MYANMAR: REPORT No. 10394-BA ENERGY SECTOR INVESTMENT AND POLICY REVIEW STUDY March 16, 1992 Industry and Energy Division Country Department II Asia Region FOR OFFICIAL USE ONLY MICROFICHE COPY Report No. 10394-BA Type: (SEC) MALHATRA,A/ X82874 / F10033/ ASTEG Document of the World Bank This document, prepared for UNDP under a World Bank executed project, has a restricted distribution and may be used by reciplents only In the performance of their official duties. Its contents may not be disclosed without authorization from the UNDP or the World Bank. FOR OFFICIAL USE ONLY MYANMAR ENERGY SECTGR INVESTMENT AND POLICY REVIEW Table of Contents Executive Summary .... . . . . . . . . . . . . . . . . . . . . . . i I. THE ECONOMY AND ENERGY DEMAND ..1 A. Introduction . . . . 1 B. Energy Resources and Production . . . . . . . . . . . . . 4 C. Energy Consumption . . . . . . . . . . . . . . . . . . . 6 D. Forecasts of Energy Demand . . . . . . . . . . . . . . . 9 II. ENERGY RESOURCES ....................... 14 A. Introduction . . . . . . . . . . . . . . . . . . . . . . 14 B. Oil and Gas . . . . . . . . . . . . . . . . . . . . . . . 14 C. Coal ........................ 18 D. Geothermal ....................... 22 E. Hydro. ...................... 22 F. Traditional Energy ........... .... ... . 23 G. Conclusions . . . . . . . . . . . . . . . . . . . . . . . 23 III. OIL AND GAS SECTOR . . . . . . . . . . . . . . . . . . . . . . 25 A. Introduction ..................... . 25 B. Onshore Oil and Gas Reserves . . . . . . . . . . . . . . 25 C. Oil and Gas Field Development . . . . . . . . . . . . . . 27 D. Oil Production Forecasts ............... . 30 E. Onshore Gas Production Forecasts . . . . . . . . . . . . 32 F. Noattama Offshore Gas Development . . . . . . . . . . . . 33 G. Major Issues in Oil and Gas Sector . . . . . . . . . . . 36 H. Conclusions and Recommendations . . . . . . . . . . . . . 37 IV. THE REFINERY SECTOR ........... ....... 39 A. Introduction ........ ......... 39 B. Petroleum Products Consumption . . . . . . . . . . . . . 40 C. Supply and Demand ................. 41 D. Issues in the Refinery Sector . . . . . . . . . . . . . . 42 E. Investment Profile ............... . . 44 F. Conclusions and Recommendations . . . . . . . . . . . . . 45 V. THE POWER SECTOR . ...... ....... . 48 A. Introduction . . . . . . . . . . . . . . . . . . . . . . 48 B. Generation, Transmission and Distribution System . . . . 48 C. Demand Forecast.. ................ 52 D. Generation Investment Plan . . . . . . . . . . . . . . . 53 E. Transmission and Distribution Development . . . . . . . . 58 F. Investment Profile ................. 60 G. Marginal Costs of Supply . . . . . . . . . . . . . . . 60 H. Issues in the Power Sector . . . . . . . . . . . . . . . 61 I. Conclusions and Recommendations . . . . . . . . . . . . . 63 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.| VI. TRADITIaL BNOWGY SICTOR ............ ... ... . 65 A. Introduction . . . . . ................ . 65 D. The Resource ase . .. . 66 C. Sustainable Yield ef Woodfuels ..... . . . . . . . . 69 D. Consumption and Demnd . ........... . . . .70 B. Investments, InstLtutLonal and Policy Issues . ... . . 73 F. Conclusions and Recoendations .... . . . . . . . . . 75 VII. ERGY PRICING . . . . . . . . . . . . . . . . . . . . . . . . 77 A. Introduction .77 S. Crude Oil and Petroleus Products .78 C. Natural Gas .83 D. Electricity Tariffs ...... .. . .. . .. . . 86 E. Coal Prlces .... . . . . 88 F. 'raditional Energy Prics .89 C. Conclusions and Reco_smendatlons .90 VIII. INSTITUTIONAL AND FINANCIAL ISSUES AND INVESTMENT PROGRAM . . . 92 A. Institutional and Flnanclal Issues .92 B. Investment Strategies .98 C. Investmnt Profile .103 D. Financial Requirements ................ . 104 1.1 MP by Sctor 1.2 Erergy Bltace Taloes 1.3 Oil and G" Productfon & Consuption (1976-1990) 1.4 Petroltm Production Consmption (197-1990) 1.5 Cool Production & Contaption (1978-1990) 1.6 Electricity Production & eAruptfon (1976-190) 1.7 Energy Conwqption Foreats 1.6 Petroltm Product Cc . mt' n Forecat 1.9 Electricity Dow_d Forecast 1.10 Ga Supply Forecast 2.1 Nyurmr: Post Discovery ad Future Potential for Ofl en Ga 2.2 Cost Reserves In KIlee 3.1 Oil Production Forecast - Baic Aass tion 3.2 Oil Production Costs 3.3 GCs Production Costs 3.4 Noatt_n offshore Gas Production Costs 4.1 NE plant characteristics 4.2 Main Ptroltu Products Production and ODstribution 4.3 Product Exports 4.4 Demwnd Forecast Scerio and Assumptions 5.1 Industrial Electrfcfty ConruAption 5.2 Existino and Expected 2ehabilitated Condition of UEPE Gan ntting Plant 5.3 Existing and Comaitted Transmission Lires 5.4 Electricity Dem nd Forcats - gate, *saAptions wd results 5.5 Transmission and Substation Invest_ nts 5.6 Distribution Inv*stuanto 5.7 Capital investment Plan For Transmissfon and Distribution 5.8 Computatfon of Long Run Narginel Cost of Supply 5.9 Suvnery of NEPE Tarfffs 6.1 Estimtes of 'oodfuet standing stock 6.2 Crop residLes viable for fuel 6.3 Woody nd non woody bimes consauption estim_tes 6.4 Charcoal production nd transport costs 6.5 Cost of fuelwood collection and transport 7.1 Energy Prices in Nyw.uar - 1989 7.2 Petroletm Product Prices 7.3 Electricity Tariffs 7.4 Price of Charcoal 8.1 Organization of the Energy Sector 8.2 Flincial statements nd analysis of energy entorprfses 8.3 Detailed Investment Profile an IRD 22977 Union of Nyanr IRD 22979 Geologic Basfns IMb 23051 Coal Deposits IM 22974 Power Systm IURD 22978 Forest Resource ItD 22976 Hydrocarbon Resources This report is based on the findings of an -e.gy sector misslon that visited Myanmar in November, 1990, and discussions with the Government of Myanmar at an energy symposium held in Yangon in January, 1992. The mission comprised: 1. Anil K. Malhotra, Principal Energy Specialist/Mission Leader 2. Hossein Razavi, Principal Energy Economist 3. Etienne Linard, Senior Power Engineer 4. John Irving, Power Engineer 5. Peter Eglington, Energy Economist 6. Moiffak Hassan, Reservoir Specialist 7. Thomas Fitzgerald, Geologist 8. Sadhan Chattopadhya, Coal Specialist 9. Isidoro Lazzarraga, Refinery Specialist 10. Paul Ryan, Biomass Specialist 11. Alfred Banks, Power Specialist 12. Chi-Nai Chong, Power System Planaer 13. P.T. Venugopal, Financial Consultant 1 AEECUTIVE SUMKARY A. Background and Objectives 1. Since the early. 1960's, Myanmar has pursued economic policies based on government ownership of economic resources, central direction of the economy, strict government controls and limited interaction with the rest of the world. Beginning in 1974, the government made a number of policy adjustments to revitalize the sagging economy, which, along with external support, helped to temporarily stimulate production. But the partial economic recovery could not be sustained in the absence of structural reforms; and in response to the major deficits and increase in debt service ratio to 36% in .983, the government cut down drastically on investments and imports. In late 1988, the government took steps towards implementation of merrket-oriented economic policies aimed at encouraging foreign capital, restructuring state economic enterprises, stimulating private sector participation and liberalizing the domestic and external trade. The Myanmar economy is now in a state of shifting from extreme centralization towards a greater market orientation and these transitions, combined with present political uncertainty, are severely affecting economic performance and investment planning in the energy sector. 2. The energy sector in Myanmar at present faces a critical situation. Modern energy consumption level is one of the lowest in the world even accounting for the low per capita income. There is significant unmet demand because of severe supply constraints. Industrial production is severely handicapped by shortage of energy. At the same time, the existing sources of supply are deteriorating rapidly for a number of reasons including the use of inadequate and obsolete technology, inappropriate policies and weak sector management. The sector is capital intensive, has incurred substantial foreign debts, and in the past has been prevented from providing domestic financial savings to the government because of excessively low pricing of energy. But it today requires substantial investments just to maintain its existing capability for energy supplies, and for the economy to grow rapidly the capital requirements will be all the greater. However, investments are not likely to result in efficient production and utilization of energy resources unless policy reforms are implemented, notably in technology acquisition, energy pricing and financial management of the sector. A much more systematic effort is also essential to evaluate the various domestic resources, whose potential is uncertain because of inadequate assessments. 3. The purpose of this study is to review: (a) the prospects for development of the country's indigenous energy resources including hydro, power, oil, natural gas, coal and biomasa; (b) the pricing policy for the energy sector; (c) selected operational issues affecting the efficiency of the energy sector including rehabilitation of power, oil and gas sectors; and (d) management and financial issues facing the major entities in the energy sector. Based on this review, a short, medium and long term strategy for national energy development is suggested. il B. £nhrsLfDmand 4. Myanmar has one of the lowest levels of energy consumption in the developing world--0.31 tons of oil equivalent (toe) per capita/yr in 1990. The total use of primary energy in 1990 was 12.3 million toe (or about 250,000 barrels of oil equivalent per day) with primary energy being supplied in the form of fuelwood plus charcoal (76.7%). biomass (6.2%), domestically produced crude oil (5.0%) and imported oil (1.1%), natural gas (8.2%), hydroelectricity (2.7%) and coal (0.2%). In terms of secondary energy the largest consuming sector was household (87.2%), followed by industry (5.6%), transport (3.9%) and other users including fertilizer manufacture (2.3%). There are serious supply restraints which curtail actual consumption of all energy products: at present, electricity is regularly load-shed in all regions of the country; natural gas is insufficient for the gas-fired generation plants, as well as for the fertilizer plants and for industrial use, leading to plants operating at far less than capacity; the availability of petroleum products has dropped precipitously; and rationing is applied even within the government and its state owned enterprises (SEEs). Modern energy consumption has stagnated ovez the last decade; petroleum products consumption has been squeezed down from 7.6 mb/lyr in 1985 to 4.4 mb/yr in 1990, kerosene use has declined from 68.7 million gallons (IG) in 1975 to about 2 million gallons in 1990, and electricity growth rate has decreased to only 3.5% per year from the earlier rates of 8%. The potential demand for modern energy is far higher than present sales. This is also reflected in the traditional energy sector where the consumption of fuelwood has increased in the absence of kerosene and there is considerable overcutting in the divisions adjacent to the cities of Yangon and Mandalay. 5. In view of the fact that present energy consumption is severely constrained by the availability of supplies, and considerable uncertainty exists regarding availability and tiaing of some of the major resources, it is difficult to forecast with any degree of accuracy the future demand patterns for energy. In order to provide an analytical framework for analysis of options, the study used two possible scenarios corresponding with high and low growth rates of GDP. The optimistic scenario assumes a GDP growth rate of 5% but also that a number of essential energy strategy steps are undertaken so that over the period of 1991 to 2005, total modern energy consumption increases at about 5%/yr, with petroleum product consumption at 7.4%/year and electricity at 7.5%/yr. The demand for petroleum products in this scenario would triple from the present consumption of 5.14 mob, while electricity demand on the interconnected system would increase to 7,207 GWh from the present level of 2,371 Glh. The second forecast also assumes that the basic steps of an energy strategy are undertaken but that the economy grows at the slower rate of 3.0%/yr, with modern energy consumption increasing at the rate of 3.1%/yr, petroleum products at 4.5%/yr and electricity at 4.3%/yr. C. DoRestic eSurces of Enerav 6. Myanmar has considerable indigenous primary energy potential, which could in the long term meet these demands. As of April 1990, the remaining recoverable proven onshore oil and gas reserves were estimated at 114 mmb and 13! bcf respectively, while the future discovery potential onshore and offshore is estimated at 800 mmb of oil and 7,000 bef of gas. The total coal resources in place are estimated at about 200 to 230 million tons. Hydropower resources iii are quite substantial, with a theoretical power potential of over 108,000 Ku and 366,000 GWh/yr of average energy. Myanmar has a foreet area of about 31.6 million ha or 47.5% of the total land area of thei country, and this with non- forest trees and agricultural residues provides the potential for substantial and sustainat .raditional energy supplies. But Myarmar has not been able to effectively nore and exploit these energy resources in the absence of appropriate t( nnology, adequate financial resources and market-oriented systems and structures. The Oil and Gas Sector 7. In the oil sector, Myanmar has changed froo self-sufficiency to being in a position of significant deficit in a relatively short period. In 1980 production averaged about 10 million barrels per year and atayed around this level until 1985 before starting its deterioration to the current production of about 5 million barrels. Alarming decline rates in the order of 20% per year have been recorded since 1985- -much higher than would be expected under Vormal oil field operating practices. Myanmar had to import about 0.7 million barrels in 1990 to meet its severely curtailed requirements. Current production forecasts indicate a further continuing slide unless major corrective actions are taken. 8. Reduction in oil production is generally due to the advanced stage of depletion of most of the fields, lack of adequate pressure maintenance, faulty well completion and inadequate surface and subsurface equipment. An increase in oil production would require a major rehabilitation effort in all the producing fields as well as delineation and development of the probable and undeveloped proven reserves. The major targets of the above investment programme would be the Mann and Htaukshabin fields where most of the probable and undeveloped proven reserves are expected to be encountered and the above rehabilitation and development programs will need to depend on a first phase data gathering and appraisal program. 9. The situation of natural gas is equally critical. Based on optLimstic projections of resources, it was generally believed that Nyanmar had ample reserves both onshore and offshore to meet domestic demand for the foreseeable future and to replace the depleting oil reserves. The Bank financed Gas Development project (Cr. 1840-BA) was designed to tap gas from the Paysgon field. However, detailed investigations and field performance in 1988 revealed that the onshore gas reserves were inadequate to meet current consumption levels for much beyond 1991. Natural gas supply from the presently developed and proven onshore reserves is forecast to decrease from 33.3 bef in 1991 to only 1.7 bcf in the year 2000 unless additional reserves are discovered. The decline is projected to be particularly sharp in the Delta and Pyay Embayment areas. In fact, the Delta area is expected to have negligible gas supply in 1991 due to total depletion of Payagon field while in the Pyay Etbayment area free gas production is expected to plunSe from 13.7 bcf in 1991 to 4.0 bcf in 1995 and to cease completely in 1997. The reduction in gas production would be even sharper if adequate compression is not installed immediately at Shwepyitha, and during the next 18 months, at Ayadaw fields. To arrest this production decline--which is due to the advanced stage of depletion of the known gas reservoirs, drops in well productivity and wellhead pressures--or to reduce it as much as possible, would require additional development nd delineation of the unproven gas reserves. iv 10. The deteriorating oil and gas production situation calls for concerted action. The government has already taken the long overdue step of inviting international oil companies to explore both onshore and offshore areas under production sharing contracts. Myanmar awarded explo,ation licenses in 1989-90 to ten companies (or groups of companies) on nine onshore and two offshore blocks with a minimum work commitment of 29 wells, with the first wells being spudded in early 1991. Approximately 32 percent of the estimated future discoveries are covered by these licenses (55 percent of the oil potent;al and 15 perce.at of the gas potential). The decision to award production sharing contracts to snternational oil companies in 1989 has stimulated exploration. But it needs to be noted that even an early success would take three to five years to bring to production after the initial discovery. 11. In the short term, Myanmar Oil and Gas Enterprise (MOGE) will need to take urgent steps for the rehabilitation of the existing fields. Increase in oil production will require upgrading of technology, rehabilitation of fields, delineation and development of probable and possible reserves. It is estimated that with an investment of US$668 million, over the period 1991-2005, oil production could be kept at about 9.96 mmb in 1995 and 5.58 mmb in 2005. Onshore gas production from existing fields is, however, unlikely to increase sigaiificantly; even with an investment of US$242 million over the period 1991- 2005 for rehabilitation and development of probable and possible reserves, gas production is estimated to only attain 23.6 bcf per year in 1995 and then decline to 6.2 bcf per year in 2004. These investments will, however, be productive only if appropriate technology is mobilized by MOGE either directly or through production sharing type contracts from the international oil industry. 12. Offshore Gas Field DeveloRment. The only promising prospects are for the development of offshore gas. Substantial gas reserves have been discovered in the Gulf of I4oattama 90 km from the shoreline in water depth of about 45 m. While MOGE estimates the proven reserves to be 7 tcf, according to mission estimates, based on wells drilled till date, the total in place reserves are about 5 tcf, of which about 1.6 tcf can be considered to be proven recoverable reserves. The remaining gas potential could be promoted to the proven category following the drilling of 3-5 wells. A level of production of some 75 bcf could be aehieved for a period of 15 years from the present proven rese-ves in the Gulf of Moattama, which could be increased to 150-175 bcf per year if the additional delineation work succeeds in confirming the gas potential of the 3- DA and MOC-8 structures. Preliminary assessments of three alternative schemes for the development of the offshore gas field: minimum development of 3-DA structure for domestic use only, export to Thailand through a pipeline or export of natural gas products such as liquified natural gas (LNG), indicate that the optimum development scheme would be the export of a minimum level of 108 bef per year of gas to Thailand with a spur pipeline providing about 42 bcf per year to the domestic market. This US$1 billion development scheme, however, depends critically on the level of producible reserves available for export and the availability of external capital and technology. The exploitation of the 3-DA structure for the domestic market, which would include a 90 km submarine pipeline and 180 km onshore pipeline from Moattam to Yangon and require an investment of about US$247 million, could form the first phase of the development scheme thus alleviating the acute energy shortages in the country. v 13. Since offshore gas development provides the best hope for the country's energy economy in the short and medium term, it is essential that urgent stops are taken by the government. The development of the offshore gas reserves requires: (a) additional delineation drilling of 3-5 wells to determine the axtent of the producible reserves; (b) a reservoir slmulation study to evaluate the optimum development plan for the fiold; (c) a detailed feasibility study co determine the exact routing of the pipeline; and (d) formation of a joint venture which could robilize the necessary capital and technology. The Coal Sector 14. The country is estimated to have a total coal resource (proved, probable, possible and potential reserves in place) of 200 to 230 million tons, in numerous deposits mostly of sub-bituminous rank, mainly in the northern regions. The country's two mines produced a total of 38,672 tons in 1989: Kalewa, using underground mining techniques, produced some 12,900 tons and Namma, using open cast mining, produced some 25,800 tons. However, Namma is a short term operation, lacking reserves for any major expansion. 15. The Kalewa deposits are the only significant deposit for consideration for further coal development at the present time, but no serious attempts have been made in the past to develop the mine at a larger scale. However, the high volatile content and good burning characteristics of Kalewa coal make it ideally suited for pulverized fuel or fluidized bed boiler operations, such as for power generation. The knowledge of reserves at Kalewa is presently limited, and reserves estimates range from 26 to 128 million tons of resources, but only about 5 million tons are proven. A mine mouth electricity generation plant of 200 MW would require about 350,000 tons/yr of coal which means that at least some 31.5 million tons of reserves in place should be proven before such a project could go ahe,d. Therefore, a detailed exploratory drilling program of Kalewa is essential. The Power Sector 16. Approximately 94% of electrical energy sold by the Myanma Electric Power Enterprise (MEPE) in Myanmar (1,844 GWh in 1990) is provided from 20 interconnected power stations with a combined available capacity of about 400 MW (54% thermal based on gas) and through an interconnected 230/132/66 kV transmission grid system extending some 600 miles from Pathein city, south-west of Yangon, to Kawlin copper mine rorth of Mandalay. Its associated 33/11/6.6/0.4 kV subtransmission and distribution networks feeding urban, industrial and a few rural loads adjacent to the transmission grid provide service to 10% of the 28 million urban population who live in the main towns and cities of the six principal Divisions of Myanmar. The balance of electrical energy sold by MEPE (94 GWh in 1990) is supplied by numerous isolated diesel and minihydel units scattered throughout the surrounding high country. Fewer than 7% of the estimated nine million rural population in these remote areas, comprising two Divisions and six States, receive electricity and their supplies are usually provided on a restricted 4-12 hours per day basis. These proportions reflect the previous governments electrification policies which have been to promote greater industrial use of power rather than development of the residential or commercial sectors. vi 17. Elctricit, d There Is a considera7le and growing unserved demand ln tho electricity market at present, both because of load sheddiLng as a result of gas and oil shortages for power generati'i4 and because industry itself is short of gas and other inputs and therefore is operating far below capacity. Over the last decade electricity consumption in Myanmar has grown at abotat 8%/yr on a&verage, but since 1985 the growth rate has fallen to only 3.5%/yr. The arerage growth over the decade is modest in comparison with growth in many of Hyanmar's Asian neighbors, despite Myanmar'o low electricity usage (45 kWh/csipita it 1990), and low tariffs (0.48 Kyats/kWh). There are no reliable long term prrjections of power demand presently available but mission estimates that increases in electricity could range from 4.8% to 8.4* oaver 1990-2010, with the power generation capacity tripling the existing capacity in the low case and increasing to about 2,000 KW in the more - imistic case. 18. Generation Ogtions. The current uncertainty a.o4t the availability of the key energy resources makes it difficult to plan for a program of power generation. The availability and volume of natural gas for the power sector plays a particularly important role in any decision on generation expansion to meet the projected increase in demand. Assuming that gas from offshore is available, as is likely if the government makes a concerted effort to attract foreign capital for this purpose, an analysis of generation options using the power sector investment programming package, Energy and Power Evaluation Program (ENPEP), indicates that' the economic sequence of utilizing various sources of energy would be: (a) to utill.ze natural gas for power generation using combined cycle power plants; (b) to fill the gap between the growth in electricity demand and the available natural gas resources with power plants using imported fuel; (c) to replace imported fuel with dowestic coal mine-mouth power plants If they are technically and economically viable in light of projected increases in international fuel oil prices; and (d) to develop hydro resources in coajunction with the combined cycle gas plants depending on the feasibility to develop potential schemes. 1 The letlized costs of generation for power ptants using various fuetl sources at full capacity over a perfod of 20 years are: natural gas with combined cycle ................... 3.41 c/kWh natural gas wlth as turbines ..................... 4.26 c/kIh natural gon with diesel engine .................... 4.8 c/;O coal-domestic (based on coal price of 25/tcn) .... 4.96 c/kWh cotl-iqported (based on coal price of $40/ton) .... 6.22 c/kWh hydro (Punglaung with 40 year life) . .............8 .80 c/kWh fuel oil In stea gonerating plent ............... 8.06 c/kWh vit 19. Based on the projections of power demand In the high growth scenario, the least cost developmetnt program for Nyanmar would be as follows: m MSITIIL P3 T 0 )m (NW) 1969 EXISTING CAPABILITY 3W 1990 TNAKETA/VYWNA (Conversion to diosel) 60 1992 REH3ILITATIOi PROGM compteted 1994 Convert SJN3OMINGIIAN to Combnrd Cyclo 71 1995 Convert THAIETA/NYAAUWOG to Ca1ined Cycte 52 1996 NEW YTANON Comined Cycle 91 50 1997 YAO Comirned Cycle # 2 SO 1996 YTANOS Comined Cyclo # 3 50 1999 YTANGO Cobined Cycle # 4 wid 5 100 2000 YUA retires .36 2000 YANO Comined Cyclo # 6 50 2001 YANOON Cbirnd Cycle # D # 1 100 2002 YANGO Coairwd Cycle 9 9 2 100 2003 PAAINLAN Nro 280 2004 SALUCKAN 93 uydro 48 2004 Retire TNATON/NAWLANTAING -'7 2005 IILIN Nydro 240 2006 YEYTA Nydro 400 2007 NOM CNAUNG Nyro 200 2008 SN1EZATE Hydro 600 2009 KUM CHAG Moro 84 2010 Retire old CT capacity -150 20. The least cost development plan would require the rehabilitation of existing plants to increase fuel efficiency and the conversion of Shwedaung, Mann, Myanaung and Thaketa to combined cycle operation adding 160 MW to system capacity by 1995. Subsequently, up to 500 MW of combined cycle plants would also be required for commissioning in stages beginning in 1996 for a total investment in power generation of around US$600 million up to the year 2000. With gas generating plants comprising over 75% of total system capacity, it would be prudent to commission Paunglaung and Bilin hydro plants as the next major capacity increments (520 KW in total) in 2003 and 2005 respectively. Subsequent development prospects would include Yeywa, Mon Chaung and Shwezaye hydro plants. 21. However the uncertainty about gas availability makes it difficult to take a decision about gas based power development at this time. Analysis of the low gas scanario reveals that in the short and medium term, power requirements could only be met by the import of costly diesel oil while steps were taken to hasten the hydro power developments. An alternative that needs evaluation is that of coal fired plants using domestic coal and located at the minemouth, should exploration at Kalewa indicate the presence of a minimum resource of 35 million tons; or imported coal could be used in Yangon. Both options would be considerably more expensive and require a minimum period of time for exploitation. These alternatives underline the need for the government to move urgently to evaluate and develop its offshore gas reserves. 22. Transmission and Distribution Systems. Under normal conditions the new 230/132 kV system would provide NEPE with a seoure high voltage grid between the Upper and Lower Nyanmar load centers. However bottlenecks caused by limitations in the associated 132/66 kV systems, limlt the capability of the 230/132 kV circuits to carry large loads during emergencies and under some circumstances the system can also become inherently unstable resulting in major load shedding. Furthermore during lightly loaded periods the 132 kV system voltage levels can rise in excess of design limits. These aspects of system operations need to be addressed urgently to improve stability of operations, viii avoid expensive breakdowns and make better use of available generating capacity. 23. In contrast to transmission developments, there has been little matching investment in the distribution networks which have been generally neglected over the last 40 years. Az a result distribution networks throughout Myanmar are in very poor condition and urgently in need of rehabilitation. Losses are high, breakdowns are frequent and poor low voltage conditions commonplace. The major urban ntcworks supplying Yangon and Mandalay being more heavily loaded are in urgent need of reinforcement. The other rural networks are also in poor condition largely because of the unavailability of suitable materials. Distribution system losses, running in excess of 30% of generation in some areas, are worsening the critical demand situation particularly as they increase in intensity duriig peak periods. The situation is worse than it appears in the low voltage (LV) distribution networks because of the high proportion of load that is supplie4' from the transmission 66/33/llkV systems. Recent information indicates LV losses actually lie between 30-50% throughout Myanmar clearly requiring urgent action to make best use of the limited generating capacity. Preliminary estimate indicates that some US$250m is required for general rehabilitation and expansion of the distribution networks in the next five to ten years. 24. Rehabilitation and Maintenance of Plants. The suspension of supply and service foreign contracts and financing has created a serious problem with the maintenance of most of MEPE's thermal generating plants and will lead to an accelerated deterioration of plant reliability. Even new units are curtailed due to lack of repairs. A planned effort needs to be undertaken to (i) provide adequate maintenance and operational spare to existing plants; (ii) carry out rehabilitation and overhauling of existing gas turbines sets; (iii) recommission gas turbine sets to burn diesel oil including the provisioning of diesel oil handling and storage facilities; and (iv) expand selected gas turbine installations into- combined cycle plants. 25. Rural electrification: Unlike most of its Asian neighbors MEPE has no strategy for expanding its rural electrification program. The number of villages electrified rose from 709 in 1979 to only 751 in 1989. Approximately 20% of MEPE's consumers (9% of total demand) are served by isolated diesel/mini hydel power stations scattered over the 14 Divisions/States of Myanmar. The number of diesel engines has increased from 570 by only' 60 since 1985 and the rate of growth of new consumers and consumption in these areas is significantly lower than for the interconnected system. A detailed rural electrification study needs to be carried out to draw up a plan for supply of electricity to the rural and remote communities. fefinery and Petrochemical Sector Issues 26. Refineries, methanol, urea and Liquefied Petroleum Gas (LPG) plants are all operating at much below their design capacities due primarily to absence of adequate crude oil and gas. The three refineries, with a design capacity of 18.9 mob per year processed 4.8 mmb in 1990, down sharply from about 9 mmb in 1989, and are operating at 25% of capacity. The 450 tons per day Seiktha methanol plant runs 1 out of 3 months at 60% capacity; two of the urea plants are shut down ancA total production averages 582 tons per day as against the total plant capacity of 1,272 tons per day, while the LPG plant is operating at 63% capacity due to inadequate gas supplies as well as leaner quality of gas. ix 27. The shortage of natural gas has severely curtailed the production at Nyanmar's four ammonia-urea plants; Sale A, Sale B, Kyunchaung and Kyawzwa. In the year 1990 total urea production was 45% of the installed capacity. The Kyawzwa plant was completely shut down in May 1990. Sale A and Sale B have had enough gas supplies but their production has been limited by a lack of spare parts and equipment problems. In 1989 these urea plants were using from 20% to 100% more gas per ton of urea than their design capabilities and it would therefore be efficient to undertake a debottlenecking study at the same time as the plants were rehabilitated. The fertilizer plants at Sale A and B and at Kyunchaung should be rehabilitated with an investment of US$11 million. Losses in all the plants are significantly higher than those at comparable plants in other countries cnd there is a need for an operational audit for control of losses and energy conservation. 28. The Seiktha methanol plant has also been starved of natural gas, and it has been operating at minimum capacity, on an intermittent basis, resulting in a total annual production of about 30% of design capacity. As a result production costs of methanol (excluding the cost of gas) are high. The economic options are either to shut down the plant or to run it at a much higher feed rate. Traditional Energy 29. The biomass fuel resources of Myanmar consist principally of woodfuels (fuelwood and charcoal), but there is also a considerable quantity of agricultural residues that could be used for fuel without adversely affecting soil fertility or animal husbandry. In 1990 woodfuel consumption was estimated to be approximately 28 million air dried tons (adt), equivalent to about 9.4 million toe, and the non woody biomass consumption was 0.9 million toe. However, there is a scarcity of reliable data on the standing stock and sustainable yield of woodfuels and on the quantity of agricultural residues available for fuel. It is estimated that the annual per capita consumption of woodfueIs is 0.7 adt and the overall sustainable woodfuel supplies for the country are only about 75% of the 1990 consumption. When woodfuel consumption and sustainable supply are compared on a state/divisional basis, the results show that, despite 45% of the country being covered in forest, there are today serious deficit situations in Central and Lower Myanmar, which by the year 2000 are projected to rise to 8.4 million adt in the woodfuel catchment area supplying the city of Yangon and 7.6 million adt in the area supplying Mandalay. These projected deficits will lead to serious overcutting of the forest particularly in the divisions of Yangon, Magway and Ayeyarwaddy. It is also expected that continuing agricultural encroachment .n these areas will exacerbate the destruction of the forests. The large areas of mangroves, that are prime sources of charcoal and fuelwood, are being particularly affected in Ayeyarwaddy Division and, with the depletion of preferred stocks there, Rakhine and Tanintharyi Divisions are now being affected. No studies have been done on the detrimental effect on fish stocks, but continued degradation of the mangroves may adversely affect these as well. 30. Woodfuel development and conservation must, however, be done within the framework of a national woodfuel strategy that considers interfuel substitution. There are several policy and institutional issues that need to be resolved before effective investment can be made in any woodfuel development and conservation program. At present villagers are permitted to grow trees or collect wood for their own use, but are not permitted to sell such wood u.tless x they obtain a license to cut and royalty is paid to the Forest Department. The current system of establishing quotas for charcoal and fuelwood production is in serious need of revision, particularly for those divisions that are in a sustainable woodfuel deficit situation. The current royalty of kyats 2 per 90 lb bag of charcoal and kyats 5 per stacked ton of fuelwood, equivalent to kyats 6.5 and 10 per adt respectively, are far from representing the economic or financial value of the wood on the stump. Without higher stumpages it would be difficult to justify government investment in woodfuel development programs or to encourage the production of woodfuels by the private sector. Government policy should encourage and support the production of wood for both subsistence and commercial purposes by the private sector, particularly by rural households. The setting of quotas should be rationalized in the context of sustainable supplies, rather than short run feasible supplies. 31. A major woodfuel development program needs to be undertaken and one of the first priorities of the program should be to carry out woody biomass and household energy consumption surveys. For urban areas, the immediate strategy should focus on improved charcoal production and woodstove programs; pilot programs for improved management of deciduous and mangrove forests and a feasibility study for peri-urban plantations. In the rural areas, action should be focused on enhancing the seedling distribution program to the villagers and development of a system of grassroots forestry extension. D. Energy Pricin. 32. A recurring difficulty in evaluating and setting domestic energy prices in Myanmar is the foreign exchange rate situation. Myanmar government have not changed the grossly overvalued exchange rate for more than a decade despite a widening gap between the official and parallel market rates. At present in the parallel market, the value of kyat is nearly one tenth of its official price of 6.2 kyat to the dollar. Maintaining such an overvalued exchange rate leads to inefficiencies in its use, adversely affects incentives to produce, reduces government revenues and results in scarcities. Even assuming an exchange rate of k50/US$, energy prices in Myanmar are extremely low: the present official prices translate into US$2.20/barrel for crude oil, US$0.21/IG for diesel and US$0.32/IG for petrol, which would be some of the lowest diesel and petrol prices in the world - with consequent huge excess demands and lack of supply. Electricity tariffs were revised in 1988 to an average of 0.48 k/kWh but they are still very low by international standards. The existing administrative procedures and technical criteria for setting of energy prices are cumbersome and inadequate and there is a critical need for alternative pricing systems and a clearly defined pricing strategy. 33. There are two key objectives in setting energy prices: they should be sufficient to provide for financial viability of the energy entities and generate sufficiently high surplus to allow the sector to provide a significant part of its future investment program and secondly, the prices should be set at levels which encourage efficient use of energy and avoids wastef.l consumption. There are serious problems with current energy prices in Myanmar since they reflect neither the economic supply costs nor the opportunity cost of energy. 34. The present method of cost-plus pricing of crude oil tends to lead to shortages of supply because of the difficulties of fully allowing for the costs of exploration and unsuccessful dev'_,.Ipment, and allowing for changes in the xi volume of production, for example following a new discovery, in the unit price calculation. The present low official price of crude oil of 110 kyats/barrel does not provide MOGE with adequate funds for its rehabilitation or development programs. The first critical step in establishing a petroleum pricing strategy is to clarify the method of approach that will be used. It is recommended that the domestic crude oil price should be tied to a suitable international crude oil price, for example a crude oil of similar quality to domestic production and available ex Singapore. The prices of petroleum products could be set on a cost-plus basis using refinery and distribution margins for each product while the price ratios of various products reflect international product prices. These prices would then promote optimal choices among products, discourage waste and eliminate economic subsidies. 35. In the short term since natural gas is in deficit, its price should be at least as high as the estimated cost of onshore gas production, but when Moattama gas is developed there will be a gas surplus and the netback value from exports should become the guideline for pricing domestic gas. The long run incremental supply cost (excluding taxes) of new onshore gas production has been determined at about US$2.42/mcf. The estimated cost of offshore gas from Moattama, when developed for domestic use only is US$1.74/mcf (including a depletion premium), but this is highly conditional upon the low investment costs associated with using the existing Jack-Up rig. The expected netback at Yangon from export of offshore gas to Thailand is evaluated to be about US$2.10/mcf. The price of gas should reconcile the objectives of stimulating both onshore and offshore development, while not raising gas prices too high which would heavily impact electricity tariffs. Therefore, the mission recommends '.hat the gas price should be set in the range between US$2.10/mcf and US$2.50/mcf. In the short term the price should be at the upper end of this range with the prospect of decreasing it in the future when the netback from exports is realized. 36. Electricity rates have been maintained at too low levels for the effective development of this subsector, and even after the recent hike in tariffs, they are still too low to provide for the efficient use of electricity and to provide sufficient internal cash flow for MEPE to sustain its financial integrity. The tariff structure has been oversimplified, by essentially setting all tariffs at the same level, without any blocks for quantity of usage, and with insufficient attention to the costs of providing capacity which is differentiated by the proportion of consumption taken at higher voltage levels and higher losses in each part of the system. In addition, like petroleum prices, electricity tariffs have been kept fixed for excessively long periods of time in spite of domestic inflation and changes in the costs of operating MEPE. 37. The electricity tariff structure and levels should be related directly to the estimated marginal costs of providing service to respective groups of customers, and levels should be revised periodically, with a six monthly adjustment change, in order to adjust for changing fuel prices, domestic inflation and other changes. Basic criteria should be the estimated long run marginal cost (LRMC) of expanding generation, transmission and distribution in order to meet the forecast demand. At the same time average tariffs must provide for satisfactory internal cash flow to MEPE for it to be financially viable on a long term basis, both in terms of sufficient cash flow for the viability and improvement of its operations and contributing to investment requirements, and to provide an adequate rate of return on the capital employed xii in the utility. To meet the needs of the electricity demand forecast, the average tariff level will have to be increased from the present 48 pyas/kWh to 68 pyas/kWh in 1992 for MEPE just to maintain an accounting breakeven. In the longer term, the average tariffs should be increased to the LRMC to provide for the necessary investments in the sector. 38. Traditional energy supplies, partieularly charcoal also appear to be underpriced, as a result of too low a level of royalties. Over the past decade, although the current kyat price of charcoal has increased, the real price after adjusting for the consumer price index has actually decreased, in spite of serious overcutting of the forests in some regions. The present royalty of k 2/90 lb. bag of charcoal and k 5/stacked ton of fuelwood, equivalent to k 6.5/adt and k 10/adt of fuelwood are estimated to be too low for efficient management of the forerts, which would appear to call for rates in the order of k 38/adt of fuelwood. 39. The fact that the kyat is significantly overvalued makes the pricing decision very complex, particularly for petroleum and gas which are or can be substituted for tradeable commodities. This creates an enormous gap between the financial and economic prices which, in turn, results in major distortions. In such cases it is impossible to ignore the economic prices. The energy prices recommended are considerably higher than the existing prices as indicated in the table below. It is suggested that prices be increa-ed in the first step to meet the minimum financial objectives of the energy entities. These should then be gradually increased to the economic level in the next two to three years. RECOUUENDED ENERGY PRICES IN WYT4UGR (k) Prices Target Existing First Step Miniima Prices at 6.2/USS at 50/USS Crude Oil 110/barrel 155/barrel 1250/barrel Petrol 16.00/IG 22.36/IG 51.43/1G Kerosene 13.50/IC 15.84/IG 45.26/IG Diesel 10.50/IG 15.76/IG 43.29/IG Fuel Oil 8.50/IG 10.63/IG 30.73/IG Natural Gas 7.50/mcf 15.50/mcf 125/mcf Coal 365/ton Domestic price to be tied to international prices with higher royalties if necessary Electricity: Residential 0.50/kWh 0.83/kWh 5.79/kWh Services 0.50/kWh 0.61/kWh 4.14/kWh Industrial 0.40/kWh 0.53/kWh 3.57/kWh Ave. 0.48/kWh 0.68/kWh 4.72/kWh Woodfuels/Charcoal Royelties 6.5-10/adt 38/adt hote: 1. The target petroleum prices shown are net of distribution margins and taxes. The government's tax policty should determine the consumer price levels, but which should be set above these floor amounts, as illustrated in Amex 7.3 (d). xiii 40. All energy prices must be considered together in a policy package and the strategy should also put in place transparent methods for establishing prices and a mechanism for annually reviewing them through the possible creation of an independent Energy Pricing Board. E. Institutional and Financial Issues 41. Institutional Framework. Coordination and Planning. Policy formulation and planning of the energy sector are the responsibilities of the Energy Planning Department of the Ministry of Energy (MOE) created in April, 1985. The Ministry of Energy is responsible for MOGE, MEPE, MPPE, and MPE. Coal development is under the Ministry of Mines (Mining Enterprise No. 3) while fuelwood and biomass are under the Forest Department (FD) in the Ministry of Agriculture and Forestry. 42. Despite announced government policy, the four energy sector institutions do not enjoy autonomy as corporate entities. While they have operational freedom, their production targets, allocations of production, selling prices, foreign exchange requirements, capital investments and budgets are all determined by MOE and Government of Myanmar (GOM). No planning beyond the following year is being undertaken by the enterprises and by the ministries. There is an absence of defined corporate objectives, project eval'.ation systems, mechanisms for the setting of prices to ensure adequate cash flow to cover all costs, debt 5- vice and future investments and incentive systems to er.courage managerial effectiveness. Financial constraints have prevented iiuport of appropriate technology contributing significantly to the poor state of the energy sector. It is recommended that an energy sector financial and investment strategy be drawn up on a regular basis and formally ratified by an Energy Coordinating Committee consisting of the chief executives of the major energy sector institutions and departments and the MOE. All investments in the energy sector which require the commitment of government funds should be in consonance with the approved energy strategy, but the energy sector institutions should have adequate autonomy to implement their investments within the defined objectives. F. Investment Program 43. A preliminary examination of financial needs of the energy sector shows required investments of about US$2,206 million over the period 1991-2000 with the least cost power generation program requiring about US$985 million. For maintaining energy supply at current minimum low levels over the next three years, there is a need for a minimum investment of about US$362 million for various rehabilitation measures. xiv IMTEn I T M S (US$ millIon) SECTOR 1991-2000 199t-1995 1995-2000 FOREIGN FOREIGN FOREIGN TOTAL COST TOTAL COST TOTAL COST Cosl Sctor 6.00 5.00 6.00 5.00 Ofl sector 1026.50 620.30 828.50 518.30 170.00 102.00 Refinery Sector 136.00 87.00 61.00 44.00 75.00 43.00 Poier Sector 964.67 658.00 610.55 418.39 374.31 239.62 Traditional Energy Sector 51.47 12.87 25.74 6.43 25.74 6.43 Total Energy Sector 2.206.84 1393.17 1,531.79 992.1Z 645.05 391.05 fourc2: Nission Estimtes (1991) 44. But for these investments to be effective they will need major import of technology. Investments in the ni and gas sector are inadvisable unless appropriate technology is mobilized by MOGE either directly or through production sharing contracts (PSC) for not only new fields but also for rehabilitation and development of existing fields. While some measures have been initiated by the government for foreign company participation both in oil exploration and production, there is considerable scope for the government to increase the private sector participation in the energy sector: in the rehabilitation of oil and gas fields, in development of unproven gas reserves, in coal exploration and production, and in build-own-operate power plants. 