 2.10 Alif Production and Profiles. The updated reserve estimate of the Alif field is consistent with its production history. For most of 1988, Alif oil production has been about 150,000 stb per day. By September 1988, the latest month for which data were made available to us, cumulative oil produced was 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 sustain crude oil production at about 150.000 bpd, the operator started gas-injection into the field for preservation of the gas cap pressure. As of September 1988, a total of 28,262 mmscf of gas had been injected. Table 2.1 summarizes Alif production data for the first nine months of 1988, the latest information available to us. Table 2,1 Alif Field - Cumulative Production/Iniection January - September 1988 Oil Productlon Rate Np Gp R G1 month (stb/d) (NNstb) (sef/stb) (mmscf) 1/88 124276 13.367 12073 1074 232 2/88 149680 17.708 18367 1447 3478 3/88 144919 22.200 23293 1097 7080 4/88 150019 26.701 27461 926 8782 5/88 149868 31.347 31877 950 12708 6/88 149929 35.845 35901 b94 16136 7/88 150006 40.495 40443 977 20221 8/88 149911 45.142 44740 925 24309 9/88 149900 49.639 49224 997 28262 Mp - Cumulative Oil Production Gp- Cumulative Gas Production R - Gas Oil Ratio (GOR) GI - Cumulative Gas Injection Source: NOMR 2.11 Four production scenarios for the Alif field were analyzed by MONR's reservoir consultant, as summarized in Table 2.2. This analysis did not result in firm conclusions, except that Scenarios Two and Three were found not to be economically and technically viable and that Scenario Four would be preferable to Scenario One. MONR is reviewing YHOC's proposed operating Table 2.2 Alif Field - Oil and Gas Production Scenarios Oil Production Gas Production Scenarios (bpd) (GPC in mmscf/day) One 150,000 600 Two 150,000 800 Three 180,000 600 Four 120,000 600 Source: MONR production profile submitted in November 1988, as summarized in Table 2.3, but will avait the results of an ongoing reservoir simulation before reaching a - 16 - decision. MOYR's experts' view that Scenario Four (120,000 bpd of oil production with a GPC of 600 mmscf of gas) is preferable, does not seem acceptable to YHOC, probably because their economics of oil and gas production vithin the framevork of the PSA are different from GOY's. Table 2.3 Alif Field - Operating Production Profile YHOC's Management Plan of Nov mber 1988 Oil & Condensate Cumulative Rate Production GOR Gas Rate Year (stbZd) (mmstb) (scf/stb) (mmscf/d) 1988 151110 63.54 1200 180 1989 165000 123.77 2110 350 1990 154550 180.18 2970 460 1994- 107680 219.48 5110 550 1992 68940 244.64 7950 550 1993 52590 263.84 9790 510 1994 43260 279.63 12440 540 1995 40330 294.35 13500 540 Source: MOIR C. Gas Resources and Availability 2.12 Recent discoveries in several fields have significantly added to YAR's potential gas availability. Completion of seven vells indicated that the Raydan field is mainly a gas field. In the Assad Al Kamil field, 17 wells were completed most of which shoved substantial gas and condensates. Based on data obtained from MOHK, the total proven and possible gas reserves in these and other fields are estimated at about 6.8 trillion cubic feet (TCF) which includes associated gas, gas cap and non-associated gas. Table 2.4 summarizes MORR's assessment of YAR's proven and possible gas reserves. - 17 - Table 2.4 YAR - Proven and Possible Natural Gas Reserves (billion cubic feet) Proven Possible Total Oil Producing Fields Alif 3,200 3,200 Azal 345 345 Nacum 8 8 Yazan 11 11 Assad Al Kamil 2.500 2.500 * ~~~~ ~ ~ ~ ~ ~~6.064 - 6.064 Potential Gas Fields Raydan, Na'een 300 300 Lam 100 100 Neem - 300 300 700 700 Total 6,064 700 6,764 Source: MONR . - 18 - 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 under discussion between GOY and the oil field contractor (see below). Some 250 NKCFD 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 of processing 260 NNCFD associated gas and 140 NNCFD of gas cap for recovery of 4,000 bpd of LPG and 5,000 bpd of C5+. Currently about 2,600 bpd of LPG and 2,800 bpd of C6+ are being recovered. The LPG together with the dry gas are reinjected back into the reservoir and C5+ is added to the crude oil stream for export. 2.14 As stated above, the current production plan for Alif adopted by the operator requires a portion of the gas produced simultaneously with oll to be injected back into the formation, in order to implement an optimum oil field depletion plan. Hovever, it is possible that part of this gas (between 50 to 100 mmscf/d) could be released for use in power generation and for other purposes, but this needs to be confirmed in connection with GOT's eventual decision on the production profile. It is recommended that GOY urgently take all measures necessary to confirm the availability and deliverability of Alif associated gas, including an agreement with YEPC, and steps be taken to permit its early utilization in substitution of costly imported fuel oil in power generation and cement production (See Chapter VI for further discussion). 2.15 Once the oil in the above and other fields currently under production is depleted, they become gas fields. It is predicted that at Nacum and Yazan this vill occur as early as 1995. These, plus Lam and Meem, the two confirmed gas fields, will then provide a reasonable source of non-associated gas (approximately 0.4 TCF) for any gas utilization project until other potential gas fields such as Assad Al Kamil are confirmed or additional oil fields are depleted and transformed into gas fields. 2.16 Two important issues are apparent in the gas subsector, namely the gas ownership under the PSA framework and the extent of YAR's natural gas potential and reserves. In view of the importance of promoting hydrocarbon exploration and production and of providing adequate incentives to find and develop the resources, both of these issues should be addressed as soon as possible. Although MONR has been actively engaged for some time in negotiatioms with YEPC in relation to provisions under Article 27 of the PSA, a resolution of the ownership issue is not yet apparent. GOY maintains that according to the provisions, ".... associated gas not exported in liquid form or used in operation for reinjection or reinjected or flared shall remain the property of the State...." The contractor bases his views on the same Article vhich states also that ".... if gas is produced or is capable of being produced from the area, the State and contractor shall study all possible economic alternatives for its use and decide on the best alternative...." and that ".... production-sharing principles of ArtLcle VII shall apply to the value of non-associated gas if it is sold and not used in operation...." It is recommended that GOY continue and expedite its negotiations on this subject and, if it becomes clear that a satisfactory agreement cannot be reached, invoke arbitration within the terms of the PSA. - 19 - 2.17 Studies related to YAR's gas potential and reserves have not been pursued as vigorously as those related to oil, due to lack of contractor incentives. An assessment will probably be delayed until the above gas ownership issue is resolved. In the meantime, investment decisions for the development of YAR's natural gas utilization should not be held up and an early 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 gas subsector to identify the next steps required for appraisal and delineation of those gas discoveries which appear economically viable, and to establish a yrogram for appraisal and development of the discoveries; close coordination vith YEPC would be essential. Once competent consultants are hired for this purpose, the reviev should be completed in about 90 days. I is furthermore recg=ended that once the above review is completed and after the ownership question is resolved, GO! design and implement a coordinated natural gas development plan covering both upstream and downstream aspects. The World Bank would be prepared to consider assisting in these studies under the ongoing 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 the Marib refinery. Sourcing of YPC's imports is generally based on government-to-government negotiations with Saudi Arabia, Kuvait and PDRY, except for LPG imports which are sourced by YPC directly based on competitive tendering procedures. 3.02 We found the statistics available in YAR on historical petroleum product imports and the country-wide and regional consumption to be internally inconsistent. For example, YPC's sales of many products during 1980-84 are shown to be consistently higher than the corresponding year's imports recorded by YPC, although there was no domestic production; differences also cannot be reconciled by inventory variations. It is known that significant unofficial imports, mainly of gasoline, take place across land borders with PDRY and Saudi Arabia; however, estimates of such imports by MOMR, using data from Customs authorities, do not provide a valid basis for reconciling the estimates of total consumption, official imports by YPC, and unofficial imports. We also noted that volume measures of YPC imports and sales are converted to weight measures using different conversion factors. The historical consumption/supply balances for products discussed below are therefore based largely on our estimates and are approximate. 3.03 Consumption of petroleum products including LPG increased from 202,400 tons in 1975 to 969,000 tons in 1984 (or at an annual growth rate of 19X), and to 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 have stagnated at a growth rate of 1X during 1984-88. Therefore, correlating road transport fuel consumption with vehicle fleet population, average distance travelled, and specific fuel consumption by type of vehicle is difficult due to the lack of reliable data. Fuel oil and aviation turbine kerosene (ATK) consumption figures are reasonably accurate since thelr end-users are readily identifiable Our estimate of YAR's hLstoric consmption of petroleum products 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 257.0 568.1 Diesel Oil 94.4 399.L 477.0 495.0 ATK 5.1 24.5 33.9 62.0 LPG 4.6 19.5 54.0 96.0 Kerosene 38.8 77.6 70.7 63.9 Fuel 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 the ports of Hodeidah and Al-Mukha, direct fuel oil imports by YGEC for its two coastal power plants, net supplies of products from the Marib Refinery since April 1986, and unofficial imports across land borders with Saudi Arabia and PDRY. Unofficial imports of gasoline are believed to have been very significant during 1984-86, far exceeding YPC's official imports, but appear to have been reduced to insignificant levels since then, which is ascribed to the devaluation of YAR's currency relative to Saudi Arabia's. The product-wise consumption/supply balance during 1984-88 is shown in Annex III-2. indicating that in 1988, 68X of domestic demand for petroleum was supplied by imports. The operations of the Marib refinery are described in Paras. 3.08 - 3.11. 3.05 Projections of products demand vere prepared as part of the feasibility study for a second refinery (see par&. 3.20) and reviewed by us in the light of current macroeconomic growth projections. Future demand for road transport fuels - gasoline and diesel oil - was estimated on the basis of anticipated vehicle fleet growth, average annual mileage and specific fuel consumption by type of vehicle. The fleet growth appears to provide the best basis for this estimate even though there have been significant additions of unregistered passenger cars to YAR's fleet. For gasoline, the study's implied growth rate of 8.3X/p.a. during 1988-95 and 5.2X during 1995-2005 is conservative 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 the dLesel oil consumption growth assumed at 4.42 during 1988-1995 and 3.0X during 1995-2005 reasonable. Demand estimates for jet fuel ezhlbit a similar phenomenon of lover growth in the future than in the past and have been based on Yemenia Airlines' growth targets, correlated with projected general economic growth. Kerosene demand is projected to decrease gradually, reflecting substitution by LPG. We consider that the study's demand projection methodology and the estimates themaalves for the above mentioned fuels are acceptable. But we have carried out independent projections for fuel oil and LPG based on our assessment of growth in YAR's power sector and of gas development and utilization. Our demand projections using base case assumptions 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 5.2 Diesel oil 495 545 670 786 902 2.7 4.4 3.0 ATK 62 70 100 140 189 12.0 7.1 6.6 LPG 96 114 193 268 331 16.3 16.3 5.5 Kerosene 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 1.2 million t in 2005 (see para 6.03). 3.06 Distribution of products is carried out by YPC through regional storage installations at Sana'a, Hodeidah, Taiz, Narib and Al-Mukha. The regions served by Sana'a, Bodeidah and Taiz account for 90-95% of YAR's total consumption of gasoline, kerosene and diesel oil, and for 1002 of ATK and fuel oil. The regional shares mentioned above take into consideration YPC's sales only and do not take into account the distribution of unofficial imports among the regions for which there are no statistics, or those by YGEC for its power plants. Historical regional consumption shares during 1985-88 and our projections of these shares for the future (YPC sales only) are shown in Annex III-3 and regional demand projections in absolute terms, in Annex III-4. They reflect the impact of increasing natural gas use expected for the 1990's and accelerated demand growth expected for the Narib and Al-Nukha areas. 3.07 YPC's and 0M1R's organizational capabilities are weak vith regard to the systematic gathering and interpretation of data on supply and consumption by product and by major user-sectors. There is no adequate coordination with the Transport Ministry, YGEC and with Customs authorities, and unofficial - 22 - imports are not adequately tracked and documented. It is recommended that MOMR/YPC engage specialized services to establish adequate systems for assembling country-wide petroleum sector statlstics, including data gathering, interpretation and demand projections, and provide training for a core of Yemeni 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 is jointly owned by Yemen Hunt Refining Company (YHRC) and YPC under the terms of the PSA. The plant was originally intended to refine part of Alif crude oil to provide only diesel oil for crude oil and gas production operations but later 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 of gasoline and diesel oil is used by YHOC for crude and gas production operations and the rest is sold to YPC under a refined products production sharing agreement. The overall refinery balance for the period April 1986 to December 1988 is shown in Table 3.3. This refinery does not produce kerosene or ATK because of the high paraffinic nature of the Alif crude oil, requiring all kerosene fractions to be cut back into diesel oil to conform to the pour point specification of 250F. Because of low sulfur content of Alif/Azal crude oil, the distillates and fuel oil do not require treatment facilities. Table 3.3 Marib Refinerv Material Balance Anril 1986-December 1988 (in '000 bbls) Total Delivered to YPC during Production X 1986 1987 1988 Gasoline 3,071 30.8 805.3 1,089.9 1,114.7 Diesel Oil 3,497 35.1 868.6 1,159.2 1,098.3 Fuel Oil 2.954 22.7 793.9 1,109.5 1,050.5 Subtotal 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, and there are possibilities for optimizing its yield pattern and increasing the production of higher-value distillates possibly by up to 5X through more dynamic operations control. To increase the benefits of refinery operations, it is recommended that NONR launch a program of improved training of Yemeni - 23 - personnel in refinery operations, and to adjust refinery operations to optimize its yield pattern. 3.11 Information on the accounts for the refinery proper, and disaggregation of refining costs in sufficient detail including for operations by the foreign partner, were not made available to us. However, indications are that the total refining costs incurred during the last three years of US$1.8-2.3 bbl, are acceptable although somewhat on the high side. In our estimation, refining at Narib is an economically attractive alternative to supplying YAR's main consumption areas with imported products. The cost of products supply from the refinery, comprising the opportunity value of crude charged to it (at FOB export price minus cost of pipeline transport from Safer to the Red Sea), plus refining cost and road transport cost of products from the refinery to Sana'a, is likely to be less than cif products import costs at Hodeidab plus road transport costs to Sana'a. It is recommended that MOMR conduct a brief study to confirm the economic benefits of continued operation of the Marib refinery, including of the desirability of relocating the facilities to Mabar along the crude pipeline route and closer to the main product consumption areas. 3.12 Currently the bulk of the fuel oil produced at the Marib refinery is transported by road to the power plants on the Red Sea coast. In our view it could be economically more beneficial to spike the fuel oil into the crude for export, and to import the fuel oil required for power generation. The quantity of fuel oil so spiked (about 3,000 bpd) would be too small relative to the crude quantity (about 140,000 bpd) to significantly affect the crude oil quality. Even alloving for some discount on the FOB export price of crude oil, this alternative is most likely to be more beneficial. It is recommended that 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 to limitations of draft, the port can admit only small tankers of a maximum 15,000 DWT with loads of up to 10,000 DWT. The tank farm adjoining the port has a total capacity of some 52,000 t of liquid products storage, excluding LPG, which is planned to be expanded to about 60,000 t by 1990 by refurbishing three gasoline tanks and constructing additional tanks for kerosene and diesel oil. Most of the current tankage which was built in 1974, is in fairly good physical condition. However, a system for maintenance through periodic inspection is lacking. Facilities for product loading into tank trucks also appear to be in good working order but require an improved system for quantity measurement through tank-truck calibration besides the current method which relies on meters. It is recommended that YPC strengthen its tank farm maintenance arrangements and measurement systems with the help of specialized assistance and increase the training of its operations personnel for all storage terminals. 3.14 Based on our demand projections, the planned 60.000/t storage capacity will not be sufficient to provide a 21-days stock of YAR's white products - 24 - demand. Based on future demand growth assumptions (para 3.05), YAR's storage requirements would amount to 87,000 t by 1995, 130,000 t by 2000 and 160,000 t by 2005. The current facilities at Hodeidah cannot be expanded to such levels because the resulting road congestion would be excessive, and because of limitations in additional land availability as well as draft limits in the port. NONR/YPC are therefore considering to install new products port and storage facilities at Ras Issa (see below). If and vhen such new facilities are installed, the current Hodeidah tank farm could be used as operational storage for supplies to the Bodeidah region. 3.15 Regarding the current storage capacities at Sana'a (excluding strategic storage capacities) and Taiz, on the basis of 30-day consumption these are already inadequate and require expansion. Annex III-5 summarizes current storage capacities by location and product. Arnex III-4 referred to earlier also summarizes the incremental white products storage needed to be installed at each location in order to provide adequate capacities on a regional basis in the future; this is based on our projections for total country and regional demand; as an order-of-magnitude, we estimate that up to 2005, required investments for this purpose total US$35-40 million. It is recommended that YPC increase its petroleum products storage to ensure an uninterrupted 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 and storage facilities with new ones as mentioned above, COY is beginning to consider relocating YAR's crude export facilities to Ras Issa, a thinly populated area on the coastline about 65/km north of Hodeidah; it has deep draft close to the coastline and is thus approachable by large tankers and potentially a good site for installation of tanker receiving/loading facilities through offshore single-buoy-mooring (SBN) and for storages for crude oil and products. 