45. While additional measures need to be initiated by the government for greater private sector participation in the energy sector, a substantial portion of the foreign exchange needs of around US$1,393 million will also have to be found from bilateral assistance, commercial loans, supplier credits and multinational agencies. The four energy sector institutions have about US$1.0 billion equivalent of outstanding loans which are mostly official development assistance (ODA). For the last three years, about US$90 million in repayments due and about US$50 million in interests due were not made due to foreign exchange difficulties. It will be necessary to resolve these and other macroeconomic issues for the necessary ODA to resume and for commercial and suppliers credits to become available at reasonable terms. G. National Energy Develogment Strategy 46. Based on the above analysis of the sector development potential and operational issues, the following strategy for energy development is recommended. In the short term (1991-1995). since the power sector will face a critical shortage of fuel supplies, an immediate plan needs to be established and implemented to cover the next three to five years of operation: (a) Conversion of gas-fired power plants to liquid fuel use would require arrangements for the procurement of crude oil for refining and supplying sufficient diesel oil for (i) continuous operation of Thaketa and Ywama power plants and for (ii) standby operation of the Shwedaung, Mann, and Myanaung plants. The estimated fuel requirement to maintain operations with minimum load shedding but limited load growth is about cne mmb/yr. All of the above stations xv should be modified for burning diesel oil/gas; arrangements for transfer and storage of diesel at each site, made and storage and handling facilities commissioned as soon as possible. (b) Rehabilitation of power plants: MEPE must take immediate steps to improve its supply of spare parts and carry out rehabilitation measures at the existing plants. (c) Power Distribution loss control: There needs to be concerted effort to bring the losses down to increase revenue and reduce the incidence of loapd shedding, by reinstating the activities and strengthening the role of the Loss Reduction Unit. (d) Rehabilitation of the onshore oilfields should be carried out on the highest priority; well production equipment, surface facilities, well completions, drilling of 24 data wells and pressure maintenance schemes should be taken up immediately while water injection schemes could await detailed investigations. The established undeveloped proved and probable oil reserves can be developed at fairly low risk under MOGE management but using international consultants and services companies. The exploration and development of possible reserves should, however, be delayed, and/or given over to international companies on a PSC or similar basis. (e) Methanol Plant: In the short term, given the existing shortages of natural gas, it appears advisable on economic grounds to shut the Seiktha methanol plant. It could be reopened when plentiful gas supplies become available from offshore development and if international methanol prices are high enough in the future to make exports worthwhile. (f) Establish Energy Pricing Criteria and an Energy Pricing Board: It will be essential to initiate a pricing reform in support of the investments which are contemplated in the energy sector. This will necessitate substantial increases in energy prices and thought should be given to the creation of an independent Energy Pricing Board. 47. In the medium term (1996-2000), the future electric power generating capacity should be based on natural gas from offshore if adequate reserves are established. (a) The assessment of the total offshore gas reserves needs to be expedited. This will enable the government to determine the economic viability of the export options and to determine the volume of gas reserves that would be available for the domestic sector. This assessment would require the drilling of 3-5 offshore wells as well as an independent reservoir evaluation based on the latest data. (b) The export of gas to Thailand through a pipeline with a spur pipeline to hyanmar for domestic supply of 42 bcf per year of natural gas provides the most economical option for the country. xvi The domestic option should be planned as an early phase of development of the export pipeline system. A detailed engineering study of the gas field development and pipeline system needs to be commissioned as well as discussions concluded early with the government of Thailand for possible contractual arrangements. (c) Gas field: Rehabilitation of onshore gas fields should be carried out along with *the development of the probable reserves but investments in the exploration and development of possible reserves should be deferred till the total offshore reserves have been determined. An examination needs to be carried out of the relative cost effectiveness of the alternatives of a trunk gas pipeline to transport offshore gas to industries in Central and Upper Myanmar versus the development of probable and possible gas reserves in those areas. (d) Conversion of Combustion turbine plants to Combined cycle Plants: The early conversion of the Thaketa, Mann and Shwedaung plants to combined cycle operation needs to form an essential part of the medium term plan. The priorities for the conversion of the plants would be Ywama, Thaketa, Shwedaung and Mann. (e) Coal Exploration: An exploration drilling program in the Kalewa area, costing about US$5.5 million, is recommended as a first step leading to a possible mining feasibility study for developing Kalewa for a 200 MW mine-mouth electricity generation plant. (f) Woodfuels Program: Steps should be taken immediately to improve the information base of consumption and sustainable supplies. 48. In the long term (2001-2010), the options to increase generation capacity are hydro plants, domestic coal and additional plants based on gas depending on the discoveries made in the intervening period. In view of the long lead times involved in development and utilization of indigenous energy source like hydro, several immediate actions are necessary if timely decisions are to be made: (a) Detailed studies of the various hydro options should be initiated so that investment decisions on hydro power plants can be taken as soon as an assessment of the total gas reserves has been completed so that the volume of gas available for the domestic power sector can be determined. (b) MEPE also needs to prepare a ten year transmission and distribution development plan which should examine the nature of future development with a view to rationalizing a basis for expansion in the urban and rural areas. (c) MEPE needs to prepare a rural electrification plan. MOE should initiate the preparation of a rural energy plan, which combines rural electrification, traditional and renewable energy supplies into integrated development schemes. xvii (d) For the woodfuels sector, a strategy for sustainable development needs to be prepared including programs of improved management in mangrove and deciduous forests within the Yangon supply area. 1 I. THE ECQNOMY AND ENERGY DEMWND A. Itroduction 1.1 Myanmar's population in 1989 was estimated at 40 million, and growing at the rate of 1.88%/yr.1 Some 10 million persons are employed in agriculture, comprising 66.2% of the estimated total employment of 15 million. The private sector is almost wholly very small scale, and out of some 40,COO registered private busir.-sses in the country only 13 had more than 50 employees in 1989. Essentially all the large businesses are government owned and operated. Overall, the statistical average GDP per capita is in the range of US$200 to US$300, but its estimation depends critically on the assumed foreign exchange rate. Manufacturing has not emerged as an engine of growth, either for the domestic economy or for exports: manufactured goods account for perhaps 5% of exports, and manufacturing and processing contributed only 9.2% to GDP in 1990. The economy is essentially agrarian, with 50% of GDP derived in agriculture, livestock, fisheries and forestry. In fact agriculture may be considered as the cornpirstone of the economy. 1.2 Myanmar is richly endowed with natural resources,2 which includes minerals, forest and marine resources, in addition to relatively abundant arable land. However, most of these resources, including those known underground resources rsnging from oil and natural gas to precious stones, are yet to be properly explored and exploited. There is good potential in most spheres for production and exports if proper economic and financial incentives were piovided, and modern technology were available. 1.3 Myanmar has a 30 year history of a planned economy, dating from 1962, and government owns and controls virtually all the larger enterprises in the country, from industrial and manufacturing plants to hotels. Wages and prices of public sector output are determined centrally, and numerous non-price arrangements have been put in place in an attempt to offset or overcome the problems of ignoring market forces and appropriate pricing. The exchange rate has been pegged for more than a decade and the parallel exchange rate is some 8 to 10 times the official rate. Widespread shortages of consumer and industrial goods exist. 1.4 In the mid-1970's, reforms had been implemented to try to revitalize the economy, by focusing investment on mining and import substitution industries, largely financed by foreign loans. This had a stimulating effect and, according to official statistics, GDP grew at close to 6%/yr during the period. But beginning in the early 1980's the situation deteriorated: the external balance of payments account went into a worsening deficit and the government was forced in 1984 to resort to restrictive policies in an attempt to correct it. It reduced domestic investment and cut imports, but this also tended to reduce foreign earnings as a result of shortages of imported inputs needed for the country's exporting industries. The value of exports, two-thirds of which have traditionally been rice and teak, began to deteriorate in 1985, and declined by 1 See map IBRD 22977 Union of Myurur 2 See map IBRD 22979 Geological Basins 2 about 40% by 1989. The decline of rice exports was caused by poor producer incentives, shortages of fertilizers and the overvalued exchange re.te. International teak prices were also weak in this period. Official imports were drastically restricted starting in 1984 and their value declined some 45% by 1989. The state economic enterprises (SEEs), including the energy SEEs, which were operating during this period at financial losses, were covered by the government through domestic loans financed through money creation, or through foreign loans. The broad money supply was increased at around 19%/yr, and although two 'demonetizations' were carried out in November 1985 and September 1987, when larger banknotes (e.g. 50 and 100 kyat notes) were simply declared void overnight, inflationary pressures eventually spilled over into the economy. In the past two years, the money supply has increased at about 50%/yr. In 1980, the ratio of gross investment to GDP was as high as 21.5%; it dropped to 15.5% in 1985, and last year (1990) was only about 13% of GDP. 1.5 The consistently declining export trend since 1984, the retrenchment of imports, declining capital inflows, and increasing debt service payments caused reductions in domestic investment, shortages of production inputs, and intensified price pressures which overflowed into the 'parallel' market along with a diminution of activities in the formal economy. In 1986 the economy began decreasing in output, and GDP declined in each of the three years up to 1988. The decline in economic activity had a pronounced effect on government revenues, especially because of the decreasing contribution of SEE related revenues. In the past, the SEEs had provided more than 70% of public revenues, but by 1988 this had dropped to 59%. By the year 1989, the contribution of SEE related revenues had fallen by k 2 billion (current kyats) annually. 1.6 The country's foreign debt has risen from about US$2.2 billion in 1983 to around US$4.6 billion at present, of which US$900 million is owed by the energy sector SEEs, i.e, almost 20% of the total sovereign debt. Foreign debt service almost doubled between 1983 and 1987, to reach some US$320 million/yr, close to 90% of the country's foreign exchange receipts. During 1987 the country's official foreign exchange reserves were down to as little as US$50 million at the official exchange rate. GDP had decreased by at least 16% since 1985 and the decline in 1988 was particularly severe: the manufacturing sector showed a plant utilization rate of 30%; consumption of modern energy, except electricity, declined; and the agricultural sector declined by 13% despite normal weather. The government deficit widened from 8% of GDP to about 13%, the money supply expanded by some 33% and inflation rose to 27% according to official statistics. On the parallel market the kyat depreciated to about k 65 to the dollar. The year 1988 was also one of political unrest, shutdowns of industry and general economic disorganization and in October 1988 the new government suspended most debt repayments. 1.7 The State Law and Order Restoration Council (SLORC) government in November 1988, announced a new shift in policy: towards a market orientation. The foreign investment law was partially liberalized; border trade agreements were realized with China, Bangladesh, India and Thailand; export earnings were allowed to be partially (and later fully) retained by private sector exporters for the purpose of purchasing imports; the Companies Act was reintroduced and amended; the Myanmar Chamber of Commerce was reformed (after a period of 26 years); new income tax regulations were introduced with lower tax rates; the production and pricing of agricultural products in the domestic market were mostly decontrolled; the SEEs were instructed to eliminate losses and were given more discretion in pricing and other management matters; and joint ventures were set up between the 3 government and the private sector. In 1989, MOGE entered nine onshore oil and gas 'participation' contracts with international oil companies, raising a total of some US$45 million in signature bonuses, and opening the door to large international companies. These contracts, in the event of a discovery and subsequent production, provide for much of the contractors' share of oil production to be priced at international oil prices. A number of these changes have meant that more and more transactions in the economy are taking place at the equivalent of international prices using the parallel exchange rate, which is seen by officials in the Ministry of Planning and Finance as a stepwise process towards an eventual liberalization of the currency. 1.8 The government has taken an official stand to encourage private sector participation in economic activities. The privatization of some state-owned farms has been agreed to in principle. However, pi ratization has been limited so far to returning small sawmills and ricemills to their previous owners before nationalization. In September, 1989 a new state-owned enterprise law was promulgated which redefined and limited the areas to be reserved for the public sector. To increase the profitability of the SEE's, some autonomy was also granted regarding the procurement and sales of products. A decision was also made to transfer all SEE accounts to a consolidated government state fund account. In the process the debts of the SEE's were written off and converted to state equity. This, in fact, was a backtracking on the announced SEE reforms since it put all SEE financial matters under the control of the central budget and had the impact of distancing the SEE managers from the issues of the cost of capital and of obtaining a return on the capital invested in the enterprise. 1.9 Though overall the direction of the government's policies is towards more efficient management of the economy, actions to date have fallen short since some essential steps have not been taken. The main price distortion, the exchange rate, has not been corrected and the government's deficit is increasing. The opening up of trade is still hampered by the multitude of restrictions and regulations. Foreign investment has in3creased but the domestic private sector still lacks adequate institutional and financial support. The SEEs are caught between having neither the autonomy they need nor the previous direction of central planning. The economic picture in 1990--with an official preliminary estimate of GDP growth of 7.4% for 1990 fiscal year--appears brighter, although it is widely believed that the rate of inflation may be much higher than officially recognized and is almost certainly on the increase. The budget for 1990 depends heavily on a continuing government deficit, partly as a result of increased 'public works' expenditures for things such as city parks and road widening, and the money supply is still increasing significantly. The public sector deficit rose to 14.4% of the GDP. The government has targeted a growth rate of 5.7% for the year to April 1991 but any optimism will have to be conditional on achieving political stability in the country, and realizing further steps towards economically viable policies. Economic Forecast 1.10 The economy has in the past, according to official statistics, shown that growth rates of the order of 5%/yr are feasible. But for these rates to be achieved in the future will require some major changes in macroeconomic policies and the structural framework of the economy. For purposes of this report two economic growth forecasts have been used: a relatively high economic growth case in which GDP growth is projected at 5%/yr until 1996, and 6.5%/yr thereafter, and a second case in which the growth rate languishes around 3%/yr. The energy 4 sector, which provides k 580 million/yr in petroleum product taxes and k 800 million in operating surpluses of the SEE's, is critically linked to the economy's performance. The energy sector, in turn, could lead the way in generating financial savings both for the public sector generally, and therefore subsequently for investment in any sectors of the economy, given suitab?. policies. In fact the energy sector could be a key area where more market oriented and sound financial policies could be re-introduced into the SEEs, and the economy generally. It could be a dynamic force in liberalizing the economy; through raising investment, achieving greater financial viability and efficiency in management of the SEEs, through enhancing relationships between Myanmar enterprises and large international companies, through state-of-art technology transfers and through increasing export earnings. B. Energy Resources and Production 1.11 Myanmar aas diverse sources of indigenous energy. As of April 1990, the remaining recoverable proven oil and gas reserves onshore are estimated at 114 mmb and 139 bef respectively, vhile the future discovery potential is estimated at 800 mmb of oil and 7,000 bef of gas. The total coal resources in place are estimated at about 200 to 230 mtons. Hydropower resources are quite subatantial, with a theoretical power potential of over 108,000 MW and 366,000 Gwh/yr of potential energy. However, the development of the hydro resources is relatively costly due to the distance of the better sites from the main transmission grid or their location in insurgency prone areas. Myanmar has a forest ared of about 79.5 million acres or 47.5% of the total land area of the country, and this with non-forest trees and agricultural residues provides the potential for substantial and sustainable traditional energy supplies. TABLE 1.1 FINAL ENERGY DOMI) BY SECTOR IN 1990 (imtoe) IMTRITIONAL ENERGY M_oERN ENERGY Fuel Biomess Petroteum TOTAL Sector Wood Charcoal Residue Products Gas Coat Electricity ENERGY Percent Trunsport 362.5 0.0 0.0 363 4.0X Industry 75.9 134.0 194.6 23.6 88.1 516 5.6X Other 109.8 0.0 19.5 129 1.4X Fertilizer 0.0 167.1 0.0 167 1.8X Household 7181.5 535.6 227.8 7.3 0.0 48.3 8000 87.2 TOTAL 7181.5 535.6 303.7 613.5 361.6 23.6 155.9 9175 100.0X Percentage 78.3X 5.8X 3.32 6.7X 3.9X 0.3X 1.72 100.02 I=t: Secondary energy after alt conversion and conversion losses Source: Energy Batance TaIles (1990) 1.12 Myanmar has, however, one of the lowest levels of energy consumption in the developing world--0.31 tons of oil equivalent (toe) per capita/yr in 1990. The total use of grimary energy in 1990 was 12.4 million toe (or about 250,000 b of oil equivalent per day) with primary energy being supplied in the form of fuelwood including charcoal (76.7%), biomass (6.2%), domestically produced crude oil (5.0%) and imported oil (1.1%), natural gas (8.2%), hydroelectricity (2.5%) and coal (0.2%). In terms of secondary energy the largest consuming sector was 5 household (87.2), followed by industry (5.6%), transport (3.9%), and other users including fertilizer manufacture (2.3%). 1.13 Over 82% of total primary energy supply in Myanmar consists of traditional fuels, predominantly fuelwood, some charcoal and other biomass, reflecting the agricultural and rural nature of the majority of economic activities. The vast maJority of traditional energy supply is firewood which is gathered on a subsistence basis, and for sale locally in rural areas. The production of charcoal is mostly for supplying the cities of Yangon and Mandalay. Crop residues, such as bagasse, are used seasonally for local steam raising. Quite unlike other developing countries, however, the proportion of traditional energy supply has shown a marginal increase since 1981. 1.14 A number of shifts in the use of primary modern energy fuels have occurred in the economy during the past decade: notably, the consumption of natural gas has increased its importance from 17.8% of primary modern energy in 1981 to 48.2% in 1990. The share of crude oil, consumed now in final form mostly as petroleum products for transportation fuels, has decreased from 72.8% to 35.2%. Hydro electricity has increased slightly from 9.0% to 15.4%. The share of coal has remained small, at around 1% of modern energy. The importance of oil and natural gas in modern energy supplies is evident as together they provide 84.1% of total modern energy. The per capita consumption of energy over the last decade has remained virtually stagnant. TABLE 1.2 SUWfIES OF M DERN ENR IN ANNA 1978 TO 1990 TOTAL Crude Oil. Gas Coat Elect MODERN SeLf import/ Inport/ Prodn ENERGY Suppty * Prodn Export Prodn Export (Grid) SUPPLIES Ratio (mnb) (mmb) (bcf) (tons) (tons) (GWh) (mtoe) X 1978 8.4 -0.8 21.4 28346 96814 677.6 1763.1 102.32 1979 8.3 -1.1 19.1 11992 64594 690.1 1610.2 106.6X 1980 9.2 -0.7 21.5 13600 45751 1081.3 1858.5 103.5X 1981 8.6 -0.7 25.3 11036 23204 1227.8 1875.5 104.3X 1982 8.2 -0.7 23.9 16836 15917 1394.7 1787.9 104.8X 1983 7.8 -0.5 23.1 28494 20109 1551.8 1758.2 103.1X 1984 7.4 -0.7 22.7 35402 30560 1674.6 1672.6 104.5X 1985 7.8 0.0 29.5 43500 21386 1890.3 2006.4 99.3X 1986 7.0 0.0 35.5 43155 10101 2119.4 2067.6 99.72 1987 6.0 0.0 40.4 37498 7155 2245.5 2062.6 99.82 1988 5.1 0.0 41.9 38713 5258 2319.6 1983.7 99.82 1989 3.6 0.5 39.1 29780 3491 2226.5 1765.4 96.02 1990 4.4 1.0 38.0 38672 4147 2371.0 1931.3 92.82 AAG* 1978/1985 -1.1 4.72 6.3X 15.8X 1.9X MAC 1986/1990 -10.6 5.2X -2.3X 4.62 -0.82 AAG 1978/1990 -5.2 4.92 2.6X 11.02 0.82 Note: TOTAL ENERGY lncludes conversion losses in use of oil, gas and coat but only hydro component of electricityto avoid doubte counting; gas products such as methanol are included in gas. Electricity is amount produced before lonses. Imports are given positive sign and exports negative. * Average Annu4t Growth. 1.15 After allowing for conversion and other losses, the use of energy at the consumer level shows an even greater preponderance of traditional energy than the 6 sources of primary energy. Firewood provides close to 90% of traditional energy needs, and the share of charcoal has only increased slightly since 1981, to about 7% at present. One factor leading to the continuing high use of firewood has been the previous governments' policy to phase out the use of kerosene, which was reduced to only about 2 million gallons in 1990. It was previously used extensively for cooking and l ghting, especially in rural areas, but also in urban centers. In cities and towns this policy has accelerated the use of electricity for cooking thus aggravating the peak demand. In terms of secondary energy, almost half of modern energy consumption is petroleum products while electricity only provides 13.5% of modern energy needs. TABLE 1.3 Cl"lPTON Of KODEUN ENERGY IN NYANUAR (1973 TO 1990) TOTAL Petrote MODERN Products Gas Coal Electricity ENERGY (nmb) (bcf) (tons) (Gwh) ("toe) 1978 6.4 11.8 104611 677.59 1315.8 1979 6.3 14.7 71316 690.09 1361.0 1980 6.7 17.7 48001 762.56 1478.8 1981 6.7 22.0 32102 853.48 1597.4 1982 6.4 20.4 30167 949.69 1517.9 1983 6.9 19.2 40829 1050.15 1552.6 1984 6.8 20.5 59563 1121.50 1590.0 t985 7.6 24.5 61690 1263.63 1816.5 1986 6.6 34.5 49432 1459.53 1952.0 1987 5.8 39.5 45004 1542.98 1990.2 1988 4.7 41.3 34059 1580.09 1882.7 1989 3.6 38.8 24954 1704.28 1664.8 1990 5.1 36.1 44166 1799.60 1814.4 MAG 1978/1985 2.41 10.91 -7.31 9.3X 6.4X MAG 1986/1990 -7.6X 8.1X -6.51 7.3X -8.1X AAG 1978/1990 -1.91 9.7X -6.91 8.51 2.71 9_tj: Total includes conversion losses in use of oil, gas and coal but onty hydro component of electricity to avoid double counting; gas products such as methanol are included in gas. Electricity is the amount consumed. C. Energy Consumption 1.16 In each of the modern energy subsectors there are serious supply restraints which curtail potential demand. At present, electricity is frequently load-shed in all regions of the country. In the resider.tial sector new connections to the grid have been markedly slowed down and they are unlikely to keep up with population growth. Natural gas is insufficient for the gas-fired generation plants, as well as for the fertilizer plants. Gas is also in short supply for industrial use; for example, at the Sittaung Paper plant, 90 miles east of Yangon, and in the country's main cement plant. The availability of petroleum product has dropped precipitously, and petrol and diesel are rationed, even within the government and its SEEs. Therefore, in the modern-energy subsectors the present consumption levels are considerably less than would be the case without widespread non-price rationing. petroleum Products Consumption 1.17 The consumption of petroleum products has been squeezed down from 7.6 mmb/yr in 1985 to 4.7 mmb/yr in 1990 (including methanol); the use of kerosene has plunged from 68.7 million gallons in 1975, to 4.8 million gallons in 1985, 7 and to only about 2 million gallons in 1990 while the potential demand is far higher than present sales. Consumption of all petroleum products is controlled through a rationing system, with allocations based on regional and other considerations including vehicle engine capacity, according to government priorities. TABLE 1.4 EFIIED PETRMEI PUCT COSUNTIO IN WAWA. 1980-1990 (million l1) 1980 195 199Q Diesel 89.6 102.7 83.8 Petrol end Nethwnot 70.2 76.3 50.0 FueL Oil 47.6 49.0 24.6 Kerosene 19.7 4.8 2.2 Ave. Fuel 6.9 6.6 4.6 Other 7.0 33.5 0.5 TOTALS 234.1 266.3 165.7 MPPE estimates that existing potential demand for diesel and petrol might be between 80% and 160% higher respectively, than present consumption (at existing official prices): while this seems a huge excess demand, such levels would only be about 40% and 30% higher than actual consumption in 1984. Some 80% of the diesel market is government purchases, much of which is for gov nment vehicles. In 1989, about 50% of total diesel consumption was for transporcation, followed by some 42% in industry but it seems probabie that a large part of the 'industrial' consumption is also actually in transportation. Since the consumer price of diesel, at k 10.50/gal, is 60% lower than the price of petrol, the demand (and actual consumption) of diesel in transportation is growing faster than petrol: at 2.8%/yr in the period between 1980 and 1985--the peak consumption year before rationing became prevalent. Since then, and up until last year, consumption decreased because of supply shortages. Petrol consumption grew at only 1.7%/yr in the same period up to 1985, and has decreased in each year thereafter. The market for petrol, used in cars and light trucks and concentrated some 60% in Yangon, consists about 80% of privately owned vehicles. It has been estimated that up to about 40% of final sales to consumers are made in the black market, where prices run around k 150/gal in Yangon in contrast to the present government controlled price of k 16/gal. 1.18 In recent years some diversification of transportation fuels has been achieved by the introduction of methanol, Liquefied Petroleum Gas (LPG) and some Compressed Natural Gas (CNG) into the transportation market. Initially, the methanol and LPG projects were intended to supply the export market, but domestic requirements are so acute and supplies have not been up to expectations so that most output is consumed in Myanmar. Methanol is blended 80/20 (80% methanol) with petrol, priced at k 11.50/imperial gallon (IG), and sold regionally for some 13,000 specially converted vehicles. About 1400 cars have been converted to run on LPG, priced at k 11.50/IG, and about 350 vebisles to CNG. Electricity Consumption 1.19 Over the entire decade of the 1980's, electricity consumption in Myanmar has grown at around 8%/yr on average. However, latest statistics show that the growth rate since 1985 has declined markedly to the low level of about 3.5%/yr. 8 These levels of growth are modest in comparison with the growth rates of electricity in many of Myanmar's Asian neighbors, despite Myanmar's low base of electricity usage (45kWh/capita in 1990). Growth of electricity demands from the domestic sector on the interconnected system over the last five years has occurred even though the connection of new consumers has been restricted, the rate of new connections barely keeping up with the population growth of about 2%/yr. Residential growth is generally thought to reflect increased use of electricity for cooking, resulting from the rising cost of charcoal and the absence of kerosene in the market. Industrial demand on the interconnected system accounted for 50% of consumption in 1990 and it is estimated that over 40% of the industrial electricity demand is in the Magway Division, where the principal industries, namely fertilizer, LPG and cement plants, are located and which compete with MEPE for gas supplies. A similar situation exists in Ayeyarwaddy, Mon and Yangon where it is also evident that electricity demand is suppressed by industrial fuel shortages. Taking into account the recorded electricity consumption figures for large industrial operations for the last three years, it can be deduced that if sufficient gas were available for large industrial operations, electricity demand could quiGkly increase in the order of 40% above current annual consumption. TAILE 1.5 ELECTRICITY CKSUSPWTIG INTERCOhNECTED AM RURAL SYSTHIS IN HYAlR, 1960-1990 cIh) i2fl 1985 1990 Residential 216.5 373.8 582.4 Industrial 407.4 654.8 1031.6 Bulk (Services) 109.3 195.5 183.1 Others 29.4 39.7 47.3 TOTALS 762.6 1263,6 184.4 Source: NEPE 1.20 Electricity consumption in the rural areas shows an overall growth of 8%/yr but the electrification ratio has stayed constant at about 6% from 1984-1990. The rural load factor is very low (25-30%) reflecting fuel limitations for generation. Natural Gas. Coal and Woodfuels Consumption 1.21 The use of natural gas has increased rapidly over the past decade from 10.9 bcf/yr in 1980 to an estimated 36 bcf/yr in 1990, but consumption in fiscal 1991 has been running at only about 33 bcf/yr because of gas production failures. TAMLE 1.6 NATURAL GAS COU"WTIU I NYMANNAR, 1960-1990 (bef) Iil 1985 1222 Electricity Generation 4.1 11.3 19.9 Industry 3.4 4.5 8.0 Nethanot/fertltizers/LPG 3.4 5.6 8.0 CNG 0.2 TOTALS 10.9 21.4 36.1 9 1.22 Coal consumption decreased markedly in the late 1970's but since then it has recovered somewhat. TAILE 1.7 CML COSUITICU IN NANI. 19O-1M Railways 35.2 17.9 1.7 Industry 13.6 13.2 12.9 Iron processing 30.3 25.8 Stock Chge -0.8 0.3 3.8 TOTALS 48.0 61.7 i4. 1.23 It is estimated that the annual per capita consumption of woodfuel is 0.7 adt (0.9ms). TALE 1.8 CSUSPTIN OF WOODRELS IN WAIR, G190-l990 Cmltt CUT) 1980 1985 1990 Fuel Wood 12.5 15.9 17.9 Charcoal 0.5 0.8 0.8 D. Forecasts of Energy Demand 1.24 Based on the macroeconomic scenarios and assumed sectoral growth rates, two principal energy demand forecasts and a number of demand sensitivity cases were developed for this report. The Base Case forecast is relatively optimistic and assumes that a number of essential energy strategy steps are undertaken, especially that oil field rehabilitation is accomplished, offshore gas resources are developed so that after 1996 plentiful natural gas is available for the domestic market, and petroleum product, natural gas and electricity prices are raLionalized. The forecasts are based on a continuation of low prices being maintained in real terms; the demand would be significantly lower if the energy prices were increased. In the Base Case, over the period to the year 2005, total modern energy consumption is forecast to increase at about 4.8%/yr in the context of economic growth which averages 6%/yr over the period (Table 1.9). Petroleum product consumption increases at 7.4%/yr, and electricity at 7.5%/yr. The second forecast--the Low Case--assumes that the economy grows at the slower rate of 3.0%/yr and modern energy consumption grows at the rate of 3.1%/yr, petroleum products at 4.5%/yr, and electricity at 4.3%/yr. Traditional energy is assumed to grow at the same rate of 21%/yr in both cases since it is tied to the rate of growth of the rural population. The Base Case is summarized in Table 1.9, showing the final consumer demand (secondary energy) for petroleum products in the transportation, industrial and other sectors, coal for industrial uses, etc., and electricity demanded from the interconnected grid and from the isolated rural system. It shows the allocation of natural gas between the power sector and other uses. The critical demands of the electricity sector for diesel and fuel oil are shown to reach about 1 mmb in 1992. These oil requirements are relieved only in late 1995 with the development of the offshore gas reserves. 10 TAMLE 1.9 SUKE CAE: NOIE" EET CCNWTI FORECAST Petroteum Products Naturt Gas Col Electricity Year Transport Elect Industry Elect Grfd Rural Id. etc. etc. (00b) (tb) (bcf) Cbcf) (atons) (14h) (GCh) 1990 4.7 0.44 16.2 19.9 64.2 2371 138 1991 4.9 0.78 15.6 19.7 45.0 2552 152 1992 5.3 1.14 9.8 20.1 45.9 2718 158 19 5.6 0.94 7.7 17.8 46.9 2896 163 1994 5.9 1.00 7.3 15.4 47.8 3087 170 1995 6.3 0.38 21.4 19.7 48.8 3247 174 2000 9.4 0.48 18. 1 34.4 53.8 4593 201 2005 14.7 0.41 12.5 35.5 59.4 7207 262 Growth to 20U594 neg neg 3.9X 2.0X 7.7X 4.4X LM: Ease Case assumes that Moattane offshore gas reserves are developed and commence production in late 1095; nd onshore oil and gas proved and probable reserves are rehabilitated and developed begimning in 1992. Gas use in industry is the residual supply after allowing for electricity needs. Source: Mission estimates (1991) Petroleum Product Demand Forecasts 1.25 The present excess demand for petroleum products has been created to a large degree by the extremely low official prices, and the decline of domestic crude oil production. For some products and markets, like petrol and diesel used for transportation, the excess demand in the official market spills over into the black market where the black market price serves in the end to equilibrate demand with available supplies. In those instances, when the official market breaks down, the black market serves finally to allocate products through a market- determined price. However, the excess demands for fuels such as fuel oil (and diesel) used in the industrial market, or fuel oil and diesel used for electricity generation, are curtailed primarily by simply reducing industrial production or electricity generation. These factors make it difficult to assess present consumption figures for the purposes of forecasting future demand and consumption of petroleum products. The black market prices provide a guideline for prices that might equilibrate the product markets. 1.26 The forecast product growth rates are separately linked to the forecast growth rates of GDP in the economy. Diesel, aviation fuel and other products are linked to' industrial GDP; petrol, fuel oil and methanol are linked to total GDP; and kerosene demand is linked to agricultural GDP, in each case through elasticities which have been assigned based on the experience of other less developed countries. The resulting average elasticity of demand for total petroleum products with respect to GDP ranges between 1.3 and 1.7. While no specific kerosene policy base been introduced, kerosene consumption is forecast to grow faster than all other products in each of the forecasts. This follows from the assumption that adequate domestic crude oil supplies are available after 1996 and with prices related to international levels the allocation system becomes redundant, so that kerosene becomes freely available. The Base Case and Low Case forecasts each assume that petroleum product prices are raised to be close to international levels by the end of 1993, and the forecasts show only a gradual pick-up in demand in the period from 1991 to 1996. In the Base Case 11 after 1996, when it is assumed that new domestic oil supplies will be available and the economy will grow at an average of 6%/yr, total product demand is forecast to increase At slightly more than 9.0%/yr. The Base Case forecast for the main products is summarized below: TALE 1.10 LSE CASE FOECAST OF PETOULELU PPDUCT CUJNPTIU IN NVAlNI, 1991-2010 (mitlton I) Q.W g ZRiQ Diesel 83.8 188.1 496.8 Petrot 38.1 73.1 174.7 Fuel OIl 24.6 35.8 52.5 Kerosen 2.2 5.5 28.8 Nethnol/petrol 11.9 15.3 28.7 Other 5.1 -11.5 29.9 TOTALS 1S5Z 3n29.3 JlA Source: Missfon Estimates (1991) Electricity Demand Forecast 1.27 The country's 40 million population can be considered in two principal electricity service areas comprising: (a) areas served by the interconnected system--the six principal lowland divisions of Yangon, Mandalay, Ayeyarwaddy, Bago, Magway and Sagaing with a population 28 million and including the major urban areas; and (b) rural areas served by isolated systems--the remaining territories comprising Shan, Mon, Kayin, Kachin, Chin and Kayah States together with Tanintharyi and Rakhine divisions with a population 9 million. Industrial, Residential and Services demand are assessed separately. Growth in the urbanized towns supplied by the grid are largely affected by general economic conditions, and by the supply capability of the system. In the rural areas growth is also affected by political and guerilla activity, and by the limited access to these areas by road and waterways to be able to operate and expand existing facilities. Using the results of econometric analysis and analysis of electricity demand in other countries and in relation to the undersupplied electricity market in Myanmar, two principal forecasts have been derived (Table 1.6): a Base Case and a Low Case. The parameters underlying these forecasts are as follows: (a) forecasts of industrial GDP growth rates and relationships to industrial electricity demand growth (industrial GDP elasticity of 1.3); (b) forecasts of services sector GDP growth rates and relationship to other/services electricity demand growth (services GDP elasticity of 1.2); (c) forecasts of urban population growth rates and relationship to residential electricity demand growth (urban population elasticity in the range of 1.6 to 2.6); (d) estimated operational load factors, reflecting the existing and expected load shedding in the system. This load factor is used to estimate the "unserved demand", and it declines in the Base Case from 75% to 67%; the latter level considered to be "normal" for the MEPE system; and (e) estimated loss factors of a technical and non-technical nature, beginning at 21% and 10% respectively and assumed in the Base Case to be reduced through actions by MEPE to the levels of 14% and 2% over the decade to 2001. 12 TAlE 1.11 SLAURY OF ELECTRICITY DEMAD FORECASTS 1990-2010 Intrasnwted Syetm Year Base Case Low Case CGWh) t*W) CGWh) (SW) 1989/90 2371 376 2371 376 1994/95 3247 530 2897 446 1999/00 4593 771 3466 573 2004/05 7207 1227 4499 766 2009/10 11653 1985 5995 1021 Av. Growth 8.4X 8.7X 4.8X 5.2X Isolated uret Sstm Year Base Case Low Case (CIA) (MM) (GCh) (NU) 1989/90 138 61 138 61 1994/95 173 70 162 67 1999/90 201 74 170 68 2004/00 264 89 201 77 2009/10 352 112 242 89 Av. Growth 4.8X 3.2X 2.9X 2.0X Sourge: MissIon Estimtes (1991) 1.28 The Base Case forecast reflects an optimistic scenario where electricity demand on the interconnected system increases by an average of 8.4%. After 1995, it is assumed that growth will accelerate as gas supplies from the offshore Moattama field become available in sufficient volumes to supply demands of both MEPE plants and industry. The Low Case forecast reflects a pessimistic scenario where electricity demand grows at about 4.8% and unsupplied demand persists until the end of the 1990's. Rural Electrification 1.29 Unlike most of its Asian neighbors, MEPE has no strategy for expanding its rural electrification program. In 1979 the number of villages electrified was 709. It rose to only 751 in 1989. Approximately 20% of MEPE's consumers (9% of total cemand) are served by isolated diesel/minihydel power stations scattered over the 14 Divisions/States of Myanmar. The number of diesel engines has increased from 570 by only 60 since 1985 and the rate of growth of new consumers and consumption in these areas is significantly lower than for the interconnected system. The growth in rural systems is forecast at 4.8%/yr in the Base Case and some 3%/yr in the Low Case. It may be noted that some rural growth, as it may be connected to the grid, is assumed to be included in the forecast for the interconnected system. Traditional Energy Demand Forecast i.30 Woodfuel consumption is forecast to increase at a continual growth in the order of 2%/yr, composed of 1.95%/yr for urban areas and 2.05%/yr for rural areas in the period to 2000, and 1.9% and 2.0%/yr thereafter, based on a population growth of about 2%/yr with only limited substitution of modern fuels for traditional fuels in the period to the year 2005. 13 1.31 The objective of this report is to review the prospects for exploitation of the country's energy resources and to formulate medium and long term plans for national energy development during the period 1991-2010. l'he energy resources of Myanmar are evaluated in Chapter 2. The oil and gas sector, which is the crucial growth subsector in the short and medium term, is reviewed in Chapter 3, while the implications of future hydrocarbon supplies on the refinery and petrochemical sectors are examined in Chapter 4. The development of the power sector is the focus of Chapter 5, while Chapter 6 is devoted to traditional energy supplies. A critical issue in Myanmar has been energy pricing; this is examined in Chapter 7. Concurrently with issues of energy pricing are those of an institutional and financial nature; these are reviewed in Chapter 8. Finally, an energy sector investment program, based on this analysis, is indicated in the final chapter. 14 II. ENERGX UESOURCES A. Introduction 2.1 The indigenous modern energy resources of Myanmar include crude oil, natural gas, geothermal, hydro and coal.' These reserves are diverse but, based on the exploration effort expended till date, the proved reserves are neither very large nor low cost. There is, however, considerable potential which still needs to be explored effectively if the country is to make optimum use of its resource endowments. 2.2 Myanmar also has an excellent forestry potential which provides for almost 80% of the country's total energy consumption. The indigenous forest potential, however, needs to be carefully husbanded if it is to continue to play an important role in the traditional energy sector. As regards other nonconventional energy resources such as agricultural residues, wind power, solar etc., they could be exploited to make a greater contribution to energy supplies, particularly in helping reduce pressure on fuelwood resources, but in the short to medium term, their contribution is unlikely to be significant. B. Oil and Gas 2.3 Oil occurrence in Myanmar has been documented and exploited since antiquity from seepages and shallow hand dug wells in the neighborhood of Yenangyaung in Central Myanmar Basin. Intensive exploration for oil, started by Burma Oil Company following the British annexation of Upper Myanmar, resulted in the discovery of the Yenangyaung field in 1886 and other significant oil discoveries along the structural trend of Yenangyat-Chauk-Minbu. The initial discoveries were made by drilling surface anticlines (essentially all topographic highs as well) associated with active oil seeps in the Central Myanmar Basin. This early effort (1886-1940) succeeded in finding some 500 mmb of oil and 290 bcf of gas, mostly at shallow drill depths. The period 1940-62, interrupted by severe damage to wells and field facilities during the second world war and a subsequent flood of the Ayeyarwaddy River, witnessed the costly and time consuming rehabilitation of production facilities and the initiation of exploration in areas removed from the early discoveries. In 1962 the industry was nationalized and all activities absorbed by the national enterprise (MOGE and predecessor organizations). National efforts were quite successful in building upon prior efforts, over 20 discoveries being made by MOGE, and an additional 130 mmb oil and 73 bcf gas were found during the ensuing period (1962-80). In the mid-1970's offshore tracts were awarded to foreign international companies but though a number of wells were drilled, no commercial discoveries were made. In the early 1980's MOGE, with assistance from the Japanese, made several discoveries offshore, the most important of which was the 3-DA gas field in the Gulf of Moattama. Onshore discoveries by MOGE since 1980 have, however, been very modest amounting to about 15 mmb oil and 24 bcf gas, the principal discovery being the Kanni field in the Central Burma Basin immediately south east of earlier finds. Oil and gas production in Myanmar reached a peak of 11.154 mmb/yr in 1984/85 and 41.95 bcf/yr in 1987/88 respectively (Table 2.1). 1 See map IBRD 22976 Hydrocarbon Resources TABLE 2.1 NAIRM: OIL AM GUS PNOUCTO Oil Production (barreLs aer day) Field 79/80 80/81 81J82 82/83 83/84 84/85 85/86 86/87 87T88 88/89 89190* Nwn/Nwinbu 22823 20162 20347 18016 17840 16669 12357 9155 7281 5938 6330 Htaukshabin 198 954 1696 1857 3440 7886 10045 8178 4753 3140 2450 Yenwagyaung 3104 3176 3310 3393 3625 3529 3462 3060 2906 2334 2302 Chauk 1020 1039 1003 1052 989 979 947 880 814 622 691 Konni 0 0 0 0 0 0 52 282 312 886 2660 Others 2973 2283 2271 2406 1861 1496 1108 1105 719 750 759 TotaL (bpd) 30,118 27,614 28,627 26,724 27,755 30,559 27,971 22,660 16,785 13,670 15,1920 Total (Ceb/yr) 10.993 10.079 10.412 9.754 10.131 11.154 10.209 8.234 6.126 4.990 5.534 Gas Production tbcf) Chauk 3.186 3.060 3.089 2.623 1.978 2.854 4.833 5.887 6.183 5.122 5.209 Ayadew 3.607 4.942 4.723 5.212 6.683 7.398 5.647 4.180 4.340 4.170 4.606 1- Hts.kshabin 0 0 0 0 0 0 0 1.035 3.043 3.451 1.763 Peppi 0.043 0.014 0.072 0.148 0.005 0.021 0.013 0 0.150 0.983 1.734 Kemi 0 0 0 0 0 0 0 0.090 0.124 0.135 0.824 Shwepyitha 3.623 3.674 3.343 3.316 1.929 2.834 3.581 5.960 7.515 7.174 7.267 Pyi (Prom.) 0 0 0 0.752 0.799 1.522 6.953 7.012 6.931 7.384 7.205 Payagon 0 0 0 0 0.175 2.014 3.994 6.873 6.825 6.587 7.402 0tlters 1.716 2.080 2.344 3.329 3.465 3.691 3.384 3.496 3.540 1.760 *3.500 Subtotal 12.175 13.770 13.571 15.380 15.034 20.334 28.405 34.533 38.651 36.766 39.510 Associated Gas 9.569 11.070 10.166 7.687 7.637 9.117 6.635 5.020 3.264 2.328 *2.000 Total (bcf/yr) 21.744 24.840 23.737 23.067 22.671 29.451 35.040 39.553 41.915 39.094 41.510 Note: *The production drop in 1988/89 was due to unsettLed conditions in the country Source: NOGE *Estimnted 16 2.4 Data available for assessment of future production potential is, however, highly variable in extent and is of limited quality. In the more prolific Central Myanmar Basin most of the data is field specific both in regard to wells and seismic profiles. Well data in the central portion of the Ayeyarwaddy Delta/Offshore Basin is fairly extensive but seismic data is less extensive and of generally poor quality. Important other areas, i.e., eastern or Pegu Ywama area and SW coastal area of the Ayeyarwaddy Delta/Offshore Basin, the SW and highly structured area of the Central Burma Basin, the Eastern Platform, Chindwin and Hukwang Basins, contain very limited seismic information and have been drilled very sparsely. Thus, any assessment of potential involves a few areas with ample data and many 'areas of no data and requires a high degree of interpretation to mesh these into a rational model. UNION OF MYANMAR OIL AND GAS PAST DISCOVERY AND FUTURE POTENTIAL e vo .... .... ........ ......... ....... ....... ............. W FtCM PROD~ Q ' DjSo . To roTE .25 . go .......... . ..... ... .j .I ... .... ......... . .... ....... ................................. , ' 0 o PROO tO EU PROVED EXPECT. *ATt 60SERVE S°° ' o:s ao TC POTENTIAL NEW DISCOVERIES 49 . M1. AZ$ - EXISMN g8 bbb bU ttEbDS .. .. ... ... .... ... ......... ..... ...... . .. . . . ... ....... ... . . ....... . . . . . . . . . .. IJ ( 510 nm 1til o bbb . i bbIs oil bbb .l, 40 . .........n.t,... ........ .... ............. . 0 40 'ibi gob 6 6osl bbls oab gall and 'bl0 - t :80 oO 3c : : 20 4.... ...... i. l t . . I i i o TOTkC.0. 