3.17 After separation in the central processing unit located at the Safer oil field, crude oil is presently transported by pipeline over about 430 km to the Ras Issa receiving station, from which it is pumped by subsea pipeline to a COY-owned tanker (T.S. "Safer") moored about 20 km offshore, which acts as a floating storage. From this 500,000 DWT tanker which has an effective storage capacity of about 3 million bbls of crude oil, the oil is pumped into export tankers moored alongside from time to time. According to information received from MOHR, the operating costs (excluding capital-related costs) for the tanker amount to about US$10 million per year, without allowing for the costs of 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 economic rate of return (ERR) of the project is estimated at about 22X and the net present 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 built during 1992-2005; (LiL) estimated total capital costs of US$68 illion for storage, US$20 million for mooring facilities and other infrastructure, and annual operatLng costs of US$7 million; (iv) freight savings on product imports at US$9 t of white products (as compared with importing products in small vessels at Hodeidah); and (v) operating cost savings on the crude oil storage vis-a-vis continuing operation of TS "Safer". Our preliminary calculations are shown in Menx 111-6. Fuel oil imports for supply to the two coastal pover plants are expected to continue being handled through their own facilities and therefore, no major fuel oil storage vould be needed at Ras Issa. 3.19 It is recommended that a detailed study be carried out to define the physical facilities required, develop the engineerLng, estimate the capital and operating costs, confirm the econowic/financial justification of the investments, aud develop a master plan for this project; the same study should also reconsider the justlifcation of investments in a multi-products pipeline from Ras Issa to Bajil and/or Sana'a and its implicatlons on the scope of products storage facilities to be installed at Ras Issa. This was originally revieved by a 1983 consultant study which recommended construction of such a pipeline vith marine facilities at the Red Sea port of Salif, but GOY has not decided on its implementation or routing. This study should be up-dated as part of the new Ras Issa study. It is evident that the economic viability of this project is closely related to YAR's storage, supply and distribution network, 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 esamined by an IDA-financed study conducted by UOP Processes Internatlonal Inc./Chemsystems (UOP/CS); the study was commissioned by GOY in 1986 and completed in 1989Y. In llne with lts terms of reference, the study took the adequate availabllity of domestic crude oll for granted; it assessed five potentlal locatlons for the new reflnery - Ras Khatenib, Ras Issa, Bajil, Narlb and Nabar - resultlng ln the conclusion that Ras Issa would be the best location. Also, several refinery configurations were evaluated, resulting in the finding that a fluid catalytic cracking configuration would be the most appropriate and largely consistent with projected trends of domestic products demand. The study analyzed the economic justifLcatLon for the investment, taking into account several scenarlos concerning future demand, crude oil slate, products yield profile, market prices and capital costs. 3.21 The analysls conducted by us of the project justLfLcation ln economlc terms is based on the above study, wLth our assessment of domestlc product demand, 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. - 26 - costs), and the Vorld Bank's current projections for international prices of crude oil and products. We have also assumed that, based largely on nev discoveries, domestic crude of Xarib-type specification will be available to supply 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 value of exported crude if the refinery project is not iaplemented, with the cost under the situation where the refLnery were built. Our finding is that, except in the outer years, the total net cost of products supply is consistently higher wLth the refinery in place thank without. This shows that it would be more economical for YAR to continue to export its crude and import the needed refined products. Annex 1I1-7 describes in detail the calculations and assumptions used in our economic analysis of the project. Therefore, and also in view of the macroeconomic impact of undertaking such a major investment, Jt i8rco ended that GOY not pursue the project further at this time. Table 3.4 YAR - Second Refinery Protect Not Cost of Products SuDDlV (in million constant Us Dollars of 1988) Without Refinery With Refinerv 1994 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 24.0 Feedstock imports (heavy stock) - - - - (51.7) (61.6) (91.7) (115.9) Rev.nua from equivalent crude oil 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 zero by 2001; (ii) marginal exports of kerosene of 1-2 thousand tons during 1996-2005; (iii) Jet fuel of 1,000 in 1994. 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 to 29,000 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 of US$49.1 million). LI At 12S on US$6 million. 3.22 Based on the costs and benefits assumed for our Base Case, the project would have an only marginal ERR of 3.2X, confirming the above conclusion. Besides the Base Case, ve assessed eight other less likely scenarios (see Annex III-7), representing combinations of differring assumptions for demand, prices, crude and product slate, and capital/operating costs. Of all the - 27 - scenarios analyzed, only those corresponding to the more optimistic UOP/CS and NOHR's sets of demand assumptions and our scenario assuming increased international product prices ("Refmis VI") show positive NPV's of the project's economic costs and benefits. The "Refmis VI' scenario assumes that the international product-to-crude price ratio would increase from 1996 onwards, reflecting a hypothesis that the world-wide demand and supply would equilibrate by 1995 and consequently, refining margins would increase to allow covering full cost recovery of new refinery investments coming on stream by 1995. However, until such time as product prices in relation to crude prices show a definite and substantial increase approaching the levels assumed in this scenario, a decision to invest in a new refinery would be very risky. It should also be noted that if domestic crude is not available in sufficient quantities for an estimated 12-year refinery operation and the resulting crude deficit has to be made up entirely by imported crude, the ERR would fall considerably. 3.23 Concerning the scenario termed "UOP/CS Base Case", our re-evaluation results 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 value equal to its present high import cost, (iii) higher FOB realization values for the export of surplus production which are not fully consistent with assumptions on freight costs on imports used for valueing refinery outputs, and (iv) what we consider over-optimistic assumptions for future crude and product prices that are much higher than those forecast by the World Bank. The scenarios corresponding to MOMR's set of assumptions show ERRs in excess of 18X because of even higher product prices assumed and a higher products demand growth rate, both of which in our view are not realistic. As a further variant, we tested the impact of delaying the substitution of fuel oil by natural gas: the assumption that gas would not be available to power and cement plants before 2005 resulted in an only small increase of our Base Case ERR from 3.22 to 4.72; in essence, the greater fuel oil demand as a result of a delayed gas pipeline implementation would not make the refinery project any more attractive. IV. POWER DEMAND AND SUPPLY A. Demand in YAR, a total 1988 consumption of 766 Gwh is estimated. 462 of this consumed by households, 272 by industrial users, and 142 by commercial users, with the remainder attributable mainly to the military, agriculture, water supply, hotels and street lighting. La Conducted by the UNDP/World Bank Energy Sector Management Assistance Program (ESMAP) and co-financed by the Government of the Netherlands. - 28 - 4.01 YAR's power sector consists of (i) the interconnected power grid located in the western part of the country and numerous isolated systems, all operated by the public utility, Yemen General Electricity Corporation (YGEC), and (ii) a large number of private autogeneration units among industries and households throughout the country. Given the lack of reliable data, YAR's overall power demand cannot be assessed with certainty; but based on information availatle from YGEC and the ongoing Household Fuel Marketing Study A which will complement the ESR in providing details on many of the ousehold energy users 4.02 In order to project YAR's future power demand, we have made certain assumptions. Given YAR's historic power demand growth and current macroeconomic growth projections, and in view of the World Bank's experience in similar developing countries, we have assumed a 6% normal annual growth in maximum 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 and 660 MW in 2015. If major industrial loads (such as cement plants and food processing industries) are included as now expected, the maximum demand in 2000 would rise to 464 MW. The maximum demand for YGEC's isolated systems which represent generation in YGEC's branches remote from the interconnected system and which was about 17 NW in 1988, is estimated to decrease to 12 MW in 2000. Household demand, including from non-YGEC systems, is assumed to grow at a compound annual rate of about 71. 4.03 Industrial power demand growth will have a critical impact on the power sub-sector. If this materializes as now expected, the share of industrial 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 estimated maximum demand for the inter-connected system of about 464/MW. If they don't materialize, the need for expanding YGEC's power supply could be delayed. The major addition in the industrial loads would be on account of the existing two cement plants of Amran and Bajil, now generating their own power, and the proposed cement plant at Al Barh (Mafraq), which eventually will account for a total cement production of about 2.6 million t/yr. However, if plans for installation of the Mafraq plant are delayed or cancelled, there would be a reduction of about 25 MW in the maximum demand. 4.04 Table 4.1 provides an overview over YAR's current and projected demand estimates. Annex IV-1 provides further details as to YGEC's sectoral sales projections through 2000, expressed in Gwh as well as YR at current tariff levels. -29 - Table 4.1:. YAR - Power Consumution Estimates (in Gwh) 1988 a/ 1995 2000 Power Generated by: YGEC Other YGE Othe: YGEC Other Households 217 139 402 201 538 266 Industrial 125 82 707 - 1,019 - Commercial 107 - 215 - 285 Other 96 - 136 - 165 Total 766 1,.661 2.273 A/ Actual 4.05 Data provided by the Household Fuel Marketing Study indicate the widespread use of electricity in both rural and urban households: about 70X of all households in YAR use electricity. Given the large amount of electricity consumed by households and its associated costs, the household electricity supply strategy is an important part of YAR's overall energy strategy for both social 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, or 541, use electricity from other sources. Assuming that the number of rural households will increase by 2% annually over the next 15 years, there will be nearly 1.8 million rural households by 2004. If implementation of the current and proposed power projects as well as the Earthquake Reconstruction Project proceed as planned, there will be approximately 370,000 rural households connected to YGEC, suggesting that the portion of rural households so connected will increase to only 211 by 2004. If the fraction of rural households using their own generators or purchasing power from private producers remains constant at 451 of all rural households, there will be over 800,000 rural households using electricity generated from sources other than YGEC. Paras 4.19 - 4.21 provide a detailed discussion of the issues involved in rural electrification. B. Generation and Transmission 4.07 This section discusses YGEC's operations only. Its system consists of two parts, namely the interconnected grid (comprising the thermal power stations at Ras Khatenib and Al-Mokha and the major diesel stations in the urban areas of Sana'a, Hodeidah and Taiz, all connected to the 132-kV network), and about 33 isolated systems throughout the country, comprising diesel units and associated distribution networks. The interconnected system has an installed capacity of 372 MW, of which 310/MW in the two thermal plants and 62 MW in the city diesels. In 1988 the grid accounted for about 931 of YGEC's electricity sales and generation. According to current plans, by 2000 this system would increase its generating capacity to 590 MW, while the capacity in the isolated systems would gradually fall from presently 26/MW to 18 MW as more of the areas now served by the diesel units get connected to the grid. - 30 - 4.08 At present the interconnected system has an excess generating capacity. In 1988, the maximum demand of the interconnected system was 143/MW, leaving a reserve of 160%. However given general demand growth, and if the Amran and Bajil cement plants and other industrial users are linked to the interconnected system during the next few years, this margin is expected to disappear in 1993; additional capacity would have to be installed then to meet demand. As discussed below, natural gas is the preferred energy for power plants. If natural gas is not available, YGEC would have to install additional fuel oil fired thermal plants instead of the more efficient combined cycle gas based power plants, or would have to take load management measures (including load shedding) as may be required to contain the demand for power within the available capacity. Either option would mean financial loss to YGEC (see para 4.13). 4.09 YGEC's auxiliary consumption in the existing power plants and line losses are high. In 1988 the percentage of auxiliary consumption at Ras Khatenib was 11.5% and that at Al Mokha, 9.5%. Moreover, the auxiliary consumption 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, we have assumed that with installation of more efficient gas-based combined cycle plants in the future and better management of existing oil fired thermal power plants, the auxiliary consumption for the interconnected system would be reduced from about 10% in 1988 to about 6% in 2000; in case of continued oil firing, the auxiliary consumption was assumed to be reduced to about 8% in 2000. It is recommended that the causes for YGEC's high auxiliary consumption be 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, YGEC has already appointed consultants (under IDA-Credit 1361-YAR) who are assisting in the streamlining of billing procedures and in reducing non-technical losses. About 4% of the remaining line losses could be attributed to the inadequate sub-transmission and distribution network which needs to be rehabilitated. UNDP/OPEC Fund are likely to support YGEC in carrying out a power system loss reduction study, strongly recommended by the World Bank, which could provide a rehabilitation and line loss reduction component for the urban areas of Sana'a, Hodeidah and Taiz under IDA's proposed Fifth Power Project. In our projections we have assumed that line losses would be reduced from 25% ir. 1988 to about 15% in 2000. In case such a reduction is not achieved. YGEC would have to generate a total of about 2816 GWH 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 be installed. It is therefore recommended that the line loss reduction study be completed with urgency and that recomended measures be strictly enforced to reduce losses to a targeted 15% by 2000. 4.11 As a result of YAR's foreign exchange shortage, and since YGEC's existing thermal plants are under-utilized, requirements of power plant spare - 31 - parts have often been met by cannibalizing unused generating units. With an increasing power demand, all existing units will soon be required in operation. To permit this to happen, it is recommended that GOY make available adequate foreign exchange to allow YGEC to acquire full spare parts supplies, especially for all units in its two thermal plants, and to install appropriate spare parts management and maintenance control systems to ensure that efficient operations are not jeopardized in the future. 4.12 GOY had earlier initiated studies to explore prospects for geothermal power generation. These however, were abandoned as uneconomical in light of the recently discovered hydrocarbon resources. We agree with GOY that no further work be undertaken on this subject at this time. C. Future Capacity Reguirements 4.13 Based on current demand projections, additional generating capacity will need to be available by 1994. The type of additioral plants to be installed depends basically on GOY's decision regarding the availability of natural gas (see Chapter VI). In our analyses we have therefore focussed on YGEC's projected operations under two scenarios, namely (i) the "Oil Option" under which no natural gas would become available and all future power generation 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 power capacity to be installed beginning in 1994 as well as for the converted Ras Khatenib plant; due to the less attractive economics of extending the gas pipeline further, it is assumed that the Al Mukha plant would continue to be oil fired. Since no details are available as yet for implementation of the gas pipeline, we considered three sub-options, namely (i) that gas would be available for the projected up-country combined cycle plants but the pipeline would not extend to the Red Sea Coast and that Ras Khatenib would continue to be oil-fired; and (ii) that the pipeline would extend to both Sana'a and Ras Khatenib. Annexes IV-2 and IV-3 provide projections up to 2000 for YGEC's power generation and sales as well as fuel requirements for the interconnected system under these options. 4.14 Under the Oil Option we assumed that the additional thermal generating capacity would be installed along the Coast. Fuel oil requirements in power generation would thus rise from about 210,000 mt in 1988 to about 720,000 mt in 2000 (see Table 3.2). With the ongoing strengthening of the Northern transmission loop, no difficulties are expected in transferring the additional power to the major load centers of Sana'a/Amran which in 1988 was responsible for 52X of the interconnected system demand and is estimated to still account for 40% of demand in 2000. In case of the Gas Option, additional generating capacity requirements would be based on combined cycle modules of 90/NW, each consisting of two-30 KW gas turbines and one-30 MW steam turbine. The first two modules would likely be located in the Amran/Sana'a/Mabar corridor and the third, in the Bajil/Hodeida area whicn is technically feasible since make-up water requirement of the modules is relatively modest (about 4,500 kg/hr per module) and no difficulty is expected in meeting requirements at these location. - 32 - 4.15 The Governments of YAR and PDRY are considering installation of a 132-kV interconnection linking the Aden system to YGEC's grid. The nature of operation of this interconnection is so far not known. Therefore, for the purposes of this review, we have assumed that there would be no economic exchange of power. 4.16 Investment Requirements. Annex IV-4 provides an estimate of the investment requirements for YGEC's new generation, transmission and distribution facilities as well as for normal system development/improvements to meet projected load growth through 2000. For the Oil Option, investments are estimated to total US$ 703 million, and under the Gas Option, US$661 million. The difference of about US$42 million is based on the less costly and more efficient combined cycle modules. Utilizing gas rather than fuel oil is advantageous and economical. Income projections for YGEC under the oil and gas options are attached as Annex IV-5. In view of the greater generating efficiency, the use of natural gas at YGEC's plants would have a clearly positive impact on the company's financial situation. Provided that r-tural gas is available (see Chapter II), it is recommended that gas use and combined cycle plant technology be introduced as soon as possible to meet YGEC's future capacity requirements and that the existing fuel oil based plant at Ras Khatenib 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 in operation by 1994, and keeping in mind the lead time required to complete the necessary power plant feasibility studies and financing arrangements prior to commencement of their construction, it is recommended that GOY reach an early decision to proceed with implementation of the gas pipeline to avoid having to install additional fuel oil based capacity or the need for loan management measures (see para 4.08). 4.18 The investment requirements shown in Annex IV-4 take into account ongoing or committed projects of a network control center, the Northern loop 132-kV transmission line, and the YAR-PDRY 132-kV interconnection. In addition, provision is included for the reinforcement to the transmission system required to meet the projected load growth up to 2000. Estimated investment requirements in distribution include IDA's ongoing or agreed Third and Fourth Power Projects as weli as the Earthquake Villages Project. It also reflects the proposed Fifth Power Project as currently under considaration. Although so far YGEC has made no provisions for reinforcement of distribution lines, replacement of overloaded transformers by others of adequate capacity, and replacement of old service connections and meters, we have assumed investment requirements of US$105 million for these purposes. 4.19 Rural Electrification. Except where electricity is put to productive use, it is often not possible to justify rural electrification on quartifiable economic grounds alone. Because of the high financial costs involved and the comparatively meagre financial benefits from rural electrification, utility companies are normally reluctant to extend supplies to rural areas. Thus, - 33 - historically in most developing countries, the generation, transmission and distribution of electricity has been concentrated in the urban areas. However, governments often consider extension to rural areas of infrastructure facilities such as electricity necessary for socio-political reasons and to (i) provide incentives for industries to locate in less economically developed areas; (ii) disperse industry and avoid concentration in a few places and the related pollution effects; (iii) counteract tendencies of populations to migrate to urban areas and overstraining infrastructure facilities there: (iv) provide better security and health services; and (v) achieve perceived social equity objectives. In practice it is difficult to quantify the benefits associated with fulfillment of these objectives. Therefore, the rate at which rural electrification is to be introduced has to take into account both the financial burden it imposes on the utility company and possibly the government budget, as well as the need to meet other government objectives. 4.20 A strategy most often adopted is for a proper analysis of the economics of rural electrification to be carried out from the national perspective, based on data on rural incomes and populations, alternative energy sources and their economic costs, and on the nature and incidence of productive activities. Such an analysis provides a starting point for formulation of a strategy which takes into account other non-quantifiable benefits from rural electrification. A rural electrification masterplan is then developed spelling out the strategy and criteria for selecting areas to be electrified, methods of financing and of providing compensation to the utility company for losses arising from its supplying power to uneconomic areas. 4.21 YAR's circumstances are typical of most developing countries in that the costs of rural electrification are high (about US$1,500 per rural household connected), rural incomes and per capita consumption are low, and population concentrations are thin. Considering costs such as mentioned, the financial resources necessary to accelerate the rate of rural electrification are immense. The additional cost of connecting 1 million rural households for example, which would result in the connection of nearly 80X of all rural households in YAR, is estimated at US$ 1.5 billion. Given the difficulty of mobilizing such resources, small-scale autogeneration by the private sector is likely to remain a dominant mode of power supply for rural households for the foreseeable future. In the short term, encouragement should be given to the private sector to supply the outer areas and to develop pilot projects to experiment with unconventional methods of power provision such as photovoltafes (solar energy), described below. It is recommended that in the medium term, GOY carry out a study to determine the benefits of rural electrification either through grid extension or autogeneration, develop technical standards, and formulate a master plan as described above. Carrying out a proper analysis of the economics of rural electrification would require data on rural incomes and populations, alternative energy sources in rural areas and their economic costs, the nature and incidence of productive activities, and others; the ongoing Household Fuel Marketing Study will provide much of the needed data. In the meantime, our investment estimates assume that the rural electrification programs included under IDA's proposed - 34 - Fifth Power Project will be implemented at a cost of about US$126 million. 4.22 Private Generation and Photovoltaics. There are alternatives to the decentralized power supply currently found in YAR. Analyses carried out as part of the Household Fuel Marketing Study indicate that, under certain conditions which exist on a widespread basis in YAR, decentralized photovoltaic systems can provide electricity for basic needs at less economic cost than small autogeneration or grid extension. Specifically, for settlements of less than 35 to 60 electrified households located at least 3 km from existing grid supply, household photovoltaic systems appear to be the least-cost electricity supply option for typical YAR rural household needs such as lighting, radio and small television. Such systems might cost on the order of US$500 per household and provide power at annualized costs 25X-50Q below the costs of grid extension or small autogeneration, depending on local circumstances. It is recommended that GOY carry out further work for the development, demonstration and testing of household photovoltaic systems to establish a basis for its decision on the use of this system in a wide-spread and systematic manner, and to determine how private sector participation in this effort can be mobilized most effectively. Results of this work could provide a useful input to the broader rural electrification study recommended above. D. YGEC ManaLement and Financial Situation 4.23 Until 2000, YGEC is expected to increase about threefold its electricity output; this will involve adding 240 MW of generating capacity and is expanding operations in transmission and distribution to cover more of the rural areas. It is, therefore, essential that YGEC's organization be better tuned to enable it more to efficiently manage its operations. Outside consultants are expected to continue assisting in developing YGEC's manpower plan and training programs and to make recommendations about changes in YGEC's organization structure to reduce costs and meet its future needs. Under the previous IDA projects, YGEC supported long-term overseas academic training and about 40 students are currently being trained in the UK and USA; however, YGEC has yet to finalize placement of these trainees when they return to YAR. YGEC also needs to implement on-the-job training for its middle management with the help of foreign experts; this is specially needed for improving its operating performance and maintenance of generation, transmission and distribution facilities. It is recommended specifically that YGEC (i) complete the ongoing programs and implement their recommendations; (ii) introduce appropriate delegation of power and responsibility to enable top management time for planning and addressing policy issues; (iii) strengthen its planning function to appropriately carry out short and long term planning ;(iv) improve the budgetary system recently introduced and initiate procedures for establishing a comprehensive cost accounting and management reporting system to bring operating costs under tighter control and (v) implement hands-on training in equipment maintenance. 4.24 YGEC is currently implementing various computer applications, the most important of which are the billing system, financial accounting and job - 35 - costing. Since most of these systems will not have been extended to all regions by the expiry of the current consultancy contract, it is recommended that YGEC make immediate plans for a follow-on phase to its financial recovery plan consultancy. particularly with regard to the extension of the computerization of billing to cover more than the 231 of consumers whose billing is now in the process of being computerized. 4.25 As shown on Annex IV-5, YGEC's financial condition continues to be weak and will continue so unless important steps are taken. The main causes are the above-mentioned excess generating capacity and high levels of system losses as well as diseconomies arising from numerous organizational units which can be rationalized, the high price to YGEC in recent years of domestically produced and imported diesel oil (which in 1988 was 29% above its economic cost), and a level and structure of power tariffs that has not been adjusted since 1981 to take account of inflation (see Chapter I). As a result, the projected rates of return on revalued assets for the oil and gas options mentioned in para 4.14 are substantially below the rates agreed with IDA under ongoing projects (31 in 1989/1990 and 51 in 1991 and beyond). In order to re-establish YGEC's financial viability, it is recommended that a comprehensive plan consisting of both revenue enhancement and cost reduction measures be instituted as a matter of urgency; on the cost side, the plan should include reduction of auxiliary and system losses to appropriate levels, rationalization of YGEC's organizational and management arrangements, and strengthening of budgetary and cost control procedures; on the revenue side, efforts should focus particularly on improving the billing system and collection of accounts receivable, on increasing power sales by connecting several major industrial consumers, and on increasing the level and adjusting the structure of tariffs (see para 1.31). 4.26 According to the World Bank's 1984 Electricity Pricing Study, YGEC's tariff structure contains cross-subsidies between consumer categories: subsidized are most industrial consumers (with the exception of some sz-qller ones), some hotels and agricultural enterprises. Although changes may have occurred since 1984 in the prices of oil as well as in power plant costs, it is most likely that both financial and economic distortions in power tariffs remain (see para 1.31). V. LIOUIFIED PETROLEUM GAS 5.01 GOY has targeted LPG as a primary substitute fuel in its efforts to decrease fuelwood demand and thereby slow the depletion of YAR's wood resources which would occur if existing patterns of residential and commercial energy consumption continue, with serious effects on welfare particularly among lower income households. Strong demand for LPG cannot be satisfied due to constraints in supply. Logistical bottlenecks, particularly in bottling and transportation, have led to severe demand/supply imbalances which in turn have spawned an active black market for LPG and cylinders. LPG produced locally from associated gas is now reinjected into the oil field reservoir due to lack of storage, loading and transportation facilities, while demand has - 36 - been met to a limited extent by costly imports. Two primary and interrelated issues arise from this situation, namely. (i) how to bring LPG production on-line as rapidly as possible in order to reduce both the cost of supply and the import bill, and (ii) how to relieve the logistical bottlenecks constraining consumption and interfuel substitution. A. Demand 5.02 Total LPG consumption in YAR increased from an estimated 27,000 t in 1982 to about 84,000 t in 1987 and 96,000 t in 1988. In 1987, the last year for which detailed information was available to us, approximately 70,000 t were consumed by households and most of the balance, by poultry farms. With improvements in the av-ilabtlity and delivery of LPG and other measures which GOY should take, we estimate that household demand could increase threefold and reach 240,000 t by 2000; in addition, a potential demand of nearly 30,000 t year could be tapped in other sectors such as by poultry farms and large commercial consumers. In 1987 approximately 43X of all households in YAR used LPG (371 of rural and 89X of urban households) according to the ongoing Household Fuel Marketing Study; average consumption for users was 125 kg/yr (109 kg/yr for rural and 179 kg/yr for urban households). While urban household penetratiozA in different areas ranged from 671 to over 95A, it was only about 361 in rural areas, leaving significant potential for consumption growth there. We therefore believe that once LPG becomes available more easily, demand for this form of energy will increase significantly. 5.03 A 1987 survey of YAR households indicated that for only 12X of all households not using LPG, the primary reason for not using it was lack of accessibility; 611 cited the high initial costs of fuel switching as well as the lack of bottles as the major reason. Of whose who were using LPG, about 431 indicated that lack of cylinders represer sd a major difficulty with LPG use. Although YPC officially charges a deposit of only YR150 per cylinder, the average household cost of an empty cylinder was about YR400, with some cases reported as high as YR1,000. 5.04 With the planned alleviation of supply constraints, policies and programs will become the critical factor in promoting LPG demand to reduce fuelwood consumption. In this regard we have analyzed two scenarios resulting from possible GOY strategies, namely: (i) "Natural Substitution" of fuelwood consumption, where no GOY action is taken beyond making domestically produced LPG available in an accelerated way. In this case, and should the current trends in household energy consumption continue, YAR's total fuelwood stocks would be depleted in about ten years to the level currently found in fuelwood deficit areas such as Dhamar. This scenario assumes that at that time, national household LPG consumption would also reflect the patterns currently found in Dhamar where it is relatively intensive. Non-household LPG demand growth is assumed at 51 annually and includes the demand by commercial users such as poultry farms which is estimated to grow to 29,000 t by 2000. - 37 - (ii) "Managed Transition' where additional actions are implemented by GOY at an early stage to promote LPG use, including (a) an increase in the availability of LPG cylinders, to ensure their adequate supply at an affordable price, (b) mobilization of and providing incentives for the private sector to participate in LPG bottling, marketing and distribution, including in bulk, (c) development and dissemination of low-cost LPG bread-ovens and other appliances, (d) formulation and enforcement of codes and standards to help ensure product safety and the smooth operation of bottling and distribution, and (e) establishment of a separate agency or unit within NOMR that would be responsible 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 future growth in domestic LPG consumption. This is characterized by steady growth in LPG demand, such that, at the end of 15 years, all households in YAR consume LPG at the average 172/kg/yr rate of those who today use only LPG and no kerosene or wood. Non-household demand is assumed to grow at 10 annually. The estimated LPG demand under the two scenarios and the maximum potential are shown on Table 5.1. Table 5.1 LPG Demand Estimates (in '000 t) 1988-2000 Projected Growth Rate 1990 20 (X) Natural Substitution 108 144 193 6.0 Managed Transition 114 193 268 8.9 Maximum Potential 119 201 340 11.1 5.06 Clearly, GOY actions can make a significant difference in LPG demand growth: according to our estimation the difference in consumption under the two scenarios after 12 years is estimated at 75,000/t/yr, which is equivalent to about 500,000/t of fuelwood or 10 of present fuelwood demand. It is recommended that GOY take adequate measures needed for a managed transition to increased LPG use, undertaking the appropriate investments and implementing policies and programs to encourage LPG substitution of fuelwood and petroleum fuels. B. Imports and Potential for Domestic Productio. 5.07 Of the 96,000/t of LPG consumed in 1988, approximately 82,000/t were imported by sea in bulk and bottled in Hodeidah by YPC. Bulk importation through the Hodeidah port is limited by the capacity of off-loading, storage and bottling facilities, and is costly due to high ocean freight because LPG must be imported in small tankers. The cif price for LPG is now about US$200/t, resulting in an annual cost to the economy of nearly US$20 million. - 38 - The remaining 14,000/t of LPG consumed in 1988 were imported in cylinders from PDRY. 5.08 Approximately 2,600/bpd (80,000 t/yr) of LPG is being recovered from associated gas at the C5+ gas plant at the Safer Alif/Azal oil fields. However, in the absence of storage, transportation and loading facilities, the LPG is reinjected back to the reservoir. Production of this LPG, whose quality is in conformity with standard commercial specifications, could be easily 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 produced from Alif/Azal gas by installation of cryogenic processing units. Based on the presently proven gas reserves (see Chapter II) and assuming (i) the same gas composition for all new fields as found at Alif, (ii) a 75X reservoir recovery factor and (iii) an 851 recovery of propane and 1001 butane, approximately 16 million tons of LPG could be available in total; in principle, this would be sufficient to meet an annual demand of 300,000/t for over fifty years. 