6790 n bb\ m TOT GAS 417 Bctb 0 500 1000 150 2000 2S00 3000 3500 400 400 000 MM bbis OIL AND EQUIVALENT GAS 6 Mcf GAS - I bbi 17 2.5 Past exploration has already yielded onshore proved and probable recoverable reserves of about 815 million barrels of oil equivalent (mmboe), comprising 679 mmb oil and 817 bcf gas. Substantial gas reserves have been discovered in the Gulf of Moattama 90 kilometers from the shoreline in water depth of about 45 meters; the most important accumulation being a miocene carbonate build up in 3-DA structure and an overlying upper miocene sand sequence in MOC-8 about 5 kilometers away. While MOGE estimates the in-place reserves to be 7 tcf, according to mission estimates, based on wells drilled till date, the recoverable reserves are about 5 tef, of which 1.6 tcf can be considered to be proved at this time. The remaining gas potential could be promoted to the proven category following the drilling of 3-5 wells of which 2 wells should be drilled in the 3-DA structure. Based on analysis of seven proved and two indicated generic hydrocarbon plays in the five basins comprising the Central Burma Tertiary Trough, the future onshore and offshore discovery potential for Myanmar is estimated to range from 425 mmboe to a maximum of 2,850 mmboe, with a mean expectation of 1930 mmboe (roughly 800 mmb oil and 7,000 bcf gas), of recoverable reserves (Annex 2.1). The prospective areas are the Chindwin and Eastern Platform Basins, which are undergoing :heir initial exploration by the production sharing contractors (PSC); the shallow marine and bay and marsh area in the SW Ayeyarwaddy Delta/Offshore Basin, where significant additional gas discoveries are possible, both from limestone reservoirs similar to offshore 3-DA and sandstone reservoirs similar to MOC-8; and the SW part of the Central Burm-. Basin, where Oligocene sandstones and Eocene sandstones may provide significant gas and oil finds. 2.6 Both the estimation of discovered reserves and potential for future discovery are made with a certain degree of uncertainty somewhat peculiar to Myanmar. With only few exceptions the productivity of the reservoirs in Myanmar is well below expectations relative to the same age, depth, and type of reservoir found elsewhere in the world. Thus reservoirs that would yield economic rates elsewhere are sub-economic in Myanmar and the recoverable fraction (% recovery factor) from reservoirs is likewise less than would be normally expected. This could be due to the petrophysics of Myanmar reservoirs being sub-optimal or it could be due to drilling and completion technology of MOGE damaging the reservoirs near the well bore, or perhaps both factors are involved. At least in some situations it is known that volcanic detrital, tuff and the like, adversely affect the reservoir. In most situations it is obvious that MOCE equipment and material are lacking to perform drilling and testing operations in an acceptable fashion. The lack of cores in nearly all and porosity logs in most important reservoirs contribute to the dilemma. The acquisition of this important data on all future wells is essential for estimation of resource potential and for effective reservoir management. 2.7 Myanmar has recently awarded exploration licenses to ten companies (or groups of companies) on nine onshore and two offshore blocks with a minimum work commitment of 29 wells, with the first wells being spudded in early 1991. Approximately 32 percent of the estimated future discoveries are covered by these licenses (55 percent of the oil potential and 15 percent of the gas potantial). The decision to award production sharing contracts to international oil companies in 1989 has stimulated exploration; at the very least a number of potentially attractive areas will be subject to exploration for the first time. Given the long time intervals normally required between initial exploration in new areas to the onset of production, even with early success significant contribution to Myanmar oil production is unlikely before 1996. Gas discoveries will require even more time. Thus license awards will do little in the short term to increase oil and gas production in the country. 18 2.8 MOEG would need to continue its exploration and delineation work in the areas that are not licensed to foreign operators but its exploration program needs to be carried out using the latest technology. Its exploration could also become more efficient (even under existing operatinb conditions) if more pre- drill seismic is applied. The average of 34 line km per exploratory well is exceedingly low, being about 1/10 of industry norms and a larger seismic effort and fewer wells would surely yield better results. Wells should be drilled with balanced non-damaging mud systems so th't well bore gauge is maintained, and full cement coverage obtained; blow-out preventers must be used; mud-iogging required on all exploratory and key field wells; high quality mud and additives utilized with efficient mechanism for solids removal from circulated mud; all appropriate cores taken and logs run; high quality cement and cementing equipment procured, with relevant stimulation material and equipment available as required; and appropriate production testing tools and procedures utilized. Even low quality reservoirs can be stimulated to improve productivity and ultimate recovery by improvements in drilling, well completion and production technology. 2.9 Due to the semi-isolation of MOGE from the world petroleum industry over the past several decades, training designed to update capabilities in the use of current technology is needed. Fortunately much of this training can be covered by association with the joint-venture and secondment arrangements in the current licensees. MOGE's current secondment program (one-year rotational basis) is designed to provide exposure and training to the maximum number of people, but it does not provide the opportunity for the foreign companies to absorb these people into their operations or provide for long term contribution to foreign company operations in Myanmar. The current secondment program will be beneficial to MOGE only if they can assemble the resources to launch a strong independent program. Any increase in exploration effectiveness of MOGE is thus critically dependent on import of appropriate technology, upgradation of skills of its trained manpower and absorption of modern oil production techniques through association with joint-vencure contractors. C. Coa1 2.10 To date some 15 coal deposits have been identified in Myanmar:1 two of these, Namma and Kalewa, are presently being mined. The remainder are in several stages of evaluation ranging from explored and evaluated, undergoing exploration, or merely identified and awaiting exploration. There are probably many more coal occurrences which have not yet been tabulated. Data concerning the geology of Myanmar deposits is somewhat dispersed and not easily accessed. Coal beds are known to occur in Miocene, Eocene, Cretaceous, Jurassic and Carboniferous age sediments. More than 90% of known coal reserves are located in the Chindwin Basin and margins; more than 80 percent is Eocene in age, and more than 95 percent is sub-bituminous rank. However, two-thirds of the of the current production is located in the Shan highlands, is of Miocene age and lignite rank. 2.11 Several promising deposits are found along the lower reaches of the Chindwin river as well as in the southern part of the country. In Sagaing division there are three major coalfields: the largest Kalewa coalfield, along side the Chindwin river, also sustains the only underground coal mine in the country. The other two important coal deposits are at Paluzawa-Chaungzon and 1 See map IBRD 23051 Coal Deposits 19 Dathwegyauk further north of Kalewa. The only other deposit of commercial interest is located at Namma near Lashio township in northern Shan State. The coal is lignitic in character; the reserves are limited, estimated to be only 2.8 million tons and one seam which attains a thickness of 50 ft. is being exploited by open-cast method. There are no other deposits in the country which are commercially exploited though some of their reserves are adequate to sustain local energy demand for brick making, steam raising, etc. Occurrence of coal deposits in Myanmar is shown in Table 2.2 below: TABLE 2.2 ESTIPATI OAL ESUMCES IN PLACE IU MTANNAR Coal fields Location Coat Estimated Reserves (imatons) Category Dathwegyauk Sagaing Div. SB 34 P4 Pauluzawa-Chsungzon So 89 P4 KsLeHa SB S P5 18 P2 105 P3 Kyobin So S NahudJau U L 1 P3 &P4 Thinbeang L S P3 Nsm_ Shan State L 2.8 P2 Samlaung N L 1.6 P2 Si-gyit R Not explored In-byin (kalaw) S so S P4 Lwegy o Not *xplored Kyauktaga Nagway Div. Se S P3 Nyenl Se S P3 S-Sub-bitueminous and L-Lignite; S-Sull deposit, less than 0.5 miLLion, P1 - proven, P2 - Probable, P3 - possible and P4 - Potential Approximately one third of these resources might be recoverable, if proven. 2.12 The Kalewa coal deposit was first discovered in 1886 and during the next several decades the Geological Survey of India reported coal occurrences extending more than 115 miles north and south of Kalewa, but other than field mapping very little exploration work was done. During the 1950's, some mine development work was taken up by the Burma Geological Department. This period also coincided with foreign collaboration with Krupp from Germany and Pierce Management Inc. from the USA for the development of the coalfield. Several bulk coal samples were sent abroad for analyses and tests for determining carbonization and briquetting properties of the coal but the results were not very encouraging. In 1956, Powell Duffryn from the UK, was hired for technical advisory services and for opening a coal mine, but that effort was not successful either. 2.13 The Kalewa coalfield, divided by the iyitha river running west to east, is on the Western limb of a major syncline with a consistent North-South strike and an average dtip of 450 to the east. Though more than 50 coal seams have been identified, only 5-6 seams attain any minable thickness. The coal seams can be grouped into the Upper and Lower Coal Measures separated by about 1,000 ft. of barren strata. On the north bank of the Myitha river, a small creek (Waye Chaung) runs between the two Coal Measures from north to south and joins the river. The UC coal seam (thickness 10 ft.) in the Upper Coal Measure which is 20 generally free from shale bands receives the most attention. About 300 ft. above and 300 ft. below the UC seam are two workable seams UA and UD which are 4 ft. and 7 ft. thick respectively. The seams in the Lower Coal Measures are superior in physical structure and hardness, but are generally less in thickness. Two seams LD and LE which are 6 ft. and 3.5 ft. thick respectively are also considered minable. The immediate roof and floor strata of all coal seams generally consist of soft shale or mudstone. A drilling program initiat:d by Pierce Management Inc. in 1953 together with Mineral Resources Development Corporation (MRDC) of Myanmar put down 22 holes in the Upper Coal Measures and 18 holes in the Lower Coal Measures. All these were located within 2-2.5 miles north of the Myitha river, and no holes were drilled on the south-side. Another hole was drilled in 1971 about one mile north of the previously covered area. 2.14 A scrutiny of the exploration records shows that choice of locations of the boreholes were not always optimal. Many borehole locations, their surface collar level and the elevation of borehole bottom were incorrectly recorded and some borehole logs are missing. Despite these shortcomings, the boreholes established that the major coal seams previously identified from the surface mapping continue up to a depth of about 550 ft. and 770 ft. in the Upper and Lower Coal Measures respectively, below the Waye Chaung floor level. It also indicated that the area covered so far was generally free from major geological problems. Based on the drilling program and past and present mining operations which cover only a small distance north and south of the Myitha river, the reserve lying within this area was first estimated to be 25.9 million tons. This was later revised to 109.8 million tons by MRDC in 1964 which covered additional areas up to 18 miles to the north of the river and 5 miles to the south. Krupp, who worked in Kalewa in 1950's and again in the 1970's has placed the total reserves at 128 million tons (Annexure 2.2). 2.15 Paluzawa-Chaungzon coalfield, located about 18 miles north of Kalewa, seems an extension of the same geological formation. More than 50 coal seam exposures ranging in thickness from 4 inches to 7 ft. were identified, of which only two seams (5 ft. and 7 ft.) attain minable thickness. The strike direction of the strata is north-south with coal seams dipping 25o-45O to the east. Though no boreholes have been drilled, MRDC has estimated that 89 million tons of additional reserves of potential category exist there. Information about Dathwegyauk, 60 miles further north, is very limited but it has a potential reserve of 34 million tons and is reported to have favorable mining conditions. However, the relative inaccessibility of the place makes it unattractive for any mining venture. 2.16 The total coal production in Myarmar reached a peak of 43,500 tons per year (tpy) in FY84 but has dropped to 29,780 tons in FY89. The annual production from Namma mine has varied from 8,000 to 30,000 tons but the present method of mining has only limited prospect due to the high overburden ratio in the future and limited proven reserves. Kalewa, though a small mine with an average production varying from 10,000 to 15,000 tpa, has prospects for future development. The main uses at present of coal are for small scale power generation, mineral processing industries, and sponge iron production, in almost equal proportions. 2.17 The present estimates of coal reserve in Kalewa vary from a low of 26 to a high 128 million tons of proved, probable, possible and potential category up to a very limited depth from the surface. Out of this, only 5 million tons are considered proven. Since the other coalfields are very remotely located, and it is not possible to cheaply transport the coal to major consuming centers, it 21 seems advisable to concentrate any immediate future production program from the Kalewa coalfield alone. 2.18 But there are two major constraints to the development of Kalewa coal. It has to be transported first by trucks and barge and then by rail to the major consuming centers. This raises the delivered cost of coal from k 350 per ton at the pithead to about k 574 at Monywa.' The coal being naturally friable, breaks down into smaller sizes as the number of loading/unloading points increase but the existing demand is for lumpy coal for open grate boilers designed to burn imported lumpy coal which are no longer available. However, no suct lumpy coal is required in cement and brick kilns where the use of gas can be easi'>y replaced by coal and for lime kiln, tobacco curing, and for heating and steam raising in miscellaneous industries. The high volatile content, low sulphur content and good burning characteristic of Kalewa coal make it ideally suitable for pulverized fuel and fluidized bed boilers for power generation. If the fine coal could be used near the mine site at Kalewa, it could also solve the transportation and marketing problems of small coal. Strategy for Growth of Coal Sector 2.19 It is clear that only Kalewa coalfield has adequate reserve to offer reasonable prospect for development as an energy base. The most important use of Kalewa coal could be power generation and it can reasonably sustain 200 MW of power generation. But the knowledge of reserves is inadequate and an exploration program needs to be initiated to determine the minable reserves. 2.20 Detailed exploration of the Kalewa coalfield, both north and south of the Myitha river for a distance of 3-17 km along the strikeline and 350-450 meters. along the slope length needs to be carried out. The area further north including Paluzawa-Chaungzon should be covered only by regional drilling at present. This will provide a firm basis for mine planning and design in the near future and for long-term development of the coalfields. The exploration will involve about 25,000 meters of diamond drilling, partly coring and partly non-coring, and geophysical logging. The estimated cost of such a program is placed at US$5.5 million with the regional drilling an additional US$1-1.5 million dollars. The detailed drilling of the prospective mining blocks will take about two years and regional drilling an additional year. 2.21 Available expertise within the country for detailed coal exploration, mine planning, design, operation and management are very limited. Drilling program may have to be assigned to foreign parties who could undertake the work in collaboration with local geologists and drilling crew. A coal survey laboratory to undertake proximate and ultimate analysis of coal ash analysis, petrography, carbonization tests, etc. would be required at a cost of US$5 million, and a training center would need to be established at site where some theoretical and practical training could be imparted. An alternate possible approach to coal exploration and development would be the invitation of foreign parties to enter into production sharing type contracts with the government. 1Average sate prtce at Nony"a ralt head is k750 per ton for tuwp coat, %365 for rLm-of-mine coal and kl77 for firws cosl. 22 D. Geothermal 2.22 Some 92 areas in Myanmar have been identified as having surface manifestation of geothermal resources. All of these are in the form of hot springs, none show geysering or fumarole activity. The hot spring areas have surface temperatures ranging from 35-65 C and appear to be related to deep-seated faulting rather than Pleistocene or older surface volcanic activity. These lie in 23 different areas: nineteen are associated with the Shan fault system, two with the Thayetma (cross fault) system and two with the Rakhine fault sYstems. These latter two are associated with mud volcanoes at Chauk and Minbu (Mann field) where undercompacted Eocene Yaw shale has been brought to the surface containing water temperatures representative of several thousand meters of burial. The others are thought to be the result of convection where deeply buried and hot water aquifers leak to the surface along fault planes. The fact that none of the hot springs areas can be directly tied to relatively young volcanism suggests that none can be considered commercially exploitable, either by hot water or steam, for generation of electric power. Lesser uses may of course be feasible. 2.23 The Yinmabin area southwest of Monywa has the highest predicted subsurface temperature 388 C (depth unknown) based on extrapolation of solution temperatures of associated minerals and may be associated with young volcanism. Springs in the Thandaung, Chaungzon, and Kawthaung have the highest surface temperatures, i.e., exceeding 60'C. These four areas appear to warrant priority for future investigation, particularly if low entropy utilization becomes feasible, anId any further exploratory work, e.g., electric resistivity surveys and slim-hole drilling, to establish temperature gradients, should begin in these areas. E. Hydroelectric Power 2.24 Myanmar has an abundance of potential hydropower resources in its river systems which drain the four main basins of Ayeyarwaddy, Chindwin, Thanlwin and Sittaung. The hydro power potential of the country is estimated to be more than 100,000 MW on an installed basis. This potential compares to the present development of 280 MW of installed capacity which represents less than one half of one percent of the country's theoretical potential. 2.25 Although the vast hydro resource is spread widely throughout the country, the existing installations--Lawpita( 168 MW), Kinda (56 MW) and Sedawgyi (25 MW)--and those under construction, Baluchaung #1, are close to the main load centers and the power grids of the ceutral region. Many other sites off the grid have been identified and include large hydro and mini-hydro in the central and the outlying regions. 2.26 In 1978 the consultant NEWJEC, under IBRD/UNDP funding, identified various theoretically potential schemes associated with the eight principal rivers flowing through the country and listed 23 previously identified proposed projects (total 5,729 MW) for review and closer examination. Subsequently to date 25 schemes totalling about 9000 MW have been 'dentified by MEPE for further detailed investigation. Since 1981 the development of four schemes have been fully evaluated to the feasibility and/or design stage including Paunglaung (280 MW - Norconsult, Norway 1982), Baluchaung #3 (28 MW - Nippon Koei, Japan 1985), Anyapya (12+9 MW - Hydroplan/Decon/Gopa, Germany 1984), Zawgyi (18 MW - IVO, Finland 1990). The two latter stations are remote from the existing t: nsmission 23 system and as such are being developed for local use only. 2.27 Paunglaung #2 (280 MW) ranked amongst the best of the original schemes in terms of the cost of energy delivered. It was somewhat costly compared with competing stations and has less live storage capacity. Nevertheless, since Paunglaung was the most accessible site, it was taken to the next stage of development. The consultant Norconsult performed a feasibility study and detailed design of that scheme in 1982 funded bilaterally by the Norwegian government. In 1987 Norconsult, in conjunction with an IDA team of experts reviewed the design. A number of technical issues were resolved before proceeding with the project including the resolution of matters relating to the optimization of the dam height, spillway construction, cofferdam design and diversion floods, rockfill dam slopes, irrigation aspects and operational conditions. As a consequence of resulting changes in the design the revised optimum multipurpose project were estimated at US$492 million. Approximately 16% of the project costs were assigned to providing water supplies to eleven local irrigation schemes to supplement existing supplies from the Yezin damsite. In a subsequent review of the cost estimates in May 1990, Norconsult provided a new estimate of project financing requirements of US$594 million (i.e., US$2120/kW) exclusive of interest during construction. Their revised multipurpose scheme (280 MW, 190m high water level, total storage 680m3, annual production 941 GWh) also reduced the scope of the irrigation component to serve an area of only 4320 hectares. This minimized the loss of annual energy production to 10 GWh, and correspondingly, reduced the allocation of irrigation costs to about 8% of the total project costs. 2.28 A 240 MW scheme on the Bilin river appears to be one of the best prospects for relatively early development and at estimated costs considerably lower than Paunglaung, primaiily due to the smaller dam size. Firm power from Bilin may, however, be more owing to the much larger water storage with mean energy generation estimated at about 880 GWh. But due to the multipurpose nature of the project, there are substantial uncertainties as to the relative economies of Paunglaung and Bilin which can be resolved only by detailed studies. The hydro potential of the country can only be realized by carrying out detailed survey- and feasibility studies for a number of prospective sites. F. Traditional Energy and Nonconventional Energy Sources 2.29 Myanmar s traditional energy resources- -fuelwood, forest and wood residues, and agricultural residues- -are plentiful and thi.ir potential contribution to the energy picture of the country are discussed in Chapter 6. The non conventional energy resources include solar and wind energy. Limited solar data indicates a modest potential for direct solar radiation in water heating, cooking, driers, solar stills etc. Since average wind velocity is only 4 miles per hour, except for Coco Islands where it reaches 7 miles per hour, wind is more suitable for water pumping than for electricity generation. But work in these areas is still at the experimental stage. G. Conclusions 2.30 Myanmar's energy resources are plentiful but exploration has been limited. In the absence of adequate surveys, seismic and drilling work, it is difficult to assess the total potential of these resources for commercial production. A 24 concerted effort needs to be made in the oil, gas, coal, geothermal and hydro sectors to evaluate the total energy potential of the country. This would need mobilization of the latest exploration technology through purchase of appropriate instrumentation and equipment, hiring of experienced international service companies and increased recourse to production sharing type arrangements in all areas of the energy sector. 25 III. OIL AND GAS DEVELOPMENT A. Introduction 3.1 Following nationalization in early sixties, the national organization (MOC, now MOGE) was vested with the responsibility to explore and exploit hydrocarbons throughout the country. MOGE succeeded in making a number of commercial discoveries of oil and gas in the Central Basin, the Pyay Embayment, the lower Delta region and in the offshore area of the Gulf of Moattama, including major fields such as Mann, Htaukshabin, Shwepyitha and Pyay on land and the 3-DA structure in the offshore. The capacity of MOGE to continue exploration in new areas, however, drastically reduced during the last decade owing to lack of adequate foreign exchange. 3.2 All the oil and gas reserves discovered in Myanmar to date are encountered in the Tertiary sediments of the Tertiary Geosyncline, which covers nearly half the country. W..h the exception of Moattama 3-DA structure, where gas was discovered in a Miocene reefal limestone build-up, oil and gas accumulations are encountered in the Oligocene and Miocene inter-bedded clastics which have been deposited over shallow marine lower coastal plains and fluvial environments. Almost all the oil and gas fields on land are situated in the Central Basin and the Pyay Embayment. The Central Basin, which has been more thoroughly studied than any other basin in Myanmar because of its easy accessibility and to early interest attached to its oil seepages, accounts for almost all the oil discovered and produced since the last century; and with the Pyay Embayment, for more than 85% of the gas discovered on land. B. Onshore Oil and Gas Reserves 3.3 The published MOGE oil and gas reserves estimates date, in the majority of cases, from 1986; the oil reserves estimates for Mann, Htaukshabin and Kanni were revised by IPEC (International Petroleum Engineering Consultants) in 1988, and in 1989 BEICIP of France reviewed the gas reserves of four of the major gas fields on land while Schlumberger carried out a detailed evaluation of gas reserves of the Payagon region in 1989. These evaluations show wide variations when compared to those carried out by MOGE, being generally more pessimistic. While some of the major reasons behind the variations may be the complexity of the structure and the lack of reliable data, it is essential to establish consistent oil and gas reserve estimates that can be reliably used in the production projections and evaluation of development options. 3.4 The initial oil in place (IOIP) estimates carried out by MOGE lead to a total proven reserves of 1,776 mmb: four oil fields; Chauk, Yenangyaung, Mann and Htaukshabin accounting for about 90%. Chauk and Yenangyaung fields have been producing for about a century and are the best geologically known fields, but these two fields are at an advanced stage of depletion. The evaluation carried out by IPEC on Mann and Htaukshabin resulted in a substantially lower IOIP of the order of 30% and 50% respectively, as compared to MOGE estimates. Based on the mission's evaluations, the proven IOIP is estimated at 1,770 mmb, in line with MOGE estimates; while the IOTP in the probable and possible category are estimated at 390 mmb and 1,750 mmb respectively. A major proportion of the probable reserves are likely to be encountered in deeper sands, in the western 26 flank of Mavn, below the 900 meters and in Htaukshabin and the undrilled blocks in Kanni. The possible oil reserves are likely to be encountered in the Lower Oligocene sands of the Pagan/Tuyintaung/Tetma/NST Trend and in the southern extension of the Htaukshabin structure. The proven initial recoverable oil reserves are estimated at 623 mmb, of which about 509 mmb have already been produced, and the unproven reserves are estimated at about 178 mmb. Consequently, the total remaining reserves are 292 mmb, of which only 114 mmb are proven (Table 3.1). T*ULE 3.1 tUNARY OF NYAIINR OIL RESERVES ESTIMATES (m-b) inital oft In Ptace Initial Recoverabte Reserves ProdLced Proven Probable Possible Total Proven Probable Possible Total until 1/4/90 Field/Structure Nbm/Ni,tu 450 100 50 600 150 (27) 17 4 171 94.1 HtAukshabin 210 150 200 560 40 (15) 15 10 65 16.3 Yenwnyauig 540 540 230 (9) 230 216.0 Chat* 400 400 150 (7) 150 145.8 Komi 40 40 80 14 (4) 7 21 1.5 Pagnetma Trnd 100 1500 1600 15 110 125 Others 120 130 39 39 35.0 TOTAL 1770 390 1750 3910 62 (64) 54 124 801 508.7 Sourc: Mifssion Estimtes, November 1990 ( ) Undeveloped proven reserves. MUj: 1. The recoverable reserves have been estimet-d assuning that 50X of the probable and 25X of the possible reerves are promoted to proven reserves folIowing delineation. 2. Recovery factors estimted from per; rmance of major sands in existing reservoir. 3.5 Estimates by MOGE of onshore free initial gas in place (IGIP) are 1,320 bcf in the proven category, with three fields (Chauk, Ayadaw and Shwepyitha) accounting for about 63% of the proven IGIP, and 2,047 bef as unproven (probable and possible), of which 83% are in the possible category. MOGE's gas reserves estimates for onshore areas were reviewed by BEICIP in 1989 and downgraded by 41%. Schlumberger Overseas carried out detailed estimates of the gas and condensate reserves in the Payagon region in 1989 and showed an average reduction of approximately 73% over existing estimates. These large differences are believed to be the result of insufficient structural control of reservoir sands. Volumetric evaluations are rarely verified against estimates based on actual reservoir pressure decline analysis because of the absence of static reservoir pressure measurements. The initial in place free gas reserves in the onshore areas are estimated to be 688 bcf in the proven category and 685 bcf in the unproven category. The total remaining initial recoverable gas reserves are estimated at 628 bcf, while the remaining reserves are 286 bcf, of which only 139 bcf, i.e. less than half, are proven (Table 3.2). 27 TAMU 3.2 UOuY OF ONOON FEE GM ERWU (bcf) Initisl Gn in Place Racoverable Resrves Produced Proven Probable Possible Total Provn Probable PossIble Total 1/4/90 Field/Region Cheek 190 5 20 215 137 2 4 143 85.7 Aymw 143 45 75 263 103 16 13 132 76.6 Htaukshabin 1I 15 1 1 11 9.3 Peppi 15 30 30 75 11 11 5 27 3.0 I:anni 9 15 30 54 6 5 5 16 1.1 Pagn/Tet= 150 150 27 27 Central Basin 372 95 305 772 268 34 54 356 175.7 Shwpyitha 112 30 80 222 81 11 15 107 55.2 Pyf (Prom) 71 5 76 51 1 52 40.2 Others 58 70 128 42 13 SS 36.2 Pyl Eiboyiuant 241 30 155 426 174 11 29 214 131.6 Delta (Payegon) 55 100 155 40 18 58 35.5 Total m il i5B I2 Z 0za Igirgs Mission Estimates, Woveor 1990. MMt3: The recoverable reserves have bn calculated a3suming that 50X of the probable nd 25X of the possible reserves are promted to proven reserves ftolloing delirneation. 3.6 The mission's evaluations show that: (a) The estimates of proven oil reserves of MOGE are reasonable. (b) The gas reserve estimates carried out by MOGE are, however, inconsistent with resenroir performance and are generally optimistic when compared with estimates based on well pressures; (c) Gas reserve evaluated from well head pressures for Chauk, Ayadaw and Shwepyitha are about 59% of existing estimates; (d) Gas reserves for Htaukshabin and Peppi fields are significantly lower than the reserves given in MOGE and BEICIP estimates, and Payagon gas reserves are expected to be totally depleted by the end of 1991; and (e) Ayadaw and Shwepyitha fields have produced more than two thirds of their proven developed reserves and are already on decline. C. Oil and Gas Field Development 3.7 Annual oil production in Myanmar has fluctuated between 10 and 11 mmb during the period 1979 to 1985--the relative stability of oil production was largely due to intense development drilling in Mann and Htaukshabin fields, (Figure 3.2) which accounted for about 75% of the country's oil production during the period. But oil production has been declining at an average rate of approximately 20% since 1985. The drop in oil production has been particularly drastic from Mann and Htaukshabin where the annual decline rates have attained 23% and 30% respectively. 28 3.8 The decline in oil production is attributed to several factors: (a) Depletion of Oil Reserves: Most of Myanmar oil fields are at an advanced stage of depletion: more than 85% of the reserves of Yonangyaung and Chauk have already been produced; Manm field, which presently accounts for more than of 40% of the country's oil production, may also be considered to be mature after 60% of the field's estimated reserves have been produced, (b) The accretion of oil reserves from new discoveries and their development during the last decade have not been sufficient to offset the oil production decline. (c) Reservoir Factors: Producing sands are generally complex, contrasted in properties, of limited areal extension due either to their lenticular nature or to compartmentalization by sealing faults. Natural pressure support from the aquifer is expected to be very limited. In addition, the majority of oil pools have been produced for a long time under rock and fluid expansion (depletion drive) which has resulted in a substantial drop of reservoir pressure (due to excessive gas production) and therefore, in severe loss of well productivity. (d) Pressure maintenance schemes have been implemented at a late stage of a field's life and have been only partially effective due to insufficient replacement of total reservoir withdrawal (oil, water and gas), or due to the discontinuous nature of the producing sands. The geological complexity and reservoir heterogeneity limit the drainage volume attributable to individual wells and severely reduce the sweep efficiency of water flood schemes. Pressure maintenance has been generally restricted to major pools rather than individual sands and, with regards to reservoir characteristics, the schemes are often poorly designed. Water injection is mainly carried out from one or two injectors situated either in the crestal area or down flank in the aquifer, rather than a more appropriate pattern flooding. Sand by sand analysis of water flood performance is difficult due to the general lack of reliable production and pressure data and the difficulty of allocating fluid production and water injection volumes to a given sand. (e) Formation Damage and Well Completion: The major causes of formation damage are the use of heavy-weight muds, migration of fines, and sand production from unconsolidated sands. The use of heavy- weight muds (relative to formation pressure) and long open hole exposure times, due to low drilling penetration rates, inevitably result in excessive mud filtrate invasion and formation plugging by fines and filtrate cake formation. Most of the well tests carried out on producers from Mann and Htaukshabin indicate very severe formation damage. If formation damage is not removed, using appropriate stimulation, it could cause permanent impairment to well productivity. It should be noted that most of the producers drilled today are brought on production without stimulation owing to the lack of chemicals and equipment. Although most producers have been completed in one major sand, analyses of well histories suggest that 29 a great number of thes producers have poor zonal isolation often resulting in co-mingled production from oil and aquifer sands. Such severe zonal isolation problems are believed to be frequent in Htaukshabin and could be a major reason behind early water production, poor well productivity, low oil recovery and ineffectiveness of water flooding. (f) Aeing of Well and Surface Production Eauipmerit: The great majority of wells do not flow to the surface without artificial lift, most oil production being obtained by reciprocating beam pumps. But single prime movers, well head equipment, sucker rods and down-hole pumps are in short supply and those functioning require constant maintenance. Gas lift applications have been very limited. Long flow lines without check valves, pose major problems such as back pressure on the well head, choking of lines, particularly in fields where surface topography is severe (e.g. Chauk, Htaukshabin and Yenangyaung fields) and wax deposits in well tubing and flow lines lead to well productivity loss. 3.9 Annual free gas production had increased gradually with increasing demand to attain a peak of about 38.65 bcf in FY87, but since then gas production has also been declining at a rate of approximately 3 to 4% due to production decline from Shwepyitha and Payagon fields. Gas production from the Payagon field, wnich amounted to some 7 bcf/yr over the period 1987/89, has declined very sharply and is expected to cease by the end of FY90. Solution gas production has declined from about 11 bcf in FY80 to about 2 bcf during 1990 mainly due to the decline of oil production and to the decrease in producing gas/oil ratio as a result of depletion of solution gas reserves. Most of the major free gas reserves have produced more than two-thirds of their proven reserves and are expected to start declining rapidly unless efforts are devoted to drill new producers and install additional compression facilities to compensate for the decline of well productivities and well head pressures. 3.10 For an immediate increase of oil and gas production, a major emphasis needs to be placed on the rehabilitation of the Rroducing oil and gas fields. Rehabilitation would need to be carried out progressively to account for present knowledge of the fields, cost and effectiveness of the rehabilitation work envisaged. Based on cost-benefit analysis, it is clear that priority in field rehabilitation should be given to (a) well and surface production equipment; (b) well completions; (c) pressure maintenance schemes; and (d) gas field development. 3.11 More than 95% of oil producers in Myanmar do not flow naturally and are equipped with reciprocating beam pumps: but now pumping units and all critical spare parts are in short supply, resulting in frequent failures and chronic maintenance. The loss of oil production as a result of low operational availability of surface and down hole pumping equipment is estimated to be in the order of 4,500 bpd. Preliminary estimates show that some 150 pumping units, associated spare parts and equipment for servicing, would be required to replace and upgrade the existing pumping units. Surface oil gathering systems, oil treatment facilities, separators, settling tanks and pumps need to be refurbished and expanded. 3.12 Most of the oil fields in Myanmar produce from 10 to 15 major (group) sands of heterogenous petro-physical properties and pressure regimes. Some wells are 30 also perforated in several sands for co-mingled production. But examination of individual well performance suggests that a large percentage of the supposedly ssingle' completion wells are producing from several sands owing to faulty primary cementation. Rehabilitation of well completions would require repair of faulty primary cementations, isolation of watered-out horizons, reentry of abandoned wells and recompletion in lower horizons across liners, well stimulation to remove formation damage, treatment and recompletion of unconsolidated sands for sand control. Rehabilitation of well completions would require testing, production logging and well-by-well analysis to identify faulty completions and design of the needed remedial work-overs, but data available at present is insufficient and unreliable for such analysis. Based on preliminary analysis, rehabilitation of well completion would be needed for about 80 to 100 wells annually. 3.13 About 65 water injection projects have been initiated on Mann and Htaukshabin since 1975. In Mann field, 12 of the 30 implemented projects have resulted in a substantial increase of oil recovery beyond the estimated recovery under natural depletion and the average oil recovery is estimated to be in the order of 35%. But the coefficient of replacement of reservoir withdrawals in sands, where the successful projects are implemented, is a amongst the lowest in the field. Water injection in Htaukshabin needs to be discontinued under its present design. Though the data available on these projects is sparse and unreliable to allow identification of the exact causes of failure, the most probable reasons seem to be: poor design of water injection pattern (very large spacing), limited areal extension and the discontinuous nature of sands, unavailability of high pressure water injection pumps, lower reservoir permeability and unfavorable water-oil mobility ratio. New pressure maintenance schemes should not be undertaken unless performance and causes of failure of the implemented projects have been fully assessed. It is estimated that some 24 new wells need to be drilled on various fields for data gathering. The main target of reh&bilitation would be blocks AB and DS in Mann field and most of the blocks in Htaukshabin. 3.14 Rehabilitation of gas fields is really the additional development needed to compensate for the decline of well productivity due to reservoir pressure drop. The projected rehabilitation program, would require the drilling of 40 additional producers on Ayadaw, Chauk, Shwepyitha and Peppi, half of these wells would be needed on Chauk and Ayadaw fields; installation of additional compression capacity to overcome back pressure from the gas evacuation system; it is estimated that 12 compression units would be required over the, next two years, most of them on Shwepyitha and Ayadaw and rehabilitation of the gas evacuation system to remove bottlenecks. D. Oil Production Forecasts 3.15 Oil production forecasts for the period 1991-2005 are estimated under three cases (Table 3.3). In case A, future oil production has been estimated from existing developed proved reserves without any additional development investment. In case B, rehabilitation of the existing fields is carried out using the latest equipment and technology; in addition investment are also made on the development of proven and probable oil reserves. In case C, production from development of possible reserves is also taken into account, following exploration and delineation o'Z these reserves. (Detailed assumptions underlying the three cases are indicated in Annex 3.1) 31 TAm.E 3.3 IYAJUA OIL Pll1CTIO FORECASTS RehabiLitation of Fietds wnd 0evelopment of Unproven Reserves (Mfb) 90/91 91/92 92/93 93/94 94/95 95/96 96/97 97/98 98/99 99/00 00/01 01!02 02/03 03/04 04/05 Proven Reserves 4.892 4.244 3.734 2.940 2.359 1.921 1.588 1.300 1.104 0.94 0.807 0.690 0.590 0.500 0.430 Rhbitetion 2.400 3.900 4.700 4.300 3.900 3.500 3.050 2.650 2.350 2.100 1.850 1.600 1.350 Urndveloped Proven Probabte Reserves 0.500 2.900 5.500 5.500 5.5EfO 5.500 5.500 5.500 5.500 4.800 4.300 3.800 LASE AIR TOTAL 4.892 4.244 6.134 7.340 9.959 11.720 10,986 10.300 9.654 9.094 8.657 8.290 7.240 6.400 5.580 Case C Development of PossiAe Reserves 0.800 2.000 4.600 6.500 6.500 6.500 6.500 6.500 6.500 6.500 6.500 6.500 TOTAL (AAB.C) *.892 jf4 6J134 8140 11f99 16.320 17.88 16.800 16,154 15.594 15.157 14.790 13.740 12. 129 0 Source: Nlesion Estimates, movesber 1990 * AssLaing no edditional development end oit production wiltl continue to dectine at the same rate observed since 1985/86. 3.16 As can be seen, production from existing proved reserves without additional investment leads to a cumulative oil production of approximately 28 mmb over the period 1990/91 to 2004/05, but the country's annual oil production would decline from 4.89 mmb in 1991 to 0.43 mmb in 2004/05 (Case A in Table 3). Oil production from the Mann field, which presently accounts for about 40% of the total oil production of Myarimar, would represent about 70% of the country's oil production around the year 2000. But with field rehabilitation, oil production could be increased to close to 6.22 mmb in 1995/6, and the estimated incremental cumulative oil production would be in the order of 38 mmb by the year 2004/05. The development of the probable and undeveloped proven reserves would increase oil production by some 5.5 mmb from 1995/96 through 2301/02, and the incremental cumulative oil production would be about 55 mmb. The major part of possible reserves is believed to be located in the Lower Oligocene sands of the Pagan/Tuyintaung/Tetma/NST oil belt situated about 50 miles to the southeast of Chauk. According to mission estimates, the recoverable possible reserves are about 124 mmb and their development could add up to 6.5 mmb/yr from 1996/97 through 2004/05. Exploration and delineation of possible reserves would require the drilling of some 29 exploration/delineation wells, nine of which will be deep test wells, and about 250 development wells. There is, however, considerable exploration risk involved in this case. 3.17 The investment required for oil field rehabili cation and the additional development of proved and probable reserves is estimated to be about US$698 million over the period 1991/92-2004/05, and the major targets of the above investment would be Mann and Htaukshabin fields where most of the probable and undeveloped proven reserves are expected to be encountered. This rehabilitation and development programs would depend on a first phase data gathering and appraisal program which is projected to include the drilling of 24 wells. The capital expenditure required for the exploration, delineation and development of possible reserves is estimated to be in the order of US$575 million, of which about US$67 million would be needed for initial appraisal and delineation (Table 3.4). The average investment costs for rehabilitation of the oil fields ranges from US$11.20 to 12.10/b (Annex 3.2). 32 Table 3.4 NtAR_ OIL FIELD REIE ILITATlO SD AITIOUA DEKWLW%WlT PROWJ4 Svmsry of Capital Expenditure (Nitlion USS 1990) Year 90/91 91/92 92/93 93/94 94/95 95/96 96/97 97/8" 98/99 99/00 00/01 01/02 02/03 03/04 04/05 !otj Capi tat Investmernt Rehabititation 10.00 43.00 43.00 18.00 5.00 119.00 Undeveloped Proven and Probabte Reserves 48.00 123.00 138.00 90.00 30.00 30.00 30.00 30.00 30.00 30.00 579.00 SubTotal 10.00 91.00 166.00 156.00 95.00 30.00 30.00 30.00 30.00 30.00 30.00 690.00 Development of Possible Reserves 9.00 37.00 84.00 77.00 61.00 41.00 36.00 .C 00 30.00 30.00 30.00 30.00 30.00 30.00 575.00 TOTAL 19.00 128.00 250.00 233.00 176.00 71.00 66. 00 6 60 00 60 00 MM0 3000 30.0012Al00 Yjls Reauired Undeveloped Proven and Probbble Reserves Data Gathering 8 8 8 Delineation 15 15 15 15 Development 30 60 40 20 20 20 20 20 20 'ossible Reserves Deep Test 3 3 3 Oelineation 5 5 5 5 Development 10 40 40 40 20 20 20 10 10 10 10 10 10 Source: Mission Estimates, Novmrber 1990 E. Onshore Gas Production Forecasts 3.18 Gas production from the presently developed onshore reserves is expected to decline from 33.3 bef in 1990/91 to 14.1 bcf in 1994/95 and to 1.7 bcf in the year 2000, implying that the present developed proven reserves will be totally depleted by the end of the century. Gas production declines would be particularly sharp in the Delta and Pyay Embayment areas, while production from the presently developed sands in the Payagon field, the sole producer in the Delta area, are expected to cease all-together in early 1990. In the central region Chauk and Ayadaw are the only structures, from the presently developed fields, to have sufficient reserves that could supply gas until the year 2000; the remaining fields, Htaukshabin. Peppi and Kanni, are also expected to be totally depleted around 1995. 3.19 Any enhancement of onshore gas production would require the rehabilitation of existing gas fields and the development of the unproven reserves. Incre&%se of gas production from the presently developed reserves would depend on how fast the probable and possible reserves are delineated, developed and brought on stream. Given appropriate investments, production from unproven reserves could attain a level of 10 bcf in 1994/95, peak at 13. _. bcf in 1996/97 and decline thereafter to 6.2 bcf in 2004/05 (Table 3.5). However, the additional production expected from unproven reserves would not be sufficient to maintain the present gas production level. The projected delineation and development program would need the drilling of 6 deep test wells, 16 delineation wells and about 77 gas producers. The capital investments (Table 3.6) for rehabilitation of existing gas fields (US$71 million) and for the appraisal and development of unproven reserves (US$171 million) would, however, provide the additional gas at an average incremental cost of US$2.03-2.42/mcf (Annex 3.3). It is likely that exploitation of offshore gas, should the reserves prove to be adequate, despite 33 a major onshore pipeline. Thus, major investments in onshore exploration should await determination of the offshore resource base would be competitive with domestic supplies from onshore gas reserves. TAKLE 3.5 EFANIU GAS PiROUCTION FMECAST: PRU AIID UNPOVEN itE VS (bcf) ONSHORE AREAS RegIon 90/91 91/92 92/93 93/94 94/95 9i/96 96/97 97/98 98/99 99/00 00/01 01/02 02/03 03/04 04/05 Central Region Proven 16.1 15.1 13.1 11.3 10.1 8.0 6.4 5.1 3.1 1.7 Probable 1.0 1.5 2.5 3.5 3.0 3.0 3.0 3.0 3.0 2.7 2.4 2.2 1.7 1.0 Possible 1.5 2.5 3.