5.09 GOY decided recently to proceed with an "LPG crash program" to expedite the utilization of this indigenous LPG. This program is being assisted by IDA under its Technical Assistance Project. Specifically, the program includes (i) preparation of an optimum and long-term LPG development plan for YAR, supported by the necessary economic justifications, (ii) installation of LPG storage and loading facilities at Safer, (iii) review of the feasibility of installing optimum size bottling plants in cities with main LPG distribution depots, (iv) procurement of LPG road tankers to transport up to 120,000 t/yr from Safer to bottling plants, and (v) implementation of a bulk delivery system to commercial and poultry farm consumers. Negotiations between GOY and YEPC to agree on a joint venture framework for making the LPG available have been underway for a prolonged period, so far without reaching a conclusion. It is recommended that the "crash program" which is estimated to cost about US$5 million, be pursued vigorously, that the YEPC negotiations be conducted as soon as possible, and that this be followed by the implementation of adequate institutional arrangements for planning the future development of LPG resources. C. Bottling. Transportation and Distribution 5.10 Bottling. The extension of the Hodeidah bottling plant which is currently under way will increase its capacity from 82,000 t/yr to 136,000 t/r; i.nstallation of facilities for bulk loading of road tankers is *.der study. The capacity expansion is expected to be sufficient for meeting domestic LPG demand until 1991 and should obviate the need for YGEC's imports of bottled LPG. Once demand growth warrants it, additional bottling capacity should be installed at optimum locations, supplemented by facilities to handle bulk deliveries. Apart from the "crash program" mentioned above, GOY has been considering a larger project the centerpiece of which is a 170,000 t/yr 0 bottling plant near Sana'a; the cost of this and other components is estimated at about US$50 million for a first phase, as shown on Annex V-1. Our review indicates that this project may be over-ambitious for YAR's requirements and I - 39 - that a system of smaller, decentralized bottling plants to complement the Hodeldah plant may be more appropriate. It i8 recommended that this project be re-evaluated in light of the conclusion of the recently completed study undertaken 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 households and another 100,000, by commercial establishments; 300,000 are in circulation in the transport/filling system. Implementation of bulk LPG distribution to about 1,500 identified commercial units and poultry farms and by the private sector vhich has already shown interest, is likely to release some 125,000 cylinders. Since many of the bottles in use are damaged and should be repaired or replaced, it is estimated that there are currently some 1.0 million bottles in acceptable condition in circulation. Assuming that the number of LPG-using households increases by 30X over the next three years there could be a total requirement of 1.7 million bottles by 1992, requiring the importation of about 300,000 additional cylinders per year. It is recommended that implementation of bulk distribution of LPG be expedited and the stock of useable cylinders be increasei to eliminate shortages which could dampen the benefits of the planned increase in L?G production and bottling capacity. 5.12 Cylinders cause only part of the initial cost of fuel switching. A household must also buy LPG appliances which can be costly: a burner ring, for example, may sell for only YR150, however, the largest share of household energy is consumed in bread baking which requires bread-oven. Their price of YR1500 to YR2500 make them unaffordable to many. Therefore, to help facilitate fuel switching and to increase interfuel substitution in households, an affordable LPG bread-oven and/or retrofitting of wood ovens should be developed and promoted. Some work in this regard has commenced under the Household Fuel Marketing Study. It is recommended that further work be undertaken towards the development and more widespread use of low cost LPG appliances. 5.13 TransRortation and Distribution. The transportation of LPG cylinders to distribution depots in urban centers is being contracted to private truckers which are reimbursed according to transport tariffs established by YPC. From these depots, cylinders are distributed through fifty YPC-owned urban retail distribution centers and 501 contracted agents; thus the market is highly fragmented. YPC arranges for transport of cylinders from its distribution depots to retail centers; there, consuimers puxchase LPG (at the official price of YR37 per filling of a cylinder of nominally 12.5/kg; actual filling average however, is 10.7/kg) and return empty cylinders; these centcrs are operated generally at a loss to YPC. In the case of the agents who are selected under procedures overseen by local village and town councils these are responsible for the transport of cylinders from YPC's depots to their shops and are refunded YR1.5 per cylinder to cover transport costs. There is no system in place allowing for government control over retailer activities; safety standards in bottle handling have not been established, entailing risks to life and property. It is recommended that the GOY develop, with assistance - 40 - from appropriate experts, national safety codes and standards and implement them 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 by YPC; this operation is not profitable. Given the high cif cost of imported LPG, the current official price of YR37 per filling of a cylinder entails a subsidy which is absorbed by YPC. Since the major impediment to LPG use is the high initial cost to consumers of switching from using other fuels (para 5.03), subsidization of LPG is not an effective promotional measure. In our view the LPG subsidy is higher than indicated by YPC's official price structure since (i) YPC's method of calculating the operating costs of the bottling plant as a percentage of the LPG cif price understates the true costs and (ii) the low LPG cost calculated by YPC does not reflect the economic costs of present bottlenecks in the distribution network and in particular, the almost total absence of bottle storage (empty or filled) at the plant. To remedy the above and to enable YPC to amortize anticipated investments in the expansion of the Hodeidah and other future plants, in new loading and storage facilities at Safer, in transportation equipment and in new cylinders, the LPG sales price needs to be revised teking into account all real costs. Our rough estimate, based on the present cif price of imported LPG of over US$200 t, indicates a realistic cost of YR52 per cylinder filling of 12.5/kg, that is, YR15 above the present official price. Since cylinders are filled on average with no more than 10.7/kg of LPG, the official price is 21X below the economic cost of supply. Indigenous production of LPG will in the best of cases reduce the economic cost to about YR40 per 12.5 kg cylinder, as it saves the cost of ocean freight on imported LPG of about US$ 105/t. 5.15 As noted earlier, because of supply constraints the actual average LPG retail price is currently about YR60 per cylinder (71X above the official price, with individual prices varying from YR40 to YR78) illustrating the willingness of consumers to pay a high price for this preferred form of energy. It is recommended that GOY revise current LPG pricing and ensure that it will fully cover YPC's costs and provide a reasonable return on the investments in rationalizing and expanding LPG production and distribution; ex-processing-plant prices should accurately reflect the economic cost of procuring and processing LPG, thereby encouraging least cost supply, and retail prices should reflect the economic cost of supply and the relative value of LPG vis-a-vis substitutes. 5.16 Development of the domestic LPG is the responsibility of a recently formed project team within IOMR/YPC, which may eveatually evolve into a company devoted solely to LPG. For the short to medium term, this entity could also have responsibility for bulk transport and bottling; once an appropriate pricing policy is in place, these functions, should be assumed by private operators. In the future, the principal role of GOY in LPG supply would therefore be limited to its production and to monitoring and controlling all LPG sector operations, ensuring safe, efficient and economic delivery of the product to the consumer, and encouraging private sector operation of all - 41 - other functions. It is recommended that COY (i) eazmine whether in the sedium term these activities can effectively be assumed by YPC or whether a separate autonomous agency would prove more appropriate, (ii) establish a separate agency, or a new department within NONR, to oversee LPG regulatory and control functions, develop, implement and enforce safety codes and standards, and monitor 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 economics and operational efficiercy of the LPG distribution network, and (iv) provide incentives for the private sector to assume responsibility for an Integrated distribution network encompassing all aspects of LPG supply, from bulk transport from Safer to bottling and distribution. This should include an examination of options for joint ventures, innovative private/public partnerships (such as "build-operate-transfer" arrangements for bottling plants), and direct private investment in and operation of small- and medium-scale plants. - 42 - VI. NATURAL GAS UTILIZATION 6.01 As described in Chapter II, nev recent discoveries have further strengthened the prospects for natural gas utilization in YAR. Our economic evaluation of the potential investments for utilizing the gas indicates that these could be highly attractive and should be considered with priority. The purpose of this Chapter is to review the poteatial demand prospects, and to provide 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 by GOY; this should be the object of future studies. In the meantime, ye have attempted to estimate YAR's potential gas demand based on experience in other developing countries vith more mature gas markets, and on the replacement of fuel 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 demand will increase from 290,000 t in 1988 to 1.2 million t in 2005 unless natural gas is made available. Fuel oil consumption in the power sector is estimated to grow from 210,000 t in 1988 to 920,000 t in 2005; these quantities would be used in the existing steam power plants at Ras Khatenib and Al Mukha and in future additional power plants (Chapter IV). Fuel consumption in the cement sector, which presently consists of plants at hAran and Bajil, is estimated to grow from 80,000 t in 1988 to 300,000 t by 2005, based on a projected growth of YAR's cement production from 800,000 t to 3.0 million t and assuming that one ton of fuel oil is needed per 10 t of cement produced. Table 6.1 YAR - Projected Fuel Oil Consumption in Power and Cement Production /a ('000 t) Cement Power Total Amran Balil Other Ras Khatenib Al Mukha Other 1988 50 30 - 105 105 - 290 1994 100 80 90 239 239 43 791 2000 100 90 90 239 239 242 1000 2005 100 100 100 239 23c 442 1220 Za Assuming no availability of natural gas. - 43 - 6.04 Substitution for LPG and kerosene could provide another but limited potential market for natural gas in YAR's residential and commercial sectors; this is a premium market since gas can substitute petroleum products and improve the cities' environment by reducing road traffic supplying petroleum products and air pollution. However, natural gas networks can only be developed economically in cities with high concentrations of commercial consumers and well developed residential sectors, leaving substantial parts of the urban and the rural markets for other forms of energy. We thus estimate that by 2005 the potential natural gas substitution for LPG and kerosene could be 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 for about 1.3 million t of petroleum products; this would be equivalent to more than 120 million standard cubic feet per day (mmcfd) of natural gas. To satisfy this potential gas demand presumes the implementation of specific infrastructure investments, discussed later in this Chapter. In view of the clear potential which natural gas has as an economic source of energy, and given its potential availability in adequate quantities in the early 1990's, it is recommended that GOY expedite its ongoing efforts to finalize the legal aspects of making gas available and to develop dnd implement a coordinated gas development plan covering both, upstream and downstream aspects. 6.05 In principle there are other potential uses for natural gas, including the production of fertilizer, methanol, automotive fuels such as compressed natural gas, and liquified natural gas. However, both the World Bank's 1987 study on the impact of hydrocarbon discoveries and consulcants' "Gas Utilization Study" (GUS)W conclude that in view of the limited domestic market for these products, unfavourable world market conditions, the particularly strong regional competition, the large investment requirements and technological constraints, these options are presently unlikely to be economically rewarding for YAR. It is recommended, therefore, that any natural gas utilization plans in YAR for the short and medium term focus only on 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 for commercialization of indigenous natural gas and LPG. The study's terms of reference were based on the assumption that adequate supplies of gas would be available. For natural gas, it evaluated six pipeline options, covering the costs of transmission, service connections to the power stations and cement plants, and conversion of existing consumers' facilities from fuel oil use. All of the options were shown to be economically attractive, except one whereby 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 the World Bank's Technical Assistance to the Petroleum Sector. - 44 - option was not considered further since it vas found to be uneconomical because (1) it would eliminate the large benefits from fuel oil substitution by cement plants and other potential non-power consumers, and (ii) it vould require ezcess generating capacity to compensate for power transmission losses over the long distances involved. We carried out further analyses of two of the five remaining options vhich GUS found to have the highest economic benefits; their routing to Sana'a, Amran and to Ras Rhatenib is shown on the Map. We did not analyze further the other three options which include extensions of the pipeline to Taiz and Al-Mukha and were found by the GUS to be 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 to Nabar; this stretch vould be of telescopic design of which 124 km of 22-inch diameter and the remaining 100 km, of 20-inch diameter; an 80 km, 18-inch pipeline from Mabar to Sana'a; and a 60 km, 8-inch pipeline from Sana'a to Amran. The primary objective of this option is to supply future combined cycle power plants in the Nabar-Sana'a-Amran "corridor" and the existing cement plant at Amran. Demand under this scenario is forecast to grow from 12 macfd of gas in 1994 to about 61 mmcfd in 2005. This option provides sufficient capacity to supply other industries and, eventually, urban commercial and residential consumers in the corridor and in Narib. Total Investments are estimated at US$193 million, of which US$139 million for the pipeline and US$54 million for compressor units to be built after 2010. (ii) Option II's components are a 224 km, 22-inch pipeline from Narib to Nabar; 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 pipeline from Nabar to Bajil and Ras Khatenib, where the existing cement and steam power plants would be converted to gas use and where future cement plants could be served by the pipeline. Investments in the pipeline would total US$220 million, and in compressor stations to be installed 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 grow from 48 mmefd in 1994 to 102 mmcfd in 2005. With additional compressors to be installed in the future, the proposed pipeline for the portion Narib-Nabar could be enlarged to handle future extensions to Taiz and other southern regions if desirable. 6.08 The projected demand for gas under the two options is summari!ed in Table 6.2. - 45 - ! Table 6.2 YAR - Projected Natural Gas Demand j (mmcfd) Pipeline Option I Plieline Option II Cement Yovr Total Cement Power Total 1994 11 1 12 14 34 48 1997 11 14 25 18 48 66 2005 11 50 61 21 81 102 C. Economic Evaluation 6.09 Our economic evaluation vhich is based on a comparison of the costs and benefits accruing to YAR with and without the pipeline, concludes that the gas pipeline project is highly attractive in economic terms. This assessment is based on the quantification of the value of substituting natural gas for other fuels, and the difference in investment costs and efficiency between gas-based and oil-based power generation. Annex VI-1 provides details on assumptions used in our analysis and economic rate of return calculations. All costs and benefits are expressed in constant end-1988 prices and are exclusive of financial costs. 6.10 Benefits. The project's main benefits consist of the value of fuel oil which would be replaced by natural gas, improvements in power and cement plant fuel efficiency, and in the savings resulting from the investment cost differential between future gas-based and oil-based power generation. Using natural gas would allow any excess fuel oil produced by the Narib refinery to be exported at the margin or permit reductions in fuel oil imports. Consequently, the benefits of using gas are based on the cif price of imported fuel oil plus the cost of domestic transport where applicable (to Bajil and Amran). Prices are estimated based on current World Bank projections of crude oil prices and of the differential between crude oil and fuel oil prices. 6.11 Costs. Project costs consist of three main components, namely (i)/the capital cost of pipeline and compressors (para 6.07) as well as the small cost to convert boilers of steam turbines at the power station and cement plants, (ii) operation and maintenance costs, and (iii) the cost of supplying gas from the fields to the pipeline. The estimates of the first two components are based on the GUS. Since the cost of gas, one of the main elements of the analysis, will depend on the outcome of GOY's negotiations with the oil field contractor, we have assumed three price scenarios, namely US$0.50, US$1.00 and US$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 two pipeline options was to determine the most economic meaus for substituting nastral gas for fuel oil. The results are summarized in Table 6.3 which compares the NPV's and ERR's for the two options, with variations in assumptions. The table demonstrates the significant economic benefits, even -46- Table 6.3 YAR - Natural Gas Utllization Project Economic Beneflts OptLon I ODntion II El! A/ zl NPV la ERR Cost of Gas US$0.50/amcf (Base Case) 275.7 24.9 536.4 30.5 US$1.00/macf 235.2 23.2 455.0 27.9 US$2.00/macf 154.1 19.7 292.2 22.5 Capital Cost Increase from Base Case by 251 242.2 22.0 483.9 26.6 by 50X 208.6 19.8 438.4 23.6 Oil Price Scenario lower 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 in power generation and cement production. In both options analyzed, the ERRs are significantly greater than 12X, the estimated opportunity cost of capital in YAR. The benefits associated with gas use are evident particularly in Option II vhich extends the pipeline to Ras Khatenib. Sensitivity tests indicate that even with real capital cost increases of 25X and 50%, or with a higher gas price, or with a fall in the international price of crude oil by 251 in real terms from our forecast, the ERR would remain well above acceptable levels. It is therefore recommended that, subject to the availability and deliverability of adequate gas volumes, GOY initiate preparations vithout delay for proceeding with the gas pipeline project, to enable the economy to benefit at an early time from this important natural energy resource. D. Pricina 6.13 As shown in our economic analysis, we assume that the economic cost of production and distribution of natural gas will be below the cost of alternative fuAls presently used by potential gas consumers. Therefore, GOY has to determine how to divide this "rent element", i.e. the difference between the cost of the gas and its value to the economy, among energy consumers, the oil field contractor, the gas distributors and, finally, tha Government. The decision will inter alla, depend on an evaluation of GOY's need for revenue on the one hand, and the effectiveness of promoting industrial development through provision of a cheap energy source on the other. In most industries, expenditures on energy amount to no more than 2-4X of total manufacturing costs. Therefore, increasing energy prices will not significantly affect their competitiveness. The objective of GOY's strategy for natural gas development is the maximization of net benefits to YAR from the use of its hydrocarbon resources. This objective has three important dimensions, each of which implies certain pricing principles: firstly, there must be an incentive to promote efficient use of gas; gas prices must neither be so high as to inhibit consumption, nor so low as to encourage wasteful use. - 47 - Secondly, because of the high front-end costs of natural gas development and its 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 upper bound 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 that have to convert existing boilers from oil to gas, the price of gas has to be set at a level below the price of oil to make the conversion investments attractive; this price differential should allow a recuperation of these investments within a reasonably short time. The lower bound is determined by the long run marginal economic cost (LRC) of supply of gas which comprises the costs of exploration, development and production, transmission and distribution. Since the LRNC falls once the basic infrastructure is in place, this principle has to be qualified: revenue flows to both production and transmission distribution companies should be high enough to cover their full costs including depreciation and sufficient returns on capital, to keep them financially viable. Producer prices can be based either on the "cost plus" method which relates the price of gas to the costs incurred by the producing company, with an additional element to provide the company with a return on the capital invested, or the "market-related" approach which involves identifying the border price of substitute fuels and deducting the cost elements form the point of use back to the well-head (mainly costs of conversion at user level, distribution and transmission). 