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 3.6 SubTotat 16.1 16.1 14.6 15.3 16.1 14.0 13.4 12.1 10.1 8.7 6.7 6.4 6.2 5.7 4.6 Pyi Embeyment Proven 13.7 11.3 8.2 5.9 4.0 2.4 0.7 Probable 0.5 0.7 1.0 1.5 1.5 1.5 1.2 1.0 0.8 0.6 0.4 0.2 Possibte 1.0 1.5 2.0 3.0 3.0 3.0 3.0 3.0 2.7 2.2 1.6 1.1 SubTotal 13.7 11.8 6.9 7.9 7.0 5.9 5.2 4.2 4.0 3.a 3.6 3.1 2.4 1.6 1.1 Delta Proven 3.5 Probabte Possible 0.5 1.0 1.5 2.0 2.0 2.0 2.0 2.0 1.4 1.0 0.7 0.5 SubTotaL 3.5 0.5 1.0 1.5 2.0 2.0 2.0 2.0 2.0 1.4 1.3 0.7 0.5 TOTAL Onshore jJU 27.9 Zi I 2 21.4 J iL.3 16.1 14.5 J1.3 i .6 2A L LI source: Mission Estimates (Novembtr 1990) TABUE 3.6 NT"A WAS U5ODUTION PROFILE AM PNASIG OF CAPITAL EWZITUtE Rehabilitation of Fietds Vnd Oelopwnt of Unproven Reserves ONSHORE AREAS Production 90/91 91/92 92/93 93/94 94/95 ff/96 96/97 97/98 98/99 9/OO 00/01 01/02 02/03 03/04 04/05 (BSCF) Proven 33.30 26.40 21.30 17.20 14.10 10.40 7.10 5.10 3.10 1.70 Unproven Reserves ProbabLe 1.50 2.20 3.50 5.00 4.50 4.50 4.20 4.00 3.80 3.30 2.80 2.40 1.70 1.00 Possible 3.00 5.00 6.50 9.00 9.00 9.00 9.00 9.00 8.10 7.20 6.30 5.20 TOTAL (BSCF)33.30 23 fLJO 3j4 24.10 21O.40 VL, I8 10IJ .145M IQ.i fiL JL2 LA & Li Summry of Capital Expenditure (MM USS 1990) Total Rehebititation 18.00 21.00 14.00 10.00 8.00 71.00 Unproven 24.00 31.00 33.00 27.00 16.00 14.00 8.00 6.00 6.00 6.00 171.00 Reserves TOTAL L.00 52.00 47.7 037.00 24 00 14.00 laE LaB LAB LAB 2U.OO Source: Missfon Est$at", (Novurtr 199) F. Moattama Offshore Gas Develogment 3.20 Substantial amounts of gas reserves have been discovered in the offshore Gulf of Moattama, 90 km from the shoreline in water depth of about 45 m. Gas was discovered in 1974 in well MOC-8 drilled on a bright spot, and the well encountered gas in five of the Upper Miozene sands situated at a depth between 3000 to .3300 ft. The five gas bearing sands total some 120 ft. and their individual thickness vary from 10 to 50 ft. The Moattama 3-DA structure was discovered in 1982, and the first discovery well, 3-DA-XA, encountered a 300 ft. 34 thick gas column in the Miocene reefal limestone build-up situated at a depth between 4,150 to 4,450 ft. A second well, 3-DA-XC, was drilled in 1983 and encountered gas in the same formation. The 3-DA gas accumulation, well defined by the gas water contact encountered in the two wells and identifiable on seismic profiles, extends over an area of about 35 to 40 sq. km. 3.21 The initial proven gas in place estimates of MOGZ for the 3-DA and MOC-8 discoveries are in the order of 5.4 tcf and 1.6 tcf respectively, while the IGIP 6stimates of several other agencies lead to an IGIP ranging from 3.9 tcf to 5.0 tcf. The seismic and well data relative to 3-DA and MOC-8 discoveries were reviewed by the mission and based on this review and preliminary evaluations, the IGIP potential was estimated at about 5 tef. Taking into account the simple geometry of the 3-DA structure, the relatively homogeneous reservoir properties and the location of the two discovery wells a total of 1.6 tcf is estimated to be recoverable. It is also estimated that at least two additional delineation wells would be required to confirm the remaining gas potential into the proven category. On the other hand about 90% of the gas potential given for MOC-8 discovery is considered to be unproven and full delineation would require at least an additional three wells. 3.22 The Hoattama gas field, even in its present stage of partial delineation, represents a major resource and can be developed rapidly. Gas production potential from the Moattama structure and field development can be evaluated based on the assumption that the proven gas reserves, would be upgraded to about 3.5 tcf following the drilling of 2 more delineation wells on the 3-DA structure and possibly to 4 tcf following the delineation of the bright spot, MOC-8; and that 70% of the recoverable reserves could be produced during a plateau of 15 years and the remaining reserves during field decline. The initial well production rate from 3-DA structure is estimated to be in the order of 35 to 40 mucf/d, based on well deliverability test results, and initial flowing well head pressure of 1,300 psig. No offshore condensate handling is required as 98% of the Moattama gas is methane; the theoretical liquid yield, based on gas composition, being about 1.5 b/mcf. Based on the above, the minimum proven plateau gas production rate from the 3-DA structure is estimated at 75 bcf/yr. If, following delineation, the totality of gas reserves is confirmed in the proven category, the gas production plateau rate which could be achieved is estimated at 150 bcf/yr from 3-DA and 25 bcf/yr from MOC-8, during a period of 15 years. 3.23 The three alternate options for the development of offshore gPS reserves are: (a) production dedicated to domestic demand only with minimum investments; (b) development oriented towards LNG production and export; and (c) pipeline gas export to Thailand. (a) The Domestic Option. This option, which could satisfy the short/medium term domestic demand for gas, envisages an annual production of 40-50 bcf using minimum installations on the offshore field. Field installations would comprise MOGE jack up, after rehabilitation, as an early production systom, one well platform, and the gas would be evacuated to Yangon area via a 24 inch, 90 Km submarine pipeline and an 18 inch, 180 km onshore pipeline. The US$247 million development, would require some 30 months for completion. 35 (b) LNG Production and Export. This option assumes that the proven recoverable reserves could support a gas production plateau of about 150 bcf/yr for 15 years, with 125 bcf/yr dedicated to LNG production for export to Japan, Korea, etc., and the remaining 25 bcf/yr for domestic utilization. This implies that a minimum of 3.5 tcf of reserves would be proved following the proposed delineation. Preliminary evaluations indicate that full field development would require one process/drilling platform, two well platforms, drilling the needed number of wells, and a 30 inch pipeline to a liquefaction plant comprising two liquefaction trains having a total capacity of about 2.5 million tons/yr of LNG. It is estimated that shipping of the LNG would require at least two LNG tankers. Preliminary estimates indicate that the total investment required for LNG development would be in the order of US$2,200 million, excluding the investment required for an LNG off-loading terminal, which range from US$100 to US$200 million depending on the water depth and morphology of the shoreline. The time required to complete the above project is estimated at about 5 years following feasibility studies and the tendering phase. (c) Gas ExRort to Thailand. Under this option it is assumed tnat a minimum of 108 bcf/yr of the gas produced would be exported to Thailand and 42 bcf/yr would be diverted for domestic utilization. A 350 km, 30 inch submarine pipeline to Kyaikkami and then a 450 km, 30 inch onland pipeline to the Bangkok region would be required, gas for domestic utilization, being diverted through a 150 km, 18 inch pipeline to Yangon region. Preliminary evaluations show that the total investment required for the project would be in the order of US$1,036 million and project could be completed ih 3-4 years following the feasibility studies and tendering phase. Land acquisition could present many uncertainties in regard to the time needed for project completion and has to be carefully accounted for from the very early stages. 3.24 Cost estimates, including phasing of construction, indicate that the option for the development of offshore gas for domestic use at a level of about 100 incfd is attractive, with an average incremental cost of US$1.24/mcf, at Yangon without royalties or taxes. The alternative of exporting the gas through a pipeline to Thailand is also promising, with an average incremental cost of US$1.38/mcf, for delivered gas to Thailand (without royalties and taxes). The price of gas sold to Thailand could range from US$2.50-3.50/mcf, and therefore this option could give a netback of around US$2.0/mcf, and assuming that some 40 bcEf/yr would also be delivered to the domestic market, this would represent the optimum utilization of the offshore gas reserves. The LNG option appears to be the least attractive, incurring very high investment costs and with an estimated cost of US$3.43/mcf for gas delivered to Korea or Japan (without royalties or taxes). (Annex 3.4). 36 TWLE 3.7 SUNNART COSTS OF OFFUIOU GAS DEVEiOPKET (Cost in sit tim of USS 1990) option Domestic Cost LNG Export Cost Gas to Thailand Cost (100 micfd) (400 mcfd) (400 mucfd) Field Devetopment Process Platform 1 Platform 120 1 Platform 120 Uelt Platform 1 platform 18 2 Platforms 36 2 Platforms 36 Jackup Rehabilitation Dehyd. & Util. 14 Utilities 5 Utilities 5 Drilling & Flowlines 4 Wells 10 20 Wells 50 20 WeLls 50 Evacuation offshore Pipeline 90 Km/24 inch 67 250 KW30 inch 183 350 KOV30 inch 256 Divertn Yangon 98 Onshore Pipeline 180 KmiS inch 96 50 Km/18 inch 25 450 Km/30 inch 306 Terminal 10 Compression 30 LNG Tankers 2 Units 550 Liquefaction Plant 2 Trains 950 Contingencies 32 288 135 Total Cost 247 2.207 je2 1-036 Lk) Source: World Bank Uission, (November 1990) (a) LNG evacuation terminal is not accounted. The cost of such a terminal mny range from USS100 to USS200 million depending on water depth and coast line morphology. (b) Land acquisition for the onland pipeLine is not included. This is estimated at about USS30 million based on similar projects in the area. G. Maior Issues in the Oil and Gas Sector 3.25 The major issues in the oil and gas sector can be summarized as follows: (a) Oil and gas reserve estimates used by MOGE for future production projections are inconsistent with existing field production data. Indeed, the absence of well and core data in adequate quantity and quality, is a major cause of discrepancies in field development projections. It is recommended that a National Reserves Evaluation Board is set up to periodically evaluate the total reserve potential of the country. (b) Technological Upgrading and Rehabilitation of fields will be a critical determinant in the growth of the hydrocarbon industry in Myanmar. Absence of the right equipment, materials and technology from seismic exploration to field development has led to a high cost of exploration and production on the one hand, and to inefficient practices on the other. (c) Development of offshore gas reserves provides the best opportunity for renewal of the energy sector. Examination of various alternatives like LNG and petrochemicals export has kept the government from exploring the more realistic and economical options of using it in the domestic economy, especially the power sector, in conjunction with a sizeable pipeline export to Thailand. But the appraisal and delineation of these reserves has yet to be completed. 37 (d) Resourge Mobilization. MOGE has been unable to generate local funds for increased exploration and development due to the extremely low prices for crude oil and gas fixed by the government. But even more critically, very little foreign exchange has been made available for purchase of crucial instrumentation, equipment and services. H. Conclusion and Recommendations 3.26 The oil and gas sector can once again play a significant role in the energy economy of the country but a clearly articulated policy and strategy needs to be defined and implemented. Major components of this should be: (a) Rehabilitation of the oilfields onshore should be carried out on the highest priority; well production equipment, surface facilities, well completions and drilling of 24 data wells should be taken up immediately while water injection schemes should await detailed investigations. At the same time the proposed program to develop undeveloped proven and probable reserves should be undertaken. This development is relatively low risk and can be undertaken under MOGE management but only if international consultants and contractors are used. MOGE can alternatively examine using PSC type contracts for rehabilitation and development of some of the fields. But investment in the development of possible reserves are risk investments and it would be advisable to let this work be carried out under production sharing contracts. (b) The assessment and appraisal of the total offshore gas reserves needs to be expedited as this will enable the government to determine the economic viability of the export options and to determine the volume of gas reserves that would be available for the domestic sector. This assessment would require the drilling of 3-5 offshore wells as well as an independent reservoir evaluation based on the latest data. (c) The export of gas to Thailand through a pipeline with a spur pipeline to Myanmar for domestic supply of natural gas provides the optimum option for the country and the domestic spur line should be planned as an early phase of development of the export pipeline system. In the event that negotiations with the Thais should fail, offshore gas should be developed for the domestic market only. A detailed study of the gas field development and pipeline system needs to be commissioned as well as discussions initiated with the government of Thailand for possible contractual arrangements. (d) Onshore gas field rehabilitation should be carried out along with the development of the probable reserves, but investments on the exploration and development of possible reserves should be deferred until the total offshore reserves have been determined. An examination of the relative cost effectiveness of the alternative of trunk gas pipelines to transport offshore gas to industries in the regions 2 and 3 to the development of probable and possible gas reserves in the area, needs to be carried out. 38 (e) Resource mobilization for the oil and gas sector requires the government to increase the price paid to MOGE for crude oil and gas and also provide adequate foreign exchange resources for carrying out exploration, delineation and production work in the most efficient manner in accordance with international norms in the industry. Investments in the oil and gas sector are inadvisable unless appropriate technology is mobilized by the domestic oil and gas sector entities, either directly or through PSC type contracts for new fields but also for exploitation of discovered fields. 39 IV. THE REFINERY SECTOR A. Introduction 4.1 The downstream oil and gas sector in Myanmar has three petroleum refineries, an LPG plant, four fertilizer plants and a methanol plant. Myanmar Petrochemical Enterprise (MPE) bas the responsibility for the operation of these plants and it is also responsible for import of crude oil and base stocks for lubricants and for export of petroleum and petrochemical products. The Myanmar Petroleum Products Enterprise (MPPE), is the sole petroleum products and lubricants distributing company in Myanmar, with the exception of some LPG distributed by MPE and CNG sold directly by Myanmar Oil and Gas Enterprise (MOGE). In 1990 the total consumption of petroleum products was about 4.7 mmb, of which 51% was diesel, 30% petrol and only 1% kerosene. 4.2 The three petroleum refineries have a total design capacity of 57,300 b/stream day (18.9 mmb/yr). The Thanlyin refinery (26,000 bpd), located near Yangon, which was heavily damaged during World War II, was rebuilt in 1955, and new units were added later. The refinery has three topping units: topping 1, with 5,700 bpd capacity, and a 1,700 bpd vacuum plant built in 1957; a second topping unit with 14,300 bpd capacity built in 1963, and a third unit with 6,000 bpd added in 1980. In 1986 a 5,200 bpd Coker and a 500 bpd Polymerization unit was built. A 1,400 bpd fractionation unit produces a narrow cut solvent (62/82 CO) out of naphtha that is used for rice oil extraction. Thanlyin also operates a lubricant blending plant, with a capacity of 14,000 tonnes/yr (tpy), and there is a candle production unit, with designed output of 5.2 tonnes/day (tpd). The wax used in this unit is brought by barges from the Chauk Refinery, which was built in 1953. The Chauk plant includes a topping and vacuum unit, with a 6,300 bpd capacity and a Wax plant producing 1,500 tonnes/month. The newest refinery, Mann, was built in 1982 and has a 25,000 bpd Topping unit, a 2,800 bpd Semi-regenerative Catalytic Reformer unit, a 5,200 bpd Delayed Coker unit, a Kerosene Hydrodesulfurization unit (3,800 bpd), an LPG Merox treating unit and a Naphtha Merox treating unit. The LPG separation plant at Mann has a design treating capacity of 24 mmcfd of wet natural gas and a design production capacity 60 tpd of Propane and 55 tpd of Butane. 4.3 Crude oil transportation to the refineries is done primarily by MPE with a fleet of 40 tugs and 150 barges, 500 tons each. Additionally, four 1,000 ton tankers are used to supply five coastal depots. The three refineries have access to river loading and unloading facilities. There is also a 10-inch diameter, 300 mile long pipeline connecting Mann and Thanlyin refineries, which was originally used to pump oil, but nowadays is used to transmit gas. Occasionally, crude oil is imported from Australia (Challis), Borneo (Brunei Light) or Indonesia (Attaka). Since the port capacity is limited, large tankers are forced to stay out in the open sea, some 80 miles from the refinery. Crude oil is transshipped using smaller vessels, which can moor at the refinery's jetties, contributing to a significant increase in the cost of imports and exports. 4.4 Petroleum products are distributed by MPPE from the main terminals in bulk to major customers as well as to depots, filling stations and retail shops. MPPE also supplies aircraft needs through nine airport refuelling stations. The 40 retail distribution system is rather old but it seems adequate for present and medium term needs. 4.5 To distribute the available petroleum products, an allocation system was established in the early 1980's. The Allocation Committee operates at cabinet level and reviews all fuel requests presented by state organizations, cooperatives and private sector consumers. The latter present their requirements through State and Division Councils. Abundant and detailed documentation is required to support petitions in an attempt to detect inflated requests or double counting. Allocations are based on regional considerations as well as other factors, such as vehicle engine capacity and government priorities. A formal procedure to control purchases is established in major towns. Each vehicle, including public sector vehicles, is assigned to a specific filling station and must keep a record bcok of all purchases. 4.6 Consumer and transfer prices for petroleum crude and products are set by the Government on a cost-plus basis. They were held constant for many years at significantly lower levels than international market values until October 1988, when consumer prices were increased over 4 times and the crude transfer price increased about 3 times: crude oil being raised from k 42.66/barrel to k 110.00/barrel. At a shadow exchange rate of k 50/US$, prices are US$2.20/barrel for crude oil, US$0.32/gallon for petrol and US$0.21/gallon for diesel, which are significantly below international prices; there is also an active unofficial market at price levels much higher than the official rates. Although black market prices are closely monitored by MPPE, reliable estimates of the quantities sold in the black market are not available, but it is said that it includes as much as 40% of final consumer petrol sales. B. Petroleum Products Consumntion 4.7 The refining capacity of Myanmar is adequate for its needs if it is operated at its design capacities. But crude oil and natural gas production have shown a declining trend during the last few years, and the pattern of petroleum products has varied. As shown in Table 4.1, the share in output of diesel has continuously increased from 35% in 1977 to 51% in 1989. Kerosene, on the other hand, has decreased in the same period, from 13% to 1%, as a result of a policy of restricting the production of kerosene established in the mid-1970's. The share of petrol plus methanol/petrol mix has increased slightly from 28% to 30%, and fuel oil has shown a marked decrease from 20% to 15% through natural gas substitution. Jet fuel has maintained a 3% market share. Over the decade the ratio of diesel-plus-kerosene versus petrol has increased significantly from 1.26 in FY77 to 2.2 in FY89. 41 TAUE 4.1 KIll PETIM.8 POXICTS COOUPTIO Product 1977/78 1984/85 1989/90 (ob) (X (ab) (X (mb) (X Petrol 1,789 28 2,144 32 1,089 23 Petrol + N09* 1,789 28 2,144 32 1,429 30 Keroswn 852 13 142 2 63 1 Jet fuel 243 4 143 2 131 3 Diesel 2,248 35 2,843 43 2,391 51 Fuel oIl 1,309 20 1,405 21 703 15 TOTAL 1. 100 6.7 100 4.717 100 * The methanol/petrol mix ia 80X methanol (N80). 4.8 LPG is produced in the refineries and in the LPG separation plant, and is distributed mainly in the Yangon area. Actual consumption in 1989 was limited by low production from the LPG separation plant, to 21,000 barrels of propane and 56,000 barrels of butane. 4.9 Some of the recently constructed plants, such as the LPG separation plant and the methanol plant, were intended to use onshore natural gas supplies to generate export products. Unfortunately the reductions in domestic natural gas and crude oil production, combined with less than favorable international market conditions, particularly for methanol, have eliminated these exports, as summarized in the Table 4.2 below. TABLE 4.2 EIWOTS OF PETIOM PRCUCTS (tonres) Product 1986/87 1987/88 1988/89 1989/90 1990 (April-Dec) Urea 90,326 121,245 60,061 51,000 11,719 Methanol - 9,111 25,235 6,900 Coke 36,496 31,504 29,522 32,700 11,105 Wax 902 1,334 - 955 182 LPG - 2,585 664 - EXPORT EARNINGS TOTAL US$0 9,306 12,688 11,709 8,904 2,722 C. Supply and Demand 4.10 Since 1984 petroleum product consumption has been supply restricted. Consumption has been limited in most years to the supplies derived from domestic crude production, except in 1989 when some 1 mmb/yr of crude (and some diesel) were imported. Restrictions reached a critical point in 1988 when total sales were at their lowest point in the past ten years. The throughput of the refineries in the period from 1980 to 1986 had been in the range of 8 to 9 mmb/yr, i.e., almost half the design capacity (Figure 2). In 1988, total refining output declined further to 4.5 mmb. 4.11 As a result of supply constraints, the allocation system and the active black market for petroleum products at prices far higher than official prices, it is difficult to assess how demand might be if supplies were available, and what price levels might serve to balance supplies with demand if the markets were 42 free. In the short term, in addition to suppressed transportation demands, there is a critical demand for diesel and fuel oll in the place of natural gas for power generatior and general industry. In the absence of increased domestic production, these needs will have to be met through imported crude oil. Two demand forecasts have been used to examine the issues in the refinery sector: (a) The Low Case, based on relatively low growth in each sector of the economy, shows consumption rising gradually from the actual levels in 1990, at growth rates beginning around 3%/yr and increasing after 1996 to a level of 5.7%; and (b) A High Case developed specially for analyzing potential refinery bottlenecks that might arise in the late 1990's. The High Case uses the consumption levels of 1984 as a basis because that year was the first full year of the allocation system and before the drastic declines in domestic crude oll production which followed. It assumes an average growth rate of 2%/yr would have occurred up until 1990. As a result the "potential" demand in 1990 was estimated to be some 7.44 mmb/yr, or about 45% higher than the actual consumption in that year. The forecast then assumes that demand increases by 2%/yr to 1993, by 3%/yr to the year 2000 and 4%/yr afterwards. TAWE 4.3 N PETOEM PUUCT DENA FOECATS (mb/yr) LOW CASE HIGH CASE Products Di*sel 3037 4129 7343 4509 5592 9109 Petrol 1266 1560 2423 2564 2915 3918 Fuel OIl 786 906 1217 877 711 786 Keroswne 240 337 711 872 1076 1671 180 340 340 340 0 0 TOTALS 2 MR t8 10294 15484 iource: Nission Estimates (1991) Mot": 1. The High Case assumes that petroleun product prices are kept at their existing low official levels, and sufficient products are suplied to fill the resulting high consumer demand. 2. LPG demnd is estimated to Increase from 21 metric tornes/day to 48/day. D. Issues in the Refinery Sector 4.12 In the last five years, refinery utilization has dropped from 50% to 25% of design capacity, resulting in a very inefficient operation. At the present processing rates, either one of the two largest refineries (Thanlyin or Mann) has enough capacity to handle crude oil processing. However, due to logistical, strategic and employment considerations, all three refineries are in operation. The Thanlyin and Hann refineries run continuously while the Chauk plant operates intermittently. At the Thanlyin refinery two topping units and the vacuum units are shut down and the coker and polymerization plants are running intermittently, while at Mann, the kerosene hydrotreating and the reforming units are not operat- ing. The Chauk refinery is in poor condition and its capacity is reduced to approximately 1,300 b/day, just accommodating the present local crude production. Thus, Wyanmar's present operational refining capacity is sufficient to process approximately 15 mmb of crude oil/yr. The LPG separation plant is also operating at 63% of capacity with a feed rate of only 15 mmcfd. Natural gas shortages have reduced the throughput and the gas which is available is also leaner than 43 previously, with a recoverable liquid content of approximat;ly 2.4 molt against a plant design value of 8.6 molt. 4.13 There is a generalized scarcity of spare parts in all refineries and rehabilitation is needed in several areas. The lack of spare parts is critical, especially in instrumentation and rotatory equipment. Partial dismantling of some unused units is taking place as an emergency solution. Fuel consumption and losses, reported by MPE as 14% to 18% by weight, are high compared with typical values of other refineries. The causes of such high fuel consumption and losses and the wide range of numbers reported can be numerous: crude received at the refinery gate has variable quantities of water and important measurement errors occur when emulsions, wax separation or water lerzils are present; most products are transported in barges in small volume shipments can cause large measurement errors and losses. The low feed rate to the refineries also causes low efficiency in heaters, boilers, measuring instruments and rotatory equipment. Faulty design or operation in oil recovery systems, flare, evaporation, drainage of tanks, and heat and product losses, are also possible sources of losses. 4.14 Though the Low Case demand forecast can be satisfied with the present refineries' configuration and capacity up to the year 2008 without any major modifications, the High Case demand forecast, which has very high petrol and diesel demands in the near term, implies that a surplus of fuel oil would be produced as early as 1996, and by 1997 the surplus would be of the order of 343,000 barrels/yr. The conversion capacity and diesel production capacity would then become critical in this case. Plant configurations for the two largest refineries, Thanlyin and Mann, are very similar from a di'ssel over fuel oil point of view; coking to Topping capacity ratio is 25.6% for Thanlyin (Topping 1 not included) and 20.8% for Mann. Local crude yields 32% to 35% of long residue so at full capacity there is a surplus of reduced crude for fuel oil production that cannot be fed to the cokers. Diesel and fuel oil productions will depend on the possibility of using coker gas oil as a diesel blending component and on the topping versus coking feed rate. Consequently, the existing refineries' configuration could not satisfy the exact product mix of the High Case demand forecast. 4.15 Methanol. The Seiktha Methanol plant was built in 1986 with a design capacity of 450 tonnes of methanol per day. Unfortunately, from the very beginning there was not enough natural gas to feed the plant. Annual production was 19,807 tons in 1986/87, 39,590 tons in 1987/88, 50,596 tons in 1988/89 and 42,272 tons in 1989/90, the latter being approximately 30% of design capacity. At design capacity the plant needs 15 mmcfd of natural gas, but in FY89 only 10 mmcfd, 100 days/yr were being allocated to the plant and the unit was running at 60% of capacity, intermittently. Frequent start ups and shutdowns and a low feed rate are also detrimental to equipment, decrease its operating life and increase failures and maintenance cost. 4.16 The present shortage of natural gas raises the issue of whether it would be more economical to shut the methanol plant rather than operate it at inefficiently low levels of feed rate. Production cost of methanol are high under low levels of operation; with operating costs given by MPE and natural gas valued at US$2.00/mcf, the estimated production costs of methanol in 1989/90 were approximately US$132/tonne. No capital charges were included, assuming them to be 'sunk' costs. The average methanol price US Gulf Coast for the last twelve years has been approximately US$140/tonne with a maximum of US$230/tonne and a minimum of US$80/tonre. Even at higher production rates and lower production 44 cost, the use of gas for methanol production must compete with the use of gas in other sectors of the economy, most of which give a higher value for gas. Even if methanol can find an export market this option is only economic if the price of methanol is sufficient to offset the costs of imported crude oil and producing petrol. 4.17 MMa. Myanmar has four urea plants: Sale A built in 1970 with a production design capacity of 205 tpd; Sale B, built in 1984, with a design capacity of 260 tpd; Kyunchaung, built in 1972, with a design capacity of 207 tpd; and Kyawzwa built in 1985 to produce 600 tpd of urea, and this plant is 10% to 15% more efficient than the older units. The shortage of natural gas has severely affected the production of urea. Kyawzwa urea plant was completely shut down in May 1990. Sale A and Sale B have enough natural gas available but their production is limited by a shortage of spare and equipment problems. Sale n is shut down due to compressor failures. In FY89, 192,000 tons of urea were produced, 45% of installed capacity; 141,000 tonnes were used locally and 51,000 tonnes were exported. The maximum historical urea consumption was close to 300,000 tonnes in FY85 while Myanmar's potential requirements of urea have been estimated at 480,000 tonnes. The key issue is the shortage of natural gas but production is also hampered by a lack of spare parts, a need for plant rehabilitation and the low efficiency of operations. E. Investment Profile 4.18 The total investments that need to be made in the refinery and petrochemicals sector are summarized in Table 4.4. Estimates of crude oil supply forecasts show that domestic sourcing of crude--and, therefore, of petroleum products--will be less costly than international sourcing at projected world oil prices. The investments in the sector are primarily directed at rehabilitation and efficiency improvements in the existing installations in the short and medium term. TAKE 4.4 INVESTfENTS IN TIE REFINERY SECTOR (USS mittion-1991 prices) 1991-------2000 1991 -------1995 1995-------2000 Total Flxed Total Fixed Total Fixed Costs Costs Costs Spare ports 6.00 6.00 6.00 6.00 Rshab/Chaulk/Thanlyn 4.00 3.00 4.00 3.00 Rehab tug fltet 50.00 25.00 10.00 7.00 40.00 18.00 Nodrnization/distribution 5.00 4.00 5.00 4.00 Loss control/efficioncy 25.00 18.00 5.00 4.00 20.00 14.00 YTnlon depot 20.00 10.00 20.00 10.00 Nann refin ry 15.00 11.00 15.00 11.00 Rehab fertilizer plants 11.00 10.00 11.00 10.00 TOTAL SECTOR 136.00 87.00 61.00 44.00 75.00 43.00 Sourco; Nission Estfmtes (1991) 45 F. Conclusions snd Recommendations 4.19 Improvement in the refinery and petrochemical sector requires action on a number of issues: (a) Utilization of Spare Capacity. At present there is more than enough refining capacity for domestic crude oil, and even with crude imports to serve the domestic products market, the Thanlyin refinery will be running at a low feed rate for several years. Marginal refining costs for refineries in such a condition are usually low and MPE could offer convenient refining services if a suitable client could be located. Important factors in refining service contracts are the refining fee and the products slate that the refinery can offer in return for the crude oil to be refined. Total yield tends to set the refining fee but the closer the individual product yields are to the client's needs, the better. Sometimes no refining fee is charged and the refining profit is realized in the form of products which are retained. The Thanlyin refinery has spare coker capacity that c&n increase the distillate yields to be offered, but it would be essential to have efficient offloading of crude to the refinery and shipping of products from Thanlyin. To accomplish any service refining deals it would first be necessary to solve the problem of high losses and fuel use. The costs of such losses could easily be as high or larger than the refining fee, thus making the deal a loser. In spite of these problems it is worthwhile to undertake a market survey, looking for a niche that could be supplied competitively. (b) Rehabilitation and Efficiency Audit. Considering the fuel use and estimated losses, it is recommended to perform an operational loss and energy audit. The audit is a tool that the refinery can use to compare present operational conditions with theoretical yields, losses and fuel use. Objectives for reducing losses and fuel use can therefore be established, and procedures can be put in place to accomplish them. Investments to improve efficiency can then be measured on a realistic financial basis. Finally, programs should be devised to train and encourage personnel to improve loss control and energy conservation. The loss and energy audit should be part of an overall plant loss and energy management program. A debottlenecking study might also be considered to improve efficiency. Rehabilitation is needed in Thanlyin topping 1, jetties, utilities, water separation and the oil recovery system. The Chauk refinery is in poor shape but its rehabilitation is not a high priority item. Action has also to be taken to assure that critical spare parts are available to the refinery operations, perhaps by permitting MPE to retain part of foreign exchange that it earns. (c) Increasing Diesel Yield. Even with the present refinery configuration, there are various processing alternatives to improve the diesel yield. At present, only up to 5% of coker gas oil is being blended with diesel, because of instability of the blend at higher levels. With appropriate analytical methods, the use of additives, and good quality control the amount blended could be 46 increased without detrimental effects on product quality. Diesel specifications for boilers, stationary and marine low speed diesel engines, gas turbines, etc., could be made less stringent than specifications for diesel used in vehicles and high speed diesel engines, and a heavier diesel oil could be produced and distributed. To handle two types of diesel can increase distribution and handling costs and therefore it would be advantageous for consumption of the new product to be concentrated in a few areas. Coker gas oil, if properly hydrotreated, is a good diesel blending component, and a hydrotreating unit could be built at Mann refinery where the reforming unit could supply the hydrogen required. (d) Refinery Iniestment Alterratives. In the context of the High Case demand forecast, a number of investment alternatives were examined, including refinery modifications and partial or full import of distillate products. The most economic alternative was for increasing the conversion capacity of the refineries, consist of a 2,000 bpd hydrotreating unit for Coker gas oil, to start up in 1996/97 and a revamping of the Mann refinery Coker to increase its capacity by 25%, by 2003/04 at a total investment of US$15 million. (e) Fuel Oil Surplus. The export market for fuel oil is very competitive and the netback from the sale of relatively small cargoes is not likely to provide better economics than investments in refinery conversion facilities or other processing modifications. Other ways of dealing with a potential fuel oil surplus are to produce new types of fuel oil if a market could be found for them. Intermediate fuel oils (IFO) are being used in other countries as fuel for low rpm marine diesel engines, and the Myanmar fuel oil characteristics, such as low metals' content, could have a competitive edge. Domestic as well as foreign ships can be supplied with IFO. It must be stressed, however, that potential refining problems which are related to the required mix of products, reflect in part the petroleum product taxation and pric..ng policies followed. A relatively low consumer price for diesel versus petrol will encourage its use in transportation and if natural gas is available the demand for fuel oil will stagnate. A consequence may therefore be the need for additional refirnery investment which could otherwise be avoided through higher diesel prices. (f) Methanol Production. Production costs of methanol (excluding the cost of gas) are high and the economic options are either to shut down the plant or to run it at a much higher feed rate. In the short term, with acute shortages of natural gas, it appears advisable to shut the plant. It could be reopened when plentiful gas supplies are available from offshore and if international methanol prices rise in the future to make export economical. (g) Urea Production. An estimated investment- of US$11 million is needed to rehabilitate Sale A, Sale B and Kyunchaung to bring them back to normal operating conditions. In 1990, urea plants used 20 to 100 percent more natural gas per tonne of urea than the design value. As in the case of the refineries and considering the natural gas shortage, there is a strong rationale for improving energy efficiency. As a complement of the rehabilitation projects, an 47 efficiency operating audit and a debottlenecking study are recommended. (h) Transportation of Crude Oil and Distribution of Products. Thanlyin is an important distribution center and is the only point of import and export of petroleum and petrochemical products. Consideration should be given to formulating a technical-economic feasibility study for improving the transportation networks serving the Thanlyin refinery. (i) Institutional Strengthening. MPE staff, although of high quality, have a need for more frequent contact with current information and techniques for efficient refinery operation and management, and product marketing. More contact with international refinery operations is especially recommended. Their computer infrastructure should be markedly improved, to allow for more complex analytical techniques to be applied in refinery operations, where they are particularly well suited. Refineries programming and optimization, alternative project evaluation, crude oil purchasing evaluation, and natural gas usage should be optimized with the help of linear programming models and similar techniques. 48 V. POWER SECTOR DEVELOPMENT PROGRAM A. Introduction 5.1 From an operational generation capacity of about 400 MW approximately 94% of electrical energy sold (1,730 GWh in 1990) by MEPE is provided from an interconnected 230/132/66 kV transmission grid system.' This extends some 600 miles from Pathein city, south-west of Yangon, to Kawlin copper mine north of Mandalay. Its associated 33/11/6.6/0.4 kV subtransmission and distribution natworks feeding urban, industrial and a few rural loads adjacent to the tran.mission system provide service to 10% of the 28 million population, who live in the main towns and cities of the six principal Divisions of Myanmar. The balance of electrical er.ergy sold by MEPE (100 GWh in 1990) is supplied by numerous isolated diesel and minihydel units scattered throughout the surrounding high country. Fewer than 7% of the rural 9 million population in tnese remote areas, comprising two Divisions and six States, receive electricity, and their supplies are usually provided on a restricted four to twelve hours per day basis. 5.2 Over the entire decade of the 1980's electricity demand in Myanmar has grown just over 8% per year on average, limited largely by supply constraints. The growth rate since 1988, however, has slowed down considerably as shown in Table 5.1 below. The relative proportion of consumption by the domestic sector has remained fairly constant at about 30% of total, with industrial and bulk consumers making up the balance. Industrial consumption has been curtailed by about 40% over the last three years largely due to the shortage of gas both as a raw material and as a source of power. Table 5.1 also shows that losses in the distribution system have been steadily increasing 'rom 21% of total generation in 1980 to 27% in 1989. Overall growth in power demand has also been modest in comparison with many of Myanmar's Asian neighbors, in spite of Myanmar's low base of electricity usage (45 kWh/capita in 1990). B. Generation System 5.3 At present MEPE has 20 interconnected power stations capable of sulpplying the grid with a cc"bined rated capecity of 661 MW. The actual firm capacity is only about 400 MW due to various limitations at each station,but this is expected to increase to around 562 MW when the ongoing rehabilitation work is completed in 1993.2 In 1990, 54% of electricity generation to the interconnected system was provided by thermal units (primarily gas-fired combustion turbine sets), whilst 46% w,-< provided from hydro sources. An analysis of the trends (Annex 5.1 (b)) shows the increase in dependency on gas fired generating plant going from 24% of production in 1980 to 55% in 1989. Even though there is now overcapacity in the system, production is severely limited by rationing of gas and diesel oil supplies for the combustion turbines; and by limitations in water storage capacity coupled with inadequate rainfall to operate the hydro stations effectively. 1 see map IBRD 22974 Pomer System 2 A summery of the interconnected system generating plant is shown in Annex 5.2 giving details of the status of each station after comnitted reinstatement works are completed. TAILE 5.1 AMl 51MM OF ERATI10AM SALES IUI 1960-1990 Centr tion Set"s Losme year Hydro Ga Stamm Diesel Purchase Total Domes Indus lulk Others Total Gen Tran Dist Other Total 1979/80 m2.15 262.68 37.50 47.19 8.77 1081.29 216.52 407.41 109.25 29.38 762.56 28.02 43.21 226.18 21.32 318.73 1960/81 ns.15 375.55 79.10 46.26 6.72 1227.81 242.29 457.10 122.23 31.86 853.48 32.40 50.81 262.04 29.08 374.33 1981/82 915.38 350.41 75.84 47.69 5.36 1394.68 281.38 498.70 132.68 36.93 949.69 44.32 67.05 309.36 24.26 444.99 S962/83 964.47 453.85 75.71 .64 13.10 1551.77 315.82 551.81 144.81 37.71 1050.15 45.44 92.64 338.62 24.92 501.62 1963/84 992.63 549.76 72.42 41.83 17.94 1674.58 340.59 585.35 157.61 37.95 1121.50 42.08 83.49 399.55 27.96 553.08 1984/85 1011.49 765.27 49.99 43.45 20.09 1890.29 373.75 654.76 185.46 39.66 1263.63 32.28 89.81 477.36 27.21 626.66 1ss/86 1003.48 996.38 55.00 41.66 22.85 2119.37 408.66 882.34 128.48 40.05 1459.53 47.18 81.74 501.94 28.98 659.84 1966/87 1042.61 1075.68 80.91 31.84 14.42 2245.46 436.95 918.75 145.96 41.32 1542.98 45.12 91.84 527.61 37.91 702.48 1987/88 1023.71 1208.74 61.37 20.35 s.4 2319.61 481.08 904.35 153.66 41.00 1580.09 46.75 137.68 516.62 38.47 739.52 1988/89 934.89 1228."4 39.41 17.91 5.80 2226.45 500.10 737.75 149.65 40.68 1428.21 42.34 114.65 608.10 33.51 M98.24 1989/90 1143.91 12m9.4 25.19 24.34 7.83 2509.00 570.39 804.87 183.15 42.24 1600.65 47.38 128.42 650.10 37.16 893.06 19so/91 1193.24 1226.00 27.60 23.22 7.50 2477.56 627.40 862.00 199.63 45.24 1734.27 50.05 136.05 519.26 37.93 743.29 SJU~Y OF UKTN RATES OVER TKE DECADE 1960/85 6.0 21.3X 3.41 -2.2X 25.61 11.61 11.71 9.6x 11.31 6.0X 10.31 4.41 16.91 15.71 3.31 14.31 sss/90 1.1x 10.11 -12.61 -24.4X -24.41 4.61 8.41 1.41 0.51 1.01 3.31 4.81 9.6x 6.91 5.81 7.11 19o0/90 3.51 18.61 .4.91 -0.6X -0.6X 8.6" 9.47x 8.11 3.45 5.21 7.9x 3.71 10.31 11.01 5.21 10.11 v0 50 Thermal Generation Facilities 5.4 MEPE has nine combustion turbine generating stations with a combined capacity of 280 MW. They are supplied with gas from three separate pipeline networks associated with the following gas fields: (i) in the Delta area at Payagon; (ii) in the Pyay area at Shwepyitha and Pyay and; (iii) in the Central Basin area at Mann and Chauk/Ayadaw. Each of the networks has different supply and demand characteristics thereby restricting MEPE in operating its generating plant in accordance with requirements of the interconnected system. Two steam generating thermal plants, totalling 30 NW, use locally supplied fuel oils from refineries at Thanlyin, Chauk and Mann (Thanbayargan). Some fuel oil is also imported (by end 1990 the government will have imported about 1 mmb of oil). MEPE also own and operate a large number of isolated diesel engines scattered throughout the 14 States/Divisions of Myanmar. Diesel plants comprise 644 sets with a combined capacity of about 100 MW. It is understood that only 50% are in good operating condition; their operation is also curtailed by fuel shortages. Coal was an important fuel for steam generating thermal power stations in the past but is no longer used. Coal imported from India was used for power generation in Yangon for over 50 years; coal fired plants were in operation at Ahlone (three 10 MW units), Ywama (three 10 MW units) but they are obsolete and were recently shut down. There is still a very old steam generating plant with four 550 kW units in operation at Kalewa coal mine which is both uneconomic and difficult to operate. 5.5 Outside MEPE control there is approximately 280 MW of installed steam generation, gas combustion turbine, diesel, and biomass fuelled generating capacity generally in small unit sizes. Of these a total of 214 MW is operated by industrial/commercial organizations under the control of the following Ministries: No.1 Industry (82 MW), No.2 Industry (12 MW), Energy (57 MW), Mines (37 MW), Fisheries (10 MW), and Trade (16 MW). Cogeneration facilities (i.e. generating equipment producing heat and electricity largely for industrial use) are in operation in Thaton (MEPE); Thanlyin (MOE); in Yenangyaung, and Chauk (MOGE); and in Lashio and Namtu (Myanmar Bawdwin Corp). W_LdTo Generation 5.6 Existing major hydro plants are located in the eastern hill country between Yangon and Mandalay at Kinda (56 MW), Sedawgyi (25 MW), and Lawpita (168 MW). Kinda and Sedawgyi have relatively small reservoirs and catchments and consequently limited capability during the dry season. The Baluchaung river system which supplies Lawpita provides a regulated flow from the Mobye dam in both wet and dry season. Under an ongoing rehabilitation program it will have a cascade pair of plants in operation by 1992 (Lawpita and BaluchNung #2 (28 MNW)); a third upstream plant (Baluchaung #3 (48 MW)) is proposed for the mid 1990's. There are also 16 minihydel sets with a total capacity about 4 MW, three are located in remote areas of the Chin state, the remainder not too distant from existing 33/11 kV interconnected networks. Eight of the minihydel stations have been constructed with imported equipment (costing about 3- 4,000$/kW), and are working satisfactorily. The remainder have been designed by MEPE; they are equipped with turbines built locally, and generators converted from old diesel plants. Although much lower in cost, typically 1- 2,000$/kW they are giving some trouble in operation. MEPE also have plans for the development of a number of new sites including seven minihydel units, and two smaller hydropower projects: Zawgyi (two 8 MW units) near Taunggyi, and Anyapya multipurpose project (9.3 MW) in the Tanintharyi Division near Dawai. 51 5.7 The government of Thailand has recently expressed an interest in the development of hydro schemes on its borders with Myanmar at Ham Mesai (25 MW), and at Klong Kra (40 MW). Both schemes are however in remote areas of Myanmar, too far to be considered for connection into the national grid and intended for local development and export of power to Thailand. Accordingly they are riot considered in MEPE's generation expansion plan. Tranamission and Distribution 5.8 MEPE's high voltage transmission system is in good operating condition much of which having been recently constructed under the IDA Power Project (Cr. 1245-BU). This comprises some 2,980 circuit km of 230/132 kV transmission, 1,233 circuit km of 66 kV subtransmission, 674 MVA of 230/132 kV grid substation capacity and 630 MVA of 66/33/11 kV primary substation capacity. [A summary of the existing and committed transmission lines and substations is given in Annexes 5.3 (a) and (b)]. Distribution networks comprise some 4,300 km of medium voltage (33/11 kV) lines, 4,300 km of low voltage (230/400 V), an estimated 800 MVA of distribution transformer capacity, and nissociated services for MEPE's 630,000 consumers. Up to date summary details of distribution plant and network details are not available, perhaps reflecting the low priority given by MEPE to this important part of their operations. The 230/132 kV grid extends 600 km across the lower and upper valley regions of Myanmar to interconnect the three principal systems: the Lawpita hydro system, and the gas based Pyay-Myanaung and Mann systems. The work to build the new grid was carried out in conjunction with a Kreditanstalt fuer Wiederaufbrau (KfW) funded project which included the construction of a 230 kV line between Thazi and Toungoo (to evacuate power from the proposed hydro station at Paunglaung). IDA also approved in 1987 an extension of the original Power project scope to enable MEPE to extend the grid by building some 66 kV subtransmission lines to reinforce supplies in the Yangon distribution network. Under normal conditions the new 230/132 kV systems would provide MEPE with a secure high voltage backbcne grid interconnecting the Upper and Lower Myanmar load centres. However bottlenecks caused by limitations in the associated 132/66 kV systems, limit the capability of the 230/132 kV circuits of carrying large loads during emergencies. Under some circumstances the power system can also become inherently unstable; the condition occurs three to five times a yeer and inevitably results in major supply disruptions. Furthermore during lightly loaded periods the 132 kV system voltage levels rise in excess of design limits; for example at Thazi 230/132 kV substation voltages someti ss rises as high as 151 kV. 5.9 In contrast to the transmission investment program, there has been little matching investmen= in distribution which has been generally neglected over the last 40 years. As a result distribution networks throughout Myanmar are in very poor condition and urgently in need of rehabilitation. Losses are high, breakdowns are frequent and poor voltage conditions commonplace. The major urban networks supplying Yangon and Mandalay being more heavily loaded are in urgent need of reinforcement. The other rural networks are also in poor condition largely because of the unavailability of suitable materials. While sales have gone up at 8%/yr in the past decade, high voltage (HV) transmission line length i.%e increased at 6%/yr, but medium (MV) and low voltage (LV) distribution lil.9 length have hardly changed, as shown Table 5.2. The loading on the distribution networks has therefore increased significantly over the same period. 52 TdA& 5.2 CAOMIU OF MRGM OF IH LV SYSTS Average 1977 1985 1990 Annuat Circuits CkfIomters) Increase NV (230/132/66 kV) 753 1149 1720 6.0% MV (33/11 kV) 2641 3085 3159 1.0% LV (230/400 V) 4096 4265 4311 0.3% Salet (CGh) 628 1263 184i 8% Cornuers (C0Os) 449 563 628 2.6% Loading Indicators Ratio NV/LV lines. 1.53 1.38 1.36 NV UA'k 238 409 583 7% LV GWh/km 153 296 427 8% LV ConsLusrs/k.s 109 132 145 2% 5.10 Yangon, the largest distribution division in Myanmar accounting for 40% of demand, is supplied by a generally underground 33/6.6 kV primary system, and 230/400 V low voltage secondary networks. More recently overhead 11 kV networks have been introduced but this is not very extensive. Parts of the low voltage network use overhead (copper conductor) lines to serve domestic and street lighting services. over 50% of the network was constructed before 1965 and about 10% of the cables were installed before 1940. Not surprisingly all the cables are badly overloaded, giving rise to poor service voltage conditions, and/or continuing failures. Frequent complaints of low voltages (as low as 60% of the contractual requirement) at small industrial v7d commercial premises confirm the situation. Upgrading work, carried out in recent years, has been done on a piecemeal basis with scant regard for longer term considerations. The distribution networks in Mandalay, the second largest city which accounts for about 20% of demand, is in better condition than Yangon but with similar problems characterized by high losses, unsatisfactory reliability and poor service voltage conditions. The Mandalay network and networks in most other areas in Myanmar are similar in design, being primarily overhead 11/0.4 kV networks supplied from 132/33 kV substation via several 33/11 kV primary substations. However, in contrast with Yangon and Mandalay, there is little or no detailed planning being undertaken in the other Divisions/States. It is notable that Bago, Magway and Sagaing Divisions have experienced the highest growth rates in Myanmar over the last five years and in all probability need considerable investment to improve their network. C. Demand Forecast 5.11 Based on an analysis of sectoral demands using demographic and economic data (see para 1.24 and 1.27), two power demand forecasts were used for this report. The Base Forecast reflects an optimistic scenario assuming that HEPE will be able to minimize load shedding and maintain a modest level of growth until 1995. After 1995 it is assumed growth will accelerate as gas supplies become available in sufficient volumes to supply demands of both MEPE plants and industry. The Low Forecast reflects a pessimistic scenario wherein unsupplied demand will persist for some time at present levels at least until after 2000 when hydro capacicy can be brought into service. Under the base case scenario, electricity generation in the year 2010 is predicted at 11,653 GWh in the interconnected system and 352 CWh in the isolated rural systems; while under the low forecast, demand is projected at about half that of the 53 base case--5,995 GWh in the interconnected system and 2';2 GWh in the isolated rural systems. Tdbl* 5.3 9UMlARY OF LOAD FCPCA3TS 1990-2010 Interconmected System Year Base Forecast Low Forecast (mAh) (N) CGWh) (NW) 1989/90 2371 376 2371 376 1994/95 3247 530 2897 446 1999/90 4593 771 3466 573 2004/00 7207 1227 4499 766 2009/10 11653 1985 5995 1021 Ave. Growth 8.4X 8.7X 4.8X 5.2Z Isolated Rural System Year Base Forecst _ Low Forecast (GWh) CPW) (GWh) CMV) 1989/90 138 61 138 61 1994/95 173 70 162 67 1999/90 201 #74 170 68 2004/00 264 89 201 77 2009/10 352 112 242 89 Ave. Growth 4.8X 3.2 2.9% 2.0X D. Generation Investment Plan Thermal Generatio.n Options 5.12 The timely development of the natural gas resources in Myanmar will be critical to HEPE's development strategy over the next decade. Gas based power plants should form the base of its generation plan. Two gas supply scenarios are conceivable (para 3.18): a high gas scenario ,n which approximately 40-45 bcEf/yr of gas is available for 25 years after the Hoattama field is developed; and a limited gas scenario in which the current level of production (33 bcf/yr) declines slowly up to 2000. This assumes rehabilitation of the existing onshore fields. Table S.4 GS SUPPLY SCENARIOS (bcf/yr) Scenario 1990 1995 2000 2005 2010 Hlgh gs 33 35 40 40 45 Lifmted gas 33 23 14 6 0 For the high gas scenario an overland pipeline would be required from Moattama to supply onshore facilities in the Delta area and then to the Pyay area by interconnecting pipelines, and possibly up to the Central Basin area. In the meantime gas supplies from existing onshore fields would be provided at a minimum level in order to maintain plant operations at present generation levels. In addition, to sustain growth in the short term, both Thaketa and Ywama stations would have to be fired with imported diesel oil for base load operation. Hoattama gas supply, assumed to become available in late 1995, would be adequate to enable MEPE to fully utilize existing plants and to 54 develop a balanced least cost gas/hydro generation expansion (para. 5.17). For the limited gas scenario, expansion of the pipeline network would not be viable. The operation of existing power plants would need to be rescheduled. At the same time the Pyay area gas supply decreases from 13 bcf/yr to 4 bef/yr would necessitate delivery of bulk diesel oil supplies from the Chauk and Thanbayargan refinery to Mann, Shwedaung and Myanaung generating stations. 5.13 The coal reserves in Kalewa (para 2.19), are the only significant deposit for consideration for further coal development in steam based power plants at the present time. The high volatile content and good burning characteristic of Kalewa coal, however, make it ideally suitable for pulverized fuel and fluidized bed boilers for power generation. it is possible that a production operation with a capacity of some 500,000 tons/yr would be feasible, probably in three smaller mines and could either be laterally along the slopes or through sinking shafts. New mines could be brought into production as and when the demand arises. It would take three to four years to get on a power plant stream. A preliminary estimate of costs of coal production are between US$25 and US$30/ton, and the investment for the mine would be about US$45 million. Hydro Generating ORtions 5.14 From a large number of potential hydro sites which could be considered for development (para 2.26), seven schemes were identified by MEPE in 1988. They include: Bilin, Shwezaye, Htamanthi, Yeywa, Mon Chaung, Kun Chaung. As indicated in Table 5.5, the best prospects aside from Paunglaung, in terms of lowest capital cost/kW, lowest levelized generation costs (LWC) and proximity to the grid are: Bilin in Mon State about 100 km from Yangon; Yeywa about 50 km from Mandalay; and Kun Chaung near Bago. Bilin is considered the most attractive scheme and preliminary investigations by Norconsult in 1982 indicate that better live storage may be developed there at lower cost than at Paunglaung Regrettably however the Bilin site is located in a "brown area" i.e. not yet free of insurgent activity and it may be difficult at the present time to carry out a thorough site investigation. Two other schemes are also under investigation: Saingdin Falls (15 MW first stage of 75 MW final development proposed in 1953), and Nam Mesai (25 MW) both of which are considered too far from the grid and therefore not included in the plan. In September 1990, MEPE initiated new feasibility studies for Bilin and Kun Chaung; when the results of this work is available, the relative positions of these schemes should be reviewed in the list of potential plants. Table 5.5 SUIARTY OF OWUARATIWE NID CHARACTERISTICS Slte Installed Storage nnual Capacity CapitelLGC Caoacitv Cacfitv Enera Factor C08tc08t8 (NW) CMcu.m) (GWh) (K) (SUSIkU)(cASh) Balurhaunsg 3 48 828 338 80.4X 33335.77 Paungtlung 280 690 911 31.1K 23758.95 lftin 240 10600 1000 47.6X 19005.65 Ywa 400 2602 1402 40.0X 15675.48 Mon Choung 200 7802 700 40.0X 315810.98 Kun Chaung 84 1666 350 47.6X 20666.06 Ntamanthl 1200 39180 5270 50.1X 28507.96 ShWe*a2y 600 1604 2000 40.0X 331911.55 gote 1. Capital costs exclude Interest during construction and are based on original estimates by MEWJEC and increed prorate with current estimate for Paunglaung. 2. The estimate cf LGC is based on a 40 year plant life assuming a 12X interest rate. 55 Least Cost Generation Development Plan 5.15 Modelling studies of the least cost generation expansion plan were performed using the Energy and Power Evaluation Program (ENPEP)1. The plan includes: (i) existing plants; (ii) committed projects, e.g. Baluchaung #2 which is under construction; (iii) Conversion of Shwedaung, Mann, Myanaung, and Thaketa, to combined cycle operation in order to increase fuel efficiency from approximately 20% to 38% whilst simultaneously increase output by up to 47%; and (iv) retirement of older or inefficient units including Ywama, Thaton and Mawlamyaing. Possible options include (i) up to 500 MW combined cycle plants (in 50-100 MW units depending on system size at the time of commissioning); (ii) 300 MW stoam station with multi fuel capability for coal/oil/gas burning; (iii) 200 MW minemouth plant near Kalewa; (iv) various hydro stations; (v) a station comprising up to either eight 12 MW medium speed diesel power plants or four 25 MW low speed diesel units with facilities for gas burning when gas becomes available. Feasible sites for thermal plant or combined cycle plants would be: Thaketa, Ahlone and Kyaiklat. These sites are close to the main load centre (Yangon), and have access to port facilities. Plants would be designed with the aim of eventually using gas from the offshore Moattama field. Prospective thermal station sites could be considered in the location of existing plants. However, further development at Mann, Myanaung, Shwedaung and Y'wama would depend on the overland development of the gas pipeline networks. This would depend on when Moattama gas is available for use in the Central Basin, and of the competing requirement by the industrial sector. No further development at Kyunchaung is likely, but the station would normally be operated for peaking purpose. 5.16 To obtain aft overview of the options for generating electricity, the table below shows the LGC of different thermal plant, at capacity factors (CF) corresponding to peak load and base load operation. The gas turbine and combined cycle plants are estimated to be lowest cost options, mainly as a result of the relatively low price of gas, of US$2.00/mcf which as a domestic fuel is assumed to remain constant over a 20 year period. Table 5.6 LEVELIZED COST OF THERAL GEIIUATIOC Peaking Base Plant Type capacity Fuel LF. LF.8 (c/kWh) Cc/kWh) Gas Turbine 50 Gas 7.88 5.01 Combined Cycle 50 Gas 7.92 3.43 50 Diesel 12.22 7.23 Stem 100 NW 100 Imported Coal 21.35 4.69 Steam 50 NW 50 Coal (Kelewa) 19.56 5.33 Steam 50 Fuel Oil 17.58 8.41 Diesel Engine 12 Diesel 20.71 9.49 1 EIPEP is the PC version of the WASP - Wien Automatic System Planming: software used by utilities in utilities wider the auspices of the International Atomic Energy Agency. 56 5.17 A least cost expansion plan based on the official exchange rates was derived for Hyanmar for the base case of high power demand and high gas availability and is summarized in Table 5.7 and Annex 5.7. The results show that the plan would require (i) the conversion of Shwedaung, Mann, Myanaung and Thaketa to combined cycle operation adding 140 MW to system capacity by 1995; (ii) use of diesel oil at Thaketa and Ywama but change over to gas in 1996; (iii) gas supplies at the other plants remaining at present levels even though output would be increased; (iv) construction of a new 250 MW combined cycle plant for commissioning beginning in 1996 with the first 50 MW unit; and (v) after 1999 a further 250 MW combined cycle plant would be necessary probably using larger unit sizes--100 MW--to take advantage of economies of scale. At that time gas fired combined cycle generating plant would comprise over 75% of total system capacity leaving MEPE vulnerable to supply problems even if more gas is found. The prudent approach, would be therefore to commission Paunglaung and Bilin hydroelectric stations as the next major capacity increments (520 MW in total). Subsequent hydro development prospects would include Mon Chaung, Yeywa, and Shwezaye hydro plants. The order in which these are commissioned however would depend on the findings of future feasibility studies to determine the likely costs of development. Tabte 5.7 LEMST CCST DEVLaR PlOGM High Power Demand-High Gas Avaltability Gererating Capacity System Fuel Incrs Total Peak Reserve Year Generation Caaacity Increase (NW) (NW) (NW) (X) 1990 Existing Peak Generating Capability 399 3760X 1991 Thaketa/Ywama Gts to use diesel Diesel 60 459 45918X 1992 Rehabilitation Program coapleted - 562 41426X 1994 Convert ShwedaLr.g/ann to Combined Cycle Gas 71 633 48923X 1995 Convert Thaketa/Myanaung to CC Gas 71 633 53023X 1996 Now 50 MW Cwcbined Cycte Yangon C-C#1 Gas 50 735 56623X 1997 Additional Yangon C-C A#2 Gas 50 785 60523X 1998 Additfonal Yangon C-C A#3 Gas 50 835 65621X 1999 Additional Yangon C-C A4&5 Gas 100 935 71124K 2000 Ywamr Stem Turbine retired Gas -36 935 77118K Additional Yangon C-C AM Gas 50 949 77111K 2001 New 100 MW Combined Cycle Yangon C-C U#1 Gas 100 1049 84919X 2002 Additional Yangon C-C B#2 Gas 100 1149 92220X 2003 Paunglaung Hydro 280 1429 101529K 2004 Baluchaung #3 Hydro 48 1477 111624K Retire Thaton/Hawtlmyaing Plants - -47 1430 14K 2005 BiLfn Hydro 240 1670 122826% 2006 Yeywa Hydro 400 2070 148735K 2007 Non Chaung Hydro 200 2270 148734K 2008 Shwezaye Hydro 600 2870 163843K 2009 Kun Cheung Hydro 84 2954 180339X 2010 RetIre Oldest Coabustion Turbines - -150 2804 198629K Sensitivity Analysis 5.18 In the event that there is limited offshore gas available for electricity generation, conversion of existing combustion turbines in combined cycle remains feasible. However, as on-shore gas supply declines, there would be a shift of fuel to imported diesel oil and additional capacity would have to come from steam plants. Two alternative scenarios were examined to test the 57 sensitivity of the base case in the period 1991-2000 under the new conditions. The results are summarized in Annex 5.4 (c). For the base case forecast scenario assuming that Kalewa coal field development proves to be feasible in the next two years, then a 200 MW minemouth plant would be implemented, with a first 50 MW unit ready for commissioning in 1996. Later on, a 300 MW coal fired station would be installed near Yangon using imported coal. Alternatively, in the event that the domestic coal option is not feasible, the proposed steam plants would be located near Yanron and dual-fired using imported heavy fuel or coal depending on the market price of these fuels. In the long term, the next additions would come from the hydro plants. For the low scenario of demand, the conversion process would be delayed along with the decision regarding the appropriate fuel for steam plants. The commissioning of the first unit would,be required only in 1999. 5.19 For the above program energy production and fuel consumption, including the requirement for rural diesel generation, are shown in Annex 5.1 and summarized below. Gas consumption shows a gradual increase after Moattama gas is brought onshore following the development of the field. Fuel oil usage is terminated after 2000 when the Thaton and Howlamyaing plants are retired. After 1995 diesel oil is largely used only to meet the electricity demands of the rural sector. TAULE 5.8(a) ENERT UERNTED FOR THE GSE CASE SCENARIO (DA) Generating Statfon 9 199QQ 5 2Q1 Gas Turbines/Comb. Cycle 1313 1821 3372 3705 5331 Diesel/Steam Plant 456 223 263 263 352 Hydro 1091 1546 1546 4226 6993 TOTAL 2860 3594 5181 8194 12677 TABLE 5.8(b) ANUAL FUEL CGSUDWTION 1990-2010 1991 1995 2000 2005 2010 Gas (bcf/yr) 19.65 19.67 34.40 35.49 51.15 Fuel Oil (bbl/yr) 0.10 0.10 0.13 0.00 0.00 Diesel (bbl/yr) 0.78 0.28 0.32 0.41 0.56 The investment requirements for the base case covering the additional generation capacity commissioned before the year 2000 are detailed in Annex 5.7. Their preliminary cost estimates are summarized as follows. Table 5.9 POCER SECTOR INVmSTNENTS (USS mlLion) Foreian Local Total 1) Rehabilitation of existing plants (including provision for oil 93.03 52.57 145.61 handling facilities) 2) Conversion of existing plants to combined cycles 128.90 43.00 171.00 3) Instatlation of rew 300 NW combined Cycle plant near Yangon 195.60 84.00 279.60 TOTAL INVESTMENT 417.53 179.57 596.20 58 5.20 Based on studies currently being carried out by MOE there appears to be potential for new cogeneration schemes associated with the refineries, paper mills, fertilizer plants, textile factories, and in food processing. The introduction of such schemes would provide dual benefits; they would make more efficient use of gas that is available and would reduce electricity demand on the interconnected system. E. Transmission and Distribution DeveloRment 5.21 To match the generation expansion program, the transmission system will need to be continually reinforced and extended in the 1990's as the loadings increase. The few bottlenecks that now exist will need to be addressed along with the planning of extensions to individual substations to meet the forecast demand. The Load Dispatch Centre (LDC) will also need to increase its mionitoring capability to cover all outstations and eventually introduce remote control facilities. This will necessitate the installation of alternative communications facilities, using either microwave or fibre optics links carried on the existing tower circuits. It will also involve considerable rewiring work at the outstations (power stations, substations, administration and operation centres) to install suitable exchanges and associated outstation equipment. The transmission expansion plan would also be designed to (i) transmit power from new generating plants, (ii) reinforce transmission and substations to meet load growth, and (iii) allow for modest expansion of the distribution networks. The scope of work together with preliminary cost estimates, excluding local taxes and interest during construction, is summarized below and detailed in Annex 5.5. TAKE 5.10 T11AhfISSIO DEWLUPEIT PUN Base Cost Estimate Proi_ct (US# Millions) Foreign Local Total 132 kV Intercoruection with Thaton System 8.62 6.56 15.18 Yaon 66 kV Refnforcement Project 24.25 19.83 44.08 Upgrading Systm Control Fac littes 11.23 5.01 16.24 Ayeyarwddy 66 kV Subtransafssion 5.78 4.21 9.99 Nnywa/Nndmltay/Kyunchmug 132 kV project 14.73 10.98 25.71 CGnral Substation Uprating progrm 16.08 11.07 27.15 TOTAL TRANSMISSION DEVELOPMENT 80.69 57.66 138.35 5.22 With regard to distribution, the only comprehensive planning study covering the needs was performed in 1985 under GTZ funding from the Federal Republic of Germany in the form of a Master Plan for future development of the Yangon network. It proposed that MEPE replace the 6.6 kV system by 11 kV as soon as feasible, and gradually uprate the 33 kV networks to 66 kV. In 1986 Norconsult, from Norway, also prepared a conceptual plan for the implementation of a 66 kV network. In 1988, EPDC, Japanese consultant, prepared yet another report for the rehabilitation of the Yangon distribution network which recommended a development program costing approximately 50,000 million yen (US$330 million). The report's estimate of the work still needed to rehabilitate the Yangon system is based on the design concepts set out in the Norccnsult report. The scope'of work involved will extend the current 66 kV construction program with a view to completing the voltage upgrading program and associated distribution by 1996. 59 5.23 MEPE distribution designs need to be updated to improve operational reliability and reduce investment costs. Savings can be effected by rationalizing the use of the different voltage classes throughout Myanmar. In Yangon the use of 33/11/6.6 kV systems should be phased out in favour of 66/11 kV as soon as feasible. Consideration should be given to the greater use of overhead lines, in preference to underground cables which are generally in use at present for MV and LV feeders. The long term cost of overhead lines can be reduced through the use of more efficient concrete pole designs, by replacing LV copper conductors, and MV Aluminum Carbon Steel. Reinforced (ACSR) conductors by all aluminum conductors, and by making other design improvements, particularly with regard to connection and isolating devices, in accordance with modern practice. 5.24 Special attention should be given to improving the design of low voltage distribution systems. Distribution transformer sizing needs to be reviewed to improve the utilization of existing LV circuits. In many cases transformers are too large for the associated LV networks resulting in overloading and poor voltage conditions. In many urban and rural areas the greater use of LV "bundled" (insulated) conductors should be considered to reduce tampering and improve reliability of supply. Bundled conductor systems are now in widespread use throughout South East Asia; their overall costs have become competitive with conventional bare conductor systems, they are easier to install and suited to densely populated urban environments. A review of metering practice would also be beneficial with the aim to rationalize the practice of dual metering for domestic consumers and to replace most of the older and inaccurate types of meters. 5.25 With regard to commercial operation of the distribution networks, most accounting and billing functions are done manually throughout Myanmar. MEPE are currently installing a pilot computerized billing system in Yangon area, to improve the efficin-ncy of metering and bill collection. Modern computerized billing systems offer considerable advantages over manual billing operations, not only with regard to improvement of financial operations of the utility, but also with regard to their monitoring capability. Data available to management through billing system can be designed, in conjunction with other technical data bases, to provide essential information about consumers, organization efficiency, and status of plant. To get the most effective use from MEPE computer billing system its exparsion needs therefore to be planned carefully. In particular it would be necessary to perform a thorough review of existing organizational procedures to support computerized billing and make changes to standard forms and collection and billing procedures to handle the flow of information. 5.26 Based on above, preliminary estimates of costs for distribution construction and rehabilitation, excluding local taxes and interest, are shown below and detailed in Annex 5.6: 60 TAUKE 5.11 SISTIUTIOW .EWE PNT 10o00 CUSS MiLlions) ForelD LeAl TotIl Ymgon ¶1/0.4 kV Rehabilitation 37.74 19.30 57.04 Nandably Division 12.61 7.28 19.89 Now Towns Project 10.88 6.50 17.38 Urban Division/Staes 43.51 26.01 69.52 Rural D1vision/States Towns 43.51 26.01 69.52 Rural Eltctrification 11.52 5.52 17.04 TOTAL 159.78 90.63 250.41 F. Investment Profile 5.27 The consolidated investment needs of generation, transmission and distribution in the least cost expansion plan for the base case scenario, for projects commissioned before 2000, are estimated to cost US$658 million in foreign exchange matched by US$681.6 million in local funds, including 356.2 million in taxes and duties. The components are summarized below and detailed in Annex 5.7. Expenditure in the latter part of the decade should also include development costs for the hydro projects which are commissioned after 2000. TABLE 5.12 INVESTMENTS l0 POSER SECTOR CExcluding Taxes and Duties) 1991-2000 1991-1995 Total Foreign Total Foreign Cost Cost (IS) (1s) (CI) (01) Rehabilitatfon 145.61 93.03 145.61 93.03 Genertion 450.50 324.50 255.70 188.10 Transmission 138.35 80.69 76.60 43.74 Distributfon 250.41 159.69 132.00 93.52 TOTAL 984.86 658.00 610.55 418.39 G. Marginal Costs of Supply 5.28 The estimated long run marginal cost (LRMC) for 1990-2000, reflecting the lower capital costs of the combined cycle expansion componert, and the estimated LRMC for 1990-2010, reflecting the higher investment costs of subsequent hydro expansion, for the base case were calculated. The results are indicated in Table 5.13. Two sets of values are shown for each level of supply (i) a value in US currenc.y (c/kWh) reflecting the opportunity costs of capital and operations as used in the ENPEP analysis; and (ii) a value in Myanmar currency (k/kWh) computed by converting all foreign costs at the exchange rate of 50k/US$ and making no adjustment to local costs as detailed in Annex 5.8. The latter value indicates the magnitude of the increase in tariff that would be necessary to be able to finance future investments. On the basis of these marginal costs of power, the existing tariff would be inadequate. Therefore, a new tariff level would need to be put into effect to cover MEPE medium term investment requirements. The design of an appropriate tariff structure would also need to take into account the characteristics of MEPE consumers to provide incentives for increased efficiency in the use of electric power. 61 TWAe 5.13 ESTINMTE LUS UhIIAL COSTS OF NE STST Encray Costs Level of Suppty IM0-200 1:z-2010 (c/WM) (k/kWih) (c/kih) (k/kWh) Gewration 2.7 1.05 4.9 1.97 Tranfussfon 3.0 1.17 5.3 2.12 Subtransuissfon 3.8 1.47 6.7 2.68 Ndiu VoLtage 4.8 1.82 7.9 3.14 Low Volttg 8.7 3.33 11.1 4.40 Ave. Cost of SuppLy 6.5 2.48 9.1' 3.58 H. Issues in the Power Sector 5.29 The major issue in the power sector is the lack of Rlanning. The situation has been exacerbated by lack of planning in the past to deal with contingency situation that has arisen because of fuel shortfalls for power generation. Lack of planning also affects the deterioration of distribution networks which have become grossly overloaded. Indeed investment in the power sector has fallen well behind the needs estimated in the Bank's 1985 Energy Sector Review. For the ten year period 1985-1994 estimated capital expenditure was to have been US$1,666 million. In fact very little has been expended in accordance with the original budget even though demand has more than doubled in the last decade. The largest investment in the last five years has flowed from IDA first lending operation to the sector (Cr. 1245-BU) approved in June 1982 but only recently completed. Other significant recent investment was financed by Overseas Development Administration from the United Kingdom (33/11 kV substations), Overseas Economic Cooperation Fund of Japan (Thaketa power statior., Lawpita rehabilitation), and Kreditanstalt fuer Wiederaufbau of Cermany (KfW) (Kinda project). Whilst planning is at a standstill, even 'committed' projects have been postponed and critical preparatory work needed to formulate plans for further investment has been put on hold. Key projects and investigative work for (i) conversion of Shwedaung and Mann power stations to Combined Cycle operation; (ii) rehabilitation of Yangon distribution system; (iii) construction of Baluchaung #3 hydro project; (iv) provision of spares to maintain operations at Hyanaung, Ywama, and Kyunchaung power stations; (v) feasibility study of the six next ranked hydro schemes; and (vi) an overall Sector Development Study, have all been delayed. 5.30 The principal issue with regard to Leneration is the critical gas and oil, fuel supply situation. Gas use for electricity generation expanded by 18% annually on average over the last ten years. Since 1989 supply has been curtailed J'nd now gas production from existing fields is declining very quickly. In the long term, gas should continue to play an important role in power generation provided its price remains competitive, and more importantly provided MOGF can guarantee adequate supplies. MEPE, however, consumes gas very inefficiently in open cycle combustion turbine sets. Their typical operating efficiencies ranging between 18-24% is normally acceptable for peaking duty but not for base load. Performance can be improved considerably to obtain efficiencies up to 38%, by installing heat recovery and steam generating equipment for combined cycle operation. Two such heat recovery units are already installed at Ywana generating station. However, they are not yet in operation, awaiting rehabilitation of the steam turbine equipment. 62 5.31 Generation by bydro-electric power stations lacks a comprehensive plan for its development. Although Myanmar has considerable hydro-electric potential (para 2.24), very few of the potential schemes have been fully evaluated particularly with regard to power sector requirements. For example, the two recently completed schemes, Kinda and Sedawgyi, have been primarily developed for their irrigation eapability and do not make a significant contribution to power supply. Recently however the government announced its plan to accelerate the program of hydro development giving priority to a number of schemes that have been considered for some time. Extra benefits of developing Hyanmar's hydro resources, above those from electricity generation, would be hydro's potential reliability, downstream irrigation benefits, and local employment created through major construction of dams and other civil works. However hydro power development requires considerable investment and long lead times for its planning and construction, and it is essential that alternative schemes are properly evaluated and prioritized early for development. 5.32 Generation by coal fired power plant also appears to be an option that has not been explored. A coal fired plant could be sited in the lower Delta area in a location where imported coal supplies can be delivered. Such a station could be provided with facilities to burn gas when offshore supplies becomes available. The possibility of a minemouth coal fired station at Kalewa should not be overlooked, but exploratory drilling would be needed to prove its feasibility notably with regard to reserves, before this prospect could be considered seriously. 5.33 The principal issue with regard to distribution is the high level of losses which results in considerable loss of revenue and waste of generation resources. MEPE statistics show losses have not improved from 35% in 1984 when a pilot Loss Reduction Progri j was undertaken under the IDA Power Project. Indeed the situation is similar to many systems in Asia at a stage when they were characterized by relatively high svstem losses largely as a consequence of rapid growth in demand. These have however been brought down from 30-35% over a 5-10 year period with little effort. Average overall losses for Indonesia, Sabah/Sarawak, and the Philippines, for example, now range between 20-22%. Experience in Thailand indicates these can be reduced even further by concerted effort; as a result overall distribution loss levels remain 6% in Bangkok city, and 8% throughout the Provincial Electricity Authority largely rural service areas. It is clear, therefore, that with adequate planning and commitment by management, losses in the Myanmar system could also be reduced significantly. 5.34 As shown in Annex 5.9, from 1981 to 1988, residential tariffs in Myanmar were higher than industrial tariffs which reflected the higher costs of serving the low voltage residential sector. Tariffs were increased overall in 1988 but they were set almost equal for the residential and industrial sectors. As a result, the flat tariffs offer little incentive for consumers to reduce their demand on the system. Energy based tariffs have little relationship with the cost of supply, offering therefore minimum scope for efficiency improvements. 63 TAME 5.14 AA fVEIES 1981-82 ,1U-89 kih kWh Sales Rev. Sales Rev. (X) (X) (X) (X) Residential (LV) 30 46 35 42 IndLstrial (NV) 53 32 52 42 Bulk (NV) 14 16 10 11 Others 4 6 3 4 5.35 Unlike most of its Asian neighbors, Myanmar has no strategy for expanding its rxral electrification Rrogram. In 1979, the number of villages electrified was 709. It rose to only 751 in 1989. Approximately 20% of MEPE's consumers (9% of total demand) are served by isolated diesel/mini hydel power stations scattered over the 14 Divisions/States of Myanmar. The number of diesel engines has increased from 570 in 1985 by only 60 to date. The rate of growth of new consumers and consumption in these areas is significantly lower than for the interconnected system. The government is now pressing for extension of existing distribution networks throughout Myanmar to provide power to a number of proposed new towns created by its relocation policies. For the four new towns near Yangon, for example, MEPE estimates that the respective loadings by 2000 would be as follows: New Dagon 16 MW, Shwepyitha 5 MW, Pale 8 MW and Hlaing Thay 6 MW. However, there is little associated infrastructure in place in the new towns and prospects for growth may be optimistic. In the event that the projects are implemented as planned, there will be further strain on the critical power supply situation in Yangon. 5.36 In contrast to other ministries in Myanmar, and certainly in contrast with comparably sized power utilities in Asia, MEPE staff have an inadeguate working environment including poorly maintained office buil.dings, furniture and operating equipment (vehicles, tools); inadequate facilities such as computers, copying equipment, technical and administrative support materials (e.g. drafting, filing, workspace etc); and absence of training programs and facilities. Although a new head office complex is under construction in Yangon, the problem is particularly acute in MEPE's distribution divisions where the most urgent attention should be focused. For an organization with a budgeted revenue of 900 million kyats in 1989/90 little has been spent on important institutional measures to improve MEPE's overall efficiency. I. Conclusions and Recommendations Generation Development 5.37 In the short term, MEPE should take immediate steps to improve its power supply situation. Generating units are curtailed due to lack of repairs and/or fuel, or they are on extended outage due to lack of spare parts. Limitations in gas supplies however provide the main cause for concern and an immediate plan should be established and implemented to cover the next three to five years of power supply. This would involve the following steps: (a) Procure crude oil for refining and supplying sufficient diesel oil in order to (i) maintain continuous operation of Thaketa and Ywama power plants; (ii) ensure standby operation of the Shwedaung, Mann, and Myanaung plants; and (iii) satisfy minimum needs of the rural 64 sector. For these plants diesel requirement could be as high as 740,000 bbl per year. In addition, steam plants at Thaton and Mawlamyaing will require up to 400,000 bbl per year of fuel oil. (b) Prepare, as soon as possible, all of the above stations for burning either diesel oil or gas, arrange for transfer and storage of diesel at each site, and commission or rehabilitate fuel oil storage and handling facilities. (c) Design and implement early conversion of the Thaketa, Mann and Shwedaung plants to combined cycle operation. This would add 103 MW to the system and reduce gas consumption by up to 50%. Likewise conversion of the Myanaung plant should also be considered within 12 months after reviewing the fuel supply situation. 5.38 In the medium term, the critical issue is related to the availability of gas. MEPE cannot afford the risk of waiting to decide whether gas would become a long term viable source of fuel for its least cost combined cycle development. In its own interest, MEPE must take steps to investigate alternative generation options. At this stage, the most likely candidates for the 1990's are steam plants burning either fuel oil, or coal, depending on availability, and hydro. However, more investigation work is needed to establish the costs and risks of development, as well as the infrastructural support, needed to develop the resources. 5.39 For the longer term MEPE must prepare an optimal development plan to exploit it3 hydro resources. Specific planning should begin immediately for large hydro generation projects whick generally have long incubation periods. 5.40 To promote generation in the Private sector three situations deserve to be encouraged by M:PE: (i) where an industry has a continuous demand for sterm for procesp heating, cogeneration, with its higher thermal efficiency than conventional thermal power plant, makes it economically more attractive; (ii) where a plant produces waste (such as sugar mill bagasse, saw mill waste, rice husks etc.) that can be used as fuel; and (iii) where a local resource (such as a hydro site, a coal mine, a geothermal reservoir or peat deposit) can be developed to meet a specific industrial requirement. Transmission and Distribution Development 5.41 MEPE needs to prepare a ten year transmission and distribution development plan. This should examine the nature of future development with a view to rationalizing design procedures to reduce costs. It should also include a review of tariffs and a strategy for rural electrification to maximize the return on investment in the power sector. 5.42 There is coknsiderable scope to reduce losses and to increase electricity conservation. A concerted effort by MEPE management to bring losses down is essential in order to increase revenues and reduce the incidence of load shedding. This cau be done by reinstating the activities and strengthening the role, of the Loss Reduction Unit that was established under the IDA Power Project. 65 VI. TRADITION"L ENERGY SECTOR A. INTRODUCTION 6.1 The biomass fuel resources of Nyanmar consist principally of woodfuels (fuelwood and charcoal), but there is also a considerable quantity of agricultural residues that could be used for fuel without adversely affecting soil fertility or animal husbandry. A major portion of the woodfuel resource is present in the forests of the country, but trees along road sides, around fields and within village compounds also contain significant quantities of fuel. However, there is a scarcity of reliable data on the standing stock and sustainable yield of woodfuels. There is also no reliable data on the quantity of agricultural residues: available for fuel. 6.2 In 1989/90, woodfuel consumption in Myanmarl was es ..mated to be approximately 27 million air dry tons (adt), equivalent to 9.3 million tons of oil equivalent (toe), representing about 82% of the total energy consumption for the country. In 1982/83 woodfuels and non-woody biomass provided 86% of the energy consumed in the household and small/cottage industry sector and it is estimated that approximately the same situation exists today. In the rural areas, fuelwood is used almost exclusively for household ccoking with a limited amount of agricultural residues in the form of cotton and pigeon pea stalks being reportedly used in the Dry Zone areas of Sagaing and Mandalay Divisions. Fuelwood is also widely used in a variety of small/cottage industries, such as jaggery boiling, brick making, pottery and cheroot production; while substantial quantities of agricultural residues are also used, including ground nut shells, ziziphus fruit shells, rice husks, and sesame stalks. Urban areas consume approximately 25% of the woodfuels primarily for household cooking and heating. Charcoal, although representing only 5% of the woodfuels consumed, is primarily sold in urban centers. As a result of this relatively concentrated demand, its increasing saleb are an important cause of mangrove forest degradation. 6.3 Although Myanmar is endowed with considerable vegetation cover, including 31.6 million ha of closed high forest (47.5% of land area)2, there has been a steady degradation and depletion of this over the last several decades due to clearing for agriculture, both settled and shifting, and collection of wood for fuel. As Table 6.1 shows, there has been a steady decline in the percentage of land area covered by forests: between 1925 and 1975, there was an estimated annual average depletion rate of 175,000 ha per year, but in the period 1975 to 1980, this rate appears to have jumped to 700,000 ha per year according to some estimates. There is some correlation between the above depletion rates and the depletion of mangrove forest in Ayeyarwady Division. There is also a correlation between the cessation of kerosene supplies for household energy use in the mid 1970s and the sharp rise in forest depletion: between 1961/62 and 1 Nymanr is divided Into 14 territorial forestry regions which correspond with the adoinistrative divisions. These are subdivided into 48 towrehip grops, previously known as forest divisions. There are 232 townships, each headed by a township officer. 2 See map IBRD 22978 66 1975/76, charcoal consumption rose at an average annual rate of 5%, but between 1974/75 and 1982/83 consumption rose by an average of 16% with increases of 20 and 35% respectively in each of the first two years of this period. Fuelwood consumption between 1967/88 and 1973/74 rose at an average annual rate of 0.35%, but between 1973/74 and 1983/84, this rate averaged 4%. There may also be some correlation between the incr6ased depletion of forests in the second half of the 1970s and increased agricultural activities. TULE 6.1 DEPLETICN OF FOREST M Year Forest Cover (X) 1925 65.8 1958 57.2 1975 52.7 1960 47.3 Source: Pe Thein, 1990 and FD, 1989. 6.4 The deteriorating forest situation is shown in Table 6.2 w'here between 1975 and 1980, a total of 6.37 million acres of closed forest were lost as was 2.63 million acres of degraded forest. In the same period, the area affected by shifting cultivation increased by 0.41 million acres in closeid and 2.64 million acres in degraded forests. B. THE RESOURCE BASE 6.5 As in the case in most other countries, there has been little effort made to estimate, with some degree of reliability, the standing stock and annual sustainable yield of wood fuel in Myanmar. Estimates have been made of the standing stock of commercial timboer, but until the current national forest inventory, mich of the resource data was out of date and often the reliability was suspect. Estimates for the woodfuel supply area for each administrative division were made by the mission using forest class maps prepared from 1980 satellite imagery. Within each division, the areas of the four forest classes as shown in Table 6.3 (Closed Forest, Closed Forest Affected by Shifting Cultivation, Degraded Forest and Degraded Forest Affected by Shifting Cultivation) were considered in relation to their distance from urban centers and rural population concentration. It should be emphasized that these estimates are rough, but are the best available at the present time. It will be observed that only 20% of the closed forest in included in the woodfuel supply rrea reflecting the fact that much of the closed forest is relatively remote from woodfuel consumption centers. It is, however, possible that woodfuels could be available from more of these closed forests if they became more economically acceasible and the management prescriptions were changed to include the cutting of non-teak species for commercial purposes and fuel. 67 TW1E 6.2 TL E CM CIG REA SITULTIo UETTEE 1975 AM IU (000 acres) Cl.Forest Deg.Forest State or Closed offected by Degraded affected by Mon Division Year Forest shift cult. Forest shift cult. Forest Total Chin 1975 2703 2030 1178 2500 487 8,896 1980 2408 1575 1368 2896 650 8,899 Ayeyarwady 1975 1347 0 1300 0 6035 8,682 1980 1233 0 1004 0 6445 8,682 Kechin 1975 15766 3066 54 559 2557 22,002 1980 13977 3622 245 922 3237 22,003 Kayin 1975 2634 1813 281 1436 1343 7,507 1980 2575 1986 355 1356 1235 7,507 Keygh 1975 1041 771 465 289 330 2,896 1960 758 808 401 457 476 2,900 Nagucy 1975 1700 103 4611 13 4648 11,075 1980 1666 193 3331 478 5408 11,076 Nendetay 1975 1872 600 1203 246 5229 9,150 1980 1451 559 1015 403 5722 9,150 Non 1975 352 313 697 432 1245 3,039 1980 277 220 425 476 1640 3,038 SBgO 1975 3525 269 1288 221 4383 9,686 1980 3625 336 757 567 4453 9,738 Yangon 1975 284 0 49 57 2123 2,513 1980 211 28 80 63 2131 2,513 Sagcing 1975 11785 2967 1996 104 6532 23,384 1980 10089 3222 2087 299 7685 23,382 Shen 1975 8156 11067 2154 11782 5341 38,500 1980 7091 10838 1909 11737 6926 38,501 Tenintheryl 1975 7041 846 927 1260 637 10,711 1980 6762 835 757 1726 631 10,711 Rekhine 1975 4362 771 1047 349 2559 9,088 1980 4121 804 779 495 2889 9.088 TOTAL 1975 62,568 24,616 17,250 19,248 43,449 167,131 TOTAL 1980 56,244 25,026 14.513 21 877 49,528 167 188 Source: FD 68 TAKE 6.3 ESTINATES OF VnWFREL SUWPPY AEAS ST DIVISIONASTATE X000 wcres) Forest Cover Clrsses CL. For. Deg/ For. Divlsion/ Closed Affected 6y Degraded Affected by State Forest Shift. Cult. Forest Shift. Cult. Total Ayeyarwady 1233 0 1004 0 2237 Yangon 210 28 80 63 381 Bago 3625 300 756 568 5249 Shan 450 7587 1909 8800 18746 Rakhine 2470 804 780 495 4549 Handelay 1200 560 1015 402 3177 Soping 720 3010 2088 300 6118 mn 83 220 425 476 1204 Taninthanryl 1400 835 755 1730 4720 Chin 480 1575 1370 1450 4875 Kayah 30 810 400 455 1695 Kayin 750 1990 355 1355 4450 Kachin 700 3620 245 920 5485 NagWay 1400 194 3330 478 5402 TOTAL 14751 14512 17492 Source: FD and issior estimtes 6.6 Very rough estimates of the standing stock of woodfuels within the woodfuel supply areas were obtained by using commercial wood volume estimates available from the National Forest Inventory and other FD estimates and then applying a f&ctor, based on experience in similar countries, to obtain the amount of wood available for fuel. Table 6.3 shows the estimated average standing commercial volume for each of the four forest classes derived from the National Forest Inventory together with a factor that represents the ratio of total above-ground woody biomass to commercial woody biomass. The standing stock of wood available for fuel from roadside, village and farm trees was estimated at an average of 1.2 adt per household (0.24 adt/capita) for non-dry zone areas and 0.4 adt per household for dry zone. This took into account that only 40% of the wood present would be used for the fuel; the rest being for house building, shade, fencing and other purposes. The standing stock of woodfuel that is present as sawmilling waste was estimated as 50% of the volume of commercial wood. The total standing stock of woodfuel in 1990 is estimated at 1123 mil.ion air dry tons (adt) from a supply area of about 68.29 million acres (ac). TABLE 6.4 VALIES USED IN ESTINATING STAMING STOCK OF WW0FUELS Ratio of Vol. of Total Woody Woodfuels Ston.Stk. 8iomfss to Available Forest Class (HCT/ac) Comm. Wood (adt/ac) Closed Forest 29 1.5 25 Closed Forest Affected by Shifting Cultivation 10 1.5 8 Degraded Forest 5 1.8 4 Degraded Forest Affected by Shifting Cultivation 1 2.0 1.4 Source: Mission estimates based on Natural Forest Inventory end FO estimates. 69 C. SUSTAINABLE YIELD OF WOODFUELS 6.7 Estimates of the sustainable yield of woodfuels are based on the mean annual increment (MAI) or growth of the forest, plantations and scattered trees. But there are no reliable data on these growth rates, in fact, it seems few such measurements have been made in Myanmar forests. In the absence of reliable growth data the mission applied estimates based on experience in other countries with similar geoclimatic conditions for growth rates for the various forest classes as shown below. Based on this data the total sustainable yield that could be harvested annually has been evaluated at about 21.46 million adt. About 85% of this stock is available from forests and plantations with the balance coming from non-forest trees in and around villages and farms. TABLE 6.5 ESTIM AED NRN RATES FOR FOREST CLAMS woodfuel Total MAI MAI Forest Class MAI (X) (adt/ac) (adt/ac) Closed Forest 2.5 1.50 0.5 CI.For.Shift.Cult. 3.0 0.65 0.2 Dgraded Forest 5.0 0.45 0.2 Deg.ror.Shift.Cult. 4.0 0.1 0.05 Plantatiorns 20.0 3.0 0.6 Plantatiors (Dry Zone) 12.0 1.5 0.3 Source: Mission est imtes (1990) 6.8 At this point, only a limited quantity of agricultural residues are used for energy and most of this is used in small/cottage industries, although the sugar industry uses bagasse as a fuel in its sugar mills. But it is likely that agricultural residue fuels will become increasingly important in divisions/states where woodfuels are or will be in short supply. Agricultural res'.dues represent a substantial fuel resource, although care should be taken to only include those supplies that are surplus to higher economic values uses such as cattle fodder and manure to maintain agricultural land fertility. 6.9 Table 6.6 summarizes the estimates for the sustainable supply of woodfuel and non-woody biomass (agricultural residues) available for fuel by division and state in 1990. The former includes wood from the four forest classes plus sawmill residues and wood for fuel from roadside, village and farm trees as well as plantations. Thus while the total standing stock in 1990 is estimated at 1,123 million adt, the total suscainable yield that could be harvested annually has been evaluated at about 21.46 million adt for woodfuels and 5.624 million adt for crop residues. 70 TAKLE 6.6 ETINMTES OF OoRPELS SrA IWU ST=Z AM USTWAIMALE YIELD. 1990 (million edt) Divisio.VState Sustoanable Yield Standing Forests Sawmil Roadside, Total Crop Stock Residues Farm * Yield Residues Village Trees Ayeyarwrddy 62.7 0.96 0.08 0.22 1.26 1.3960 Yangon 11.9 0.18 0 0.22 0.40 .5120 Be"a 177.1 2.60 0.03 0.53 3.16 1.1012 Shen 164.4 3.05 0.01 0.52 3.58 .3540 Rekhine 130.5 1.87 0.02 0.30 2.1S .2930 NKndaley 70.5 1.14 0.01 0.13 1.28 .6060 Saga In 91.5 1.64 0 0.13 1.77 .5440 M"gWy 87.2 1.61 0.01 0.11 1.73 .3290 Non 11.7 0.23 0 0.21 0.44 .2370 Tanintheryl 83.7 1.29 0.03 0.12 1.44 .0740 Chin 55.9 1.04 0 0.01 1.05 .0470 Kayah 16.8 0.33 0 0.02 0.35 .0250 Kayin 69.2 1.10 0 0.17 1.27 .1020 Kachfn 89.7 1.43 0.01 0.12 1.56 .0930 TOTAL6 112l2 18.41 0 J& 21.46 5.6242 $curce: Nissfon Estiontes (1990) D. CONSUMPTION AND DEMAND 6.10 Data on woodfuels consumption is also scarce and unreliable, based mainly on limited surveys carried out by the FD. The mission used these estimates as well as estimates made bv several other agencies and its own very limited sample to arrive at a current annual per capita consumption figure for woodfuels of 0.7 adt (0.9 ml3). It was difficult to see a clear difference betiveen rural and urban consumption, but more definitive data may indeed show such a distinction. There was also some indication that the consumption could vary considerably by region, with the Dry Zone in central Myanmar possibly having figures as low as 0.2 to 0.4 adt per capita. 