6.14 Few general guidelines for the optimal structure of consumer prices can 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 a variable 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 towards the definition of a rational pricing policy for natural gas, that (i) in setting price terms for the natural gas producers, GOY ensure that they encourage gas exploration efforts and the future involvement by foreign investors operators in the gas pipeline project, and (ii) cost studies be undertaken to define the upper and lower bounds of possible natural gas consumer prices which should be sufficiently below the price of fuel oil to encourage its substitution, as inputs for the final prices to be adopted and for the more basic discussion of distributing the rent from gas utilization. E. Strategy 6.16 Given the attractiveness to YAR of developing its potential for utilizing natural gas, it is recommended that GOY's preparation for implementing the project be based on an action plan aiming at completion of the project before 1994 when new power plants are required to come on stream; this action plan would require setting up an adequate institutioiial framework for an integrated program of gas development and utilization and the assignment of a qualified engineering firm to design an optimum gas project. - 48 - The elements of an institutional framework should include: (i) a joint coordination comittee between the oil/gas field operators and GOY which will oversee both upstream and downstream aspects of project development; (ii) a gas project team to plan the implementation of the gas project and to monitor the future development of gas resources; the leader of such a team should be a member of the JCC; experience elsewhere shovs that this group would eventually evolve into a national gas company to handle the planning and operation of the gas industry in YAR; and (iii) a market survey group to be formed vithin the gas project team to examine the natural gas market potential including eventually smaller industries and residential and commercial consumers located along the planned pipelines. 6.17 Using the GUS as a point of departure, the joint coordination committee should develop an integrated gas project, incorporating all upstream and downstream components--gathering, treating, processing, transmission distribution, and conversion of consumers' facilities--into the development plan and the project design. Following completion of an agreement with the oil/gas field operators for supplying YAR's future gas requirements, including on the estimated gas availability and cost of production, the principal step is the assignment of an engineering firm to design an optimum gas project which should be fully integrated, encompassing all upstream and downstream components, and estimate investment requirements for gathering, treating, transmission and distribution, as vell as conversion of consumer facilities from liquid fuels to gas. This plan will need to be followed by the acquisition of the needed land and pipeline construction. We estimate that from the time GOY decides to proceed vith the project, implementation vill take about three years. In order for the pipeline to be completed by the time additional power generating capacity is required by 1994, G(Y's decision on proceeding 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 of different aspects of YAR's energy sector and presented our observations and recommendations for action. This final chapter is meant to briefly summarize what currently are the principal options and a strategy which GOY may want to follow, together vith a summary of all the recommendations made in this Energy Strategy Reviev. 7.02 Table 7.1 lists the principal investment options in YAR's energy sector, together vith order-of-magnitude estimates of capital cost and estimated time required for implementation. The "crash program" to make domestic LPG available to replace imports, the design and implementation of which has been initiated, should be vigorously pursued. Preparations for the - 49 - 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 the operating oil company as to the availabilLty and deliverability of associated or non-associated gas, and secondly, assessing the overall hydrocarbon potential of YAR with the help of outside experts, resulting in the formulation of a coherent hydrocarbon exploration strategy and in attracting private investors for exploration and the gas pipeline project. Table 7.1 YAR - Enerwv Sector Investment Options Investment Requirements Estimated Proiect (US$ Million) Implementation LPG Production and Utilization 40-60 1989-1991 Natural Gas Development and Pipeline 139-220 1990-1993 Ras Issa Petroleum Handling and Storage (including crude shipment) 107 1990-1993 Petroleum Products Pipeline n.a 1990-1993 Regional Petroleum Products Storages 34-40 New 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 Issa petroleum 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 generating facilities, possibly as early as 1994, may be required regardless of the source of energy, i.e. natural gas or imported fuel oil. Other investments in power transmission, distribution and normal development should be implemented as nov planned. - Concerning the second refinery, this project is economically not attractive, also, sufficient oil reserves have not been proven in YAR to ensure 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 aspect meriting GOY's early attention. It is recommended that adequate provisions be made in the planning for domestic public financing of such projects, and that contacts be initiated with bilateral and multilateral sources of public and private funds; early decisions by GOY as to the involvement of the private sector, possibly in the form of "build-operate-transfer" or similar schemes, would help in structuring, designing, implementing and funding these projects which in their scope and complexity go beyond YAR's institutional capabilities; consideration should be given to obtaining the services of specialized consultants or international banks for this purpose. - 50 - 7.05 To the extent funds are available under the IDA Credit for Technical Assistance to the Petroleum Sector, these can be allocated to financing some of the studies recommended in the preceding chapters. The World Bank stands ready also to consider supporting separately the development and implemen- tation of any economicall- attractive investment project in YAR's energy sector, such as the natural gas pipeline and the Ras Issa storage and pipeline facilities, or additlonal hydrocarbon exploration. It is recommended that GOY develop with urgency a core investment plan for the energy sector on the basis of which discussions could take place at an early stage with the World Bank and other international agencies to review possibilities for fundting, and with the Bank regarding its possible role in project promotion and the coordination of funding from other sources. 7.06 This section lists in summary form the recommendations made in this report (with references to the paragraphs where each is discussed in detail), where possible in order of priority as perceived by us and classified by the ministry or agency likely to be charged with considering and implementing them, as follows: (i) Ministry of 0.l1 and Mineral Resources 1- Hydrocarbon Availability (a) MONR should continue and expedite its negotiations with YEPC on the availability of gas, and if it becomes clear that a satisfactory agreement cannot be reached, invoke arbitration under the terms of the PSA. (Paras 2.16 and 6.04) (b) If possible under the Alif field production profile, the availability and deliverability of Alif associated gas should be confirmed and steps be taken to permit its early utilization in substitution for costly imported fuel oil in power generation and cement production. (Para 2.14) (c) MONR should commission a brief review of the gas subsector to identify the next steps required for appraisal and delineation of those non-associated gas discoveries which appear economically viable, and to recommend a program for appraisal and development of the discoveries in close coordination with YEPC; a coordinated natural gas development plan should be designed and Implemented. (Para 2.17) (d) MONR should carry out an independent comprehensive review of YAR's overall hydrocarbon prospects, with a view to preparing a long-term perspective exploration plan for utilization of the country's hydrocarbon resources. (Para 2.05) (e) MOHR should establish a comprehensive hydrocarbon exploration policy which would (i) clearly define the role and responsibilities of both the private and public sector entities vis-a-vis the country's needs, (ii) aim at optimizing YAR's hydrocarbon resource utilization, and - 51 - (iii) introduce a competitive approach to petroleum industry operations. (Para/2 .04) 2- Natural Gas Utilization (a) MONK should develop and implement a coordinated natural gas development plan covering both upstrem and downstream aspects. (Para 6.04) (b) Subject to the avallabilLty and deliverabllity of adequate natural gas quantities, GOY should proceed with the development and implementation of a gas plpeline project at an early stage to enable YAR to benefit from lts important natural gas resources end to avoid having to install additivonal fuel-oil based power generating capacity. (Paras 4.17 and 6.12) (c) Preparations for implementing the natural gas pipeline project should be based on an action plan aiming at completion of the project before 1994 when new power plants are required to come on stream; this action plan would require setting up an adequate institutional framework for an integrated program of gas development and utilization, and the assignment of a qualified engineering firm to design an optimum project. (Para 6.16) (d) MOKR should ensure that price terms to be set for natural gas producers encourage exploration efforts and the future involvement by foreign investors/operators in the gas pipeline project; cost studies should be undertaken to define the upper and lower bounds of natural gas consumer prices, to serve as a basis for distributing the rent to be derived from gas utilization. (Para 6.15) (e) For the short and medium term, natural gas utilization plans should focus only on the use of gas as a source of energy for the domestic requirements. (Para 6.05) 3- Liquified Petroleum Gas (a) Since it may be over ambitious, the larger LPG bottling project should be re-evaluated in light of the results of the recently completed study under the LPG "crash program". (Para 5.10) (b) MOHR should (i) examine whether bottling and distribution of LPG can effectively be assumed by YPC inT the short to medium term or whether a separate autonomous agency would be more appropriate, (ii) establish a separate agency, or a new department vithin MONK, to oversee LPG regulatory and control functions, and monitor the impact of pricing and other policies on safe and efficient supply, (iii) within the framework of the long-term plan for developing LPG resources, implement policy, pricing and institutional measures to improve the economics and operational efficiency of the LPG distribution network, - 52 - and (iv) provide incentives for the private sector to assume responsibility for an Integrated distribution network. (Pars 5.16) (c) NONR should develop national safety codes and standards and implement them to assure safe operations within the LPG supply network. (Para 5.13) (d) MONR should undertake further work towards the development and more widespread use of low cost LPG appliances. (Para 5.12) (e) MOHR should take adequate measures in support of a managed transition to higher LPG consumption, undertaking appropriate investments and implementing policies and programs which encourage the substitution of fuelvood and petroleum fuels. (Para 5.06) 4- Petroleum Products (a) MOIR should carry out a detailed study to develop a master plan for the Ras Issa project, define the physical facilities required, develop their engineering, estimate their capital and operating costs, and confirm the economic/financial justification of the required investments; it should also update the analysis of the multi-products pipeline project developed in 1983. (Para. 3.19) (b) MOHR should conduct a brief study to confirm the economic benefits of continued operation of the Marib refinery. (Para 3.11) (c) MONR should launch a program of improved training of Yemeni personnel in refinery operations, and to adjust operations to optimize its yield pattern. (Para 3.10) (d) MOMR/YPC should engage specialized services to establish adequate systems for assembling country-wide petroleum sector statistics, including data gathering, interpretation and demand projections, and provide training of a core of Yemeni personnel for this purpose. (Para 3.07) (e) Since it is not economically viable, the Second Refinery Project should 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 followed by implementation of adequate institutional arrangements for planning the future development of LPG resources. (Para 5.09) (b) YPC should expedite implementation of bulk distribution of LPG and increase the stock of usable LPG cylinders to eliminate shortages which could dampen the benefits of the planned increase in LPG production and bottling capacity. (Para 5.11) - 53 - (c) Spiking of fuel oil from the larib rofinery into the export crude should be considered as soon as possible since supplying lt as fuel to coastal power plants does not appear econosical. (Para. 3.12) (d) With the help of specialized assistance, YPC should strengthen its tank farm maintenance arrangements and measurement systems and Increase the training of Lts operations personnel for *11 of its storage terminals. (Para 3.13) (e) YPC should increase its petroleums products storage capacity to ensure an 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 existing structural 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 the benefits of rural electrification either through grid extension or autogeneration, and develop technical standards; it should also formulate a strategy and master plan for rural electrification, including methods of mobilizing resources and mechanisms for compensating YGEC for financial losses associated with providing power to unprofitable reas. (Para 4.21) (c) NEW should carry out further work on the development, demonstration and testing of household photovoltaic systems, and to determine how private sector participation can be mobilized most effectively. (Para 4.22) (iv) Yemen General Electricity Corooration (a) YGEC should design and institute a comprehensive plan to improve its profitability and bring it in line with the levels agreed with IDA; such a plan should consist of both revenue enhancements and cost reduction measures. (Para 4.25) (b) YGEC snould make arrangements for a follow-on phase to its financial recovery consultancy, particularly with regard to the extension of the computerization of billings. (Para 4.24) (c) The line loss reduction study should be completed, and recommended measures should be strictly imposed to reduce losses to a targeted 15X by 2000. (Para 4.09) (d) YGEC should investigate rigorously the causes for high auxiliary consumption 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 enable them to develop long-term plans for power generation and transmission, identify the lowest cost options and determine appropriate standards and risk criteria in accordance with YGEC and GOY policy, (iii) improve rhe budgetary system recently introduced and initiate procedures for establishing a comprehensive cost accounting and management reporting system to bring operating costs under tighter colAtrol, (iv) introduce appropriate delegation of power and responsibility to enable top management increased time for planning and addressing policy issues, (v) improve operation and maintenance management of generation, transmission and distribution facilities, (vi) complete the ongoing training programs, and (vii) implement hands-on training in equipment maintenance. (Paras 1.16 and 4.23) (f) YGEC should install appropriate spare parts management and maintenance control systems to prevent jeopardizing efficient operations in the future. (Para 4.11) (g) Subject to the availability of natural gas, YGEC should introduce gas use and combined cycle power plant technology to meet future generating capacity requirements and convert the existing fuel oil based plant at Ras Khatenib to gas. (Para 4.16) (h) YGEC should up-date its assessment of long-run marginal costs of power supply, the results of which should be used to provide a basis for future 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 ministries should use this framework in a coherent manner to evaluate their projects and policy proposals and implement a policy action program to eliminate existing distortions. (Para. 1.10) (b) GOY should follow up the MOHR Organization Study with a brief but comprehensive review of the roles of the various petroleum sector institutions, with the aim of defining linkages between agencies, delineating authority and responsibilities, eliminating duplication and strengthening personnel policies including on pay scales and incentives. (Para. 1.22) (c) GOY should apply appropriate risk management strategies to cope with the variability in international oil prices; this risk management should relate not only to the enetgy sector per se, but is just as relevant for macro-economic policies and their effect on all sectors of 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 mineral agreements should be based. (Para 2.06) (a) GOT should facilitate energy audits with the help of specialized consultants and provide energy conservation investment icentives to industry and other major consumers. (Para 1.32) (f) GOY should continue to give high priority to skills training for the energy sector. (Para 1.04) 2- Pricing (a) GOY should (i) adopt full economic cost pricing as a min!mum requirement for all fuels except kerosene, (ii) align the relative prices of diesel and fuel oil to their relative international prices, (iii) consider using taxation of petroleum products as a means for raising Government revenues, and (iv) revise petroleum product prices at least once a year in line with movements in international prices and the foreign exchange rate. (Para. 1.30) (b) GOY should allow YPC to revise current LPG pricing and ensure that it fully covers costs and provides a reasonable return on the investments in rationalizing and expanding LPG production and