6.11 In 1990, it is estimated that the total woodfuel (fuelwood and charcoal) consumption was 28 million adt, which, compared to an estimated 23 million adt cornsumption in 1980 represents 2% average annual increase. The non-woody biomass consumption is estimated to have increased from 900,000 tons in 1980 to 1.5 nillion tons in 1990, an average annual increase of 5.2%, indicating the increasing use of this resource for e orgy, particularly in fuelwood deficit areas such as the dry zone, where it is thought that there is increasing substitution of fuelwood with crop residues. The major share (21 million adt or 75%) of the woodfuels consumption is in rural households where fuelwood is usually collected and burnt on a subsistence basis. Charcoal is not generally used in the rural areas, and very little in the way of non-biomass energy is consumed. In Yangon, the major woodfuel used in charcoal, although some fuelwood is consu.ed by households as well as by tea shops and sidewalk eating establishments. ltut most of other urban centers appear to use fuelwood almost exclusively (Annex 6.3). 6.12 While information on fuelwood and charcoal demand is limited, there appears to have been a significant increase in consumption shortly after kerosene supplies were curtailed in the mid 1970's. Charcoal and fuelwood consumption jumped in growth from a few percent per year to between 20% and 30% 71 per year in 1975 and 1976. Coincidentally, the reported harvest of mangroves increase markedly. 6.13 Projections of woodfuel consumption were based solely on population projections without any allowance for conservation or fuel substitution as there seemed to be little chance of this occurring at least in the medium term. These projections (Table 6.7) indicate that the overall sustainable woodfuel supply for the country is only about 75% of the 1990 woodfuel consumption and even with the addition of crop residues that could be available for fuel, there is still an overall energy biomass supply-demand gap of some 2.5 million adt. When woodfuel consumption and sustainable supply is compared on a state/divisional basis the results show that, despite 45% of the country being covered in forest, there are serious deficit situations irn Central and Lower Myanmar that are leading to depletion and degradation of the forest resource and the attendant ecosystem. The former region is associated with the Dry Zone, i.e. Mandalay Division, the southern half of Sagaing Division and much of Magway Division. The latter is comprised of Ayeyarwaddy, Yangon and Bago Divisions, but with the former two being particularly affected. Urban demand in Yangon is a major problem, but the high rural population as well as urban dema-d in Ayeyarwaddy is also putting a strain on the woodfuel supplies. 6.14 There are two main areas that have inter-divisional transportation of woodfuels. The first of these is the Yangon woodfuel supply catchment that has Yangon city as the focal consumption point. Woodfuels, particularly charcoal, are currently transported from all these outlying Divisions to Yangon. In the Dry Zone, there is transport of wood from Sagaing Division to Mandalay City, while towns in the northwest of Magway Division obtain woodfuels from southern Chin Division. The trade between divisions/states in woodfuels, particularly charcoal, is likely to increase over the next 10 years. In 1990 the mission estimated that some 2.5 million adt of wood equivalent of woodfuels was traded with the major share of this (1.8 million) being imported into Yangon. By 2000, woodfuel trade is projected to be about 3.5 million adt with approximately 2.2 million adt being imported by Yangon. By then an increasing quantity (0.7 million adt) is also projected to be imported by Handalay. 6.15 Table 6.7 shows the wood balance situation through 2000 to 2005. For those divisions that are overcutting this will r3sult in a reduction in the standing stock and sustainable woodfuel yield. The extent of this reduction, and henca the exact sustainable yield in future years, is difficult to predict as the overcut areas are not necessarily lost completely. Regeneration from seedlings and coppice can and often does occur, perhaps quite vigorously, if the areas are protected over the first few years after cutting. On the other hand, however, areas may be repeatedly cut over a relatively short period of time so that regeneration is destroyed or severely degraded while some areas will undoubtedly be lost to agricultural encroachment. 72 TAKE 6.7 PJECTII OF IDWEL TUfINI, TMDE AM MET SULUPDEFICIT sr DIVISIGIISTATE Foe the year 1990, 2M wd 2005 (mlittin #dt) D1vfsfonl Sut tn. Internt lNoet Crop Crop Biss Stcte e d CnumLp Export lzport Sur tus/ Ro Reg,ue Sur tug/ Woodfust Feuel Consgop Defici ft g - -0 t-§ 8:28 0~ 20: 3 -g lg ' KSay 8:'8 0.20 8 0 * a. .86 .5 ',°1.00 8 i.! {St 0 th. 1 | $-g 8:IS I 0 - TOTALS 1 8.7 3L567 La -12.41 L61 1.49 -2 sw lYnrwaddy w1.00 olha :4 Nauwa 0.30 0. S:s 0.701 Jf df int arye TOTALS QL!4Z N 41 LZl LZQ -12.41 L.J- j -10.40 6.7Tewoodfuel balance situation inth Central. and Lover Myanmar diisin troJethed poihmnt whee itoisupin8 projected tha bys 2005 2008a wil have almstexausted yitsd rsouckeo woodfe whe YarwaddyU 4wil onlhepproxim 50t tof the st0%anding rstocknit haedi 90 with a co rrespdfiitondn deceas inlonat 6.1 theDyZn he woodfuel defcitsiuaption in Cetalad0oer00na is proJectedtorsto1 cmtchiont athe conhation is6 prllojete ato rise% tbov20eo the sustainabed yield.B 2005 the deficit is projected to rise to about 9.5 million adt. 73 6.18 The per capita consumption of crop residues is bound to increase, particularly in the Dry Zone rural areas. It is p"o1ected that by 2000 an average of 10% of the biomass consumed would be croo residues; 3.6 million tors. By 2005 crop residue use as fuel is projected to rise to 4.5 million tons, with not only rural industries but many households using a greater proportion of agricultural residues for fuel. Some increase in crop residues available for fuel could occur with potential increases in crop production, but this is not possible to estimate at present. E. INVESTMENTS. INSTITUTIONAL AND POLICY ISSUES 6.19 Ai.y substantial woodfuel resource development should be preceded by both an assessment of the biomass available in the more critical areas and a survey of household energy consumption. Present estimates indicate that the two problem areas, the Dry Zone and Lower Myanmar will have biomass deficits of 8.4 and 7.3 million adt in 2000. This would require the growing of approximately 4.5 million acres of trees dedicated for fuel in the Dry Zone 1, a program of 450,000 acres a year for ten years or considerably more if multipurpose plantings are established. In lower Myanmar (Bago, Yangon and Ayeyarwady Divisions) a total 1.4 million acres of woodfuel plantings would be required or 175,000 acres over a eight year period. This scale of plantings is clearly beyond the capacity of the FD and, in any uvent, much of the deficit relates to rural areas where fuelwood is not traded to any extent. Improved forest management may increase productivity by an additional 0.3 adt/ac/yr which would mean a management program over 22.3 million acres in the Dry Zone and there is only an estimated 10 million acres of accessible forest. In Lower Myanmar an increase in productivity of 0.6 adt/ac/yr may be achieved requiring 10.8 milliotk acres to be brought under management, again more than the accessible forest for woodfuels extraction. 6.20 Based on the information that is availa"le, the approach to alleviating sustainable woodfuel shortages in the short term should be one that considers both supply and demand side options and within the context of both the rural and urban consumer for those areas considered to have serious woodfuel shortages. For urban areas the immediate strategy for investment (Table 6.b, should be an improved charcoal and wood stove program, principally with the provision of technical assistance; a pilot program for improved management of deciduous and mangrove forests to enhance the production of woodfuels and other forest products; species and provenance trials for woodfuel and multipurpose trees and shrubs within woodfuel impoverished areas; a feasibility study for peri-urban plantations; and at the same time every effort must be male to achieve a reasonable degree of substitution with kerosene, gas or electricity. In rural areas action should initially be focused on localized shortages through enhancing the seedling distribution program to village-rs; assistance in the development of village nurseries; developing a system of 'grassroots' forestry extension that will assist villagers to grow and manage trees while understanding and acting on the villagers' concerns and priorities related to forestry. 1 A mean wnmuul increment (MAI) of Tm3 or 4.5 adt/ha/yr (1.8 adtlac/yr) Is assumed for the Dry Zone and 2C.3 or 13 adt/ho/yr (5.2 adtlaclyr) for Lower Nyanmar. 74 TAELE 6.8 COCT OF IUmSTlENTS FOR UMNEL DEVELOPIENT AU CONSEtVATIONU Itam Cost Duratfon USS million (months) Bluas Assesment 0.42 16 Household Energy Survey 0.20 10 improved Stoe Program 0.22 18 Improved Charcoal Production 0.20 24 Improved Forest nagement 'Pilot) 0.50 36 Species and Provenane Research 0.11 36 Plentation Fe sibility 0.04 2 Plantatton Program (200,000 sc) 44.90 96 Seedling Program 2.88 48 Develop Extensfon System 2.00 48 ouce: Mission Estifmtes (1990) 6.21 But there are several policy and institutional issues that need to be resolved before effective investment can be made in any woodfuel development and conservation program. These include: (a) The Growing and Harvesting of Trees for Commercial Purposes by Villa prs. At present villagers are permitted to grow trees or collect wood for their own use, but are not permitted to sell such wood unless they obtain a license to cut and a royalty is paid. In order for Myanmar to overcome its woodfuel deficit problems and the associated forest degradation it will be necessary to adopt a policy that encourages and supports the production of wood for both subsistence and commercial purposes by the private sector, particularly the rural households. For villagers to have the incentive to grow woodfuels and other wood products for the urban market the legislation might be altered to permit the sale of wood grown by these people. The same rationale applies to allowing the sale of wood products from forests that would be managed by villagers, although in this case care has to exercised so that the cutting is controlled and limited to designated managemezut areas, possibly with some form of extraction permit as is currently issued to charcoal manufacturers, but without the same fee. The policy direction is to provide incentives, not disincentives, for popular participation in the production of wood for fuel and other purposes. (b) Nonsustainable Woodfuel Quotas. The current system of establishing quotas for charcoal and fuelwood production is in serious need of revision, particularly for those divisions that are in a sustainable woodfuel deficit situation. The quotas, which are based on very rough approximations of sustainable cut for these and other forest products, are established each year in discussions with the Planning Department of the Ministry of Finance and Planning. These quotas are the upper limit for production of a traded wood product in each division and, despite the fact that it is recognized that the quotas set for charcoal and fuelwood are far above any sustainable rates, the quotas are raised each year to meet anticipated increases in consumption. 75 (c) woodflI Stumpaggp . The current royalty of k 2 per 90 lb bag of charcoal and k 5 per stacked ton of fuelwood, equivalent to k 6.5 and 10 per adt respectively, &re far from representing the economic or financial value of the wood on the stump. The mission estimates that a stumpage of k 38 per adt of wood for fuel is required currently to cover the costs of wood available through managing existing forests. A stumpage of between k 54 and k 142 would be needed to cover the cost of wood for fuel from dedicated woodfuel plantations depending upon the site conditions and resultant yield potential. Without higher stumpages it is difficult to justify government investment in woodfuel development programs or to encourage the production of woodfuels by the private sector. (d) Continuiny Agricultural Encroachment. The decline in the percentage of land area covered by forest and the increase in forest affected by shifting cultivation are indicative of the continuing encroachment and destruction of forest for agricultural purposes. In fact, in line with evidence in several other countries, it is suspected that clearing for agriculture in Myanmar is the major cause of forest degradation and depletion. Such destruction also reduces the resource base of woodfuels exacerbating a deficit situation in Central and Lower Myanmar. Unless such agricultural encroachment is stopped or at least regulated on a meaningful land use basis that considers the need for wood products as well as ecological and soil/water protectior. needs, plans and programs for woodfuel resource development and conservation will be frustrated. (e) Forestry Degartment Strengthening. The Forestry Department is likely to have some staff deficiencies if it were to undertake a major woodfuel development program within the public estate; however, they lack the manpower and training for developing and conserving woodfuels, particularly within the private sector. F. CONCLUSIONS AND RECOMMENDATIONS 6.22 Central and Lower Myanmar have insufficient woodfuels and non-woody b'omass to support thne current and projected consumption of such fuels on a sustainable basis even allowing for transport across divisional or state boundaries. The continued overcutting of the forest resource to supply woodfttels and agricultural encroachment in these areas is having an increasingly detrimental effect on the environment. The large areas of mangroves, that are prime sources of charcoal and fuelwood, are being particularly affected in Ayeyarwaddy Division and, with the depletion of preferred stocks there, Rakhine and Tanintharyi Divisions are now being affected. No studies have been done on the detrimental effect on fish stocks, but contin'ed degradation of the mangroves must adversely affect these. 6.23 Interventions to alleviate the woodfuel supply deficit in Central and Lower Myanmar from both an urban and rural point of view involve both 76 cen.servation as well as resource development and manager-nt. However, any action taken should be within the overall energy context with special consideration being given to interfuel substitution, perhaps when the oil fields have been rehabilitated, with kerosene, without which it will be difficult to overcome the woodfuel shortages and the associated environmental degradation. Woodfuel development and conservation should be done within the framework of a national energy strategy, with the problem being clearly defined using reliable data on woodfuels supply and demand at least for the identified problem areas. The interventions will need the support of legislation that recognizes the role played by woodfuels in both the forestry and energy sectors and the need for private sectir involvement In woodfuel development and conservation. Finally, to be effective in planning and implementing such interventions the Forestry Department should be strengthened. 77 VII. ENERGY PRICING A. INTRODUCTION 7.1 Recent policy shifts by the government, towards liberalization of the economy provide an opportunity for more rational and flexible energy pricing so that it can make an important contribution to government's fiscal and budgetary objectives. The shortage of public finance has been identified as a major constraint in energy sector development. Appropriate pricing policies can help to relax this constraint both directly--by taxing energy consumers whose demand is price inelastic and whose incomes are high--and indirectly by enabling the SEE's to self finance a larger share of their investment program. A main cause of domestic energy shortages has been the persistently low and inflexible energy prices over a considerable period of time: the shortages in petroleum products being handled by rationing at official prices and tolerating a black market, and in electricity by frequent load-shedding. This problem is critical to economic growth because ultimately the supply gap is met through curtailment of economic production and socio-economic welfare. 7.2 The basic problems in energy pricing in Myanmar are: (a) present price levels are much too low to induce energy conservation, to promote efficient energy decisions, to provide funds to the energy SEEs, to provide adequate taxes to government, and to cover the costs of supplies; (b) all the modern energy prices have been much too inflexible, being kept fixed over several years in spite of domestic inflation, changes in the costs of energy supply and other significant changes elsewhere in the economy; (c) the administrative procedures and technical criteria for setting prices are cumbersome and lacking; and (d) some of the relative prices appear to be out of line in view of the country's needs and difficulties. 7.3 There are also associated problems which accompany the basic problems of pricing; the energy SEEs lack satisfactory autonomy to make effective use of pricing policy; the government itself is operated extensively on a non-cash basis and needs reform for pricing to be effective, and foreign exchange policies severely limit the potential effectiveness of energy pricing policies. Therefore any serious consideration of pricing reform overlaps with important issues of institutional organization and management within the energy SEEs and in government operations. This chapter reviews the current status of energy prices in the main sectorb of the economy, both in terms of the relation to economic costs and in terms of their net impact on government financial resources. 7.4 A recurring difficulty in evaluating and setting domestic energy prices in Hyanmar is the foreign exchange rate situation. Myanmar government has not changed the grossly overvalued exchange rate for more than a decade despite continuous appreciation of the kyat and a widening gap between the official and parallel market rates. At present in the parallel market, the value of kyat is nearly one tenth of its official price of 6.2 kyat to the dollar. Maintaining such an overvalued exchange rate leads to inefficiencies in its use, adversely affects incentives to produce, reduces government revenues and results in scarcities. Table 7.1 gives a comparison of energy prices in some South Asian countries which demonstrates that Myanmar's prices, at the real exchange rate, are considerably lower than those of its neighbors. 78 Assuming an exchange rate of k 50/US$, the present official prices translate into US$2.20/barrel for crude oil, US$0.21/gal for diesel and US$0.32/gal for petrol, which would be some of the lowest diesel and petrol prices in the world, and electricity tariffs, which were revised to an average of k 0.48/kWh in 1988, would be 0.90/kWh, which are very low by internatioi-al standards. TAKE 7.1 COWARIU OF E-MET PRICES FOR SELECTED FELS INI SIfI ASIA CIF Ratio of YANGON Domestic MYAWNNR INDIA THAILAND PHILIPPINES VIETAM PRICES to CIF at k6.2/S atk5O/S 1990 1990 1990 1989 1990 Prices Crude Olt S/b 17.70 2.20 14.80 25.00 0.09 G"aolino $/lO 2.58 0.32 3.80 1.60 3.01 0.82 1.03 0.31 Kerosene S/IG 2.18 0.27 0.98 1.51 1.21 0.64 0.91 0.30 Diesel $/16 1.69 0.34 0.60 1.38 1.21 0.61 0.87 0.39 Fuel Oil 5/IG 1.37 0.27 1.10 0.64 0.87 0.33 0.61 0.44 Natural Gas S/mcf 1.21 0.15 4.20 2.80 2.00 0.08 Cot S/ton 59.00 7.30 L9.00 58.00 62.00 8.2-10.30 39.00 0.19 Electrielty Tariffs 4/kWh Residential 8.00 1.00 1.5-3.8 5.50 6.10 2.10 Services 8.00 1.00 3.5-9.4 7.90 8.60 6.40 Industrial 6.00 0.80 2.1-9.3 7.20 7.60 3.10 Avere 7.70 0.96 2.6-5.1 6.90 8.10 2.40 7.5 There are two key objectives in setting energy prices: they should be sufficient to provide for financial viability of the energy entities and generate sufficiently high surplus to allow the sector to provide a significant part of its future investment program, and, secondly, the prices should be set at levels which encourage efficient use of energy and avoids wasteful consumption. There are serious problems with current energy prices in Myanmar since they reflect neither the economic supply costs nor the opportunity cost of energy; and there is a critical need for an alternative pricing structure and a clearly defined pricing strategy. B. CRUDE OIL AND PETROLEUM PRODUCTS PRICES 7.6 As shown in Table 7.2, the price of crude oil had remained virtually unchanged in Myanmar from 1980 to October 1988, and in addition prices were only increased slightly during the 1970's, in spite of the increases in international oil prices in that period. As a result, mounting losses were incurred by MOGE. Finally, in an effort to reform the situation, prices were reestablished at higher levels by the government in October 1988, when the price of crude was increased from k 42.66/barrel to k 110.00/barrel, and natural gas from k 2.10/mcf to k 7.50/mcf. The consumers' prices for petrol, kerosene, diesel, fuel oil and aviation fuel were also kept fixed between 1975 and October 1988. Furthermore, in the period 1982 to 1988, petrol, diesel and fuel oil were handed over to KPPE at the same price it had to sell products to the consumer, thus denying MPPE any margin to cover its operating or other costs. This led to the running down of MPPE's previously accumulated financial reserves. Eventually each of the 79 petroleum operators, MOGE, MPE and MPPE were accumulating debts. 7.7 The prices of both crude oil and petroleum products are supposed to be set on an accounting cost-plus basis, for crude oil ex-MOGE, for products ex the refineries (MPE), and for sale on a cost plus basis to the consumer, by MPPE. Presently, the hand-over price of crude from MOGE to MPE is k 1. per barrel; MPE then prorates its costs to each product in relation to the value of sales and adds a commodity tax; for example, diesel is handed over to MPPE at k 7.6/IG; MPPE then adds its costs plus a 5% sales tax to determine the final official consumer's price, for example k 10.50/IG for diesel. Price markup and tax details are shown in Annex 7.2. By all accounts the setting of petroleum product prices in Myanmar has been a ponderous and uncertain process. No clear procedures and scheduling for price adjustments exist, and Aethods of pricing are not well-defined, and the mandate for recommending and implementing price changes is not focused in one place. 7.8 At the same time as maintaining low official prices the market continues to be regulated through an allocation system, but since 1984 the government has tolerated an active black market in all the petroleum products, in which prices have been far higher than official levels. In November 1990, for example, the black market price of petrol was between k 150/gal and k 160/gal, being about 10 times the official price. One result of his situation has been a significant loss of potential government tax reven!5es, perhaps in the order of k 1 billion/yr, because commodity and sales taxes on petroleum products are related to official prices and not to the black market prices. As well as the obvious incentives for theft and other illegal activities, the past system of low petroleum product prices plus allocation has led to serious misallocation of financial resources, notably by under investment in crude oil and natural gas development, and by significant losses of fiscal funds for the government. 7.9 Efficiency and fiscal objectives can only be met through higher and more flexible prices for all petroleum products. Simultaneously, a balance must be struck with social objectives such as the provision of low-cost public transportation. The method of cost-plus pricing of crude oil tends to lead to shortages of supply because of the difficulties of fully allowing for the costs of exploration and unsuccessful development, and allowing for changes in the volume of production, for example following a new discovery, in the unit price calculation. Excessively low prices of oil and oil product prices contributes to excess demands and lack of supply. The present cost-plus system for establishing product prices also has several limitations: refining cost allocations among products is arbitrary ard can lead to distortions--for example since MPE gets a higher profit margin on fuel oil than diesel, it has a higher incentive to produce fuel o'l and also the profitability of conversion units is reduced. The price of diesel on world markets is usually between 10% and 15% less than petrol, and therefore the relative official prices of petrol and diesel in Myanmar appear to be out of line with each products' value. Although this is a taxation policy, the relative prices tend to cause a shift towards diesel consumption, which could in the future, cause an imbalance of product mix in the refineries. TALE 7.2 CRUDE OIL AM REffY PETROLBM PRODUCTS TRSSFEt PRIMS 1915-1990 &V - kycts. b bwrret, IC q l2erial C(ten) ----ME TO NPE ---- -..NPE TO NPPE ------ ----....... ------N.........PPE TO CONSUNERS---------------------------- Superfor Fuel Aviation Superfor Fuel Aviatlon Crude oil Petrol kerosene DSesel Oil turb Fuel Petrol kerosene Dieel Ofl Turb Fuel Year Ky/b Ky/b Ky/b Ky/b Ky/b Ky/b Ky/b Ky/b Ky/b Ky/b Ky/b Ky/b 1975 29.05 0.83 3.03 2.08 1.95 1.41 2.61 3.50 2.50 2.50 1.90 2.61 1976 29.05 0.83 3.05 2.10 1.97 1.43 2.61 3.50 2.50 2.50 1.90 2.61 1977 30.10 0.86 3.05 2.10 1.97 1.43 2.61 3.50 2.50 2.50 1.90 2.61 1978 30.10 0.86 3.05 2.10 1.97 1.43 2.61 3.50 2.50 2.50 1.90 2.61 1979 37.80 1.08 3.05 2.10 1.97 1.43 2.61 3.50 2.50 2.50 1.90 2.61 1980 40.60 1.16 3.05 2.10 1.97 1.43 2.61 3.50 2.50 2.50 1.90 2.61 1961 40.60 1.16 3.05 2.10 1.97 1.43 2.61 3.50 2.50 2.50 '1.90 2.61 1962 42.70 1.22 3.50 2.41 2.50 1.90 3.00 3.50 2.50 2.50 1.90 3.00 1963 42.70 1.22 3.50 2.41 2.50 1.90 3i 3.50 2.50 2.50 1.90 3.00 1964 42.70 1.22 3.50 2.41 2.50 1.90 3.W 3.50 2.50 2.50 1.90 3.00 1965 42.70 1.22 3.50 2.41 2.50 1.90 3.00 3.50 2.50 2.50 1.90 3.00 19J6 42.70 1.22 3.50 2.41 2.50 1.90 3.00 3.50 2.50 2.50 1.90 3.00 1986 42.70 1.22 3.50 2.41 2.50 1.90 3.00 3.50 2.50 2.50 1.90 3.00 198J 110.00 5.14 11.80 10.00 7.60 6.00 10.00 16.00 13.50 10.50 8.50 13.50 o Note: 1986 Prices Effective 20-10-88, snd still apply in early 1991. 81 Recommendations on Pricing of Crude Oil and Petroleum Productg 7.10 While the historical and expected future costs of crude oil and natural gas exploration, devalopment and production are not good guidelines for the setting of price levels, they do provide importdnt information for determining whether to invest in future oil and gas exploration and development. Provided that the fully-accounted-for costs are less than the cost of importing crude oil or petroleum products for which domestic production would substitute, investment in domestic production is economically attractive and should be undertaken. The estimated cost of exploration and development investment for possible oil reserves has been determined to be about US$12/barrel, and for proven and probable reserves between US$11/barrel and US$12/barrel. Such costs plus an allowed cost for operations, storage, transportation and delivery to domestic refineries of about US$5/barrel, provide an estimate of the full-cycle cost of domestic crude oil supply. On the basis of these estimates, and after analysis of the actual historical costs incurred by MOGE, the long term supply cost (without taxes or royalties) of domestic crude oil is estimated to be about US$17/barrel (i.e., about k 850/barrel at -he shadow exchange rate of k 50/US$). This is a critical finding for inves'-- purposes because it means that investment in domestic crude oil supp. as a high probability of being economically successful in light of forecut- of future international crude oil prices. From the perspective of domestic pricing policy it means that crude oil prices should never be lower than US$17/barrel, or k 850/barrel. 7.11 There are essentially two ways in which domestic prices for petroleum products could be tied to international prices: (a) phase in the domestic crude oil price at the refinery gate equal to the price of imported crude, delivered to the refinery (i.e., about US$25/barrel equivalent to about k 155/barrel at the official exchange rate or as high as k 1,250/barrel at an estimated shadow exchange rate of k 50/US$), o-; (b) set oil product prices (ex-taxes) equal to imported product prices, at the consumer level. Following the first approach would provide to MOGE a cash flow (in domestic funds or in equivalent US$ at a foreign exchange rate of k 50/US$) which should be adequate to pay for the oil field rehabilitation which is critically needed, and any surplus funds would provide a return on MOGE's invested capital or flow back to the Central Fund or possibly be captured by government through a higher royalty on MOGE's crude production. Consumer prices would be increased indirectly through passing forward the increased crude price to the refineries and thence to the consumer. Under the second approach, consumer product prices would be increased directly, taxes would be added, and increases in the cash flow to MPPE would occur, and thence to MPE and to MOGE. Such a 'netback' arrangement would, however, necessitate the imposition of restrictions over the revenues to be retained by MPPE and MPE. 7.12 A clearly defined, explicit long term strategy of relating domestic oil prices to international oil prices, at a realistic exchange rate, should be implemented. The mission recommends that domestic crude oil price should be tied to a suitable international crude oil price, for example a crude oil of similar quality to domestic production and available ex-Singapore. Prices would be set every six months, after an assessment by an independent Energy Pricing Board. With the existing price arrangements the cost of imported crude does not flow through to the official petroleum product prices; the cost is simply carried on the government accounts, and the crude is in effect transferred to MPE at the official price. In the future, import costs should be carried by MPE and they should become reflected in product prices each time that product prices are 82 revised. The government should set up an "Oil Price Stabilization Fund" showing the amounts which were not passed forward into product prices, or conversely if interrational oil prices were to decline then thls fund would show a surplus until the next revision of prices. The price of petroleum products would still be set on a cost-plus basis, however, using refinery and distribution cost margins for each product which would reflect the international product price relatives ex-Singapore. The objective is that these prices should promote optimal fuel choices, discourage waste and eliminate economic subsidies, i.e., the weighted average price of all petroleum products should be at least equal to the weighted average of their border prices. TARIE 7.3 LLUSTRATIVE WILD-UP OF PETROL PRICE, S U UZMB/bwrrel C0DE OIL .........(kyats/pallon)- --.- at k 6.2/USS at k 50/US$ at k 50/US$2 Retinery - Crude oIl cost 4.43 35.74 35.74 - Cost of Aefinig 0 d 2 Adin Expenses 2.03 2.93 10 63 - Profit Nargin (5X on costs) 0.32 1.89 2.32 - Commodity Taxl 10.98 37.77 10.98 .1P hand-over price 17.76 77.43 59.67 Distribution 2 - Distribution Costs2 3.06 3.06 8.47 - Profit Margin (2X on costs) 0.42 1.61 1.36 - Sales Taxes (5X) 1.12 4.32 3.66 ,. .. ... . .. .. Price to Consuier TOTAL including Taxes 22.36 86.43 73.16 TOTAL without Taxes 10.26 44.34 58.52 ------ ~ ..... Annex 7.3(a) Amex 7.3 (d) I/ Commodity Tax under the exchange rate of K 6.2/US$ is kept at the present rate, which is 170X. This results in 10.98. In moving to the exchange rate of k 50SUS$, commodity tax is retained at k 10.98 in column 3, and set at 100X in column 2. 2/ Ref ining nd distrIbution costs under the exchange rate of k 50/US$ have been adjusted to correspond to the revaluation considering that all foreign exchange accounting will be done by the enterprises at the exchange rate as used for determining prices. 7.13 Assuming that an international crude oil price of US$25/barrel delivered ex-Yangon pertains, Table 7.3 illustrates the range of consumer prices of petrol under various assumptions of tax rates and refinery and distribution costs. The minimum prices, which should reflect the international price relativities, are the estimated opportunity values of petroleum products at Yangon as given below: T'FLE 7.4 ESTINAT CFPORTUUITY VALIE OF PETROLEN PRDUCTS (bsed an Singapore product prime) Gulf Crude ---- Products In Yngon-------- in Fuel Yangon Petrol Kerosene Diesel Olt Price per barrel of Crude 25 36 32 30 21 Yangon Prices In S/IG - 1.03 0.91 0.87 0.61 in k 9 k 6.2/US$ 6.38 5.61 5.37 3.81 In k 501US$ 51.43 45.26 43.29 30.73 flge: Transportation costs of crude are estimted at $5/barrel ex-Dubai wnd of products at $3/barrol ex-singspore, landed In Yangon. These product prices exclude local distribution costs and taxes. 83 On this basis, the minimum prices at an exchange rate of k 50/US$ (excluding taxes) of kerosene, diesel oil, fuel oil and premium petrol would be k 45.26/IG, k 43.29/IG, k 30.73/IG and k 51.43/IG respectively. The government's taxation policy should determine the price level to be set above these floor amounts taking into account other socio-eoonomic objectives. 7.14 The price increases which are contemplated are obviously substantial and a possible first step towards such a pricing regime could be to adopt the opportunity value criteria, using the international oil price as the guideline, but to use the official foreign exchange rate. This would suggest a modest increase of petrol prices to k 22.36/IG, as illustrated in the first column of Table 7.3. It will be seen that except for the change in crude oil cost to correspond to border parity, the present formula for the price build up is retained and the commodity and sales taxes as well as the profit margins are left at existing percentages. Proceeding on the same basis, the prices for aviation fuel, kerosene, diesel oil and heavy fuel oil work out to k 18.32/IG, k 15.84/IG, k 15.76/IG and k 10.63/IG respectively. Although the price levels would be far below the desirable minimum it would at least be a constructive ;tep in the right direction. A further step which could be considered is to prorate the refinery and distribution costs of the different products in line with typical relative product prices in Singapore. In subsequent price revisions where the objective is to move closer to the real exchange rate, the commodity tax might be at a lower percentage for the petroleum products. 7.15 Price increases are expected to have only a limited effect on total industrial production costs, as energy accounts for a relatively small proportion of the cost of production of most industrial operations. In addition, in Myanmar, most of the rural population and the poor rely primarily on biomass and the other traditional fuels. Another expected positive result of rational pricing, is likely tu be institutional change for better management both within the energy SEEs and in government bodies such as MOE and the Department of Planning and Finance. The self-financing ratios of the energy SEE's would improve. Overall, the impact of higher and more flexible crude oil and petroleum product prices are expected to be positive, and most important they are expected to reduce the gap between petroleum product supply and demand within all sectors of the economy so that eventually the allocation system could be abandoned and the black market eliminated. C. NATURAL GAS 7.16 The pricirng of natural gas must address the dynamics of supply and demand. To reduce an excess supply, the price of gas can be set as low as feasible, i.e., at the level of the estimated long run supply cost, with the objective of promoting the use of gas through substitution for petroleum products in existing markets and through creating new markets for gas such as its use in electricity generation or as a feedstock for example for the manufacture of urea and methanol, while allowing just high enough a price to sustain supply. The long run cost of supply can therefore be viewed as a minimu price for gas. On the other hand, if natural gas is in deficit the gas price should be set as high as feasible in order to discourage its use through substitution for example by fuel oil, to induce conservation, and to stimulate its domestic supply. Therefore the energy equivalent value of petroleum products such as fuel oil indicate a maximi price that might be considered for gas. If natural gas is exported, there are two implications: the netback from the export must be greater or equal to the 84 estimated long run supply cost of gas (otherwise th. export would not be economic), and, this being the case, the netback value of the gas would indicate the appropriate price for domestic gas. 7.17 For - .ing natural gas in Myanmar there are three criteria which establish a range m;. guideline for prices in the longer term: (a) if the development and export offshore gas is economical, financeable and is in fact realized or if it is assumed to be realizable, tee export netback value of gas (calculated to Yangon) would indicate the appropriate level for gas prices; (b) if gas is in deficit, the substitute petroleum product energy equivalent value (fuel oil or possibly diesel as used in the power sector) indicates the maximum price; and (c) the estimated long run supply cost of gas indicates the minimum price that should be set. 7.18 On the basis of estimates of capital and operating costs and assuming energy prices stated in Annex 7.1(g), the netback values of gas in the domestic marl-et were estimated as part of a Gas Utilization Study (1991) and ar- given in Table 7.5. Gas use for power generation provides the best valourization of gas in all scenarios; and all gas applications have netback values higher than marginal costs of supply, except new fertilizer and CNG plants. The export netback value of gas is estimated at about US$2.10/mcf, based on fuel oil replacement value in power plants ex-Bangkok of US$3.50/MMBTU. TABLE 7.5 USSM/IBTU Power 4.18-4.95 Manufacturing 5.09-5.14 Ref inery 4.58-4.77 Paper Manufacturing 3.99-4.07 Cement 3.65 Methanol 2.61-2.92 CNG 2.21 Fertilizer 1.23-1.66 Notes: 1. Wetback values of gas, is considered to be representative of the benefits of gas utiLization, is defined as the fuel reptacement value or as the price of gas which makes its use as feedstock economically viable. 2. Netback values were evaluated for seven sectors--fertilizer, cement, paper, methanol, CNG, industries and LPG. 3. The distribution pipeline costs for manufacturing have not been fncluded in the netback values--hence, net benefits will be lower than for the power sector. 7.19 The investment and operating cost programs to produce incremental onshore and offshore natural gas have been described in detail in Chapter III. On the basis of these estimates, and assuming a discount rate of 12% per year, the long run incremental cost of future gas supplies (i.e., average incremental cost or AIC) have been calculated. In the case of developing Moattama offshore gas for the Thai market, it is estimated that the economic supply cost would be around US$1.88--2.0/mcf depending on onshore pipeline costs and location of the power plants using the gas. The estimates for onshore gas include an exploration component. In the case of offshore gas, exploration costs are treated as 'sunk costs' and a depletion premium is added to the development and operating costs which represents the estimated discounted cost of replacing the Xoattama offshore reserves through further offshore exploration. The long run incremental cost (excluding royalties and taxes but including exploration) of new onshore gas production has been determined to be about US$2.42/mcf (delivered to Yangon). The estimated cost of gas from Moattama, when developed and delivered for 85 domestic use at 40 bcf/yr and using the existing Jack-Up rig, is US$1.24/mcf, delivered to Yangon excluding royalties and taxes. This is highly conditional upon the low investment costs associated with the rig. Adding a depletion promiui. of US$0.50/mef brings the estimated ec nomic supply cost to about US$1.74/mcf, ex-city gate Yangon. Recommendations for Gas Pricing 7.20 Bearing in mind all the complexities and uncertainties involved, a good deal of j_.ugement is required in establishing the price of gas. The future prospects for gas development, the difficulty that MOGE would have in quickly d3ploying a rapid inflow of local funds, and the impact of high gas prices on electricity tariffs suggests that prices should not be raised right up to the level of petroleum product equivalent straight away. On the other hand, it would not be strategic, in the short term, to price gas at less than the estimated long run cost of onshore supplies, because if the offshore option were to fail or be significantly delayed it is essential to have onshore supplies, and there is also a chance that they might turn out to be larger than presently expected. This suggests a price ef at least US$2.42/mcf. Since the estimated cost of offshore gas developed for the domestic market is US$1.74/mcf, the suggested US$2.42/mcf price would hold out the promise for any joint venture partners in offshore development to deliver gas into the domestic market at a profit. The prospect for profit .ill be a necessary ingredient for the participation of private sector partners, and for the project's financeability. Any excessive profits can be recaptured by government through an efficient royalty arrangement. Thus, a price ir- the order of US$2.42/mcf, which is slightly less than 60% of the energy equivalent value of fuel oil (CIF Yangon) would appear to reconcile the objectives of stimulating both onshore and offshore developments, while not raising gas prices too high which would heavily impact electricity tariffs and might be a problem for the government later if the PSCs' discover and produce gas, or if the short term high domestic price might tend to inhibit a gas export ieal. In the longer term, if a gas surplus is realized, the export netback value of gas, estimated at about US$2.10/mcf, becomes the relevant guideline and it may therefore be strategic at a later date to reduce the gas price in the domestic market, in order to stimulate its use (Table 7.6). The mission recommends that the gas price should be set in the range between US$2.10/mcf and US$2.50/mcf; in the short term at the upper end of this range with the prospect of slightly decreasing the price in the future when the netback from exports is realized, 86 TAILE 7.6 IOICATONS PM UTTIN UfTUlMA US PRICE IN rNVMU U,$/Acf k/nt PRICING To PARKT: at k 3JUM at k504Q&1 IbrIsTor3 (9g8 deficits) Equivakent Value of diosel 5.50 34 275 Max Equivalent value of fuel oil 418 26 209 LQrm to (potential gas surplus) Value In methanol mwnufacture 2.60 16 130 Value in CNG Manufacture 2.21 14 110 Notbeck Value of Exports 2.12 13 106 * PRICING BY COSTS: Shart ToI (oas deficits) Coat of onshore gas No short term Increase in output possible. Lem Term (potential gos surplus) Cost of onshore gas 2.42 15 121 Min Coat of offshore ps 1.74 1' 87 * will d pend on the price which is realized for gas delivired to Th_ and which Is assused here to be USS3.50/mcf nd on the actual costs of develt,pment and transmission from Noattame to the point of stle. These prices and costs are particularly uncertain. Source: Mission Estimetes (1991) D. ELECTRICITY TARIFFS 7.21 Over the period from 1979 to 1988, there were few revisions of electricity tariffs and the average revenue per kWh sold ranged from k 0.25/kWh to k 0.30/kWh. Presently, the average revenue is k 0.48/kWh, equivalent to only 0.090/k'Wh at an exchange rate of k 50/US$. In real price terms, electricity tariffs have decreased over the past 10 years in spite of the nominal tariff hikes in 1984 and l958. Myanmar tariffs are also exceptionally low in comparison with tariffs in other countries of South East Asia. For example, tariffs in Thailand average the equivalent of about 6.9C/kWh. The tariff structure is simple in its design, which presumably reflects both the fact that MEPE has inadequate funds to install more complex metering, and that estimates have not been made of the respective long run marginal costs for each type of service. Tariffs are now recommended to government by MOE, after consultation with MEPE. The basis has been cost-plus in an accounting sense, and tariffs have not been used as a means of effecting demand management. TAILE 7.7 NYANNAR ELECTRICITY PRICES IY 1990 tOWSUNEI CATEGORY uklr ERICE General Purpose Pyas/kWh 50.00 Residential Power Pyas/kWh 50.00 Small Power Pyas/kWh 50.00 Industrial Pyas/kWh 45.00 Large Industrfal Pyss/kWh 40.00 Sulk Pyas/kWh 45.00 Street lighting (Mininum 40 Watts) - 40 Watts ky/Mon 8.00 - Every AdditionaL 10 Watts ky/Mon 2.00 Department At cost Source: EPE 87 7.22 The issuos of electricity pricing have cssentially three components: (a) tariff levels have been maintained at too low levels for the effective development of this sabeector, and even aftre the hike in tariffs in October 1988 they are still too low to provide for the efficient use of electricity, and to provido sufficient internal cash flow for MEPE to sustain its financial integrity and raise at least part of the funds needed for the investment required in generation, transmission and distributiot. in the future; (b) the tariff struccure has been oversimplified, by essential setting all tariffs at tha same level, without any blocs for quantity of usage, and with insufficient attention to the costs of p?oviding capacity to some customers; and (c) like the petroleum prices, electricity tariffs have been kept fixed for excessively lonig periods of time in spite of domestic inflation and changes in the costs of operating MEPE. 7.23 The existing average tariff of k 0.48/kW* Lective from November 1988), already appears not adequate to cover the fin;.acial costs of MEPE of 1991. During 1992-94, as gas availability further declines, more diesel and fuel oil will have to be used, while gas prices have also been recommended to be slightly more than doubled, thus causing large increases in fuel costs. Assuming that the additional fuel will be imported and GOM will supply the fuel to MPPE at normal consumer prices, but with commodity and sales tax exemptions, it will be necessary to raise the electricity tariffs: a 40% increase of the average tariff to bring it to k 68.2 Pyas/kWh before the end of 1991 will still result in a financial loss situation during 1991 and 1992, but MEPE losses would stand to be made up over the next three years (Annex 8.2). The position will be more bleak if the more realistic shadow exchange rate of k 50/US$ is applied. As with petroleum prodvtets, the artificially low exchange rate seriously biases the calculation of costs for purposes of efficiently pricing energy. 7.24 The average tariff should at the minimum be sufficiently high tu assure the financial viability of MEPE. The revenue requirement should cover AU costs and it should include a rate of return on assets commensurate with the capital structure of the utility, allowing for the debt and equity mix on the balance sheet. Depreciation allowances should also be included, sufficient to replace the assets. Therefore, depreciation should be calculated on the up-to-date revalued assets. There is also a case for the revenue requirement to include an allowance for the funding, or partial funding, of future investments by the utility. The tariff structure and levels should be related directly to the estimated marginal costs of providing service to respective groups of customers. Basic criteria in this respect are the estimated long run marginal cost (LRMC) of expanding generation, transmission and distribution in order to meet the forecast demand. The short run marginal costs may also be relevant because in the short-term, .."e marginal generation, for example, for Yangon, is by diesel- fired units. Recommendations for Electricity Tariffs 7.25 The estimated costs of electricity generation, transmission, and distribution are shown in Table 5.13. They depend, of course, on the forecast opportunity costs of fuels and financial capital, in the context of the generation plan developed in the Base Case forecast of electricity demand and these costs provide a guideline for tariffs. 88 TWLE 7.5 PUPOW TMIFFS (K/eb) First Stag. Long Run Proposed Existing Prqposed Tariffs besed on LRNC2 Tariffs 1990n20 1990-2010 Residentlot 0.50 0.83 3.56 5.79 Services 0.45 0.61 2.54 4.14 Industrial 0.45 0.53 2.10 3.57 Averag 0.48 0.68 2.87 4.72 1: Based on financial viability of NEPE 2: LRNC based an exchsng rote of k 50/US$ Source: Mission Eatfmtes (1991) 7.26 Apart from the obvious significance of the exchange rate assumption, it is clear that the marginal costs at low voltage, serving the residential sector, are substantially higher than at medium and high voltages serving the other two sectors. Therefore, on a cost basis the residential sector tariff should be some 60% to 70% higher than industrial tariffs. On the basis of long run marginal costs, using the official exchange rate, and to ensure the financial viability of MEPE, the industrial, service sector and residential tariffs need to be raised some 8-33 pyas/kWh as given in Table 7.8. In the short run, the average tariffs need to be increased from k 0.48/kWh to k 0.68/kWh in order to ensure financial viability of MEPE; but in the longer term, the average tariffs should increase to the LRMC to provide for necessary investments in the power sector. 