distribution; ex-processing-plant prices should accurately reflect the economic cost of procuring and processing LPG, thereby encouraging least cost supply; retail prices should reflect the economic cost of supply and the relative value of LPG vis-a-vis substitutes. (Para 5.15) (c) YGEC should be alloved to raise service charges and average tariffs in the short-to medium-term and rationalize its tariff structure to better reflect the economic cost of power supply to different consumer categories. (Para 1.31) 3- Investments and Funding (a) Adequate provisions should be made in GOY's budgetary planning for domestic public financing of energy investment projects, and contacts be initiated with bilateral and multilateral sources of public and private financing. (Para 7.04) (b) GOY should develop a core investment plan for the energy sector on the basis of vhich discussions could take place at an early stage with the World Bank and other international lending agencies to review possibilities for funding, and vith the Bank regarding its possible role in project promotion and the coordination of funding from other sources. (Para 7.05) - 56 - (c) GOT shouU. make available adequate foreign exchange to allow YGEC to acquiro full spare parts supplies, especially for the units In its two thermal plants (Para 4.11) The World Bank EN3IE January 1990 - 57 - Annex 1-1 YAR - 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;i Gross Supply YGEC Priv. Production 5600 7404 Imports 96 444 64 62 372 149 Primary xports -7342 Stock changes 390 Total available 5600 452 96 444 64 62 372 149 Conversion Petroleum Reftntng -430 127 144 159 Charcoal Production -600 140 Electrie Pover Generation 811 252 -21 -11 -210 Own consumption -22 .87 -S Trana./diatrib. loss -179 -12 Set Supply Available 1000 140 545 235 96 550 64 62 401 98 Consumption by Sector Industry 121 82 2 111 Comerce 80 94 10 3 Transport 550 62 281 Households 5000 60 194 143 80 64 Public/Other 111 3 Agriculture 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 Totals Gross Supply YGEC Prtv. Production 2070 7404 9474 i yports 102 471 65 63 372 140 1217 1217 Primar Exports -7342 -7342 Stock Chsnges 390 340 Total availablo 2070 412 102 471 65 63 372 140 1217 3739 ........................................................................................................................... .................... Conversion Petroleum Refining -430 136 144 150 430 0 Charcoal Production -222 114 -108 Electric Power Generation 221 112 -22 -I1S -197 -312 -I Conversion lossess Own Cons. -22 -160 .92 -274 Trsnsm./distrib. logs -15 -I -16 Net Supply Available 1848 0 114 46 19 102 189 61 63 401 93 133 3340 Consumption by Sector Industry 11 7 2 64 93 159 177 Comerce 61 8 1 3 3 77 Transport 589 63 281 933 933 Households 1848 49 17 12 85 65 150 2076 Public/Other 10 3 3 13 Agriculture 1 9 85 94 95 ......................................................... ....................................................................................... Source: tission *esiaes - 58 Annex I-2 YAR - ENERGY STRATEGY REVIEW page 1 of 3 EVOLUTION IN GROSS AND FINAL ENERGY CONSUMPTION GROSS ENERGY CONSUMPMON 1988 Stbuetum of Pnmwy ErnW Dwnard 3.8 toe GROSS ENERGY CONSUMPilON 2005 Sbrct, arf Pumwy E&W Ownatd Natuai rmos (i i7%) Fudw=W (t3Dr.) Oil (55.4Z) 6.3 mmtoe - 59 - Annex I-2 page 2 of 3 YAR - ENERGY STRATEGY REVIEW FINAL ENERGY CONSUMPTION 1988 Wwtumtw of Piwot Owiand Ebctiw-iri (I SX) Petaleum Prducts (40A%) Fueiw=Wd/chwcl (57.7X) 3.8 mtoe FINAL ENERGY CONSUMPTION 2005 Stnxtuz 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 3 YAR - 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 GDP RATIOS (in parantheses: % change 2005/1988) Population Growth Non-oil GDP GDP (65%) (56%) (78%) Final Energy Demand 0.89 0.94 0.83 (47%) Commercial Energy Demand 1.37 1.45 1.27 (126%) Fuelwood/Char- coal Demand 0 0 0 (0%) Efficiency Adjusted Fi- 1.07 1.13 1.0 nal Energy Demand (76%)1) 1) 1 too of fuelwood - 0.4 efficiency adjusted toe - 62 - Annex 1-4 YAR - ENERCY STRATEGY REVIEW DOMESTIC UNIT PIICESOF PETROLEUM PRODUCTS PtYR /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 3.00 real price (1980) 2.30 2.55 2.48 2.36 2.10 1.65 1.46 1.20 real gaso. price index 1.00 1.11 1.08 1.03 0.91 0.72 0.64 0.52 cf, US$/tonne 390 406 383 307 307 247 141 176 cf, YR/liter 1.79 1.87 1.76 1.41 1.66 1.80 1.33 1.80 economic consumer pr. 2.34 2.45 2.32 1.91 2.21 2.41 1.90 2.49 net revenue -0.04 0.15 0.28 0.69 0.39 0.19 1.10 0.51 Xerosene, current price 1.50 2.06 2.06 2.06 2.06 2.06 2.30 2.30 real price (1980) 1.50 2.02 1.96 1.87 1.66 1.30 1.12 0.92 real kero. price index 1.00 1.35 1.31 1.25 1.11 0.87 0.75 0.62 cf, US$/tonne 393 418 385 286 286 265 156 180 fc, YR/liter 1.81 1.92 1.77 1.32 1.54 1.93 1.47 1.84 economic consumer pr. 2.22 2.36 2.18 1.64 1.92 2.41 1.88 2.35 net 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 2.41 real price (1980) 1.98 2.36 2.18 2.08 1.85 1.45 1.18 0.97 real Jet-f.price index 1.00 1.19 1.10 1.05 0.93 0.73 0.59 0.49 cf, US$/tonne 306 424 386 313 313 265 156 180 cf, YR/liter 1.41 1.95 1.78 1.44 1.69 1.93 1.47 1.84 econ.cons.pr. 1.74 2.39 2.18 1.79 2.10 2.41 1.88 2.35 net revenue 0.24 0.02 0.11 0.50 0.19 -0.12 0.53 0.06 Diesel Fuel, current pri 0.90 1.65 1.50 1.50 1.50 1.75 2.00 2.00 real price (1980) 0.90 1.62 1.43 1.36 1.21 1.11 0.98 0.80 real dies. price index 1.00 1.80 1.59 1.52 1.34 1.23 1.08 0.89 cf. US$/tonne 350 380 347 347 260 268 138 168 cf, YR/liter 1.61 1.95 1.60 1.60 1.40 1.96 1.30 1.67 economic consumer pr. 1.98 2.15 1.97 1.97 1.76 2.4 1.68 2.16 net 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 1.72 real price (1980) 1.23 1.59 1.43 1.36 1.21 1.09 0.84 0.69 real fuelo. price inde 1.00 1.29 1.16 1.11 0.98 0.89 0.68 0.56 cf, US$/tonne 208 264 242 212 212 172 126 109 cf, YR/liter 0.96 1.21 1.11 0.98 1.14 1.26 1.18 1.11 economic consumer pr. 1.21 1.51 1.40 1.24 1.45 1.60 1.55 1.49 net revenue 0.02 0.11 0.10 0.26 0.05 0.12 0.17 0.23 LPG (12.5 kg). curr. pr. 40.00 42.00 4.00 47.00 37.00 37.00 37.00 37.00 real price (1980) 40.00 41.18 41.90 42.73 29.84 23.42 18.05 14.86 real LPG price index 1.00 1.03 1.05 1.07 0.75 0.59 0.45 0.37 cf, US$/tenne 448 448 352 254 189 cf, 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 0.21 W.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 100 102 105 110 124 158 205 249 Exchange 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-5 PETROLEUM PRODUCTS REAL PRICE INDEX 1.2 1.8 cis 6-41~~1. asI Q7 19aE 19w 19E2 19&3 1984 198e 1988 19Z7 t kla'are O jet-fuud A desd X fuel ail a gasoline v LPG CONSUMER PRICES AND ECONOMIC COST YR /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 Review Historical Consumptionof Petroleum Products (1975-88) (in '000 tons) Diesel Fuel Gasoline Kerosene ATK Oil Oil 1975 49.5 38.8 5.1 94.4 10.0 1976 74.2 50.1 8.9 131.3 10.0 1977 119.6 54.5 15.3 183.7 10.0 1978 139.2 59.2 11.2 200.1 8.0 1979 191.7 53.1 10.2 314.0 9.0 1980 208.1 77.6 24.5 399.1 6.0 1981 207.9 55.0 24.3 365.0 5.2 1982 240.6 73.3 25.8 416.3 24.4 1983 297.4 74.8 23.5 469.8 37.9 1984 257.0 70.7 33.9 477.0 76.4 1985 316.6 77.4 49.0 503.2 216.7 1986 381.0 69.9 51.3 509.7 320.8 1987 459.0 68.1 53.0 544.0 270.6 1988 568.1 63.9 62.0 495.0 289.0 Growth Rate, % p.a. 1975-84 20.1 6.9 23.4 19.7 25.3 1984-88 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; and Fuel Oil: 6.5 Source: MOMR, YPC, and Mission estimates EMTIE 4187P/12 - 5 6Annex III- YAR EEneray $ra1egy Qtviow H-_-ricAl CanIsUmoion/SUR1_y Balances fQr rit1Qly A ProductC1 l19214 "ii (in '000 tons) 1984 M5y 198 12IL7 1988 Gasoline A. SUDO1Y YPC 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]3257 Total Supply _42.55 l3S.Z_ 334.0 458.2 S76.65 S. Consumption YPC Sales 87.82 90.04 194.75 415.74 568.10 'Other' Sales A/ 169.17 226.60 186.24 43.26 Total Consumption _i.99 3164 38Q.99 459.00 / 568.1Q Kerosene A. SUDD1Y YPC 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 0.87 Total Consumption 70.65 77.37 69.8i5 68 Q / 63.90 ATK A. Suply YPC 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 ion YPC 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. Supply YPC Imports 483.73 549.49 303.41 402.45 363.75 'other' Imports __.Q7 4,38 - 3.42 _ 2.13 - 8.25 Total Imports 492.80 553.87 306.73 404.58 372.00 Refinery Supply - 116.i2 115.64 147.5Q Total Supply 492.U 5S3.87 423.35 5a6022 5!9.50 B. 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. 5yuQl YPC 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 161.72 204.32 187.78 107.21 149.40 Retinery Supply _-- - 124.52 L74Q1 164.75 Total Supply 161.72 204.32 312.1 211.52 314.15 B. Conumt5jljion YPC Sales 77.54 81.89 140.74 167.03 148.40 'Other' Sales _/ - 134.83 180.09 103.57 140.60 Total 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/ UOPiCS Cl Kero,cr.e and ATr d/ B. VGE EM'IE i'1q8 P- -66 - Annex I I 1 YAR Energy Strateg g Ryiw Historical 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 1.2 1986 " 47.7 17.3 32.7 O.S 1.8 1987 " SO.9 15.1 29.2 2.6 2.2 1988 " 49.0 20.7 24.5 3.6 2.2 1990 (Projected) SO.0 20.0 24.0 4.0 2.0 1995 " 48.0 22.0 23.0 S.0 2.0 2000 n 49.0 20.0 23.0 6.0 2.0 2005 " 48.0 22.0 22.0 6.0 2.0 Kerosene 1985 (Actual) 18.7 41.7 37.0 2.6 1986 n 22.8 39.2 35.2 2.8 1987 n 23.9 38.8 34.7 0.2 2.4 1988 a 24.2 37.7 34.5 O.S 3.1 1990 (Projected) 24.0 38.0 34.0 1.0 3.0 1995 a 20.0 30.0 41.0 S.0 4.n 2000 a 20.0 30.0 37.0 8.0 S.0 2005 a 20.0 30.0 34.0 10.0 6.0 ATK 1985 (Actual) 62.2 21.7 16.1 1986 a 62.7 22.0 15.3 1987 a 63.7 16.7 19.6 1988 a 62.3 19.5 18.2 1990 (Prajected) 63.0 20.0 17.0 1995 a 65.0 20.0 15.0 2000 a 67.0 20.0 13.0 2005 69.0 21.0 10.0 pResP Qil 1985 (Actual) 45.1 31.6 19.9 3.4 1986 a 45.2 29.4 19.8 2.0 3.6 1987 a 44.7 29.6 18.3 4.9 2.5 1988 " 47.3 24.7 20.6 4.9 2.5 1990 (Projected) 45.0 25.0 22.0 5.0 3.0 1995 a 45.0 25.0 22.0 5.0 3.0 2000 " 45.0 25.0 22.0 5.0 3.0 2005 n 45.0 25.0 22.0 S.0 3.0 Fuel Oil 1985 (Actual) 49.0 S. 0 1986 n 26.8 73.2 1987 " 24.2 75.8 1988 28.7 71.3 1990 (Projected) 29.0 71.0 1995 a lS.O 85.0 2000 1S.0 85.0 2005 a is.0 85.0 A/ On YPC's sales only SourCC. MOMR EM' IE a.tI YAR ENERGY STRATEGY REVIEW Petroleum Products Demand Prolections and Operational Storaae Reauirements (1990-2005 Total Country Sana,a ogdeidah Ta1M Mareb Al-*ikha 12990 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 10,000 Hodeidah 60,000 1aiz 8,200 Kireb 2,800 Al Mukha 14.100 tz - 68 - Annex 111& YAR - Energv Strategy Review Petroleum Product Storaae Capacity (as of end-1988) SANA'A a/ HODEIOAN TAIZ HAREB AL-MUKHA Days Days Days Days Days of 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.; and diesel 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 of days of consumption is for Hodeidah regional consumption only. 4/ Denotes *very high". _/ Average density for all products- 0.82 Source: YPC, MOMR EMTIE 4187P/pl3 - 69- YAR - ENERGY STRATEGY REVIEW RAS ISSA PRODUCT AND CRUDE STORAGE i 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 83 Re.6amoline 4U8 542 600 64 733 9 655 9S 957 1,012 1,211 1,275 1,342 1,414 1,40 1,547 DOntic Kero 60 60 60 60 60 60 59 58 57 54 55 54 53 52 51 50 Jet Futl 70 75 81 a7 93 100 107 M4 122 131 140 149 158 I4 178 189 Dincl 372 395 411 443 469 497 519 541 54 583 78 9 90 854 878 902 Fuel Oil 297 34 404 449 402 407 374 38 12 12 152 158 14 171 178 185 LI 114 19 28 0 0 0 0 0 0 0 0 0 0 0 0 0 Bitum 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 2,791 Total Storage Rqured 0 21 days 58 63 69 74 80 87 91 94 101 104 130 135 141 147 154 161 Incr. Storage 58 5 5 4 4 7 5 5 5 5 24 6 4 6 6 7 Invtstent 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 1.35 at 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 401 and 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 3.00 Cap 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 4.35 Test 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 Savings per 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 25.12 per 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 Case Cast 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 4.35 Benefit 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 20.77 IRR 2t.5S Tnt Case Ceet 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 4.68 llnoftit 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 2005 Total Storage…… - - Required 240000 tons Investent - 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 4.0 Use 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 4.0 Befit 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 10.0 llt 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 6.0 IRA 14.51 eVY 3.5 Test Case Cost 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 4.0 Bnetit 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 10.0 Ibt 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 Case Cost 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 8.3 Benefit 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 35.1 Ibt 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 26.8 IRI 21.61 WV 34.0 Tnt Case Cast 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 8.7 Bmfit 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 24.0 et 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 15.3 a - 70 - Annex ILU Page 1 of 6 YAR - Energy Strategy Review Second Refinery Proiect Economic Analysis Introduction 1. Following the discovery of commercially exploitable crude oil reserves in YAR, GOY commissioned UOP Processes International, Inc./ChemSystems (UOP/CS) to study the possibilities of establishing a second petroleum refinery in the country. We have reviewed this IDA- financed study entitled "Feasibility Study for a New Refinery" of February 1989 which serves as a basis for our analysis. 2. The assessment of the proposed new refinery investment is a function of projections/assumptions concerning: (i) domestic demand for petroleum products; (ii) economic prices of crude and products; (iii) refinery crude slate and products slate; and (iv) economic capital and operating costs of the refinerv. In addition to UOP/CS's sets of assumptions concerning each of the abovementioned parameters, the World Bank and MOMR generated independent or modified projections concerning domestic demand and prices of crude and products. In our analysis of the economic justification of the proposed investment, discussed below, the various sets of assumptions concerning the four main parameters have been combined to generate a number of scenarios for assessing the impact of variations in estimates of demand, prices, crude slate, product yield, and capital investment on the project economic rate of return (ERR). The data sets attached to this Annex summarize the bases and assumptions made by UOP/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 are based on a detailed analysis of historic consumption trends, end-use analyses, and correlations with general economic and sectoral growth trends. Our projections are essentially based on those by UOP/CS, except in the case of fuel oil and LPG, which are based on our independent assessments. The UOP/CS base case demand scenario assumes that in the case of fuel oil demand, natural gas will be made available well before 1994 for a proposed new power station near Sana'a, as well as to the cement plant at Amran, resulting in reduced fuel oil demand commencing 1992-1993. Our "Base Case" demand estimates for fuel oil are based on gas availability to the proposed Sana'a power and the Amran cement plants by 1994 and subsequently to the Ras Khatenib power and the Bajil cement plants by 1997, and on our independent assessment of power demand. The impact of fuel oil substitution by gas on the project has been assessed by a separate variant to our Base Case in which it has been assumed that natural gas will not be - 71 - Annex III-Z page 2 of 6 estimates made by MOMR staff, but modified by us in that the rate of growth from 1996 will be slower than MOMR's implied growth rates, so that it will coincide by 2005 with the level of demand projected by us for each product. This modification to MOMR's estimates is based on the consideration that MOMR's estimates is based on the high, perhaps transient increases in consumption of gasoline and jet fuel which occurred during 1987, and extrapolated to the long-term. Even though MOMR's original long-term projections in our view lack validity, the demand projections as modified by us have been considered as one of the three scenarios to test the sensitivity of the ERR to demand growth. Prices of Crude and Products 4. Our forecasts of economic prices of products t-t Hodeidah/Salif have been built from international crude oil price projections in the Arab Gulf (AG, Light Arab), applying (i) the historical relationships (ratios) between crude and individual products at refining source, and (ii) freight rates for transport of products to Hodeidah/Salif. Two crude price scenarios have been considered: the first based on the World Bank's projections at $15.4 per barrel in 1990 increasing to $21.8 per barrel in 2000 (all in constant 1988 terms), and the second based on UOP/CS's base case projections which are significantly higher. Concerning product prices at source, our projections are based on the average 1983-1987 ratios between crude and individual products in AG, applicable till 2005 as the Base Case, and as a variant, the ratios changing upwards from 1996 reflecting an assumption that the world-wide supply/demand for products will equilibrate by 1995; thereafter the prices and price ratios will be such as to enable full cost recovery of the most efficient new refinery coming on stream by 1995. The latter assumption implies that the current effective refining over-capacity worldwide, which results in refineries recovering only their rash operating costs, will change when, as now postulated, the worldwide demand outstrips supply by 1995. 5. The price relationships (ratios) between crude and products, at source, projected by UOP/CS are essentially similar to ours; those projected by MOMR are the same as those of UOP/CS. Concerning the economic CIF prices: (i) UOP/CS' projections are based on product prices in the Mediterranean market plus a freight rate of about US$14 per ton to Hodeidah/Salif reflecting transport in small (less than 10,000 DMT) tankers because of restrictions in port facilities at Hodeidah; and (ii) our projections are based on the assumption that the Ras-Issa port development and storage facilities to accommodate larger tankers (up to 80,000 DWT) will be justified and will have been implemented before the proposed refinery is commissioned in early 1994; as a consequence, the source of products would be Arab Gulf, with lower freight rates for transport of products to Ras-Issa. Our estimates of CIF prices thus result in lower economic values for imported products, compared to those of UOP/CS, as well as those of MOMR. Crude Slate and Crude Throughput 6. The Feasibility Study is based on a refinery capacity of approximately 60,000 bpd, processing about 75X domestic Alif crude and 251 imported reduced crude from the Arab Gulf areas. There are major - 72 - Annex III-7 page 3 of 6 uncertainties about availability of Alif crude in adequate quantities till the year 2005 (12-year refinery operation commencing 1994). Current indications 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. Although MOMR have indicated the possibility of additional crude oil production from other fields yet to be defined, credible estimates of production rates and more importantly, the quality of crude oil, are uncertain. 7. It is thus not possible at this time to estimate with certainty the crude slate beyond 1996 to be used by the refinery. If, in fact, Alif crude availability declines as currently expected, the deficit of crude for refining will need to be supplemented by suitable imported crude. The impact of this situation has been bracketed by the two separate Bank- developed scenarios where the refinery prou-;-es either Alif crude plus reduced crude or imported crude plus local cundensate, each processed throughout the life of the investment. Thus, two crude slate scenarios have been assumed: (i) UOP/CS' where 75X Alif and 25% imported reduced crude are assumed to be processed; and (ii) our alternative case where 75% Light Arab imported crude and 25% domestic :ndensate from other fields yet to be confirmed, are used. Product yields trom the abovementioned two feedstock 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 production of 100,000 tpy (at 100% throughput) of LPG on the consideration that there will be no production of LPG from Alif field associated gases. The opportunity value of refinery LPG is very high since the freight for transport of imported LPG from source to Hodeidah is about US$100 per ton. Since it is now reasonably certain that investments for LPG recovery from Alif associated gases as well as from other non-associated gas fields will have been justified and implemented before 1994, our Base Case assumes that the refinery will not produce any LPG, and the refinery yield pattern has been adjusted accordingly. However, the impact of having to produce LPG at the refinery on ERR has also been tested as a variant to our Base Case. Capital Costs 9. UOP/CS's estimates of cepital costs are based on U.S. Gulf Coast erected costs (the normal benchmark) in constant 1986 US$; the erected costs at Ras Issa are estimated from the above, using a location translation factor of 1.5. It is further assumed that the proposed Ras Issa product storage facilities will be justified and implemented, resulting in a reduction in refinery capital cost on account of avoided crude and product storages at the refinery. At 7-day crude storage and 15- day product storage, the avoided refinery capital cost is estimated at about US$35 million for grass-roots location at Ras Issa. Taking also into account the additional investment required for linking the refinery with Ras Khatenib power station by a power tranumission line (which is not required in case the refinery is not built), the net reduction in refinery capital cost is estimated at about US$10 million. Road linkages and other infrastructures will be required in either the with- and the without- refinery cases. " our 1 r " a 'vl - , r 1 -9 I - 73 - Annex-III-7 page 4 of 6 ERR has been tested by assuming variation of +101 over the Base Case capital cost estimates. Operating costs as estimated by UOP/CS for the various crude slates and capacity throughputs have been adopted with some adjustments, particularly arising out of changes in LPG production discussed in para 3 above. Although there would be some differences in the capital costs when based on the two different crude slates, these would be relatively minor and have been ignored for the present analyses. For the economic analyses, capital related costs and charges have been excluded. Economic Evaluation 10. Our Base Case is defined by the combination of the following assumptions: (i) demand, corresponding to UOP/CS estimates except for fuel oil and LPG where our higher projections were used; (ii) crude oil prices corresponding to the Bank's crude oil price projections, expressed in constant 1988 terms; (iii) product to crude price ratios based on 1983-87 average spot price ratios in the Arabian Gulf, remaining constant throughout the 12 years of refinery operation; (iv) lower freight rates for Arab Gulf crude to Ras Issa in large tankers; (v) crude slate consisting of Alif (75X) and imported reduced crude (25%); (vi) no production of LPG at the refinery, with adjustments to gasoline and fuel oil production on the base refinery yield pattern as in the UOP/CS Study; and (vii) capital cost based on US Gulf Coast erected cost, using a location multiplier of 1.5, but reduced by US$30 million representing net avoided expenditure when compared with the "no refinery" scenario. The ERR and NPV estimates for the 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 the test cases (RefMisVl), as well as for UOP Base Case (REUOPBa) are shown on page 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 are estimated as follows: First, demand variations as represented by the difference between our Base Case and the MOMR Case (equivalent to about 30X in the initial years of operation, gradually declining to about 91 by 2000 and to nil by 2005, comparisons of RefIis 2 and RefMis 3 scenarios) account for about 0.6% in the ERR. Second, the scenario ReMinMo, which has an ERR of 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 demand is estimated at 0.61 as mentioned above, and the effect of making LPG, at 1.31 (comparison of ReMinMo and ReMinVl). Thus, by difference, the residual effect of product price assumptionu on ERR is estimated at about 171. The implied price variations as measured by the difference in CIF Hodeidah/Salif prices between MOMR estimate and our Base Case estimate, is about 451 in the initial years of operation declining to about 301 by the year 2005. The ERR is thus highly sensitive to price assumptious exemplified further by comparison between our Base Case and RefHis 2, where an 8Z variation in prices results in about 6 percentage point difference in the ERR. Third, regarding the impact of variations in capital cost assumptions, a 101 variation ir capital costs results in a change of about 1 percentage point in the ERR. In summary, while it is very difficult to disa regate the 4' act of -i v' vI' * V ' ' * , , I , C. In - 74 - Annex IIl-7 page 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 net present values (NPV) at a discount factor of 12X for all of the Bank's scenarios, except RefMisVl. The primary reason for the high positivo NPV and ERR for the MOHR cases is the product price assumptions. As mentioned above, the very high product to crude price ratios and high freight rates on top of high base crude prices assumed by MOMR result in 30-45X higher opportunity values for the refinery output. In our view, such high opportunity values are untenable in a responsible economic analysis, and do not form a valid basis for a sound investment decision. The ERR/NPV calculation corresponding to the scenario termed "UOP/CS base case" are based on our calculations using UOP/CS assumptions on demand, and CIF prices but with our adjustments to the capital costs on end-1988 terms and removing inconsistencies in UOP's own calculations concerning CIF import costs and FOB revenues from export product surpluses. The scenario termed "UOP/CS base case" in our analysis thus includes some adjustments to some of the assumptions made by UOP/CS in their own analysis. The ERR calculated by UOP/CS is about 18.61, whereas our analysis shows an ERR of 12.4X due to the adjustments referred to above, and discussed below. Firstly, UOP/CS' latest crude oil price projections in 1988 constant dollar terms is $27.4 per barrel in 1995 increasing to $33.3 in 2000 and to $39.3 by 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, the opportunity value imputed to refinery products in UOP/CS scenario is unacceptably high, and these price assumption variations account for the major part of the difference in the ERR calculations. Secondly, UOP/CS assume that Alif crude will carry a price premium of 51 over the Arab Light marker crude. We have conservatively assumed that there will no price premium which would result in lower imputed feedstock price te the refinery with a small consequent improvement in the ERR. Thir,y y, the imported heavy residue, a part of the refinery feedstock, has been assumed by UOP/CS as 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 of freight from the AG area. The difference is relatively small and will have marginal impact on project ERR. Fourthly, UOP/CS assume that the export of surplus fuel oil will have a value of 1X sulfur fuel oil (rather than 3.51 sulfur fuel oil), and that the export of gasoline will have a value corresponding to premium gasoline (rather than regular gasoline). We have assessed the impact of these assumptions on the ERR as 0.6, and 0.3 percentage points. Fifthly, UOP/CS have assumed that surplus exports of kerosene and gas oil will be to nearer-by markets with no freight penalties, that the production of bitumen will correspond to domestic demand each year with export of surplus in the form of fuel oil, and that the refinery will achieve 1001 capacity utilization from the first year. We find it difficult to accept these assumptions: In summary, the impact of all of UOP/CS assumptions in their evaluation of the ERR, other than the product prices, is relatively small and not likely to exceed about 2 percentage points. Basically, UOP/CS's crude oil and consequent products price assumptions are unacceptable to us. 13. Our scenario RefMis Vl, differs from our Base Case in that the product in crude price ratios will increase from 1996 reflecting a - 75 - Annex III-7 page 6 of 6 hypothesis that the world-wide demand and supply of products will equilibrate by 1995 and consequently product prices will increase to permit full cost recovery by new capacity investments. RefMis VI scenario shows our ERR of 13.31. It should be borne in mind that this scenario also assumes that Alif crude will be available in adequate quantities for 12 years of refinery operating life. If in fact Alif crude availability is not sufficient, resulting in having to import deficit crude, the ERR will reduce considerably. The magnitude of processing local or imported crudes is reflected by comparison of Base Case (RefMis 0), and RefKis 1. To the extent that the refinery has to import crude oil to supplement or replace Alif 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 the various scenarios analyzed. Attachment 2 sets out the data sets on demand, prices, crude and product yields corresponding to various sets of assumptions. 15. In conclusion, we assess that the proposed new refinery is not economically justified, and should not be proceeded with at this time. The project justification may be reassessed in the future, when the international crude prices increase at rates significantly higher than those projected by the Bank now to the levels approaching those projected now by UOP/CS. ja - EnerYv Strateav Review Estimated ERRs for Refinery Investment (Codes refer to data in Data Sets at Enclosure) V A R I A B L E S P r I ca a Crude Slate Refinery Product Product Alif/ Arab Ligbt/ LPG Production Nm Dogd Crudo Ogi Ratio Freight Red Crude Condensate Witlout a I.' a) R*mix 0 (Baes C"e w/ 1.5 CP) D2 PCI PO1 PR2 Fl CS3 - - x 3.2 -131.6 b) Refmis VI D2 PCI PO1 In V1 CS3 - - x 13.3 +26.0 C) Rofmis V2 D2 PCI PO1 FR2 F1 C03 - 2.2 -144.6 d) Refala 1 D2 PC1 PO1 PR2 F1 - CS2 - x -8.1 -237.0 *) Retini 2 DZ PCI PO2 PR2 CS3 - - 9.2 -47.6 f) 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 - 20.1 159.8 b) 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 price ratios from 1996 onwards; (c) Refmis V2 measures impact of producing LPG from refinery, in turn based on assumption that LPG dma.d will not be met in full by recovery from natural gas; td) Refmis 1 measures impact of change in crude slate; (e) Refmis 2 measures impact of biaher import CIP price reflected by sourcing supplies from Mediterranean area and transport in small ships. with Implied assumption that the proposed Alif port development and storage project will not come about; and (f) Refmis 3 measures impact of higher domestic product demand 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 crude price growth rates, somewhat higher product to crude price ratios, higher freights, and 100,000 tpy production of LPG from refinery. The combined effect of price assumptions (crude. ratios, source, and freight) results in significantly higher CIF prices at Hodeidah, wbich translate to about 140-1662 higher by 1995. and 122-1602 higher by 2000 relative to those based on the Base Case. Comparison of this case with 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 consideration that FOM's original estimates of growth rates beyond 1995 did not appear to be tenable), even higher product to crude price ratios It resulting in the highest CIF Bodeidah prices. The impact of not producing LPG at the refinery is measured by the variant case ReMinVi relative to RuMinMo. I, 4. Variable that has been changed with reference to respective base cases are underlined. 0 S. Capital cost estimates in 1988 prices for all our scenarios are US$347 million (including US$6.0 million of working capital); for WP/CS scenario: US$347 million (including working capital); and for MOM scenarios: US$347 million (including US$6.0 million of working capital). - 77 - Attachment 2 to Annex III-7 Page 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 83 Reg.Gasoline 559 630 684 742 806 875 950 997 1047 1099 1154 1211 1275 1342 1414 1488 1567 Domestic Kero 63 60 60 60 60 60 60 59 58 57 56 55 54 53 52 51 50 Jet Fuel 64 70 75 81 87 93 100 107 114 122 131 140 149 158 168 178 189 Diesel 544 545 568 591 616 642 670 692 714 737 761 786 808 830 854 878 902 Fuel Oil * 316 418 401 385 369 354 340 333 327 320 314 308 301 295 288 282 276 LPG 81 86 99 114 132 152 175 186 199 212 225 240 251 262 274 287 300 Bitumen 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 Oil Power Plants - 312 284 259 235 214 195 175 158 142 128 115 - - - - 115 Other 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 83 Reg.Gasoline 560 630 684 742 806 875 950 997 1047 1099 1154 1211 1275 1342 1414 1488 1567 Domestic Kero 64 60 60 60 60 60 60 59 58 57 56 55 54 53 52 51 50 Jet Fuel 64 70 75 81 87 93 100 107 114 122 131 140 149 158 168 178 189 Diesel 544 545 568 591 616 642 670 692 714 737 761 786 808 830 854 878 902 Fuel Oil * 350 482 553 589 654 587 587 559 223 197 173 152 158 164 171 178 185 LPG 96 114 139 148 163 178 193 208 2234 238 253 268 280 292 304 317 331 Bitumen 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 Oil Power Plants 263 354 414 449 478 496 480 446 208 153 116 134 139 144 149 154 160 other 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 83 Reg.Gasoline 560 771 842 920 1005 1098 1200 1232 1266 1300 1335 1371 1408 1446 1486 1526 1567 Domestic Kero 64 60 60 61 61 62 62 61 59 58 57 56 54 53 52 51 50 Jet Fuel 64 74 82 91 101 113 125 130 136 142 147 154 160 167 174 181 189 Diesel 544 545 585 628 675 725 778 790 801 813 825 838 850 863 876 889 902 Fuel Oil 316 418 451 486 524 566 610 559 223 197 173 152 158 164 171 178 185 LPG 96 86 99 114 132 152 175 188 201 215 231 229 242 255 2f" 284 300 Bitumen 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 113 118 121 124 126 129 132 138 144 151 158 165 173 181 189 198 207 Alif S/ton 113 118 121 124 126 129 132 138 144 151 158 165 173 181 189 198 207 Imp.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 1.33 Reg.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 1.27 Domestic 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 1.31 Jet 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 1.31 Diesel 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 1.17 F. 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 0.73 LPG 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 1.14 Bitumen 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 PRICES RCFMIS1 -''' (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 113 118 121 124 126 129 132 138 144 151 158 165 173 181 189 198 207 Light Arab S/ 112 117 120 123 125 128 131 137 143 150 157 164 172 180 188 197 206 Condensate 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 1.33 Reg.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 1.27 Domestic 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 1.31 Jet 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 1.31 Diesel 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 1.17 F. 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 0.73 LPG 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 1.14 Bitumen 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 PRICES REFMIS2 & 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 27.6 FOB AG S/ton 107 112 115 118 120 123 126 132 138 145 152 159 167 175 183 192 201 CIF Ned.S/ton 113 118 121 124 126 129 132 138 144 151 158 165 173 181 189 198 207 Alif S/ton 113 118 121 124 126 129 132 138 144 151 158 165 173 181 189 198 207 Imp.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 1.33 Reg.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 1.27 Domestic 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 1.31 Jet 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 1.31 Diesel 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 1.17 F. 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 0.73 LPG 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 1.14 Bitumen 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-7 Page 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 107 131 138 145 152 160 168 175 182 189 197 204 211 218 226 233 241 CIF Med.S/ton 113 137 144 151 158 166 174 181 188 195 203 210 217 224 232 239 247 (P07) Alif S/ton 120 144 151 158 165 173 184 191 198 205 213 224 231 238 246 253 264 Imp.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 1.37 Reg.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.30 Domestic 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 1.33 Jet 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 1.33 Diesel 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 1.18 F. 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 0.64 LPG 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 1.14 Bitumen 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 PRICES RENINMOD - 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 107 131 138 145 152 160 168 175 182 189 197 204 211 218 226 233 241 CIF Med3./ton 113 137 144 151 158 166 174 181 188 195 203 210 217 224 232 239 247 (P07) ALif S/ton 120 144 151 158 165 173 184 191 198 205 213 224 231 238 246 253 264 Inp.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 1.53 Reg.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 1.38 Domestic 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 1.39 Jet 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 1.39 Diesel 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 1.21 F. 