7.27 To obtain the desired degree of flexibility, it is essential that an annual review procedure should be established with explicit criteria for setting tariffs. A clear procedure for establishing the annual revenue requirement should also De established. Marginal costs should be estimated and updated annually in order to act as guidelines for setting tariffs in each service sector and for setting the levels of bloc tariffs in each sector. Two bloc tariffs should be considered, with higher tariffs in the second bloc, and the second bloc might be set equal to the marginal cost of diesel generated power. Capacity charges for industry should also be increased. It is recommended that a study of tariffs be undertaken so that electricity prices can be set on a sound, long term basis. E. COAL PRICES 7.28 Coal prices are set on an average cost-plus accounting basis, including the relatively low cost operation at Namma and the higher cost at Kalewa. TABLE 7.9 SELLIU PRICE of COAL IN 1969 kltn At Location Kalewa Cost Run- Nine Coal 365 Aonyia LuWpy Coal 715 Nine Site 750 onywia Coal Fines 177 Nonywa "amm Cost Run-of Nine Coal 260 Lashlo iashed Fines 207 Pyay-Oo-Lwin Iron & Steet Plant Scurce: Mining No. 3 (1989) 89 Recommelations for Coal Pricing 7.29 The price of coal should be established in relation to the cost of imported coal of comparable quality, and allowing for internal transportation costs. This would provide the incentive for the mines to develop efficiently when coal is in demand domestically and when it can be mined at less cost than imported coal. If necessary, coal royalties could be used to recapture profits for government. F. TRADITIONAL ENERGY AND PRICES 7.30 Prices for fuelwood and charcoal vary considerably depending on location, local urban demand, the quantity of the sale, and the quality of the charcoal. Yangon City has the highelt charcoal prices ranging from kyats 4.00 to 6.70 per viss while fines and dust may be obtained from some outlets for kyats 2.50 per viss, the good quality charcoal fzom dense mangrove or deciduous forest species sells for kyats 5.00 to 6.70 per viss. Outside Yangon City charcoal prices are generally lower and in areas where supplies are easily accessible, for example, Magway and Bago Division, prices are lower. Mandalay Division (south of Mandalay City), however, has higher prices due to increasing shortages of wood. 1TAKE 7.10 CNACRL RETAIL PRICES Location Charcoal Price (kyats/viss) Yangon City: Charcoal from Ayeyarwaddy 4.00 -6.70 Charcoal from Tanintharyl 4.50 - 5.00 Charcoal from Bago/N.gway 2.50 - 6.00 Yangon Division Town 3.00 - 3.40 Rago Division West 3.60 Bago Division East 1.20 - 2.60 Nagway rivisfon 1.80 - 2.50 .andalay Division 2.00 - 4.70 Ayeyarwaddy Division (Pathein) 4.10 - 4.40 Source: Mission estimates (1990) 7.31 Fuelwood is the principal fuel for rural households where it is usually collected on a subsistence basis from nearby forests, although in some cases it may be purchased by the villagers. It is also the principal fuel for the majority of urban households outside Yangon City who purchase the fuelwood from retail outlets. As shown in the table below, there is an even greater variation in fuelwood prices than charcoal prices even in the same areas. TO"LE 7.11 FELUEOD RETAIL PRICES Location Price (kyats/ADT) Yangon City S00 - 1700 Yangon Division Town 310 - 700 (kyats 150/ADT for sawdust) Pyay Town 220 BSgo Division East 95 - 1570 Hagway Divislon 60 - 440 Mandalay Division (south) 115 - 1120 Nandalay City 340 Source: Mission estimates (1990) 90 Recommendations on Pricini 7.32 In the markets for charcoal and fuelwood there are many suppliers, wholesalers and retailers, and unlike the other energy subsectors, prices are determined essentially by the interplay of supply and demand. However, the evidence that charcoal prices have declined in real terms over the past decade combined with the fact that prices jumped up earlier in 1990 when sustainable-cut limits were temporarily placed on supplies, suggests that prices are lower than would be consistent with long term sustainable supplies. 7.33 Traditional energy supplies, particularly charcoal, thus appear to be underpriced as a result of too low a level of royalties. The present royalty of k 2 per 90 lb bag of charcoal and k 5 per stacked ton of fuelwood is equivalent to k 6.5 and k 10 per ADT of fuelwood, assuming a 14% conversion rate from wood to charcoal. These rates are estimated to be too low for efficient management of the forests, which would appear to call for rates in the order of k 38 per ADT of fuelwood. 7.34 In the non-Dry Zone areas, charcoal from plantations or managed forests close to Yangon or in the Ayeyarwaddy Division have relatively low supply costs, and such an increase in royalty rate could be absorbed mainly through a reduction in the profitability of forest cutting and only partly through retail price increases. On the other hand, the supply of charcoal from western Bago and southern Magway Divisions which has higher supply costs would tend to be curtailed, leading eventually to upward pressure on retail prices. Overall, a higher royalty would address the problem of overcutting; it would tend to reduce supplies, raise retail prices and dampen consumer demand. G. CONCLUSIONS AND RECOMMENDATIONS 7.35 It is clear that all energy prices must be considered together in a policy package, otherwise unwanted substitution will take place or certain segments of the population and economy will be adversely and unfairly impacted. There are strong direct links between energy prices, for example the prices of fuel oil and diesel directly affect the costs of electricity generation which must be passed on to the consumers in the form of higher electricity tariffs. The recommended prices shown in Table 7.12 are considerably higher than existing prices and one means for phasing increases into the economy would be to first use the existing official foreign exchange rate and in the future if the official rate is not changed, to adjust prices into line with a realistic shadow exchange rate. 7.36 The pricing strategy which has been developed has stressed the importance of first putting in place effective methods for establishing prices and a systematic means of annually reviewing them. Creating institutional mechanisms such as an independent Energy Pricing Board should be examined as part of this pricing strategy. 91 TMWE 7.12 RECONNENDE1 ENEWN PRICES IN YMA_ -Prices Target First Step MInfmna Ex1stina Prices at 6.2&U # at SQ/US Crude Ofl 110/b 155/b 1250/b Petrol 16.00/10 22.36/10 51.43/10 Kerocon 13.50/10 15.84/10 45.26/10 Diesel 10.50/10 15.76/10 43.29/10 Fuel O1l 8.50/IG 10.63/10 30.73/10 Natural Ga 7.50/mcf 15.50/hic 125/mef Cosl 365/ton Domestic price to be tied to international prices with higher royaltles If necessery Electrici ty: Residential 0.50/kWh 0.83/kWh 5.79/kWh Services 0.50/kWh 0.61/kWH 4.14/kWh Industrlol 0.40/kWh 0.53/kWh 3.57/kWh Averao 0.48/kWh 0.68/kWh 4.72/kUh Woodfuele/Chorcoal Royatties 6.5-10/ADT 38/ADT 12a: 1/ The target petroloun prices shown are net oi local distribution costs and taxe. The goverrant Is tax poLicy should determine the consumer prico levols, but which should be set above these floor amote.ts 92 VIII. INSTITUTIONAL. FINANCIAL ISSUES AND INVESTMENT PROGRAM A. INSTITUTIONAL AND FINANCIAL ISSUES 8.1 All modern energy activities are carried out by four SEEs under the MOE: MOGE is responsible for exploration, drilling and production of oil and gas; MPE operates three refineries, four fertilizer plants, a methanol Plant and an LPG extraction unit; MPPE is entrusted with the marketing and distribution of petroleum products throughout the country, down to retail outlets; and MEPE fulfills the objectives and purposes of development of electric supply and distribution; development, promotion and search for hydro electric power resources; electric supply for industries, commercial users and others in bulk and retail. The coal sector is managed by Mining Enterprise No. 3. Each of these enterprises is headed by a Managing Director who is assisted by Directors in charge of departments (Annex 8.1). In addition, the traditional energy sector is handled as a departmental undertaking in the Ministry of Agriculture and Forestry. 8.2 Until 1988, the SEEs then known as 'State Corporations,' lacked autonomy and accountability, and in an environment of administered prices which over the years increased far too slowly, felt discouraged as profits were eroded due to rising costs and accelerating debts. The current government placed the reforming of the SEEs high on its agenda and at the outset the government announced its intention to decentralize decision making and to give autonomy to the SEEs in procuring their inputs, allocating their production, and deciding the prices of their products. From October 1988, prices of petroleum products, in consultation with th(i6 concerned SEEs were raised four to five times and of electric power about 1.5 times so that the SEEs would not make losses on their revenue operations. From April 1, 1989 SEEs were relieved of all their domestic bank debt through conversion to state-owned equity. Simultaneously all SEE operations were brought under the umbrella of the central budget. The budgets of the energy enterprises, divided into the categories of current, capital, and loans and investments, and into domestic and foreign currency, are coordinated in MOE and then consolidated in the Ministry of Finance and Planning for Cabinet approval while the receipts and payments of the SEEs are handled through a common State Fund Account, including foreign currency. But profits are not permitted to be retained with the SEE's and are surrendered to the government as contribution. These arrangements were intended to free the SEEs of financial concerns so that they could focus wholly on production related matters, but have had instead the impact of curtailing the financial autonomy of the SEE's. 8.3 In practice, it is questionable whether the SEEs enjoy more autonomy than in the past. All pricing of energy is still controlled by the government and the mechanisms are inadequately reflective of the autonomy required in a market oriented system. The current local currency expenditure and revenue budgets proposed by SEEs appear to have easy passage with the governmental authorities scrutinizing it. But foreign exchange constraints in the economy and the priorities enjoyed by some other sectors for allocation of foreign exchange result in the energy SEEs obtaining only a minor proportion of their needs, although it is demonstrable that if longer term economic considerations were reckoned with, the priorities would be reversed. Procurement powers delegated 93 to SEEs have no practical utility in the absence of adequate foreign exchange releases and the extant tight control on how the releases are applied. One other area where autonomy was to prevail was in allocation of products by the SEEs. The serious gap between energy demand and supply and the need to protect essential and/or weaker sections of the community have, however, led the government to retain allocation of energy within MOE. The apex structure of each enterprise having a wholly in-house set up, leaning on the Energy Planning Department of MOE for advice on many a matter of operations, is also not reflective of decentralized administration. SEEs do not have long-term plans other than Government approved annual programs to guide them. Deviations from annual programs or the taking up of any work which is essential but has a long- term impact, therefore lead to 'ad hoc' approvals from MOE. 8.4 To implement the policy directions of a move towards a market oriented system, greater autonomy and decentralization in the energy enterprises are required. Delegation of adequate financial powers, setting up of SEE planning units and co-ordination among the energy enterprises are some of the major requisites for implementation. The phasing of reform AREA OF REFORM Year of reson 1 1 2 3 4 5 6 7 8 9 10 1 MACROECONOMY Ji L ste _ainta_ _ stabtisty l MARKET Goods & services: Prices Liberalize prics of sonr necessities (Induding husstn) Ii . Goods & services: Trade Reo Adu tariffs to modest level Goods & services: Distribution i r.o| Develop Labor market | tendoSg hiringbenl s; i Financial market [ Ratuctum and develop --7'< ' iza d sn hi _ , . : . .~~* . I OWNERSHIP STRUCTURE . SmaU enterprises [-+-;-'j 5 Large entelprises j Ev Suate -. 5 Re ss' aaM $ f e Foreign investnent GOVERNMENT Legal framework Ic Extend zefonns to oter ares l I. '.. Institutional semteSal nd nxtoAW t.Ns niet id b . framework - Instit tionalize Socialsafetynet Souirc World DevelopmentReport 1991. World Bank Note Shading indicates intensive action. QRs- quantitative restictions 94 8.5 It is necessary that the perception be created that energy enterprises have an existence of their own, relatively independent of the government, so that suppliers of credit, investors and lenders feel encouraged to deal with the enterprises. Experience in other countries has demonstrated that commercial enterprises in the State sector are successful if only the government provides them with broad mandates and targets, otherwise leaving them alone to manage their business, but reviews performance at periodic intervals. The primary ingredients for autonomy are (a) establishment of the SEEs as full corporate entities with independent boards of directors and all the powers of commercial corporations, (b) operation outside the centralized government budgeting process, (c) right of retention of earnings (d) access to foreign exchange loans or other foreign exchange payments, and (e) responsibility for price setting, wage and salary determination and employment conditions, subject to an independent authority. 8.6 The SEEs should be granted autonomy and responsibility in managing their assets. The governmernt needs to appoint a Board of Directors drawing most members part time from outside of the particular enterprise including a few eminent public persons. The SEE's should also have the right to issue shares to institutional investors or to individuals. In addition the shareholdsrs should be allowed to transfer ownership to others. The SEEs must be taken out of the jurisdiction of the sonventional budget and essentially given financial autonomy. To be autonomous organizations, they must begin and remain financially viable. At present, the SEEs do not have their own surplus funds with which to establish themselves independently. To inject working capital the government would have to subscribe an initial paid-up capital, which might simply be set at the value of net assets. This amount would be represented on the balance sheet in the form of shares, and dividends would be expected to be paid in due course. The SEEs must have the right to maintain funds for capital and operating expenditure out of their own income. Repair and maintenance and depreciation expenditures should be provided in the accounts and the corresponding cash flows should be retained in the enterprises. A provision for a development fund for future investments should also be allocated out of annual profits after deducting taxes and duties. Procuring raw materials and controlling investment resources must be under the authority of the SEEs. They should also be granted the right to recruit and. retain qualified personnel on salaries and wages, and under competitive working conditions with the private seecar, by freeing them from civil service restraints on hiring and firing. It is realized that the reorganization of the enterprises as corporate entities with sufficient autonomy will involve time and phasing. It is, however, recommended that a start be made for defining the new structure and the rights and obligatior,s to be bestowed on the entities. Other steps may follow in quick success-ons over a period of three or four years. Financial Saystems 8.7 Financial autonomy is basic to the process of making SEE's autonomous entities. Under the present system, the SEEs have to surrender their income to the State Central Fund (SCF) and they can acquire current and capital expenditure from SCF, but all expenditures are subject to budget control. This gives little financial responsibility to the SEEs. As a result the SEEs are not sufficiently profit oriented and they have only few incentives for reducing costs. Although the oil SEEs could generate sufficient resources for their needs as a result of 95 rational pricing, at present investment funds may be held back by the budget procesa, especially if macroeconomic pressures become severe. Rel.ance on budgetary transfer has adverse effects on the autonomy and operation of all the state economic enterprises. It is recommended that no enterprise should be subject to the government budget process. A satisfactory pricing policy should be enunciated for each enterprise and implemented, preferably overseen by an independent authority. 8.8 A core problem is the scarcity of foreign exchange. Shortages of imported spare parts and of raw materials are affecting capacity utilization. It is interesting to note that an export retention scheme is applied to the private sector, under which the foreign exchange proceeds may be retained for purchasing officially recognized imports. The benefits of a similar scheme should be available to the energy SEEs also, especially MOGE and MPE, which already earn foreign exchange. Further the energy enterprises could be permitted to buy from authorized dealers foreign exchange with their kyat income at free equilibrium exchange rates. 8.9 One of the major obstacles to the expansion of oil and oil product supply is the lack of sufficient domestic and foreign financial resources within the concerned SEEs. Due to inadequate financial resources, investment in exploration and development drilling has been cut back and that in turn has led to the dwindling of production and low operating incomes. The low official oil and oil product prices are other major factors causing the present financial constraints within MOGE. Recent liberalization of the economy was supposed to permit pricing flexibility for all the SEEs, but the SEEs still have to put up their price proposals to MOE where they are considered and may be further recommended to cabinet. The low official petroleum prices cannot generate the cash flow to meet domestic investment requirements of the oil SEEs. The mobilization of adequate domestic financing is important and it may be one of the means for attracting external capital inflows. Since more than 50% of the total oil SEEs' investments is in foreign exchange, mobilization of foreign exchange is of critical importance for development of the sector. 8.10 The policy of keeping official energy prices low has also led to inadequate transfer of financial resources to the Government. Even with the underpricing of energy outputs it was of little benefit to the consumer because supplies fell far short of demand. In addition, considerable quantities of oil products are siphoned away from the official to the unofficial black market, where prices are a multiple of the official prices, and the profiteering is paid for by the consumer. 8.11 In the past, the profit margins of the oil SEEs have declined, in part because of inflation, and in part because of costing methods. Costing practices applied by these enterprises have undervalued certain cost elements; depreciation is charged at historical rather than at replacement values and imported materials are costed at the overvalued official exchange rate. In addition to the introduction of rational pricing, the energy SEEs must look to cost reductions to enhance their profitability. Planninig 8.12 Planning for expansion must be a vital element for each of the enterprises. Strong planning units should be set up in each of the SEE's, minimally to prevent decline in production and optimally to meet demand growth in the most cost 96 effective manner. Specific mention is made in this context of two issues which were highlighted when IDA Credit 1245-BA was extended to MEPE in 1982 for transmission lines, namely the need to develop the nucleus of a planning directorate into an effective planning unit and to reduce system losses from 32% in 1981 to a targeted 20% in 1987. Studies for both were undertaken and financed under the Credit. 'rhe situation today is that planning is suspended and system losses are at about the same level as in 1981. Corporate planning is an essential component of an efficient SEE operations and in its absence suboptimal decisions and investments are likely. Coordination of Energy Strategy and MOE 8.13 Coordination among the energy enterprises is facilitated by the Energy Planning Department in (EPD) MOE. Also the Managing Directors meet with the Minister in committee frequently. If the enterprises function with the kind of autonomy recommended, a qualitadive change in the role of EPD as well as in the agenda of the coordinated committee will need to take place. The new focus will be on the strategies for energy supply in the longer term and on the investments to be taken up and approved. EPD will play a supportive role to the enterprises, provide advice to the energy coordination committee and ensure that policy and investment decisions of the committee are given effect to. Considering that coal, woodfuel and biomass are also important resources, though not falling within the purview of the four energy enterprises under MOE, the coordination committee would be well advised to include representation in respect of these resources also, so that the energy policy for the country is duly integrated. 8.14 A critical component in the country's energy strategy has to be its pricing policy. All energy prices should be considered together in a policy package, and a mechanism for annually reviewing them needs to be set up. It is recommended that thought be given to the creation of an independent Energy Pricing Board as a quasi-judicial body for this purpose. 8.15 Besides the major organizational and system changes indicated above, there are certain specific changes that need to be made in the various energy enterprises. MOGE 8.16 As its activities in the future will become more complex and involve sophisticated technology, e.g., rehabilitation of declining oil and gas fields, development of offshore gas, enhanced oil recovery, etc, new skills and expertise from staff would be called for. Training of staff in modern technology should, therefore, be a high priority for MOGE. MOGE has before its recommendations of consultants made in February 1990 for infrastructural and institutional development; these require careful study and implementation. Some of the recommendations worth emphasis are the strengthening of the Production Directorate by establishing a Production and Reservoir Engineering Unit, a Petroleum and Production Engineering Unit and an Enhanced Recovery Engineering Unit. As fields go through rehabilitation, maintenance will become an important function and so it should be delinked from Engineering/Construction Directorate with decentralization to sites. 8.17 Reser'e estimation (proven, probable and possible) of oil and gas has to be done with adequate precision since investment decisions in the hydrocarbon 97 subsector are largely influenced by these estimates. A National Reserves Evaluation Board, consisting of geoscientists and reservoir engineers from MOGE, EPD and universities with the necessary independence should be set up. The Board should also be free to obtain the assistance of international consultants/ agencies in the review of the reserves estimates on a periodic basis. 8.18 The technical and financial relationships between MOGE and foreign oil companies exploring and eventually producing oil/gas have to be evolved with care to the mutual advantage of all the parties. Management Committees established for administering the PSCs and comprising representatives of MOGE/government and the contractor underpinned by various subcommittees have got off to a satisfactory start. MOGE would be well advised to take full advantage of the training provisions in the contracts, particularly in areas where expertise will be required in the future and among others in engineering of surface facilities and pipelines, well drilling, logging, testing and cementation. MOGE should send or cross-post senior technical and management personnel to these companies, in order to gain experience in the international oil business. This is not to suggest that MOGE should not have training arrangements other than under the provisions of the PSCs. Indeed these are necessary as MOGE has to catch up with modern technology in a number of skills. In all new schemes for rehabilitation or development, MOGE must build in training in-house using experts employed for implementing the schemes as part time trainers and also seek other means to acquire expertise. 8.19 MOGE will have surplus staff due to reductions in the volume of its operations: the number of rigs working is about half of the 45 at an earlier time, and oil and gas production have declined. While activities could gather pace in the future, provided investments are made, in the meanwhile HOGE could set up servicing companies as subsidiaries, for example for seismic surveying, drilling, construction of surface facilities and pipelines, maintenance of equipment to effectively use the surplus staff. These companies could provide the PSC's with sorely needed services and support as well. 8.20 MOGE needs to focus special attention on acquisition of modern oil technology in its operations. An effective method is to employ international consultants and contractors for specialized tasks; but a more efficient means would be increasing areas where joint ventures with private interests can operate, particularly where highly complex technologies are needed. MPE 8.21 MPE has experienced and good quality professional and technical personnel but they lack adequate exposure to modern technology and innovations. Expertise in areas such as system planning and operation optimization, process engineering, non-destructive inspection, safety, instrumentation, loss control and energy conservation needs to be updated through regular training programs. 8.22 MPE does not have a marketing unit. A better knowledge, perhaps through greater co-ordination with MPPE, of the likely future needs of the domestic market needs would be beneficial to its operating and planning efforts. Equally important is the knowledge of the international market. It would be beneficial for its export operations to have people in permanent contact with foreign markets either directly or through an agent in Singapore or other similar trade centre. 8.23 The existing computer infrastructure at MPE is very limited. An upgrade to help in refineries programming and optimization, alternative project 98 evaluation, crude oil purchasing evaluation, natural gas usage using LP models and techniques is urgently indicated. Ma 8.24 MPPE too needs a botter computer system. Since it is marketing all petroleum products except for LPG and CNG, the question arises why it should also not market these two products. There appear to be technical advantage in all marketing specialization resting in one enterprise. MPPE may, however, spin off operation of retail outlets and movement of products from subterminals to private owrership and management so that the private sector is directed into these small xize activities where much capital does not have to be put up. But such privatization may have to go hand in hand with rationalization of petroleum product prices. an 8.25 With a sanctioned staff strength of 15,418 including 739 officers, MEPE staffing appears too liberal, when compared to utilities in the area, yielding the following ratios--consumer/staff in distribution, 42; grid staff/substation, 67; and staff/power station, 175. There is scope for reduction in the number or at least for holding dowu increases until the volume of power generated and distributed grows adequately. In addition as technological changes happen, technical competence ai.d skills of the manpower should be raised and training of professional staff kept under constant attention. 8.26 MEPE is currently installing a pilot computerized billing system in Yangon. Although this system is being installed primarily to improve efficiency of metering and bill collection, it also provides MEPE with the opportunity to address basic problems. To get the most effective use from the system, its implementation needs to be undertaken carefully. In order to take up a Lhorough review of the organizational procedures to support computerized billirg and to make changes to standard forms and collection and billing practices, MEPE should seek assistance preferably from a neighboring utility. 8.27 Power distribution to 600,000 consumers is a major function of MEPE, and consideration should be given to establishing two semi-autonomous entities under separate chief engineers: one for the National Grid and System Control and the other for States and Divisions. In addition to its normal operating staff, each entity should have its own planning, accounting, material purchases and administration. As an initial step, it is suggested that the respective operations could be segregated under separate deputy chief engineers. B. INVESTMENT STRATEGIES 8.28 Under the conditions prevailing in Myanmar with severe energy shortages, suppressed demand, stagnation and uncertainties the focus has to be on the contingencies of the short term of next four years and on pressing to best advantage whatever resource is at hand. Nevertheless, a perspective view of the Longer term has to be kept so that strategies are consistent and investments dovetail from one period to the next. Unless investment programs are immediately initiated, the short term (1991-1995) will be characterized by further abrupt declines in production of natural gas and crude oil, aggravating the prevailing situation of under capacity operation of power stations, refineries and 99 petrochemical plants, of consequent scarcity of power and of petroleum and petrochemical products. 8.29 _Th ghgrt taro (1991-25) strata should focus on rehabilitation of existing facilities and on relatively low risk investments: (a) The most critical action to be taken is rehabilitation of the onshore oilfiolds, first by drilling of 24 data wells, improving well and surface production equipment, next by well completions and then by improving pressure maintenance schomes. These and other ancillary measures, to rehabilitate the developed proved reserves require an outlay of about US$119 million over the next five years and arm estimated to yield a production of 11 million barrels of oil during 1991-1995 and 26.7 million barrels during 1996-2005. The established undeveloped proved and probable reserves can be developed for production with fairly low risk and it is therefore recommended that this should also be done under the management of MOGE but using international consultants and service companies. The investiAents required are US$399 million in the period up to 1995, and US$150 million thereafter, with an expected incremental oil production over the entire period of 54.8 million barrels. The proving up of possible oil reserves, however, carries more risk and should be delayed until later, and/or given over to international oil companies on a PSC or similar basis. (b) To develop the Moattama offshore gas reserves it is essential as a first step to assess the reserves more completely. This will require the drilling of 3 to 5 delineation wells at a cost of US$10- 15 million, with the objective of establishing whether proven recoverable reserves can be increased from the present 1.6 tef to 5 tcf or more. The best economic option for Myanmar would appear to be that about 42 bcf/yr of offshore gas should be dedicated to domestic markets and the remaining production of between 108 bcf/yr and 133 bcf/yr should for export to Thailand by pipeline. Assuming that the offshore gas fields will be developed under a production sharing contract, or under some joint venture arrangement with private sector companies, the minimum investment that would be required from Myanmar would be for the pipRline to Yangon, the cost of which will be of the order of US$173.0 million. Such a pipeline has to be laid in an early phase of offshore gas development, as soon as the production profile is determined, so that gas can flow to Myanmar by 1995/96; (c) In the event that export of offshore gas does not fructify for whatever reasons: reserves not exceeding 1. 6 to 2 tcf or failure to enter into a contract for export, the imperatives for offshore gas field development for domestic supply remain. Capital expendit are of US$247 million is required for drilling production wells, installing platforms and laying a pipeline to Yangon. Thus, a project for exploitation wholly for domestic utilization should be planned on a fall back basis and kept ready for implementation; 100 (d) In view of the shortage of natural gas, there will be an increasing need to fire diesel and fuel oil for power generation. The gas turbines at Thaketa, Ywama, Shwedaung, Mann and Myanaung must be made operable on diesel. Facilities for diesel fuel handling and storage must be constructed, and oil supply must be secured. Continuous operation of Thaketa and Ywama and standby operation at the other plants are seen to be necessary. In order to reduce load shedding to a minimum, diesel requirements for power generation are placed at about 700,000 barrels/year. In addition, fuel oil at about 350,000 barrels/yr will also be required at Thaton and Mawlamyaing plants. Until domestic crude oil production can be increased this will involve an import of crude oil of over 1 million barrels/yr for refining, specifically for the power sector at a cost of about US$25 million. (e) Many combustion turbine units are operating beyond their inspection and maintenance schedules. Foreign inspection, replacement of parts and servicing cannot be further delayed without jeopardizing their future operation. Steam turbine plants and units are also in poor condition mainly due to lack of repairs, lack of proper water treatment and use of heavy oil firing in some boilers. An allocation of US$145.6 million for a power plant rehabilitation program is recommended. (f) The least cost power development program to meet the Base Case demand forecast requires the conversion of Shwedaung, Mann, and Thaketa from open to combined cycle operation during 1993-1995. This will increase the output from the three existing stations by 103 MW maintaining the present level of fuel consumption. Although the e-6nomic cost of uprating is marginally lower than the option of building a new plant, it is prudent to delay a decision to invest further in combined cycle plants until the gas supply situation is clear. (g) An important means of increasing power availability is the reduction of losses, mainly at the distribution level. Statistics show that losses have not been reduced from 35% in 1984 when a pilot loss reduction program was undertaken with assistance from consultants under the first IDA power project. Reactivation of the Loss Reduction Unit in MEPE with a specific mandate to show results is an 'investment' which has good potential for dividends. (h) The refineries under MPE are operating at 25% capacity for want of crude oil. Nevertheless, Thanlyin and Chauk refineries need some urgent rehabilitation involving about US$4 million. MPE has also to renovate marny of its tugs and an initial expenditure of US$5 million starting with four tugs seems necessary. Both MPE and MPPE have several miscellaneous modernization investments to make by way of instrumentation, safety appliances, control systems, computers etc. A total of US$5 million for the purpose will be a modest provision to make until 1995. MPPE is also committed to a new depot for petroleum products at Yangon at a cost of US$20 million. 101 8.30 For the medium term investments in the period 1996-2000, major studies and investigations will have to begin as soon as possible: (a) Producir,g onshore gas fields are in decline and production is decreaslng rapidly. To arrest the decline, or reduce it as much as possible, additional development and delineation wells and compression are essential. A five year program to rehabilitate and develop proved and probable gas reserves is estimated to cost US$137.5 million. The exploration and development of possible gas reserves is estimated to require US$66.50 miilion in the first 5 years and US$20.00 million in the following 5 year period, and as with oil exploration and development, it is recommended that these investments should be financed through PSC contracts or similar arrangements. (b) Offshore gas will be available first in the lower delta region. The expected speedy economic development in that region combined with the near absence of onshore gas in the area will place a heavy demand on the offshore gas. At the same time, the upper delta has potential for fast economic growth, and it too will have a lack of onshore gas and so consideration may be given to a gas pipeline from Yangon to that region. A pipeline route and engineering survey would need to be undertaken; (c) Even if offshore gas is developed, the forecast growth of electricity demand will lead to a stage when gas supplies will become stretched to the limit and for this and other reasons it becomes prudent to invest in the country's hydro resources. Hydro facilities are forecast to be needed by the year 2003, and the initial steps for planning these should begin immediately. In addition, as information unfolds MEPE should reassess its generation options including the possibility of a domestic coal based power plant. The delineation of the coal field in Kalewa at a cost of US$6.0 million and commissioning of a feasibility study for a minemouth based power plant is recommended; (d) MEPE also needs to prepare a ten year transmission, and distribution development plan. On occasion overloads have already occurred on the new 230/132 kV transmission systems, between the Upper and Lower Myanmar load centres caused by limitations on the associated 132/66 kV systems. Instability in the power system has also cccurred, leading to major load shedding now and then. On the distribution side, investments have been minimal for years with the result that the networks are in poor condition throughout Myanmar. A scheme to replace the 6.6 kV system in the city of Yangon with 11 kV and to upgrade 33 kV networks to 66 kV has made little progress. The Mandalay distribution system is in a relatively better state, but it is also characterized by high distribution los3es. Investments in the distribution upgradation are estimated at US$250.4 million; (e) MEPE needs to evolve an integrated strategy for rural electrification. Rural electrification is both a way of enhancing national unity, of such critical importance to the country's future 102 and a way of nurturing rural economic development and the agricultural sector; (f) MPE should undertake an operational loss and energy audit of the refineries, to identify possible investment opportunitie to increase plant efficiency. A debottlenecking study might also be considered. Both of these studies should employ the assistance of international consultants; and (g) Assuming that the constraint of crude oil supply is lifted, resulting in a higher growth in petroleum product demand than forecast in the Base Case, MPE's refineries might need some investment to increase conversion capacity in order to offset a possible imbalance of product mix, particularly excess fuel oil. The situation should be monitored and if necessary plans could be drawn up for a hydrotreating unit for coker gas oil, to be commissioned at Mann in 1996/97 or alternatively for a mild hydrocracker and a vacuum unit to start up in 1996/97 at an estimated investment of US$15 million. 8.31 In the Mediu"l term, the core program during 1996-2000 would consist of the following: (a) The next stage of developing the oilfields would be for MOGE to explore, delineate and develop possible oil reserves in the event no foreign oil companies showed an interest in undertaking this work. The investments are placed at US$575 over ten years with US$288 million being in the first five years. The likely incremental production is estimated at 65 million barrels with 3 million barrels being discovered in the first five years. (b) In the event that offshore gas were not available, the development of possible onshore gas reserves would be imperative. It would require an investment of about US$86.5 mtllion over a ten year period and is expected to yield an incremental gas supply of 86.3 bcf over a ten year period. (c) Assuming offshore gas is developed, the construction of a pipeline from Yangon to the Pyay area would probably be economic at an estimated costs of US$50 million. (d) On the basis of the least cost power expansion plan, new combined cycle plants in the vicinity of Yangon of 500 MW have to be commissioned in stages, the cost of which is placed at US$450.5 million over the period 1991-2000. Given the gestation period of at least three years for combined cycle plants and about 10 years for hydro, investments will, however, have to commence long before 1996. (e) The transmission system is in reasonable condition but will need some expansion in this period, estimated to cost US$138 million. The work of upgrading the distribution system has to be taken up in earnest, with an investment of US$250.4 million. (f) Projects for conservation of energy as a sequel to the carrying out of energy audits in refineries may call for an adequate outlay. 103 8.32 The long term, beyond 2000 also should receive attention if only in the context of planning. Large scale power plants are called for in the optimum generation plan for the period between 2000 and 2010, including 300 MW of combined cycle plants and 1852 MW of hydro. The first major hydro plant is required to be on stream in 2003, and thus detailed engineering studies for various hydro sites will need to be completed by 1995. C. INVESTMENT PROFILE 8.33 Details of the investment profile needed in the quinquennial until 1995 and until 2000 are given in Annex 8.3, and are summarized in the Table below: TABLE 8.1 INVESTNT PRFILE (us$ NIUlU.-1991 prices) Short Torm (1991-95) Foreign Local Total RehabilitatIon of proven oil reserves 71 47 119 Development of probable oil reserves 239 159 399 Rehabilitation of proven onshore gas reserves 43 28 71 Development of probable gsa reserves 40 27 67 Rehabilitation of Power Stations 93 53 146 Conversion to combined cycle/new CT's 188 68 256 Transmission systems 44 33 77 Distribution systems 94 39 133 Rehabilitation of Refineries 9 1 10 Renovation of river tugs 7 3 10 Modernization/diftribution/efficiency/logs control 8 2 10 Petroleum Product Depot at Yangon 10 10 20 Gas Pipeline Moattamm-Yang.., (for Moattame offshore gas) 125 48 173 Coal Exploration 5 1 6 Fertilizer Rehabilitation 10 1 11 Traditional Energy Sector 6 20 26 TOTAL 994 540 14 MediuM Term (1995-2000) Development of proved and probable oil 91 60 1SO Development of proved and probable gas 12 8 20 Combined cycle power plants near Yangon 136 58 194 Tranmmission system improvements 37 25 62 Dist. 7ution system improvementa 66 52 118 Refinery energy conservation investment 14 6 20 Hydrotreating at Meri refinery 11 4 15 Renovation of Tugs 18 22 40 Traditional Energy Sector 6 20 26 TOTAL 391 el Notes: 1 Maintenance and operational requirements for operations are not include in the above. 2. Purchases of fuel like diesel oil/imports of crude oil are also not reflected in the table. 3. Taxes nd duties are not included. 4. Moattaem gas field development costs are not included as it is expected that this would be done by PSC's. 5. Development of oil and gas reserves could also be done under PSC type agreements. 6. Investments in the traditional energy sector are estimated at US$51.5 million, depending upon the first stage of data collection, pilot projects. 104 D. FINANCIAL REOUIREMENTS 8.34 The energy sector's resource mobilization requirements are far greater than any other sectors. Because of the magnitude of these investments, the cost to the nation of either (a) a failure to optimize investments; or (b) an inefficient utilization of assets, can be extremely high. The recommended investment profile is directed at efficient utilization of existing resources and assets and at a least cost power expansion program. 8.35 The total investment needs in the period 1991 to 1995 are US$1,532 million (1991 US$), with a foreign component of US$992 million; and in the period 1996 to 2000 are US$645 million, with a foreign component of US$391 million. This assumes that offshore gas development will be done under a production sharing contract, or other Joint venture arrangement, with financing from contract partners and only minimal investments from Myanmar. In the context of examining how the funds needed for investments would be available to the four energy sector enterprise, financial statements incorporating the prices now recommended (first step) have been prepared and are contained in Annex 8.3. Table 8.2 presents a summary of the cash flow for the years 1991-95. TABLE 8.2 ENER8Y ACTIVITIES: NOGE. NEPE, PE & NEM CAN FLOW DtRIfh FY1991-1995 Equivatent (USS million) Ck million) at 50k/USS Sources Net income before interest on foreign loans, state taxes, tevies and state takes of profits 9868 197.4 LESS state taxes, as above 9269 185.4 Add Depreciation 3389 67.8 Internal cash generation 3988 n.A GON Equity contribution 4006 80.1 New foreign loans/investments 5256 847.8 TOTAL SOURCES 13250 1007.70 AnL Ication Construction requireaents 9498 430.8 Debt service on foreign loans 3552 572.9 Chnges in working capital 200 4.0 TOTAL APPLICATION 13250 1007.7 8.36 It is interesting to note that the total of state taxes, levies and takes in the five years equals the GOM equity contributions and the new foreign loans/ investments. With the shadow exchange rate in operation, the necessity for moving to the target minimum energy prices becomes paramount as the first step prices will not provide adequate revenues to cover the construction and debt service requirements. But the serious constraint is the availability of foreign exchange. 8.37 Given Myanmar's foreign currency constraints and the fact that the four energy enterprise have had to defer repayments of foreign loans and interest to the extent of US$150 million as at July 15, 1990, the outlook for finding the foreign currency requirements for the future are clouded. The silver lining is that the government has in the last two or three years taken significant action to improve the foreign trade regime and to encourage foreign investments. The response to invitations to explore for oil and gas in new areas of the country 105 has been significant. Moattama offshore gas development presents an opportunity for financing through a PSC or similar arrangement. For onshore oil and gas development the government and the energy SEEs must also pursue with vigor any openings to attract financing. Foreign investment interest could probably be attracted to the exploration ar-I development of possible reserves, and perhaps to enhanced oil recovery schemes. It is also possible that new power stations such as the combined cycle units could be installed under build-operate-transfer type contracts (BOT) and/or other supplier credit arrangements. As for resumption of bilateral assistance, macroeconomic policies are presently the major constraint, which with determined effort by the government, could be relieved. 106 ANNEX 1. GDP BY SECTQR IN MYANMAR (Billon. '87 kvta) 1976 to 1990 YEAR AGRICULTURE INDUSTRY OTHER TOTAL 1976 21.2407 3.9835 14.6983 39.9225 1977 22.3873 4.2963 15.6247 42.3083 1978 23.S061 4.7054 16.5517 44.7632 1979 25.3375 5.0182 17.4064 47.7621 1980 26.6774 5.3924 18.1782 50.2480 1981 29.4359 5.8856 19.0879 54.4094 1982 31.7013 6.3163 19.9544 57.9720 1983 33.5999 6.7386 20.9157 61.2542 1984 35.2461 7.0069 21.7365 63.9895 1985 36.8006 7.6638 22.9664 67.4308 1986 37.8373 8.0298 24.1805 70.0476 1987 38.0288 7.5269 23.7531 69.3088 1988 36.1888 7.0663 23.1143 66.3694 1989 31.5700 5.9870 21.1250 58.6820 1990 34.9400 6.9000 21.1800 63.0200 AN?= 1.2 (*) ENERGY BALANCES IN MYANMAR. is IW e4smm U s) TRAD1l1ONAL GY DERN DiERnY FPW- lma Cude mM p ,B Pe*ada' PlObcAs wood Cucos Reske 0o1 an COl Hydoe Hyd. ewer GM udo Dsud P* lKae AV F FOR OFde GROSS SUPPLY 1C.T U MCwT MT UTB W7 BffT OWN OWWH OWH C1W1 OWN IW ADMM MM MUI MM MM Pr.Auc* 23536 2206 4.437 40.1 33.0 1113.9 30 5i bld Urn M Las -299 -4.0 I_pot 0.7 1.6 11.7 - expa OROSS SUPPLY AVAUABL 25336 1907 5.0S7 36.1 39.6 1113.9 3D 5. 11.7 CONVERlN Cbosid NFO&SCdw -1406 357 Power - -3.7 -0.05 1143.9 -30 7.83 2510 131.7 -2.3 Pusoa R eflu1q -3.3 -2.6 3.3 331 2.2 4.6 24.6 1I.4 MIU LNo -0.2 1.7 Cavuuisb Lame -4223 -43 -1150 -1.3 -19.2 -3.09 -2475 -53 Trmslidr La -753 -39.5 0 MEM SU Y AVARABLE 179M 614 7S? 0.0 10.4 36.5 -217 -53 13 1757 92 93.2 39.S 2.2 4.6 24.6 14. S- Hxw Els (e) -as NT DOLESTC CONSUMPTION 17906 314 757 10.4 36.5 17S7 92 93.2 39.3 2.2 4.6 24.6 5.9 CNSUMPT1ON BY SECTOR Tgmwm 0.0 0.7 0 0 S52. 37.4 0o 4.0 3.5 5.7 hdeby 139 5.6 35.7 993 52 2.4 2.0 0.2 0.1 10.9 0.2 akt 0.0 220 12 1L3 0.4 0.0 0.5 10.2 0.0 Fata 4.1 0 0 0.0 0.0 0.0 0.0 0.0 0.0 H_obhld 17908 314 563 0.0 545 29 0.0 0.0 2.0 0.0 0.0 0.0 TOTAL 17903 314 7S7 1OA 36.5 1757 92 93.2 39.3 22 4.6 24.6 5.9 SOURCES OF DATA [PEC IPEC IPEC [PEC [WEC MOE [x:C WBIS MOE esr B51 OEl MOE UEMOB OB MOM MOB &MOD &BEECIP &DBEI &M & EST CONVERSON TO000rOT 0.401 0.653 0.401 136.430 23.039 0.647 0.064 Q0.4 0.0e 006 0.064 3.744 3.357 3.647 3.647 3.m 2tlOO AN1KM 1 2 th) ENERGY BlNCES IN MYANMAR. iL 1990 (THOUSAND TOE) PRDIARY ENEROY SBCONDARY 04EROY TRADITIO.AL ENERGY MODERN ENRGY T0TALs Wood Oweel ReN OH an Coa Hydro Hydo Power Odd 1i DieAtl Ptr Kao AsP POO Oi 0r GROSS SUPPLY prodectlm 9437.6 84.6 605.4 1125.0 24.6 314.2 7.4 0.S 12W FieldUn edLoom -119.9 -112.5 -232 Impote 90.0 1.0 43.7 1S OROSS SUPPLY AVAILABLE 9437.6 0.0 764.7 693.4 1012.5 25.6 314.2 7.4 0.5 43.7 12S0 S All Pdis lqy 76.7% 0.0% 6.2% 5.7% .2% 0.2% 2.6% 0.1% 0.0% n4% 100 * modem M mow 33.1% 48.2% 1.2% 15.0% 0.4% 0.0% 2.1% 1N CONVERS O craeoe Productloo -563.7 563.7 0 Powereretiom -105.0 -0.03 -105.6 -2.S -0.5 211.6 11.1 -86 0 P cma Refl -524.4 -72.9 313.3 127.8 *.1 16.9 94.3 36.0 0 MethdowULNO -5.7 5.7 0 Ceavenks Loses -1693.2 -2.2 -461.0 -171.0 -467.3 -2.00 -206.6 -4.9 -303 Tmenadi Lase -63.5 -3.3 -67 NET SUPPLY AVAILABLE 713D.7 535.5 303.7 0.0 361.6 23.60 0.0 0.0 0.0 148.1 7.6 343.9 133.5 &I 16.9 94.3 36.3 91" % 78.1% 5.8% 3.3% 0.0% 3.9% 0.3% 0.0% 0.0% 0.0% 1.6% 0.1% 3.8% 1.5% 0.1% 0.2% 1.0% 0.4% 100 Socomy Zbpu (ceb) -25.0 -25 N!1T DOMEST CONSUMPTION 7181.5 535.6 303.7 361.6 23.6 148.1 7.8 346.9 133.5 8.1 16.9 94.3 11.8 9175 CONSUMPTON BY SECTOR TrMn-od 0.0 0.0 0.0 197.5 125.5 0.1 14.7 13.4 11.4 363 ISduty 75.9 194.6 23.6 U3.7 4.4 33.7 6.8 0.8 0.5 41.8 0.4 514 Odher 0.0 18.5 1.0 67.7 1.2 0.0 1.7 39.1 0.1 129 Patlilzer 167.