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 0.61 LPG 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 1.14 Bitumen 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. ------------- Et BASE CASE 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 em soi. .... .... .... .... .... .... .... .... .... .... .... .... .... .... .... .... ....276 Prem.Gasoline 156 163 166 169 16 176 173 181 190 199 208 219 229 240 251 263 276 ReD.Gasotine 149 156 159 167 170 174 175 173 181 190 199 215 219 229 240 251 264 Doestic Kero 154 160 164 167 170 174 170 178 187 196 205 215 226 236 247 259 272 Jet fue: 154 160 164 167 170 174 170 178 187 196 205 215 226 236 247 259 272 Diesel 139 145 147 150 154 157 153 160 168 175 184 193 202 212 222 232 244 Fuel Oil(3.5X) 86 90 92 94 96 98 96 100 105 110 115 121 127 133 139 145 153 LPG 207 213 216 219 222 225 183 190 197 205 213 226 235 244 254 264 280 Bitumen 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 2005 e.a e 163 166 169 173 176 1-3 181 190- 199 208 219- 229- 240 25- 23 2 Prem.Gasoline 156 163 166 169 173 176 173 181 190 199 208 219 229 240 251 263 276 ReD.Gasotine 149 156 159 167 170 174 170 178 181 190 199 215 219 229 240 251 264 Domestic Kero 154 160 164 167 170 174 170 178 187 196 205 215 226 236 247 259 272 Jet Fuet 154 160 164 167 170 174 170 178 187 196 205 215 226 236 247 259 272 Diesel 139 145 147 150 154 157 153 160 168 175 184 193 202 212 222 232 244 Fuel Oi(3.5X) 86 90 92 94 96 98 96 100 105 110 115 121 127 133 139 145 153 LPG 207 213 216 219 222 225 183 190 197 205 213 226 235 244 254 264 280 Bitumen 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 162 170 174 177 181 185 189 197 206 215 225 235 245 256 268 280 292 ReD.Gasotine 155 168 166 170 179 177 181 189 1970 21 215 235 235 245 256 267 279 Domestic Kero 159 168 171 175 179 182 186 194 203 212 221 231 241 252 264 276 288 Jet Fuet 159 168 171 175 179 182 186 194 203 212 221 231 241 252 264 276 288 Diesel 144 152 155 158 161 165 168 175 183 191 199 208 217 227 237 248 259 Fuel Oilt(3.5X) 89 94 96 98 100 103 105 110 114 119 125 130 149 172 197 227 261 LPG 211 220 225 230 235 240 245 255 265 276 287 298 310 322 335 348 362 Bitunen 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 162 196 206 216 226 236 247 256 265 275 285 299 308 318 328 338 351 Reg.Gasoline 155 187 196 205 215 224 235 243 252 262 271 285 293 302 312 321 335 Domestic Kero 159 197 206 216 226 236 248 256 265 275 285 295 304 314 323 333 342 Jet Fuel 159 197 206 216 226 236 248 256 265 275 285 295 304 314 323 333 342 Diesel 144 177 185 193 202 211 222 229 237 246 255 263 272 280 289 298 304 Fuel Olt3.5X) 89 104 109 114 119 125 130 135 140 145 151 148 154 158 163 168 167 LPG 211 246 246 254 262 271 304 312 320 328 337 360 368 376 384 393 419 Bitumen 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 162 221 232 243 254 266 279 289 300 311 323 335 345 356 367 379 394 Reg.Gasoline 155 201 211 220 230 241 253 262 272 282 292 303 313 323 333 343 354 Domestic Kero 159 202 212 222 232 243 255 264 274 284 294 305 315 325 335 345 356 Jet Fuel 159 202 212 222 232 243 255 264 274 284 294 305 315 325 335 345 356 Diesel 144 177 186 195 203 213 223 232 240 249 258 268 276 284 293 302 312 Fuel 0il(3.5X) 90 91 95 99 104 108 115 119 123 128 133 136 141 145 149 154 159 LPG 214 246 253 261 269 278 304 312 320 328 337 360 368 376 384 393 419 Birumen 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-7 Page 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 64 Reg.Gasoline 848 1029 1211 1211 1211 1211 1211 1211 1211 1211 1211 1211 Domestic Kero 122 148 175 182 189 197 294 211 218 226 233 241 Jet Fuel 14 17 20 13 6 -2 9 -16 -23 -31 -38 -46 Diesel 550 668 786 786 786 786 786 786 786 786 786 786 FuelOil (3.5O) 216 262 308 308 308 308 308 308 308 308 308 308 LPG 70 85 100 100 100 100 100 100 100 100 100 100 Bitumen 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 2429 Condensate 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 64 Reg.Gasoline 904 1097 1291 1291 1291 1291 1291 1291 1291 1291 1291 1291 Domestic Kero 42 51 60 60 59 58 57 56 55 54 53 52 Jet Fuel 95 115 135 135 136 137 138 139 140 141 142 143 Diesel 550 668 786 786 786 786 786 786 786 786 786 786 Fuel Oil (3.52S) 228 277 326 326 326 326 326 326 326 326 326 326 LPG 0 0 0 0 0 0 0 0 0 0 0 0 Bitumen 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 2294 Imported 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 64 Reg.Gasoline 904 1097 1291 1291 1291 1291 1291 1291 1291 1291 1291 1291 Domestic Kero 0 0 0 0 0 0 0 0 0 0 0 0 Jet Fuel 137 166 195 195 195 195 195 195 195 195 195 195 Diesel 550 668 786 786 786 786 786 786 786 786 786 786 Fuwl Oit (3.52S) 228 277 326 326 326 326 326 326 326 326 326 326 LPG 0 0 0 0 0 0 0 0 0 0 0 0 Bitumen 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-7 Page 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 Net Year 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 Value 1995 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 17.9 1997 330.4 79.3 4.5 16.7 293.0 157.4 19.4 1998 345.8 83.0 4.5 16.7 322.5 150.8 23.3 1999 361.9 86.9 4.5 13.5 355.7 141.8 30.6 2000 378.8 91.7 4.5 13.5 482.2 48.4 42.0 2001 396.5 96.0 4.5 13.5 522.2 34.2 46.0 2002 415.0 100.4 4.5 13.5 553.4 29.3 49.4 2003 434.3 105.1 4.5 13.5 582.6 27.5 52.7 2004 454.7 110.0 4.5 13.5 613.6 25.2 56.2 2005 (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 Net Year 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 Value 1995 256.5 61.6 3.8 16.7 272.2 79.9 13.5 a 12% Discount Rate: 26.4 1996 315.8 74.8 4.5 16.7 322.4 145.9 56.5 1997 330.4 78.3 4.5 16.7 344.4 146.9 61.4 1998 345.8 81.9 4.5 16.7 372.0 143.8 66.8 1999 361.9 85.8 4.5 13.5 404.9 136.6 75.9 2000 378.8 93.8 4.5 13.5 557.6 40.1 107.0 2001 396.5 98.0 4.5 13.5 600.2 25.3 113.1 2002 415.0 102.4 4.5 13.5 632.4 21.6 118.7 2003 434.3 107.0 4.5 13.5 661.9 21.7 124.3 2004 454.7 111.8 4.5 13.5 693.0 21.8 130.3 2005 (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 Net Year 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 Value 1995 358.6 84.0 3.8 16.7 506.2 43.1 a 12% Discount Rate: 7.0 1996 437.3 102.4 4.5 16.7 611.5 50.6 1997 453.4 106.2 4.5 16.7 636.9 56.2 1998 470.1 110.1 4.5 16.7 663.4 62.0 1999 487.5 114.1 L.5 :3.5 691.0 71.4 2000 514.8 112.0 4.5 13.5 732.9 88.1 2001 530.4 116.2 4.5 13.5 754.1 89.4 2002 546.6 119.8 4.5 13.5 776.9 92.4 2003 563.4 123.5 4.5 13.5 800.4 95.6 2004 580.6 127.3 4.5 13.5 824.8 98.8 2005 (34.4) (6.0) 605.4 126.4 4.5 13.5 852.4 143.0 Jsn-90 YEMEN ARAB REPUBLIC ENERGY STRATEGY REVIEW YGEC - POWER SALES PROJECTIONS YR 1987 1/ 1988 1/ 1989 1990 1995 2000 Average _ Price YR YR YR YR YR YR Per KWH GWH Millions GWH Millions GWH Millions GWH Millions GWH Millions GWH Millions Households 1.10 183 208.6 217 247.0 238 261.8 273 300.3 402 442.0 538 592.0 Commercial (100 KW 1.10 55 62.1 57 64.4 63 69.3 68 74.8 91 100.0 120 132.0 Commercial >100 KW 1.10 45 49.5 50 55.0 56 61.1 65 71.5 124 136.0 165 182.0 Industrial (100 KW 1.10 38 42.5 43 48.1 49 53.3 50 55.0 74 81.0 99 109.0 Industrial )100 KW 1.10 20 22.0 22 24.2 26 28.6 29 31.9 44 48.0 59 65.0 Industrial (100 KW 0.65 30 19.5 60 39.0 77 50.5 117 76.0 228 148.0 305 198.0 Amran Cement 0.60 - - - - 30 18.0 70 42.0 85 51.0 140 84.0 Bajil Cement 0.60 - - - - 40 24.0 50 30.0 105 63.0 140 84.0 Al Barh Cement 0.60 - - - - 35 21.0 140 84.0 Yemani - Hodeidah 0.65 - - - - - - 20 13.0 40 - 40 NAB/8isc. Taiz 0.65 - - - - - 22 14.3 60 88.4 60 88.4 Red Sea Flour, Hod. 0.65 - - - - - 36 23.4 36 36 1 Hotels (100 KW 1.10 5 4.9 3 3.3 3 3.8 4 3.8 6 6.6 8 8.8 w Hotels 100 KW 0.65 4 2.6 12 7.8 12 7.8 12 8.4 18 12.0 22 14.0 w Military 1.10 21 23.1 24 26.4 26 28.6 28 30.8 32 35.0 38 42.0 1 Mosques 1.10 1 1.6 2 1.7 2 1.9 2 2.0 2 2 4 2.7 3.0 Water (NWSA) 1.10 17 18.7 20 22.0 21 23.1 22 24.2 27 30.0 32 35.0 Agriculture 0.75 15 11.3 18 13.5 20 15.0 22 16.5 28 21.0 33 25 0 Street 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 2 e _- == - = = _= 1/ Actual EM3IE JM YEMEN ARAB-REPUBLIC ENERGY 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 2608 Isolated Systems 39 39 39 36 35 30 30 Toal iflW In 18 1I Units Sent OtlILgWbl Interconnected System 674 856 1145 1620 1784 2326 3033 Isolated 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 3294 Isolated Systems 59 59 59 54 53 4C 45 IV Maximum Demand tMW) Interconnected System 143 181 224 32T 352 475 595 Isolated Systems 17 17 17 1S 15 12 12 TLal 160 1 7 la 3 4Q bo V Installed Capacity ._M9j a) 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/ Actual KS/yh EM3IE I I IEMEN ARAB _REPUBLI ENERGrYSTRAjEQY 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 2608 Isolated Systems 39 39 39 36 35 30 30 !TQ$ 5i5 6 209 1332 1480 2Q7 2618 II Units Sent Out IGWhI Interconnected System 674 856 1145 1620 1784 2326 3033 Isolated 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'q2 Isolated 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" 588 Isolated Systems 17 '7 17 15 15 '2 '2 IgLai 160 98 21 336 2 4976 9o0 V Installed Capacity (MW) (a) Interconnected System Thermal 310 310 310 310 310 310 310 Combined Cycle/CombustTurbine - - 30 30 240 438 Diesel 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 TvDe A. 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 12.515 Natural Gas (MMCFT) - 464 2,977 9.536 16,750 b. With Gas FirinQ for Ras Khatenib from 1994 Fuel 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 1997 Fuel Oil (t) 210,033 2b4,373 353,559 19b.314 480,478 133.899 93,000 Oiesel 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/ ALtual KS/yh EM3IE - 86 - Annex IV-4 Yemen Arab Reputlie Energy_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 108,595 552,883 661,478 Total - 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 important assumptions: (a) Fuel Oil Prices are based on crude oil estimates of US$15/bbl in 1989 gradually increasing to US$24/bbl in 1999/2000. These prices translate to prices of YR800/ton (including transportation costs) in 1989 and YR1,400/ton in 1999/2000. Diesel oil prices to YGEC have been assumed to remain at the current level of YR2,317/ton throughout the period since this price would still be higher than the internationial price in 2000. (b) Timely Connection of Major Industrial Consumers. The share of electricity consumption by industrial consumers is expected to increase substantially from 23Z in 1988 to 51% in 2000 largely as a result of expected new consumers and expansion of their production facilities. Major industrial consumers, Amran and Bajil Cement plants are expected to be connected on May I and April 1, 1989 respectively. To the extent that industridl consumers are not connected at the projected rate sales forecasts 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? 5 6ross 6eneration (61M) 9Ell 1,009 :.29 1,549 1,672 i,7' 1,949 2,005 2.109 2.251 2,'7 2 4 2 Energy 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 1 Service 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? 46 Other 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 1,071 Salaries and Alle cen 200 220 .24 266 292 327 A60 396 443 487 536 590 649 Mauntenance, materials, etc. 58 B2 92 100 110 120 132 145 160 176 193 213 234 Oeprecisti±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) (7t5 Internt 116 111 101 92 79 65 95 104 1"0 125 130 135 14J Surplusl(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 8IC Revenue Shortfall - 76 102 233 406 539 701 936 979 1,116 1,277 1.426 1.616 4Airagre Net Revalued Assets - ',717 4,439 5,931 7,613 8,906 10,134 11.300 12,402 1,,460 14,470 15,?29 17,061 Actual 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'.5 Target Rate of Rturn 3 - 5 5 5 5 5 5 5 5 5 5 Required 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-5 Page 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 .,364 Energy 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!"7 Line 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:.'7 Strvice Charges 76 94 95 105 it. 120 125 131 139 144 151 !9 167 Capacity Charge 9 12 17 IS 25 27 29 32 S5 ;7 40 43 *e Other 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 645 672 Salaries and Alloancn 2C0 220 242 266 292 327 360 396 443 487 536 590 Mointenance, MIterials, etc. 59 92 92 1O 110 120 132 143 160 176 193 213 DeprKiaton 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; i3451 Interest 116 111 101 92 79 65 95 104 110 110 120 125 129 Surplus/lDeficitl After Interest (55) (77) (70) (33) (103) (15) (262) (2172! (293) (364) (351) (376) (4731 Reuired Surplus Befre Interest - 111 133 292 391 445 503 55q 616 660 71e 7' 927 Revenut Shortfall - 76 102 233 406 539 670 727 799 914 94! 1,029 1.170 Average 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.531 Actual 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) (2.11 Target Rate of Return tl(l -3 5 5 5 5 5 5 5 Required Average Tariff Ircren;e 1tI 10.6 - 10.4 11.2 6.' 5.0 - - 1.9 - O e .5 FILENE: YGECIS2 - 90 - Annex IV-5 Page 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 0 567 595 Gross 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 2,530 Energy 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. 44 Energy 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,"7 Service Chargn 76 94 95 105 111 120 125 131 139 144 151 159 16l Cawcity Chargs 9 12 17 I 25 27 29 32 35 37 40 43 4b ote 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" 626 641 634 414 361 325 353 Wlarin 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 - 193 213 274 krcaitim 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 95 104 110 110 120 125 129 Surplus(kticit3 After Interet (553 (17) (70) (331 (103) 1150) 1262) (272 (2M) (771 1491 1571 (1553 Revired Surplus Bfore Interest - 11 133 m 391 445 503 559 616 660 '71 778 827 Re"Ue Shortfall - 76 102 233 406 53 670 727 ?99 627 646 710 852 Awage 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 5 Required Average Tariff Increase (1) - 10.6 - 10.4 11.2 6.7 5.9 - - - - - - FILEMNAE: YSECIS3 - 91 - ANNEX V-1 YAR Energy Strat3gy Review LPG Project Components and Cost Estimates (in UsS '000) Additional compression equipment (Safer) 1,000 Storage and Truck Loading (Safer) 9,976 Sava'a Bottling Plant 17,000 Infrastructure 1,680 Unloading facilities (Hodeidah) 1,300 Trucks and semi-trailers: 30 5,380 Land 1,000 Site survey/soil investigation 110 Bottles 350,000 8,400 Spares 410 Training/Initial Operations 1,100 Overall Project Management 2,530 49,886 Source: Fluor Daniel N.V. and MOMR MS/yh EMTIE - 92 - Annex VI-1 Page 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 on consultant's estimate. The sizes and costs assessed for the pipelines are on the basis of capacities required to provide gas from the gas fields at Marib to Sana'a to Amran, as follows: US$ Million Pipeline (1993-1994) 1988 Prices 124 km and 22" and 100 km 20" from Marib to Mabar, 80 km 18" from Mabar to Sana'a and 60 km 8" from Sana'a to Amran 161.4 Compressors (2010-2013) 35.1 (b) Conversion of Amran Cement. Conversion of kiln burners for gas firing 0.4 (c) Operation and Maintenance of Pipeline. Annual fixed 0 and M costs estimated at 1.5% ,f the pipeline cost 2.4 (d) Compressors fuel cost. Annual cost 2012 through 2013 0.1 Economic Benefits (a) Fuel oil equivalent. The incremental quantities of fuel oil that would be substituted by gas in the Amran cement plant and the estimated gas consumption of the proposed new power plant in the Sana'a area. The price of fuel oil shown below, has been computed on the basis of World Bank projections of the international price of crude oil through the year 2000. A real increase of 4.81 per annum in international oil price was assumed after 2000. Prices were converted to December 1988 pric s. - 93 - Annex VI-i Page 2 of 6 Proiected Prices (US$/ton) 1990 1995 2000 2005 2013 Crude 117 126 159 207 296 Product Ratios .73 .73 .73 .73 .73 Freight 4 4 5 6 7 Fuel Oil 90 96 121 153 223 (b) Investment Differential. DifferEnce in capital costs. between oil-based and gas-based power gereration over the period 1993-2013. (c) Fuel Efficiency. Reflects the savings in fuel on account of the greater efficiency of the combined-cycle plant over the fuel-based steam power generation. 2. OPTION 2 Economic Costs (a) Pipeline Capital Costs. The sizes and costs assessed by the consultants under this alternative are on the basis of capacities required to deliver gas to the Ras Khatenib steam power station and the Bajil cement plant, in addition to the Sana'a-Amran extension, as follows: US$ Million Pipeline (1993-1994) 1988 Prices 224 km 22" from Marib to Mabar and Sana'a 60 km 8" from Sana'a to Amran and 288 km 16" from Mabar to Bajil and Ras Khatenib 256.04 Compressors (2010-2013) (b) Conversion of Amran and Bajil cement plants and Ras Khatenib power si ;ion 1.80 (c) Operation and Maintenance. Annual 0 and M costs estimated at 1.5% of pipeline cost 3.83 (d) Compressors fuel cost. Annual cost 2012 through 2013 0.30 Economic Benefits Benefits were measured as in Option I with the addition of fuel substitution 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 at Cement Operat. Cost FO Equivalent Invest Plants Coepr. and of -- Invest. Fuel Net Costs Conv. Fuel Naint. 6as Power Cement Oiff. Effic.Benefi 1992 96.8 0.0 -96.8 1993 64.6 13.0 -51.6 1994 0.4 2.4 2.2 1.5 12.5 -6.8 0.4 2.6 1995 2.4 3.4 9.4 12.2 0.0 2.3 18.1 1996 2.4 4.2 14.9 12.8 13.0 3.7 37.8 1997 2.4 4.4 17.2 13.4 -4.8 4.3 21.3 1998 2.4 5.7 27.1 14.0 32.8 6.8 72.6 1999 2.4 6.5 34.3 14.7 -6.8 8.6 41.8 2000 2.4 6.7 37.9 15.4 -18.6 9.5 35.1 2001 2.4 7.3 45.0 16.2 50.4 11.3 113.2 2002 2.4 7.3 47.2 17.0 15.7 11.8 81 9 2003 2.4 8.5 59.5 17.7 -34.7 14.9 46.6 2004 2.4 9.6 72.8 18.5 -50.4 18.2 47.1 2005 2.4 10.7 88.0 19.5 0.0 22.0 116.4 2006 2.4 11.3 98.4 20.4 0.0 24.6 129.7 2007 2.4 11.3 103.3 21.4 9.9 25.8 146.7 2008 2.4 12.4 121.2 22.5 9.9 30.3 169.0 2009 2.4 13.5 141.0 23.6 9.9 35.2 193.8 2010 10.5 2.4 14.7 162.1 24.8 0.0 40.5 199.8 2011 7.0 2.4 15.3 177.6 25.9 0.0 44.4 223.2 2012 10.5 0.1 3.8 15.3 186.4 27.2 9.9 46.6 240.3 2013 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 ENTIE Nay-89 _ 95 - ANNEX VI-I Page 4 of 6 YEMEN - ENERGY STRATESY REVIEW OPTION 2 Gas Distribution Project COSTS 9ENEFITS 6as Value at Cement Operat. Cost FO Equivalent Invest Plants Ccepr. and of -------------Invest. Fuel Nst Costs Conv. Fuel Naint. 6as Power Cement Diff. Effic. Benefit 1992 153.6 0.0 -153.6 1993 102.4 13.0 -89.4 1994 1.8 3.8 8.5 38.6 15.9 -6.8 9.7 43.3 1995 3.8 9.9 46.9 15.6 0.0 11.7 60.4 1996 3.8 11.4 53.9 20.9 13.0 13.5 86.1 1997 3.8 11.6 58.2 21.9 -6.8 14.6 72.5 1998 3.8 13.1 70.1 24.2 32.8 17.5 127.8 1999 3.8 14.2 79.2 26.0 -6.8 19.8 102.1 2000 3.8 14.4 85.1 29.5 -18.6 21.3 99.0 2001 3.8 15.7 100.1 30.9 50.4 25.0 186.9 2002 3.8 16.1 109.3 32.4 15.7 27.1 163.5 2003 3.8 16.6 117.6 33.9 -34.7 29.4 125.8 2004 3.8 17.6 132.0 35.3 -50.4 33.0 128.5 2005 3.8 17.9 141.2 36.8 0.0 35.3 191.5 2006 3.8 17.9 149.7 39.0 0.0 37.4 2C4.3 2007 3.8 17.9 157.1 40.9 9.9 39.3 225.5 2008 3.8 17.9 164.6 42.9 9.9 41.2 236.8 2009 3.8 17.9 173.0 45.1 9.9 43.3 249.5 2010 3.8 17.9 181.5 47.3 0.0 45.4 252.3 2011 10.8 3.8 17.9 189.9 49.4 0.0 47.5 254.2 2012 7 0.3 3.8 17.9 199.2 51.9 9.9 49.8 281.5 2013 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 ENTIE fay-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 89 948 IsnttedoSystmdysin15 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 27 270 326 382 438 468 468 524 580 636 646 666 722 Diesel 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 1032 Totatlsotated 23 23 21 21 20 20 18 18 18 18 18 18 18 18 18 18 18 18 18 18 INKMSTUTS - 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 $000 NT) -Power 12.6 80.9 123.3 135.9 204.2 246.6 259.2 2M.6 29.6 354.5 415.4 476.3 508.9 508.9 569.8 630.7 691.6 724.2 72.2 75.1 -cement 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6 105.6 fuelfactor 1.0 Cin 115/tan) Price of Fuel Oft C CIF Nodeldah) 98. 96 .0 100.0 105.0 110.0 '15.0 121.0 127.0 133.0 139.0 145.0 153.0 160.0 168.0 176.0 185.0 194.0 203.0 213.0 223.0 LocaL Freight Nadeidmh/Pm-a 20.4 20.0 20.8 21.9 22.9 23.9 25.2 26.4 27.7 289 30.2 31.8 33.3 35.0 36.6 38.5 40.4 42.3 44.3 46.4 Cost of Delivered Fuel 1181.4 116.0 120.8 126.9 132.9 138.9 146.2 153.4 160.7 167.9 175.2 184.8 193.3 203.u 212.6 223.5 234.4 245.3 257.3 269.4 Gas Cast 8 Fuel O1Il Equi valent Cin..US$ 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 7.0 Ceiwnt 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 59.1 129.6 143.4 160.5 183.8 209.7 227.4 247.9 270.0 302.8 Not 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 REVIEW Gas for las Katenib in 1994 Gas Distribution Project Project 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 2013 Interconnected System 321 352 383 412 436 456 475 494 513 532 551 595 631 669 709 751 796 844 895 948 Isotated SpSts 15 15 14 14 13 13 12 12 12 12 12 12 336 367 397 426 449 469 487 ~506 525 544 563 607 631 669 709 751 796 844 895 948 Generating 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 774 Diesel 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 1064 Total Isolated 23 23 21 21 20 20 18 18 18 18 18 18 18 18 18 18 18 18 18 18 INVESTNENTS - 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 34.7 Gas 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 35.90 Fuel 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 3.71 Gas 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 2.0 Local 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 46.4 Cost of Delivered Fuel 118.4 116.0 120.8 126.9 132.9 138.9 146.2 153.4 160.7 167.9 175.2 182.4 193.3 203.9 212.6 223.5 234.4 245.3 257.3 269.4 Gas 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 54.3 PROJECT ECONONIC COSTS 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 Gas 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 29.3 PROJECT CNUIC BENEFITS Gas 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*.3 Power 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 0 Net Benefits -153.6 -89.4 43.3 60.4 86.1 72.5 127.8 102.1 99.0 186.9 163.5 125.8 128.5 191.5 204.3 225.5 236.8 249.5 252.3 254.2 281.5 295.7 OPTION 2 EROO 30.5X 20-year (1994-2013) .- -- NPV 8 12X 536.4 MAP SECTION YEMEN ARAB REPUBLIC V 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 | - , __ C,^dsO;lPipe. Oi LPG Bo .g Po'- P,.p..d CI P, \d, P pLne 0 LPCbAngFo LL (PIo,r,,.dl E-6rig Rotn-y NPop-ed Ro5r -nd Pnod-co Pont ( l L Exisi~~~~~~~~~~~~~~~~AnP on De C on.on. onAnn POodeI yr3cods A E..~,, Pnopd o.o ~ S,ooo' d N-YRood, . .OflOSIo- Ppwer Plo Noo Cgpi=h \ * ,zd.h rA E_fsinE T-= onsoionSo 0 To-o \ 0 So odk c . o PIon. d 132 kV Dcammion Lma W odi \ 2 \ - r _ Exi9 D9~~~~~~UO 132 kV TUnmsso o- _ -- llpo Eud 0 20 40 60 t0 100 _ J C \ KI~~~~~~~~~~~~~~~~~~~~~LDM0TE*S tu .or dl . X < All H MILES 18- \iKh_ H i p anb OA ;I X~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ AonI Od Fold wtil A. ° /~ ~ '' Abi l ., Hw iY Al Al Fi\h A' IQ doW /\ / f-l- 14- 4 ' o' '',' .~~~MA'.,.__/_ E ./ D I I BO UT A