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 167 Houseod 7181.5 535.6 227.8 0.0 45.9 2.4 0.0 0.0 7.3 0.0 0.0 0.0 3O TOTAL 7181.5 535.6 303.7 361.6 23.6 148.1 7.8 34t.9 133.5 8.1 16.9 94.3 11.8 9175 % All Secoodey ErV 78.3% 5.8% 3.3% 0.0% 3.9% 0.3% 1.6% 0.1% 3.8% 1.5% 0.1% 0.2% 1.0% 0.1% 100 S Modem Energy 31.3% 2.0% 12.8% 0.7% 30.2% 11.6% 0.7% 1.5% 8.2% 1.0% 100 109 ANNEX 1.3 PRODUCTION AND CONSUMPTION OF GAS AND CRUDE OIL IN MYANMAR 1978 to 1990 Naural Gas Crude Oil Gross Mktble Gross Refin Prod Cons Prod Cons YEAR mmcf/yr mmb/yr 1978 21.41 11.85 9.56 8.40 1979 19.14 14.67 9.99 8.30 1980 21.53 17.72 11.02 9.22 1981 25.26 22.00 10.11 8.60 1982 23.85 20.38 10.44 8.21 1983 23.13 19.17 9.79 7.84 1984 22.67 20.51 10.17 7.44 1985 29.45 24.51 11.20 7.79 1986 35.54 34.48 10.25 6.99 1987 40.45 39.49 8.27 5.98 1988 41.91 41.28 6.17 5.12 1989 39.09 38.81 4.84 3.62 1990 41.51 36.10 5.55 4.40 ANNEX 1.4 CONSUMPTION OF MAIN PETROLEUM PRODUCTS (MiI ion i1 in MYANMAR 1978 to 1990 Petrol Kero Av Fuel Diesel Fuel Oil Coker HFO Propne Butane LPG TOTAL Gasi 1978 62.6 29.8 8.5 78.5 45.7 0.0 0.0 0.0 0.0 0.0 225.0 1979 64.8 22.7 7.1 80.7 46.4 0.0 0.0 0.0 0.0 0.0 221.7 1980 70.2 19.7 6.9 89.6 47.6 0.0 0.0 0.0 0.0 0.0 234.1 1981 72.5 12.0 6.8 87.7 55.0 0.0 0.0 0.0 0.0 0.0 234.0 1982 71.4 4.3 6.6 88.4 54.3 0.0 0.0 0.0 0.0 0.0 224.9 1983 70.0 5.4 6.9 96.9 50.8 10.0 0.0 0.0 0.0 0.0 240.0 1984 71.6 5.3 6.8 93.2 48.6 10.6 1.2 0.0 0.0 0.2 237.4 1985 76.3 4.8 6.6 102.7 49.0 1.8 25.0 0.0 0.0 0.0 266.3 1986 68.9 2.0 6.8 99.9 43.9 6.7 0.3 0.0 0.0 1.4 229.8 1987 65.6 0.8 5.7 79.7 41.1 4.4 0.0 4.9 0.9 1.1 204.2 1988 51.7 0.2 4.0 68.3 35.1 0.0 0.0 1.8 2.1 2.7 166.0 1989 34.3 0.9 3.8 66.2 17.9 0.0 0.0 1.6 2.1 0.0 126.9 1990 38.1 _ 2.2 4.6 83.8 24.6 0.0 0.0 _0.2 0.3 0.0 153.8 Note: yeaIs are fiscal year lli ANNEX 1.5 PRODUCTION AND CONSUMPTION OF COAL IN MYANMAR (tons/vearl PRODUCTION OF COAL CONSUMPTION OF COAL lmrnga Apparent YEAR Kalewa Namm Total Total Total Stock coal+coke Coal Coke Coal Change 1978 12696 15650 28346 112827 88598 8216 104611 12333 1979 6065 5927 11992 77020 58890 5704 71316 -434 1980 13600 0 13600 58565 35187 10564 48001 786 1981 8070 2966 11036 39480 15826 7378 32102 -5240 1982 8750 8086 16836 34rj2 11182 4735 30167 -2149 1983 12204 16290 28494 47071 13867 6242 40829 1532 1984 13652 21750 35402 64928 25195 5365 59563 1034 1985 13200 30333 43533 65207 17869 3517 61690 -288 1986 12600 30555 43155 55361 4172 5929 49432 -2105 1987 16442 21056 37498 50038 2121 5034 45004 -5385 1988 15400 23313 38713 37489 1828 3430 34059 6482 1989 13600 16180 29780 26864 1581 1910 24954 6407 1990 12915 25757 38672 _46571 1742 2405 44166 -3752 Notes: year is fiscal year (end) SOURCE: Industry No 3 and MOE 112 ANNEX 1.6 ELECTRICITY CONSUMPrION IN MYANMAR (OWh/vr) Fiscal BULK INDUSTRY RESIDENTIAL OTHER TOTAL Y ear_ _ _ _ _ _ _ _ _ __ _ _ _ _ 1976 81.2 288.8 159.6 26.4 556.0 1977 81.3 346.4 174.2 26.4 628.2 1978 82.8 378.8 188.4 27.7 677.6 1979 88.5 373.5 200.3 27.7 690.1 1980 109.3 407.4 216.5 29.4 762.6 1981 122.2 457.1 242.3 31.9 853.5 1982 132.7 498.7 281.4 36.9 949.7 1983 144.8 551.8 315.8 37.7 1050.1 1984 157.6 585.4 340.6 37.9 1121.5 1985 195.5 654.8 373.8 39.7 1263.6 1986 128.5 882.3 408.7 40.1 1459.5 1987 146.0 918.8 437.0 41.3 1543.0 1988 153.7 904.4 481.1 41.0 1580.1 1989 167.9 962.9 529.5 44.0 1704.3 1990 183.1 _ 1031.6 582.4 47.3 1844.4 SOURCE: MEPE 113 A&NNEX 1.7(s) SUMMARY OF BASE CASE MODERN ENERGY CONSUMPTION FORECAST PETROLEUM PRODUCTS NATULG COAL CTRICf TOTAL Transport Electricity Industy Electricity Grid Rural MODERN Intd tc etc ENERGY mmb mmb bcf bcf mtous GWh GWh mtoo 1990 4.7 0.4 16.2 19.9 44.2 2371.0 138.2 1848.6 1991 5.0 1.1 15.6 19.7 45.0 2552.0 152.0 1913.4 1992 5.3 0.9 9.8 20.1 45.9 2717.8 157.6 1858.5 1993 5.6 1.0 7.7 17.8 46.9 2895.7 163.5 1758.4 1994 5.9 0.4 7.3 15.4 47.8 3086.7 169.6 1742.0 1995 6.3 0.4 21.4 19.7 48.8 3247.3 173.5 2228.9 1996 6.6 0.4 35.1 21.9 49.7 3419.5 177.7 2732.5 1997 7.2 0.4 29.3 24.3 50.7 3654.3 183.1 2733.5 1998 7.9 0.4 23.8 27.5 51.7 3908.8 188.8 2772.6 1999 8.6 0.4 18.4 30.7 52.8 4236.4 194.8 2823.4 2000 9.4 0.5 18.1 34.4 53.8 4593.3 201.2 3046.1 2001 10.3 0.5 11.9 38.4 54.9 4982.3 208.0 3121.0 2002 11.2 0.5 6.3 43.5 56.0 '413.7 220.3 3258.4 2003 12.3 0.5 9.5 39.9 57.1 5954.3 233.5 3411.7 2004 13.4 0.4 5.1 43.6 58.3 6550.2 247.5 3566.3 2005 14.7 0.4 12.5 35.5 59.4 7207.1 262.4 3747.1 2006 16.1 0.4 10.7 36.3 60.6 7931.3 278.2 3943.5 2007 17.6 0.5 9.1 37.9 61.8 8729.8 295.0 4190.0 2008 19.3 0.5 9.2 37.8 63.1 9610.5 312.9 4459.5 2009 21.2 0.5 2.2 44.8 64.3 10582.0 331.9 4757.3 2010 23.2 0.6 -4.2 51.2 65.6 11653.7 352.1 5086.2 AAG 1990-1995 5.8% -2.9% 5.7% -0.2% 2.0% 6.5% 4.7% 3.8% 1996-2005 8.9% 0.8% -5.2% 6.1% 2.0% 8.3% 4.2% 5.3% 1990-2005 7.8% -0.5% -1.7% 3.9% 2.0% 7.7% 4.4% 4.8% 114 ANNEX 1.7 1b) SUMMARY OF LOW CASE MODERN ENERGY CONSUMPTION FORECAST PETROLEUM PRODUCTS NATURAL GAS COAL ELECTRICITY TOTAL Trmnsport Electricity Transport Electricity Grid Rural MODEMN Ind etc Ind etc ENERGY __mmb mmb bcf bef mtons GWh GWh mito 1990 4.7 0.4 16.2 19.9 44.2 2371.0 138.2 1848.6 1991 4.9 0.8 15.6 19.7 45.0 2484.1 149.6 1896.9 1992 5.1 1.1 9.8 20.1 45.9 2589.1 152.9 1825.6 1993 5.3 0.9 7.7 17.8 46.9 2699.4 156.4 1707.3 1994 5.5 1.0 7.3 15.4 47.8 2815.3 160.0 1670.7 1995 5.7 0.4 21.4 19.7 48.8 2897.3 161.3 2135.7 1996 5.9 0.4 35.1 21.9 49.7 2984.2 162.9 2615.3 1997 6.2 0.4 29.3 24.3 50.7 3076.1 164.5 2571.5 1998 6.6 0.4 23.8 27.5 51.7 3173.3 166.3 2560.0 1999 6.9 0.4 18.4 30.7 52.8 3316.4 168.3 2553.1 2000 7.3 0.5 18.1 34.4 53.8 3466.9 170.3 2710.6 2001 7.7 0.5 11.9 38.4 54.9 3625.1 172.6 2711.8 2002 8.1 0.5 6.3 43.5 56.0 3791.4 179.2 2765.9 2003 8.6 0.5 9.S 39.9 57.1 4013.6 186.1 2824.5 2004 9.0 0.4 5.1 43.6 58.3 4249.2 193.2 2872.1 2005 9.5 0.4 12.5 35.5 59.4 4499.1 200.7 2932.6 2006 10.1 0.4 10.7 36.3 60.6 4764.1 208.4 2993.6 2007 10.7 0.5 9.1 37.9 61.8 5045.3 216.4 3087.8 2008 11.3 0.5 9.2 37.8 63.1 5343.5 224.7 3186.2 2009 11.9 0.5 2.2 44.8 64.3 5659.9 233.4 3291.8 2010 12.6 0.6 -4.2 51.2 65.6 5995.6 242.4 3405.1 AAG 1990-1995 3.7% -2.9% 5.7% -0.2% 2.0% 4.1% 3.1% 2.9% 1996-2005 5.3% 0.8% -5.2% 6.1% 2.0% 4.5% 2.2% 3.2% 1990-2005 4.8% -0.5% -1.7% 3.9% 2.0% 4.4% 2.5% 3.1% ANNEX 1.8 SUMMARY OF PETROLEUM PRODUCT FORECASTS (million bls vr ear) BASE CASE LOW CASE HIGH CASE for refinery aIaysis oly YEAR Gen Use Elect Use Total Gen Use Elect Use Total Gen Use Elect Use Total 1989190 4.74 0.44 5.18 4.74 0.44 5.18 7.00 0.44 7.44 1990/91 4.98 0.78 5.76 4.88 0.78 5.66 6.88 0.78 7.66 1991/92 5.27 1.14 6.41 5.07 1.14 6.21 6.76 1.14 7.90 1992/93 5.58 0.94 6.52 5.27 0.94 6.21 7.19 0.94 8.13 1993194 5.91 1.00 6.91 5.47 1.00 6.47 7.38 1.00 8.38 1994/95 6.27 0.38 6.65 5.69 0.38 6.07 8.24 0.38 8.62 1995196 6.65 0.39 7.04 5.92 0.39 6.31 8.48 0.39 8.87 1996197 7.25 0.40 7.65 6.23 0.40 6.63 8.73 0.40 9.13 1997/98 7.90 0.42 8.32 6.57 0.42 6.99 9.08 0.42 9.50 1998/99 8.62 0.42 9.04 6.92 0.42 7.34 9.47 0.42 9.89 1999/00 9.42 0.45 9.87 7.30 0.45 7.75 9.84 0.45 10.29 2000/01 10.28 0.46 10.74 7.70 0.46 8.16 10.26 0.46 10.72 2001/02 11.24 0.48 11.72 8.12 0.48 8.60 10.68 0.48 11.16 2002/03 12.28 0.47 12.75 8.57 0.47 9.04 11.15 0.47 11.62 2003/04 13.44 0.41 13.85 9.04 0.41 9.45 11.69 0.41 12.10 2004/05 14.70 0.41 15.11 9.55 0.41 9.96 12.20 0.41 12.61 2005/06 16.09 0.44 16.53 10.09 0.44 10.53 12.69 0.44 13.13 2006/07 17.62 0.47 18.09 10.66 0.47 11.13 13.21 0.47 13.68 2007/08 19.31 0.49 19.80 11.26 049 11.75 13.77 0.49 14.26 2008/09 21.16 0.52 21.68 11.90 0.52 12.42 14.34 0.52 14.86 2009/10 23.20 0.56 23.76 12.58 0.56 13.14 14.92 0.56 15.48 PAA 1990 TO 1995 5.8% -2.9% 5.1% 3.7% -2.9% 3.2% 3.3% -2.9% 3.0% 1996 TO 2005 8.9% 0.8% 8.6% 5.3% 0.8% 5.1% 4.0% 0.8% 3.9% 1990 TO 2000 7.1% 0.2% 6.7% 4.4% 0.2% 4.1% 3.5% 0.2% 3.3% 1990 TO 2U105 7.8% -0.5% 7.4% 4.8% -0.5% 4.5% 3.8% -0.5% 3.6% 1990 TO 2010 8.3% 1.2% 7.9% 5.0% 1.2% 4.8% 3.9% 1.2% 3.7% ANE 1.9 SUMMARY OF ELECTRICITY DEMAND FORECASTS INTERCONNECTED SYSTEMS RURAL SYSTEMS TOTAL DEMAND AND SALES BASE CASE LOW CASE BASE CASE LOW CASE BASE CASE LOW CASE DEmAND DEMAND DEMAND DEMAND YEAR Gen Load SALES Ge Lad SALES Gen Load SALES G Lod SALES DEMAND SALES DEMAND SALES 1989f90 2371 1636 2371 1636 138 94 138 94 2509 1730 2509 1730 1990(91 2552 1761 2484 1714 152 99 150 97 2704 1860 2634 1811 1991f92 2718 1902 2589 1812 158 104 153 101 2875 2006 2742 1913 1992f93 2896 2056 2699 1917 163 110 156 105 3059 2165 2856 2021 1993/94 3087 2 2815 2027 170 115 160 109 3256 2338 2975 2136 1994/95 3247 2403 2897 2144 174 121 161 113 3421 2524 3059 2257 1995/96 3419 2599 2984 2268 178 128 163 117 3597 2727 3147 2385 1996J97 3654 2850 3076 2399 183 135 165 122 3837 2986 3241 2521 1997/98 3909 3127 3173 2539 189 143 166 126 4098 -271 3340 2665 IWq8/99 4236 3431 3316 2686 195 152 168 131 4431 3583 3485 2818 199'/00 4593 3767 3467 2843 201 161 170 136 4795 3927 3637 2979 200i)I01 4982 4135 3625 3009 208 171 173 142 5190 4306 3798 3150 2001/02 5414 4547 3791 3185 220 181 179 147 5634 4728 3971 3332 2002/03 5954 5002 4014 3371 234 191 186 153 6188 5193 4200 35?4 2003(04 6550 5502 4249 3569 248 203 193 158 6798 5705 4442 37W8 2004/05 7207 6054 4499 3779 262 215 201 165 7469 6269 4700 3944 2005/06 7931 6662 4764 4002 278 22^ 208 171 8209 6890 4973 4173 2006/07 8730 7333 S54S 4238 295 242 216 177 9025 7575 5262 4415 2007f08 9611 8073 5344 4489 313 257 225 184 9923 8329 5568 4673 2008/09 10582 8889 5660 4754 332 272 233 191 10914 9161 5893 4946 2009/10 11654 9789 5996 5036 352 289 242 199 12006 10078 6238 5235 Growth to 1995 6.5% 8.0% 4.1% 5.6% 4.7% 5.3% 3.1% 3.7% 6A% 7.9% 4.0% 5.5% 1996 to 2005 8.3% 9.7% 4.5% 5.8% 4.2% 5.9% 2.2% 3.8% 8.1% 9.5% 4A% 5.7% 1990 to 2000 6 ..% 8.7% 3.9% 5.7% 3.8% 5.5% 2.1% 3.8% 6.7% 8.5% 3.8% 5.6% to 2005 7.7% 9.1% 4A% 5.7% 4.4% 5.7% 2.5% 3.8% 7.5% 9.0% 4.3% 5.6% to 2010 8.3% 9.4% 4.7% 5.8% 4.8% 5.8% 2.8% 3.8% 8.1% 9.2% 4.7% 5.7% l / ANNEX 1.10 SUMMARY OF (FREE) GAS SUPPLY FORECAST-S FOR D)OMESTIC MARKET, BCF per year BASE CASE LOW CASE HIGH CASE Onshore Offshore Total Onshore Offshore Total Onshore Offshore Total 1990 33.0 33.0 33.0 33.0 (mci poss) 33.0 1991 33.3 33.3 33.3 33.3 33.3 33.3 1992 27.9 27.9 26.4 26.4 27.9 27.9 1993 23.5 23.5 21.3 21.3 23.5 23.5 1994 20.7 20.7 17.2 17.2 23.7 23.7 1995 19.1 20.0 39.1 14.1 14.1 24.1 20.0 44.1 1996 14.9 40.0 54.9 10.4 10.4 21.4 40.0 61.4 1997 11.6 40.0 51.6 7.1 7.1 20.6 40.0 60.6 1998 9.3 40.0 49.3 5.1 5.1 18.3 40.0 58.3 1999 7.1 40.0 47.1 3.1 3.1 16.1 40.0 56.1 2000 5.5 45.0 50.5 1.7 1.7 14.5 45.0 59.5 2001 3.3 45.0 48.3 0.0 0.0 12.3 45.0 57.3 2002 2.8 45.0 47.8 0.0 0.0 10.9 45.0 55.9 2003 2.4 45.0 47.4 0.0 0.0 9.6 45.0 54.6 2004 1.7 45.0 46.7 0.0 0.0 8.0 45.0 53.0 2005 1.0 45.0 46.0 0.0 0.0 6.2 45.0 51.2 2006 45.0 45.0 0.0 0.0 5.0 45.0 50.0 2007 45.0 45.0 0.0 0.0 5.0 45.0 50.0 2008 45.0 45.0 0.0 0.0 5.0 45.0 50.0 2009 45.0 45.0 0.0 0.0 5.0 45.0 50.0 2010 45.0 45.0 0.0 0.0 5.0 45.0 50.0 AAG to 2000 -18.1% 4.7% -28.1% -28.1% -8.8% 6.7% to 2005 -22.2% 2.3% -100.0% -100.0% -11.3% 3.1% to 2010 -100.0% 1.6% -100.0% -100.0% -9.5% 2.2% Note: Associated gas production is now about 2 bcf/yr and could increase depending on oil field rehabilitation GDP IN MYANMAR. 1975 to 1989/,90 CDP in billioni 1987 Kyails 70 - 60 - c: 40 n -_ 0 ~ 5 30 20 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 l*18!'. In [ l'J8 1.*W YEAR 0 Totol CDP t Aqrculltu'e C Agtc g Ilncdutry ........- i......--. . .................-- ..... .. ... .. .. ... .. .. .~~~~~~~~~~~~p . <. . *.a... *~~~~ 0 z L- .,; LU~~~~~~~~~~~~~~~& Z . . 8 i~~~~~~~~~. . . . . . . .. . . . . :)2". .. ............ . 2 * .. .<.° . . .. 3.... .. eI 2 *~/c ._ - N0 0 .". O, . e 'ti ........* ........... ............................ ..... ..2... 0. 0 o * * o1 . . . . . . . . . . . . . . . . .... ... ....... ...... 0 0 0 0 0 ..9 . . . . . . . . . . 4.. N.. . . . . . . . . . .. . . . . . . 83iV389 dO 01 wn~o3 .io A.llltYSOdd X 611 120 ANNEX 2.1 MYANMAR PAST DISCOVERY AND FUTURE POTENTIAL FOR OIL AND GAS Notes: (a) The vertical axis indicates the degree of certainty of various quantities of recoverable oil and gas (not in-place reserves). (b) The horizontal axis indicates the amount at various levels of certainty. (c) The graph portrays the entire spectrum of possibilities for Myanmar from that which has already been produced to the amount that may exist, although with low probability of occurrence. (d) The graph indicates that some 1479 mmb of oil and equivalent gas (bbls oe) have been found with 100% certainty which includes 600 mmboe produced to date, 525 mmboe proved remaining reserve, and 354 mmboe expected additions to proved reserve; the boundary between expected additions and undiscovered potential is rather more fuzzy than sharp; (e) Undiscovered potential is represented by a curve ranging from a near certain (95% chance) of 425 mmboe additional being discovered (bringing total oe to 1904 mmb), a mean chance (44%) of 1930 mmboe additional being discovered (bringing total oe to 3383 mmb); and an outside chance (5%) that 2850 mmboe or more additional will be found (bringing total to 4329 mmboe or higher). (f) Note that of discovered 1479 mmboe, 46% is oil and 54% is gas, while expectations for new discoveries average 35-40 oil and 60-65% gas. 121 ANNEX 2.2 ESTIMATE OF RESERVES AT KALEWA Proven Probable Possible Total (PI) (P2) (P3) (a) Pierce Management Inc. (1954) Upper Coal Measure - - 13.7 13.7 Lower Coal Measure 2.7 3.7 5.8 12.2 Total 2.7 3.7 19.5 25.9 (b) MRDC, 1964 North of Mvitha River Upper Coal Measure 1.9 2.1 40.5 44.5 Lower Coal Measure 2.7 3.7 7.5 13.9 South of Mvitha River Upper Coal Measure - 12.0 17.3 29.3 Lower Coal Measure 0.8 - 21.3 22.1 Total 5.4 17.8 86.5 109.8 Source: Coal Committee Report, 1967. Note: The coal reserve of the areas which have been drilled and which lie above the Waye Chaung level is considered as measured or proven (PI) reserve. The reserve which lies between Waye Chaung level and 400 feet below is designated as probable (P2), whereas that lying between 400 feet and 800 feet below is taken as possible (P3) reserve. Similarly, in the areas where exploration consisted of outcrop examination and field mapping only without drilling, the reserve above the Waye Chaung level is classified as probable (P2). The reserve between the creek level and 400 feet below it is regarded possible (P3) whereas that between 400 feet and 800 feet below is classified as potential (P4). 122 .1EX3A OIL PRODUCTION FORECAST - BASIC ASSUMPTIONS (a) Future oil production from Myanmar fields for Case has been evaluated based on the following assumptions. Oil production from the major oil flelds would continue to decline at a rate similar to that experienced slnce 1985/86. Rehabilitation of pressure maintenance schemes, well completion and production surface facilities will not be carried out. AddLtional development of undeveloped proven reserves are not undertaken. (b) Future oil production profile for Case B assumes Zield rehabilitation development of undeveloped proven and probable reserves: Renewal and optimization of surface pumping equipments. Upgrading and optimizatlon of surface productlon facilities and flowline network. Drilling of 24 key wells for data gathering in the developed sands. These key wells would also be part of the projected delineation program of probable reserves. Extensive workover programs to repair well completions, to shut-off water producing zones and prevent sand production. Optimization of the present pressure maintenance schemes. Drilling of approximately 60 wells to delineate the undevelopment proven and probable reserves. These delineation wells would then be completed as producets or injectors whenever possible. Drilling of some 190 wells to bring the above mentioned reserves on full production and maintain an oil production plateau of 5.5 mmb/yr for about 7 years. Installation of the associated well equipment and surface facilities for oil, gas and water treatment for production as well as pressure maintenance. (c) Future oil production profile for Case C assumes successful exploration, dellneatlon and development of oil reserves in the possible category. ANE 3.2 Ws OIL PRODUCTION FROM PROVED. PROBABLE D POSSIBLE RESERVES MILIONS OF BARRELS PER YEAR End Proved Reserv Prob_ble .inbb ranuve Year Rescrues Ouput re h_ km Widxmt With fr added ExIA. Ad .________ Rdhab. Rehb. Dcv driil. duigiag TOTALS Supply 1991 4892 - 4.892 1992 4.244 4.2" 1993 3.734 2.400 6134 2.40 1994 2.940 3.900 0.500 0.900 8.140 5.20 1995 2.359 4.700 2.900 2.000 11.959 9.60 1996 1.921 4300 5.500 4.600 16.321 14.40 1997 1.5U 3.900 5.5m 6S00 17.4U8 15.90 1998 1.300 3.500 5.500 6.500 16.800 15.50 1999 1.104 3.050 5.500 6.500 16.154 15.05 2000 0.944 2.650 5.500 6.500 15MM94 14.65 r; 2001 0.807 2.350 5.500 6.500 15.157 14.35 2002 0.690 2.100 5.5m 6.500 14.790 14.10 2003 0.590 1.850 4.800 6.500 13.740 13.15 2004 0.500 1.600 4.300 6.5X0 12.9oo 12.40 2005 0.430 1.350 3.800 6.500 1O2.06 11.65 V Barars at 12% 61.23 56.78 MBlionm Nv Bare at 10% 84.73 66.25 Milious ANNEX 3.2 (b) INVESTMEN t COSTS FOR OIL PRODUCTION FROM PROVED. PROBABLE AND POSSIBLE RESERVE (Million dollars) Proved & Developed Undeveloped Possible Reserves Proved & Probable Reserves Ouput Increment Invest in without with added Other Rehab. Rehab. Drill Capital Drill Capital TOTALS 1991 0 1992 10 3 6 19 1993 43 23 25 18 19 128 1994 43 53 70 46 38 250 4. 1995 is 83 55 45 32 233 1996 5 55 35 45 36 176 1997 20 10 20 21 71 1998 20 10 20 16 66 1999 20 10 20 10 60 2000 20 10 10 20 60 2001 20 10 10 20 60 2002 20 10 10 20 60 2003 10 20 30 2004 10 20 30 2005 10 20 30 SUM 1273 PV SMill at 12% 637.38 PV $Mill at 10% 706.37 Investment costs per Incremental barrel (PV basis) 0 12% 11.23 US$/B Investment costs per Incremental barrel (PV basis) 0 10% 10.66 US$SB ANNEX 3.3 ONSHORE NATURAL GAS PRODUCTION. AND ESTIMATED GAS SUPPLY COSTS TABLE 1 of 1 MYANMAR - ALL REGIONS ESTIMATED PRODUCTION CAPITAL INVESTMENT (Mill US$) IN End Year (bcf/Yr) Proven Unproven Prob & Poss Prob & Reserves Reserves Poss Surface Total Operating _ Proven Prob. Poss. Total Wells Facil Invest Costs 1991 33.3 0.0 0.0 33.3 1992 26.4 1.5 0.0 27.9 18.0 22.0 2.0 24.0 0.7 1993 21.3 2.2 0.0 23.5 21.0 29.0 2.0 31.0 1.5 1994 17.2 3.5 3.0 23.7 14.0 29.0 4.0 33.0 2.6 1995 14.1 5.0 5.0 24.1 10.0 23.0 4.0 27.0 3.4 1996 10.4 4.5 6.5 21.4 8.0 12.0 4.0 16.0 4.4 1997 7.1 4.5 9.0 20.6 12.0 2.0 14.0 4.7 1998 5.1 4.2 9.0 18.3 6.0 2.0 8.0 4.7 1999 3.1 4.0 9.0 16.1 6.0 6.0 4.7 2000 1.7 3.8 9.0 14.5 6.0 6.0 4.7 s 2001 0.0 3.3 9.0 12.3 6.0 6.0 4.7 2002 0.0 2.8 8.1 10.9 0.0 4.2 2003 0.0 2.4 7.2 9.6 0.0 3.8 2004 0.0 1.7 6.3 8.0 0.0 3.4 2005 0.0 1.0 5.2 6.2 0.0 3.1 PV SUMS 97.1 19.2 30.4 146.8 47.9 89.4 11.6 101.0 19.2 Assumed Interest Rate 12.00% Supply Cost at the Field for new gas; PV basis at 12.00% 2.42 USS/MCF Avge. Supply Cost for all gas @ field; PV basis at 12.00% 1.40 US$SMCF * thtis includes 38.7c/MCF for operating costs of old gas which is the same as estimated for new gas, and ignLores all sunk costs associated with eristing reserves. 126 - Oooooo oooooeoooe oO ot "ca N 033>-- ---------- o 4w @ RR R SR °R R RR RR O O @~~ 14 U Iii _o ~~iiF # "^*eso"oo_N^t-¢>"ffi°>S;aN0 ANNEX 3.4 (b) DEVELOPMENT OF MARTABAN OFFSHORE GAS FIELD LNG PRODUCTION INVESTMENTS in million of USS (1990) Year Process Liqifact Opeate TOTAL and Field Pipeline LNG insure Continge Costs Production Cash Flow Complex Terminl Develop Tankers 92.5c/mcf MMCF/D BCF/YR Cods 1 50 15 20 13 0 0 98 2 100 30 55 28 0 0 213 3 300 115 80 74 0 0 569 4 300 51 53 60 20 60 22 484 5 200 275 70 25 75 27 570 6 150 275 65 81 240 88 571 7 135 400 146 135 8 135 400 146 135 9 135 400 146 135 10 135 400 146 135 11 135 400 146 135 12 135 400 146 135 13 135 400 146 135 14 135 400 146 135 15 135 400 146 135 16 135 400 146 135 17 135 400 146 135 18 135 400 146 135 19 135 400 146 135 20 135 400 146 135 21 122 360 131 122 22 109 324 118 109 23 98 292 106 98 24 89 262 96 89 25 80 236 86 80 TOTALS TCF/$Mill 2.7 4894 PV OF PRODUCTION AND COSTS BCFJSMill 605 2075 AVERAGE COST OF GAS ON PV BASIS AT 12% in US$/MCF 3.43 ANNEX 3.4 (c) DEVELOPMENT OF MARTABAN OFFSHORE GAS FIELD GAS EXPORT TO THAILAND INVESTMENTS in million of USS (1990) Year Process Operate TOTAL Field Pipeline Compress Insure Continge Costs Production Cash Flow _Comwlex Develop 25clmcf MMCF/D BCFIYR Cots 1 15 70 15 0 0 100 2 30 200 35 0 0 265 3 115 300 60 0 0 475 4 51 120 25 10 115 42 206 5 20 220 80 20 6 37 400 146 37 7 37 400 146 37 8 37 400 146 37 9 37 400 146 37 co 10 37 400 146 37 11 37 400 146 37 12 37 400 146 37 13 37 400 146 37 14 37 400 146 37 15 37 400 146 37 16 37 400 146 37 17 37 400 146 37 17 37 400 146 37 19 37 400 146 37 20 37 400 146 37 21 33 360 131 33 22 30 324 118 30 23 27 292 106 27 24 24 262 96 24 25 22 236 86 22 TOTALS TCF/$MiW 2.9 1749 PV OF PRODUCTION AND COSTS BCF/SMill 678 933 AVERAGE COST OF GAS ON PV BASIS AT 12% in US$/MCF 1.38 129 Figure 4.1 OIL AND GAS FIELDS %IrMomndolay Pakokku W ydow %; K|n \\ V Chcuk Tetmc \ (% ~Yenonaygung MG WbnnMagwo Htoukshobfn ) Kanni _ \< 4%=~~TW i Htcntabin >t\*' ............fl. Of H tlmontun.2 Pom Bengal heytaii) Sittong 'X N Pgu.. I asXe GON Pao-on Of 3 M 130 FIgure 3.2 0l prvduct1c. v.s. N- of w2 i6. 'mom 2 __ _ _ _ _ __ _ _ _ _ _ 198 1985 1990 150 s 1980 1985 1990 Total carmt gas praumtlmi: 32.6 cfdl plint CTurrent d for gas: 38.5 f 4 _ffT pIj 11.1 cfd N d _w dm 16.0 _icfd Psam 420 pslg W"mtU"g vrtilixer Carrmt ewly: 4.5 ImI () inay h qu/ d : 4.5 =fd Carrm .Wpy: 1.17 ncfd ftewe: 380 psI Dewd : 1.5 Fefi r ~~ *Ue 1 V+2.5 alle, 6P+16 dfle. Wcnm r&tm 13.6 mm L~~~~~~~~~~~~~~~~~irtptzctIi: 13.6 icfd C_1 to Ay4:r 7 _:fd at 600 pdg I cWpessau unit: 2.7 cfd ctm vefCis: 19.0 _f * Cmt dma Is l utted to 11.1 m_fd - AS d~ to ..ete yol_in It_J m uaply: IS.7 _cfd trn. d_md: 16.5 mcfd Note: diltlil ca sije I. muROtly rerPIra at prel re: 250 psi Ab1w im to 3a v be" IIeIm H2bu gas turbime Peppi: 4.5 macfd Current suply: 11.0 macd [N] i capecity: 12.0 m_cf u¢ Utmkinbabl: 3 macd MOGR dmand: 0.5 _cfd Hum: 3 mcfdt 3.5S=JI I BP UnitHG! dravxd: 1.0 mcfd 0- _ Rlatel capaclty: 2.8 afdci To= Edinaxy Culrrent dlom: 2.S_f MA LPG plat _arret opratl: (13.7-11.3-2.4 _mcfd) JmLm c1 acity: (23.0-18.0-5.0 macfd) Kmi: 7.5 acfd Current gas proluctim: 18.0 mcEd Itimted aurreat dima: 21.0 macd ( yan)mn gas turbine Carreat supply: 4.6 _cfd Carret dmd: 9.0 _cfd 11.2 rm 1_n cawdity: 12.5 _:fd gyPE : 400 podg 10 ale", 8" 8.7 siles, lo' w Sektbha metbnol plant muepjitha: Œ.15) curruat sopply: 5.3 _cfd 1S mcfdL_. Currnt diul: 11.4 mcfd 3.8 mcfd' I PLet in wrkiag at 3.8 acfd I 4 to 6 imtbs a yeaw 1.5 _cfd IP _Q X ep fJy'uIgn cmet pleat f.5 ~ mea LP c tsuply: 1.7 _mcfd Dema : 7.0 mcfd 0.4 Fe 11 ICurrent ga prcauctiw: 17.0 wKfd Ibtimted acrrent ddmu: 30 mcfd T Tl cu t gas prduti : 135 _cfdb| 8 | Ib~~~~ltiStedl arrt deo_d: SS _:fad Curreit din..: 11.5 _fd 8 Ixaf cq lty: 16.0 tcfd Minim prm e: 250 psig 145 u11, 10" 21 miles 1 _un Fertilizer Pint 55 all"* 10 czrmt ip Nil 4ll |- V DnauI : 12.0 cfd LIne nod to be upsrled due to ccrrosim Fen cawacity: 12.0 _:fd Ci~einsim Cow (2) MInIi1 press: 610 psig 1 Unit S/D lwck of spres Pl._t has beu slbut-dGm 3 Units, G0 eff. (3.6 Ecfd) Cq prflUiU Cmp (1) fr pst 5 mattu due 4 Udts, 40Z eff. (3.2 -cfd) 2 Umlts to abot fall of gas Rted Cwcity: 16.0 mcfd Current capacity: 4.0 mfd Garret Cqmcity 6.8 Fid 135 Figure 3.4 DEVELOPMENT OF MARTABAN GAS FIELD (A. Domestic Option, B. LNG Export, C. Gas Export to Thailand) of e Mynou ae g° oShl '9..4h A /? tX ~~~~~Pegu. 4 e' V [ / H A )GOgf k ePoon| _of C Martaban field 136 ANNEX 4.1 MPE PLANT MAIN CHARACTERISTICS Plant Capacity Unit Year of Process Personnel Completion Design REFINERIES Thanlyin 2,300 Topping 1 5,700 bbpd 1,957 Foster W. Topping 2 14,300 bbpd 1,963 Foster W. Topping 3 6,000 bbpd 1,980 MHI Vacuu n 1 1,700 bbpd 1,957 Foster W. Coker 5,200 bbpd 1,986 UOP Polimerizat. 500 bbpd 1,986 UOP SBP 1,400 bbpd LPG Merox UOP Lube Blending 14,000 Ton/year Candle Fact. 5 Ton/day Chauk 830 Topping 6,300 bbpd 1,953 Vacuum Wax plant 1,500 Ton/month Mann 1,470 Topping 25,000 bbpd 1,982 Reformer 2,800 bbpd 1,982 UOP Coker 5,200 bbpd 1,982 UOP HDS 3,800 bbpd 1,982 UOP LPG Merox Napht.Merox Fertilizers Sale A 205 MT/day 1,970 Stamicarbon (A+B) 770 Sale B 260 MT/day 1,984 Stamicarbon Kyunchaun 207 MT/day 1,972 Stamicarbon 600 Kyawzwa 600 MT/day 1,985 UHDE 830 Methanol 550 Seiklw 450 MT/day 1,986 Lurgi LPG 350 _Minbu 24 MMscf/day 1,987 ___ SOURCE MPE ANEX 4.2 PRODUCTIONIDISTRIBUTION STATISTICS - ALL REFINERIES AND LPG EXTRACTION PLANT 1986-87 1987-88 1988-89 1989-90 ITEM UNIT Producfion Distribution Production Distribution Production Distnbution Prodution Distnlbion Crde Oil BBL 5,970,629 5,979,000 5,111,755 5,113,547 4,737,318 4,470,502 4,809,720 4,777,929 PRODUCT ____ Propane BBL 25,942 25,200 72,907 52,374 45,739 37,302 31,009 21,255 Butane BBL 20,692 9,808 81,778 46,629 60,096 40,839 42,653 55,879 Total LPG BBL 46,633 35,008 154,685 99,002 105,836 78,140 73,662 77,134 Gasoline BBL 1,888,722 1,887,427 1,514,800 1,485,804 1,154,404 1,063,974 1,165,374 1,187,102 Kerosene BBL 14,114 18,400 504 574 51,878 29,841 34,246 49,566 Diesel Oil BBL 2,301,857 2,302,743 2,127,431 2,112,190 1,962,751 1,971,215 2,405,003 2,396,885 , Fuel Oil BBL 1,089,623 1,121,566 915,111 917,824 513,261 540,199 483,947 531,417 . Jet Fuel BBL 148,457 163,057 173,673 173,809 141,597 113,757 154,190 154,013 Spec. Boil. Point BBL 27,057 25,143 16,372 17,833 11,973 11,982 15,295 15,045 TOTAL BBL 5,516,464 5,553,344 4,902,576 4,807,037 3,941,700 3,809,108 4,331,718 4,411,163 Petrolum Coke MT 44,977 40,820 38,003 37,699 30,060 25,266 32,025 41,459 Paraffin Wax MT 3,203 2,518 2,350 2,382 555 1,001 2,511 2,626 Lubricans BBL 80,543 80,429 65,310 65,389 53,542 53,605 54,001 S4,001 SOURCE: MPE 138 ANNEX 4.3 PRODUCT EXPORTS (Kyast in Thousnds) |PRODUCT UNIT 1986-87 1987-88 1988-89 1989-90 UREA MT 90326 121245 60061 51000 KS 47888 65378 44490 32146 KS/MT 0.53 0.54 0.74 0.63 -_____________ % ofProducdon 30 38 28 27 PETROLEUM COKE MT 36496 31504 29522 32700 KS 12342 9761 11387 141S9 KS/MT 0.34 0.31 0.39 0.43 % of Produoton 81 83 98 102 METHANOL MT 9111 25235 6900 KS 5064 22571 3613 KS/MT 0.56 0.89 0.52 %of Production 23 So 16 LPFY MT 2585 664 KS 778 400 KS/MT_ 0.30 0.60 PARAFFIN WAX MT 902 1334 955 KS 2120 4027 3912 KS/MTr 2.35 3.02 4.10 % of Production 28 57 _ 38 |TOTAL KS 62350 85008 78448 54230 l l 1000 US$S 9306 12688 I 11709 I 8094 NOTES: Lust consignmnt price (FOB) Urea - US$121.50/MT Methanol - USS 77.00/MT Q3URCE: MPE MYANMIR ENERGY STRATEGY f4: BASE CASE, high econo ic growth PETROLEUM PRODUCT DEMAND ALL OIL PRODUCTS H4: BASE CASE, high economic growth ALL OIL PRODUCTS NOTE: SCENARIO 4, HIGH ECONOMIC GROUTH OF 5.5%; PLENTIFUL OFFSHORE GAS SUPPLY; OIL REHABILITATION IS UNDERTAKEN, GIVING ADEQUATE DOMESTIC CRUDE BY 1996, ASSUMING REVISED PRODUCT PRICES. METHANOL PRODUCTION/CONSUMPTION INCREASES WITH TOTAL GDP AFTER 1996. ACCELERATION OF KEROSENE DEMAND AND LESS FUEL OIL DEMAND GDP Long-Run GDP Growth Rates elast Price j....... .......... Elast 1989-91 1992-96 1997-2011 Link to 1991-96 97-2011 Agriculture 2.3X 4.3X 6.0X KEROSENE 1.10 3.00 0.6 Mining 4.6% 8.2% 8.5% Industry 7.0% 7.3% 8.5% D/AVG/O 1.00 1.20 0.6 Services 3.8% 4.9% 6.5% Total GDP 3.3% 5.0% 6.5% PETROL 1.10 1.40 0.7 FUEL OIL 0.80 0.60 0.6 METHANOL 0.00 1.00 0.6 ...................................................................................... Population Growth Urban 3.0% 3.0% 3.0% Rural 1.6% 1.6% 1.6% Total 1.9% 1.9% 1.9% FISCAL PETROLEUM PRODUCT DEMAND, in Mill gallons DEMAND YEAR ................................................................................. GROWTH FUEL Nethan/ AV OTHER TOTAL DIESEL PETROL OIL Kerosene Petrol FUELS MN Gall KM B/Yr %/Yr 1989/90 83.8 38.1 24.6 2.2 11.9 4.6 0.5 165.7 4.7 1990/91 89.7 39.5 25.2 2.3 11.9 5.0 0.5 174.1 5.0 5.0% 1991/92 96.2 41.7 26.3 2.4 11.9 5.3 0.6 184.3 5.3 5.9% 1992/93 103.2 43.9 27.3 2.5 11.9 5.7 0.6 195.2 5.6 5.9% 1993/94 110.8 46.4 28.4 2.6 11.9 6.1 0.7 206.8 5.9 6.0% 1994/95 118.9 48.9 29.5 2.7 11.9 6.6 0.7 219.2 6.3 6.0% 1995/96 127.5 51.6 30.7 2.8 11.9 7.1 0.8 232.4 6.6 6.0% 1996/97 140.5 56.3 31.9 3.4 12.7 7.8 0.8 253.4 7.2 9.0% 1997/98 154.9 61.4 33.2 4.0 13.5 8.6 0.9 276.4 7.9 9.1% 1998/99 170.7 67.0 34.5 4.7 14.4 9.5 1.0 301.6 8.6 9.1% 1999/00 188.1 73.1 35.8 5.5 15.3 10.4 1.1 329.3 9.4 9.2% 2000/01 207.3 79.8 37.2 6.5 16.3 11.5 1.1 359.7 10.3 9.2% 2001/02 228.4 87.0 38.6 7.7 17.4 12.7 1.2 393.0 11.2 9.3% 2002/03 251.7 94.9 40.2 9.1 18.5 13.9 1.3 429.6 12.3 9.3% 2003/04 277.4 103.6 41.7 10.7 19.7 15.4 1.5 469.9 13.4 9.4% 2004/05 305.7 113.0 43.3 12.6 21.0 16.9 1.6 514.1 14.7 9.4% 2005/06 336.9 123.3 45.0 14.9 22.3 18.7 1.7 562.8 16.1 9.5% 2006/07 371.2 134.5 46.8 17.6 23.8 20.6 1.9 616.3 17.6 9.5Z 2007/08 409.1 146.7 48.6 20.7 25.3 22.7 2.0 675.2 19.3 9.6% 2008/09 450.8 160.1 50.5 24.4 27.0 25.0 2.2 740.0 21.2 9.6% 2009/10 496.8 174.7 52.5 28.8 28.7 27.5 2.4 811.4 23.2 9.6% 2010/11 547.5 190.6 54.5 34.0 30.6 30.3 2.6 890.1 25.5 9.7% Avge PM 9.3% 8.0% 3.9% 13.9% 4.6% 9.3% 8.1% 8.3% H4: BASE CASE, high e*canmic growth ALL OIL PRODUCTS FISCAL TOTAL OIL PRODUCTS YEAR CONSUJPTION PER 4> CAPITA PROPORTION OF SALES ....... ................. ................................................................ POP GALL/YR/ FUEL Methan AV OTHER miLl PERSON DIESEL PETROL OIL Kero Petrot FUELS TOTAL 1989/9 40.12 4.13 50.62 23.0X 14.82 1.3X 7.22 2.82 0.32 100.02 1990/91 40.90 4.26 51.52 22.7X 14.52 1.32 6.82 2.92 0.3X 100.02 1991/92 41.70 4.42 52.22 22.6X 14.22 1.32 6.52 2.9X 0.32 100.02 1992/93 42.51 4.59 52.92 22.5X 14.02 1.32 6.12 2.92 0.3X 100.02 1993/94 43.33 4.77 53.62 22.42 13.72 1.32 5.82 3.02 0.32 100.0X 1994/95 44.18 4.96 54.22 22.32 13.5 1.22 5.42 3.02 0.32 100.02 1995/96 45.04 5.16 54.9X 22.22 13.22 1.22 5.12 3.02 0.32 100.02 1996/97 45.91 5.52 55.52 22.22 12.62 1.32 5.0% 3.12 0.32 100.02 1997/98 46.81 5.91 56.0X 22.2X 12.0X 1.4X 4.9X 3.12 0.32 100.02 1998/99 47.72 6.32 56.6X 22.2X 11.4X 1.5X 4.8X 3.11 0.31 100.02 1999/00 48.64 6.77 57.12 22.2X 10.9X 1.7X 4.62 3.2X 0.32 100.02 2000/01 49.59 7.25 57.62 22.22 10.32 1.82 4.52 3.22 0.32 100.02 2001/02 50.56 7.77 58.12 22.12 9.8X 2.0X 4.42 3.22 0.3X 100.02 2002/03 51.54 8.34 58.62 22.1X 9.3X 2.1X 4.31 3.22 0.31 100.0X 2003/04 52.54 8.94 59.02 22.0% 8.92 2.32 4.22 3.32 0.32 100.02 2004/05 53.56 9.60 59.52 22.0% 8.42 2.5% 4.1% 3.3% 0.32 100.0X 2005/06 54.60 10.31 59.9X 21.92 8.02 2.62 4.02 3.32 0.32 100.02 2006/07 55.67 11.07 60.22 21.8% 7.62 2.82 3.9X 3.3% 0.32 100.0% 2007/08 56.75 11.90 60.62 21.72 7.22 3.12 3.82 3.42 0.32 100.02 2008/09 57.85 12.79 60.92 21.62 6.82 3.32 3.62 3.42 0.32 100.02 2009/10 58.98 13.76 61.22 21.5% 6.5X 3.62 3.5% 3.42 0.3X 100.02 2010/11 60.13 14.80 61.52 21.4% 6.12 3.82 3.42 3.42 0.32 100.0X NYAWNAR ENIERGY STRATEGY L2: LOW CASE, low ecoomc growth PETROLEUI PRODUCT DEMAND ALL OIL PRODUCTS L2: LOU CASE, low economic growth ALL OIL PRODUCTS NOTE: SCENARIO 1, LOW ECONOMIC GROWTH OF 3X/ YR; CONTINUED SHORTAGES OF GAS SUPPLY OIL REHADILITATtON IS UtDERTAKEN, GIVING ADEQUATE DOMESTIC CRUDE BY 1996. ASSUMING REVISED PRODUCT PRICES. METHANOL PRODUCTION/CONSUMPTION REMAINS CONSTAMT AFTER 1996. ACCELERATION OF KEROSENE DEMAND AFTER 1996 GDP Long-Run GDP Growth Rates elast Price ............ Elast 1989-91 1992-95 1997-2011 Link to t99t-96 97-2011 Agriculture 1.62 2.5X 2.5X KEROSENE 1.10 4.00 0.6 Mining 3.32 4.52 4.5% Industry 4.02 5.12 5.1X D/AVGJO 1.00 1.30 0.6 Services 2.12 3.02 3.02 Total GDP 2.0X 3.02 3.0X PETROL 1.10 1.50 0.7 FUEL OIL 0.80 1.00 0.6 METHANOL 0.00 0.00 0.6 Population Growth Urban 3.0% 3.02 3.0% Rural 1.6% 1.6X 1.6% Total 1.9% 1.92 1.9% FISCAL PETROLEUM PRODUCT DEMAND, in MilL gallons DEIAND YEAR ................................................................................. GROWTH FUEL Mlethan/ AV OTHER TOTAL DIESEL PETROL OIL Kerosene Petrol FUELS Gall MM B/Yr 2/Yr ........ ....... ........ ..................................................... 1989/90 83.8 38.1 24.6 2.2 11.9 4.6 0.5 165.7 4.7 1990/91 87.2 . 38.9 25.0 2.2 11.9 4.8 0.5 170.6 4.9 2.92 1991/92 91.6 40.2 25.6 2.3 11.9 5.1 0.5 177.2 5.1 3.92 1992/93 96.3 41.6 26.2 2.4 11.9 5.3 0.6 184.2 5.3 3.92 1993/94 101.2 42.9 26.8 2.4 11.9 5.6 0.6 191.5 5.5 4.02 1994/95 106.3 44.3 27.5 2.5 11.9 5.9 0.6 199.1 5.7 4.0% 1995/96 111.8 45.8 28.1 2.6 11.9 6.2 0.7 207.0 5.9 4.02 1996/97 119.2 47.9 29.0 2.8 11.9 6.6 0.7 218.0 6.2 5.32 1997/98 127.1 50.0 29.9 3.1 11.9 7.0 0.7 229.7 6.6 5.42 1998/99 135.5 52.3 30.7 3.4 11.9 7.5 0.8 242.1 6.9 5.42 1999100 144.5 5k.6 31.7 3.8 11.9 5.0 0.8 255.2 7.3 5.42 2000/01 154.1 57.1 32.6 4.1 11.9 8.5 0.9 269.2 7.7 5.52 2001/02 164.3 59.6 33.6 4.5 11.9 9.1 0.9 284.0 8.1 5.52 2002/03 175.2 62.3 34.6 5.0 11.9 9.7 0.9 299.6 8.6 5.52 2003/04 186.8 65.1 35.6 5.5 11.9 10.3 1.0 316.3 9.0 5.62 2004/05 199.2 6t3.1 36.7 6.0 11.9 11.0 1.0 334.0 9.5 5.62 2005/06 212.4 71.1 37.8 6.7 11.9 11.8 1.1 352.7 10.1 5.62 2006/07 226.4 74.3 39.0 7.3 11.9 12.5 1.2 372.6 10.7 5.62 2007/08 241.5 7. 7 40.1 8.0 11.9 13.4 1.2 393.8 11.3 5.7X 2008/09 257.5 81.2 41.3 8.9 11.9 14.3 1.3 416.2 11.9 5.72 2009/10 274.5 84.8 42.6 9.7 11.9 15.2 1.3 440.1 12.6 5.7X 2010/11 292.7 88.6 43.8 10.7 11.9 16.2 1.4 465.5 13.3 5.82 MG to 2000 5.62 3.72 2.62 5.52 0.02 5.62 5.02 4.42 2005 5.9X 3.9X 2.72 7.02 0.02 5.9X 5.02 4.82 2010 6.12 4.12 2.82 7.72 0.0 6.12 5.02 5.02 L2: LOW CASE, Low ecomic growth ALL OIL PROCWCTS FISCAL TOTAL OIL PRODUCTS YEAR CONStMPTION PER t CAPITA PROPORTION OF SALES ....... ................. ................................................................ POP GALL/YR/ FUEL Nethan AV OTHER mill PERSON DIESEL PETROL OIL Kero PetroL FUELS TOTAL 1989/9 40.12 4.13 50.6X 23.0X 14.8X 1.32 7.2X 2.8X 0.31 100.0X 1990/91 40.90 4.17 51.1X 22.81 14.7X 1.3X 7.02 2.81 0.3X 100.02 1991/92 41.70 4.25 51.7% 22.72 14.42 1.3X 6.72 2.9X 0.32 100.02 1992/93 42.51 4.33 52.32 22.62 14.22 1.3X 6.52 2.9X 0.3X 100.02 1993/94 43.33 4.42 52.82 22.42 14.02 1.3X 6.2% 2.9X 0.32 100.02 1994/95 44.18 4.51 53.42 22.32 13.82 1.32 6.02 3.02 0.32 100.02 1995/96 45.04 4.60 54.0% 22.12 13.62 1.22 5.72 3.02 0.32 100.02 1996/97 45.91 4.75 54.7X 22.02 13.32 1.31 5.52 3.0X 0.3X 100.0X 1997/98 46.81 4.91 55.32 21.82 13.02 1.42 5.22 3.12 0.32 100.02 1998/99 47.72 5.07 56.02 21.61 12.72 1.42 4.92 3.12 0.32 100.02 1999/00 48.64 5.25 56.62 21.4% 12.42 1.52 4.72 3.12 0.32 100.02 2000/01 49.59 5.43 57.22 21.22 12.12 1.52 4.42 3.22 0.32 100.02 2001/02 50.56 5.62 57.91 21.02 11.81 1.62 4.22 3.22 0.32 100.02 2002/03 51.54 5.81 58.52 20.81 11.52 1.72 4.02 3.22 0.32 100.02 2003/04 52.54 6.02 59.12 20.62 11.32 1.72 3.82 3.32 0.32 100.02 2004/05 53.56 6.23 59.62 20.42 11.02 1.81 3.62 3.32 0.32 100.02 2005/06 54.60 6.46 60.22 20.22 10.72 1.91 3.42 3.32 0.32 100.02 2006/07 55.67 6.69 60.81 19.91 10.51 2.02 3.22 3.42 0.32 100.02 2007/08 56.75 6.94 61.31 19.72 10.22 2.01 3.02 3.42 0.32 100.02 2008/09 57.85 7.19 61.92 19.52 9.9X 2.12 2.92 3.41 0.32 100.02 2009/10 58.98 7.46 62.42 19.32 9.72 2.22 2.72 3.52 0.32 100.02 2010/11 60.13 7.74 62.92 19.01 9.42 2.32 2.62 3.52 0.31 100.02 143 ANNEX 4.4(e) HIGH DEMAND FORECAST ASSUMPTIONS The High Case has 1984/85 as base year considering that it is the last year before oil production started to decline. Total annual consumption was increased by 5% to take partially into account the kerosene suppressed demand. An average growth rate of 2% was used for the years 1984/85 to 1993/94, 3% for the next five years and 4% assumed from then on. Scenario B has 1989/90 as base year .nd demand growth rate start at 2.9%, gradually increasing up to 5.7% in 2009/10. Assumptions for High Case The following assumptions have been made to develop Scenario A: - Domestic oil production will increase to a level of approximately 10 NMBBL per year by 1996. - Demand will depend on what market can bear at a given retail price. - Kerosene production is no longer restricted. - Methanol mix (M80) is considered as part of the gasoline market since its consumption is easily reversible. - Methanol is preferably exported, being used as fuel only when gasoline is scarce. - Short term fuel needs for power generation has not been considered. They will have to be supplied with the present refining capacity or by imports. Natural gas production will return to historical levels before any refining investment plans have been executed. - LPG production will depend on refinery operating mode. All LPG will be used in the domestic market. - Wax will continue to be produced at Chauk refinery at today's rates. - Coke production will have no limitations other than refining optimization. All production is to be exported. - All other specialty products are included in the product with the closest related fuel values. ANNEX 4.4(fl PETROLEUM PRODUCTS DEMAND FOREiCAST Hlrh Case for Refinery Analysis GA_ WLI - -OEE DIISEL FUEL 0. TOTAL DEMAND GROWIH DEUAND OROWTH DEMAND OROWYR DEMAND OROWrH DEMAND I OROWIH YEAR mLS MBBLS % MINKS X MILS MBX M %L 194-83 7.011 2.0 1993- 2,514 2.0 838 4.0 4.357 3.5 670 1.0 8,379 3.0 1994-95 2,564 2.0 872 4.0 4,S09 3.5 677 1.0 S.622 3.0 1995-96 2.616 2.0 906 4.0 4,667 3.5 683 1.0 *.873 3.0 1996-97 2,668 3.0 943 4.5 4,831 S.C 690 1.0 9,131 4.0 1997-9 2,748 3.0 985 4.5 5,072 5.0 697 1.0 9,502 4.0 199899 2,S30 3.0 I.029 4.5 5,326 S.0 704 1.3 9,890 4.0 1999-0 2,915 3.0 1,076 4.5 5,S92 5.0 711 1.0 10.294 4.0 2000W01 3,003 3.0 1,124 4.5 S,872 5.0 718 1.0 10,717 4.0 201-02 3,093 3.0 1,175 4.5 6,165 5.0 726 1.0 11,158 4.0 2002-03 3.186 3.0 1,228 4.5 6,474 5.0 733 1.0 11,619 4.0 2003-04 3,281 3.0 1,283 4.5 6,797 5.0 740 1.0 12.101 4.0 2004-05 3,380 3.0 1,341 4.5 7,137 5.0 747 1.0 12,05 4.0 200-6 3.481 3.0 1,401 4.S 7,494 5.0 75S 1.0 13,131 4.0 2006-07 3,585 3.0 1,464 4.5 7,869 5.0 763 1.0 13,68D 4.0 207-08 3,693 3.0 I.530 4.5 8,262 5.0 770 1.0 14,255 4.0 200O-09 3,804 3.0 1I _'9 4.5 8.675 5.0 778 1.0 14,855 4.0 2009-10 3.9158 1,671, 9,109 786 15,4t3 FIG 1 PETROLEUM PRODUCTS DISTRIBUTION THOUSAND OF BARRELS 30k 0 ------ 2600 2000 0 t97 78 -71 To-go 80-St 61-32 52-43 13-84 84-86 86-05 30-57 5y-88 35-01 58- b0 - GASOLINE +iKIESOOENIE -J9T FUEL -8 DaIIEEL --FUEL. OIL METHANOL MI FIG 2. CRUDE OIL REFINING MILLION OF BARRELS 101 8 6 4 2- 0 1980-81 81-82 82-83 83-84 84-86 86-86 86-87 87-88 88-89 89-90 147 ANNEX 5.1 I! Summary of Industrial Electricity Conumwtoa Major Indway Regiw Supply 1987/18 19U8/89 1988/89 No Supply % Suply Costat duo to fuel shalg kV MWh MWh MWh Constraint Tot ith associated MEPE Gerting Staion Cemen Factory Kyanln Ayeyarwad 66 35129 29357 35846 35000 Oa - Shwedg/Myanusag OS Jute Mill Myangmys Ayeyarwad 66 5445 4399 4764 S500 Glan Mi Padhin Ayeyarwad 66 3711 2303 1859 4000 Mthonol Plant Kyangit Ayeyawead 66 2787 3565 3902 4000 as - Shwedaung/Myanuang GS Subtotal 47072 39624 46371 48000 4% Paper Mal Yi UVgo 132 11142 9851 11415 11000 Spning Weaving Shwedaung Bago 11 4899 3350 6675 6500 Papet Mil Sttung Bgo 33 1329 1021 6648 6500 Defeace Indury f3 Siade Bago 66 6838 5538 5796 6800 Maine Tool Plnt DikOo B ago 66 4742 2845 4889 S500 Heavy 1ndostl e4Htonbo Bago 66 4925 3119 3149 5000 Subtotal 33875 25724 38572 40800 3% Cemet Myalng 0.1 Pa- Karen 66 7T02 4969 11370 10000 1% Sale Fetlizer Plant Magwe 66 111288 65465 58487 160000 Ca - Chauk GS Kyawa Ferlzer Magwe 66 120727 103881 96912 150000 GsC - ShwedaunglMyanuwng OS Mnn Refiney Mini Magwe 33 14187 20115 19172 60000 Kyunchsung Fertilizer Magwc 66 49823 45603 48529 60000 Ou - Kyunchuang OS Munn Oi Field Mimbu Magwc 33 12925 11543 12135 20'300 LPG Factory Mlmbu Magwo 33 11456 11940 5318 15000 Ga- Mann GS Cement MI Thayet Magwo 66 11357 9488 13618 13000 Ga - Swedaung OS Malun HI No. 2 Defense Magwe 33 5855 6521 6000 6000 Hlauk Sha-Pin OD Field Mimbu Magwo 33 5182 3857 4412 6000 Ywalthy- Mimbu Magwe 33 2384 2424 1808 2500 Subtotal 345184 280837 266391 492500 42% TextDe MDt Palik Mandalay 33 8519 607S 32137 32000 Steel Milt Pyn-Oo-Lwin Mandalay 33 22191 14740 33076 35000 Textile MDI Mdiktila Mandalay 33 8314 6141 10313 10000 Subtotal 39024 26956 75526 77000 7% Tyre Feaory Thaon Mon 33 9907 7363 9154 12000 1% Disd - Thaton OS Copper Mine SadinvI Saiging 33 54505 31042 31890 60000 Ywalthkyil TextDe Sdagng 33 7517 4856 7214 7500 Subtotal 62022 35898 39104 67500 6% Dalk U Foodstuffs Yangon 132 5000 28032 Sted Ml Ywama Yangen 33 9704 9247 9859 10000 Yanon Wat Supply Yangon 33 10019 8729 8219 10000 le Ftory Thanidn Yanon 6.6 7935 6733 6675 8000 Juts hIm Yangon Yangon 33 5520 4332 5520 6000 Teatn Ml Thaliaing Yangon 33 3106 2207 2560 3500 Subtotkl 36284 31248 37833 65532 6% Smll Industry 11/6.6kV 177899 165072 178330 209000 18% Otwer Mdlum lnduries 11 145742 120290 107215 ISO00 13% Total 904311 737981 809866 1172332 100% ANNEX S.tI (b) TREND ANALYSIS OF GENERATION. SALES AND LOSSES 1980-2000 Arnual Generation in % of Tot'. Generation Annual ules in % of Total Sales Loss in % of Total Generaton Year HyJro Gas Steam Diesel Purchase Total Domes Indust Bulk Others Total Gen Trans Distr Others Total 1979/80 67% 24% 3% 4% 1% 100% 28% 53% 14% 4% 100% 3% 4% 21% 2% 29 1980/81 59% 31% 6% 4% 1% 100% 28% 54% 14% 4% 100% 3% 4% 21% 2% 30 198182 66% 25% 5% 3% 0% 100% 30% 53% 14% 4% 100% 3% 5% 22% 2% 32 1982/83 62% 29% 5% 3% 1% 100% 30% 53% 14% 4% 100% 3% 6% 22% 2% 32 1983184 59% 33% 4% 2% 1% 100% 30% 52% 14% 3% 100% 3% 5% 24% 2% 33 1984/85 54% 40% 3% 2% 1% 100% 30% 52% 15% 3% 100% 2% 5% 25% 1% 33 1985186 47% 47% 3% 2% 1% 100% 28% 60% 9% 3% 100% 2% 4% 24% 1% 31 19S6/87 46% 48% 4% 1% 1% 100% 28% 60% 9% 3% 100% 2% 4% 23% 2% 31 1987/88 44% 52% 3% 1% 0% 100% 30% 57% 10% 3% 100% 2% 6% 22% 2% 32 19U8/89 42% 55% 2% 1% 0% 100% 35% 52% 10% 3% 100% 2% 5% 27% 1% 36 1989/90 46% 52% 1% 1% 0% 100% 36% 50% 11% 3% 100% 2% 5% 27% 1% 36 1990(91 48% 49% 1% 1% 0% 100% 36% 50% 12% 3% 100% 2% 5% 21% 2% 30 149 ANNEX 5.2 ExistinS and Expected Rehabilitated Condition of MEPE Generadna Plant 1. dIneonne Svyem ENEP gode 5xdon Type/ . Rating Total Firm Copacity Year Fuel Units MW MW 1990 1992 US Stat of plat (after rehabilaon in 1992) LAWP LAwplta - Exising hyd pal 6 28 168 131 1960 Before rehabilitalon under OECF funding LAWN LawpitalBludacaungl hyd pal 6 28 196 1992 Restore fuaioutput(168MW)428MW in cascade KIND Kinds hyd fra 2 28 56 28 42 1986 Incresed gation llows raervofr filling SEDA Sedawgi hyd hap 2 12.5 25 8 20 1988 Has competing irrigation requIremts Tatkyd hyd 2 0.6 1.2 1 1987 Ablone atm fo 3 10 1950 Unlikely to be rehabitad Ahione gt g/fo 2 2.18 4.36 2 1985 Unable to oprate in parlel gt g/fo 2 1.1 2.2 YWIG Ywam atm fo 3 10 30 7 20 1957 Rehabilitation under IDA project YW2G Ywama 8t gS 2 18.45 36.9 37 1980 Gas Operation YW20 Ywamu gt gfr 2 18.45 37 1980 Gas/Fuel oil Opertion KYaT Kynckhdang gt g/fo 3 18.1 54.3 36.2 36 1974 Gad66 kV timniaions MYJB Myanung John Brown gt g/fo 1 18.45 18.45 18 1975 66 kV System Constraint MYGH Mysnaung Hitchi gt gas 3 16.4 49.2 36 36 1975 OECF sps rehabiitation Kyaldat gt g/fo 5 2.18 10.9 3.05 1983 Unable to Oprate in parai MANN Mann 8t gfr 2 18.45 36.9 34.5 35 1980 Chaulk gt g8fo 4 2.18 8.72 2.2 1982 Unable to Opernte inparallel SHWE Shwedaung 8t gfr 3 18.45 55.35 36 36 1982 THAK Thaka at gfr 3 19 57 19 57 1989 Change to diee in 1991 THAI Thaton aT gt gfr 1 17 17 17 1985 To be conncted to grid in 1992 THA2 Thston ST atm fo 3 6 18 18 1986 To be rehiabiitated/connected to grid in 1992 MOUL Moulmein ST atm fo 2 6 12 12 1980 To be rehabilitated/connected to grid in 1992 Subtotol Interconnectable Capacity MW 661.48 398.95 562 2. Isolated MEPE GenNratie Statons Sttea/Divirions No Av. Tot MD kW MW MW I Output of Kindc and Sedawgi is resricted by low Ayewardy 21 540 11 28 reservoir lewis due to low rainfall and competing Slin 30 427 13 8 irrigation. Yangon 6 203 1 149 Rachine 18 475 9 1 2 Output at Shwedaung, Myaung, Chauk, Kyunchaung Mon 13 499 6 10 Mann a Thaton is resietred by compiting fuel Madalay 6 610 4 54 needs of neauby indusry. See Annex 5.1 (a) Magwe 18 229 4 90 Bago 5 50S 3 75 3 The 66kV sytem consaints auociated with Kyunchsung Tanlaai 7 713 5 I and Myanaung need to be rectibed when the saio Sa4ging 27 234 6 25 are to be uprated to combined cycle opmation Chin 9 402 4 0 KArln 9 318 3 3 4 It is feaible to instll heat recovery equipment only Kaysh 4 196 1 I at Mann. Shwedaung. Mynaung ad Thakea KIchln 15 417 t 0 I8 402 76 445 5 The maximun demanda(MD) in eh State/Divison incudes the component wpplied by the intrconnet sysem. -4- - - -N- ---N- ~~~~ - -- - -- - el * i II S iuAI i i~~~~~~~~~~~~~P C Pb S Pb jf - _- - N_ - - - N - L NN|^ ^22N NNN2 R|RN N N N t~~~~ ~ ~ ~ I N N - N N g I I t}3} 3i3i1|3|4 iiI iiiI 151 ANNEX 5.3 thi SUMARY OP EXISTINO AND COMM IED TRANSMISSION SYSTEM SUBSTATION8 230/132kV Trammuaoi. Gidd Subhatoa CaacIty Subtrus Trafo Recorded MV/h loading* 194-199 SubstatioName Region No MVA Tot kV kV Loading 191415 1935/6 1916/7 19S7/S 19W9 I Hlawga 230kV YangeO 2 60 120 33/11 99% S46240 54820 59100 72A's 721350 2 TalgoD 230/132kV Bago 1 33 33 66 33 38% 17036 19203 S5S45 466J4 7049 3 Tlazi 2O/132kV uMnlay 1 60 60 13% 116070 117706 123337 117145 £5621 1 IS iS 66 33/11 1 30 30 132 35 4 Taw,gdwigyi 230/132kV Magwe I 30 OD 132 ! I S PyImn 230kV Mandalay 1 30 30 13 6 Swedamrg2S0kV B4O 1 100 100 66 11 7 Thaketa230kV O/S Yangon 2 100 200 66 33/11 13% tS7958 215107 I Lawpita 230/132kV O/S Kayah 2 100 200 9 ahauk 132kV Magwc 1 40 40 66 11 72% 191660 172842 149537 146048 176M 10 Mmn132kV 0/S Magw 1 50 50 33 11 Myanuig 66kV O/S Ayeyarwady 85 12 Kind 132kV 0/8 Shan 2 35 70 13 Sedawgyi 132kV O/S Mandalay ad 30 14 Mandalay 132kV Mandalay I I1 IS 33/11 67% 162762 172536 10175 116U0 195740 1 30 30 33 15 Magw 132kV Magw 1 15 IS 33/11 SS% 234%3 16 Kalaw 132kV Shan 2 15 30 33/11 20% 36391 17 Pylno 132kV M edaay 2 15 30 33/11 17% 4333 45423 50159 38174 30454 IS Nyauwilgyi 132kV Maay 1 40 40 33/11 22% 50925 79872 77596 75U20 54117 19 Daikoo 132kV Bagp I is is 33/11 20 Yi 132kV Bag0 2 15 30 33 19% 0 0 22435 34052 21 Kawlin 132kV sagain 1 15 is 33/6. Subtotal 230/132kV grid S/S cpcity 694 44% 1135281 1155U42 1208749 15679D7 16S491 Ywam 0/S to 33kV 168300 616300 190760 1275C0 132600 Subtotl 0/S Subation capcity 675 Subtotl Tra_ainaion Systn Loadig MW @ .7 Capaeity factor 213 216 228 276 326 Notes I The tables inelude deatailc of *1 main abatien tranafonne includin: Generati Station tanaormer capacity Tranm anin Systenm nterometion Transformsan d Sudttion Service capeaity mypying the Subtranilion Sysems 2 Transfonmer loading I ctimted from total nergy enat out _mally basd oo L=ad Factor - 0.7. Note that output Ywam is sipptied dirctly into he 33tV busbr. 3 See pog 2 of 2 for Subtam zaaon Systm Tranaomer capacity. 152 ANNEX 5.3 (bh (contd) SUMMARY OF EXISTING AND COMMITrED TRANSMISSION SYSTEM SUBSTATIONS 66V S ubtib iualon SubaUtioS Cpacity Subom Trafo Rwcrdcd MWh loadings 19t4-1989 Regio No MVA Tot kV kV Loading 19t415 19t5/6 190617 191718 191U9 I pyay(Pem) nago 2 10 20 11 41S 46201 499M2 49932 52073 49799 2 Tatayi33kV Shb 1 5 5 I 1 3 HIzads Aycyaswady I 5 5 11 46% 10372 11746 13225 14096 14190 4 YMey AycyaMwdy 1 3 3 11 61% 6941 W601 9396 10383 11140 5 BDhcia (atheio) Aycyarwady 1 10 10 11 33% 15302 17669 19154 20375 20460 6 Myaunya Aycya-ady I S S 11 23% 9921 12281 12565 12053 11072 7 Pako&ku Mag- 1 2.5 2.5 11 i Wai ma4.wc 1 12.6 12.6 6.6 9 Ht.abo Ayeyarwady I 5 5 6.6 37% 14440 14147 155I6 1356S 11363 10 Nyuagcehadauk Ayeyawaty 1 10 10 6.6 10% 6610 6745 8572 3790 6121 11 Side Ayeysmady I 10 10 6.6 12 Mbayet Cemc Magw 1 9 9 6.6 11 9 13 Pathei Glas AyCywady I 9 9 6.6 4 2 14 Sate Fetilizor Magwe 1 14 14 3.3 111 65 15 Kywgchauig FcL. Magwc 1 14 14 3.3 50 46 16 Pa-an Mon I ea S 17 Mayaugu U/C tango. 2 30 60 33 is lan4down U/C Yangon 2 30 60 33 19 AWone U/C Yngfon 2 30 60 33 20 Ywma 0/S YAnon 21 Tiuton O/S Mon I cat 20 22 Sbwcdaimg O/S Bago 3 25 75 23 Kytuchqat 0lS Manday 3 25 75 Ywm G/s Yagon 33 168W0 190780 127500 132600 Subtotal 66kV Subtma Capacity 152 109164 219478 319192 254019.17 256174.65 Subt alGs8 Subitation capacity 170 Subtotal Subtuaniacm Syitm Loding MW @.7 Capacity factor 18 47 52 41 42 Total TraninUl System Laading 231 263 280 318 368 153 ANNEX 5.4 (a) (i) 6) ELECTRICITY DEMAND FORECAST FOR THE INTERCONNECTED SYSTEM: BASE CASE FORECAST ASSUMPTIONS FOR FORECAST: HIGHER ECONOMIC GROWTH RATES; HIGHER POPULATION ELASTICITIES FOR RESIDENTIAL DEMAND, AND MORE RAPID DECLINE IN LOAD FACTOR; TARIFFS KEPT CONSTANT IN REAL TERMS. Long-Run GDP Growth Rates GDP Price 1989-91 1992-96 1997-2011 elast Elast Agriculture 2.3% 4.3% 6.0% Mining 4.6% 8.2% 8.5% Industry 7.0% 7.3% 8.5% 1.30 0.6 Services 3.8% 4.9% 6.5% 1.20 0.6 Total GDP 3.3% 5.0% 6.5% Residential Urban Population Growth POP elest 3.0% 3.0% 3.0% 1990-96 2.00 0.5 Growth in Use per Consumer 1997-2001 2.40 0.5 3.0% 3.0% 3.0% 2002-2011 2.60 0.5 Population Growth Rural 1.6% 1.6% 1.6% Total 1.9% 1.9% 1.9% ANNEX 5A (a) (Q) (i) ELECTRICITY DEMAND FORECAST FOR THE INTERCONNECTED SYSTEM: BASE CASE FORECAST QENERATION REQUIREMENTS DEMAND TOTAL ENERGY LOAD MAXImum ELECTRICITY DEMAND BY CATEGORY ( GROWTH SALES LOSS FACTORS GENERATION FACTOR DEMD FISCAL OTHER/ UNSERVED NON-TECH NON-TECH TECH DEMAND YEAR 1lDUSTRY RESIDENT SERVICES DEMAND LOSSES TOTAL GWH % % GWHoo MWo 1919/90 945.0 497.0 194.0 47.3 163.6 18.9 1636. 10% 21% 2371.0 72.0% 375.9 1990191 1031.0 527.0 ?02.8 61.9 158.5 1931.2 7.3% 1760.9 9% 22% 2552.0 73.0% 399.1 1991192 1128.8 558.9 214.8 90.3 152.2 2145.0 8.3% 1902.5 8% 22% 2717.8 75.0% 413.7 1992193 1236.0 592.6 227.4 74.2 143.9 2274.0 6.0% 2056.0 7% 22S 2895.7 73.0% 452.1 1993194 1353.3 628.4 240.8 67.7 133.3 2423.4 6.6% 2222.4 6% 22% 3086.7 72.0% 4t9.4 1994t95 1481.7 666.4 254.9 44.5 120.1 2567.6 5.9% 2403.0 5% 21% 3247.3 70.0% 529.6 1995196 1622.3 706.6 269.9 32.4 104.0 2735.2 6.5% 2598.8 4% 20% 3419.5 69.0% 565.7 1996197 1801.6 757.8 291.0 36.0 85.5 2971.9 8.7% 2850.3 3% 19% 3654.3 69.0% 604.6 1997198 2000.6 812.7 313.7 20.0 62.5 3209.6 8.0% 3127.0 2% 18% 3908.8 68.0% 656.2 1998199 2221.7 871.7 338.1 22.2 68.6 3522.3 9.7% 3431.5 2% 17% 4236.4 68.0% 711.2 1999h00 2467.2 934.8 364.5 24.7 75.3 3866.5 9.8% 3766.5 2% 16% 4593.3 68.0% 771.1 2000/01 2739.8 1002.6 392.9 0.0 82.7 4218.1 9.1% 4135.3 2% 15% 4982.3 67.0% 848.9 2001102 3042.6 1081.3 423.6 0.0 90.9 4638.4 10.0% 4547.5 2% 14% 5413.7 67.0% 922.4 2002103 3378.8 1166.2 456.6 0.0 100.0 5101.6 10.0% 5001.6 2% 14% 5954.3 67.0% 1014.5 2003t04 3752.1 1257.8 492.3 0.0 110.0 5612.2 10.0% 5502.2 2% 14% 6550.2 67.0% 1116.0 2004/05 4166.7 1356.5 530.6 0.0 121.1 6175.0 10.0% 6053.9 2% 14% 7207.1 67.0% 1227.9 2005/06 4627.2 1463.1 572.0 0.0 133.2 6795.5 10.0% 6662.3 2% 14% 7931.3 67.0% 1351.3 2006107 5138.5 1577.9 616.7 0.0 146.7 7479.7 11>I% 7333.1 2% 14% 8729.8 67.0% 1487.4 2007/08 5706.3 1701.8 664.8 0.0 161.5 8234.3 10.1% 8072.9 2% 14% 9610.5 67.0% 1637.5 2008/09 6336.8 1835.5 716.6 0.0 177.8 9066.7 10.1% 8888.9 2% 14% 10582.0 67.0% 1803.0 2009/10 7037.0 1979.6 m.s 0.0 195.8 9984.9 10.1% 9789.1 2% 14% 11653.7 67.0% 1915.6 2010111 7814.6 2135.0 832.8 0.0 215.6 10998.0 10.1% 10782.4 2% 14% 12836.2 67.0% 2187.0 Avg. PAA 10.6% 7.2% 7.2% 0.9% 8.8% 9.4% -7.7% 8.3% 8.7% TOTAL ELECTRICITY PROPORTION OF SALES RESIDENTIAL SALES AND CONNECTIONS CONSUMPTION PER Resident Inc in RES CAPITA FISCAL RES GWH Consume Cons per MWH/ POP KWHNYR/ IND RES SERV YEAR (000) Yr (000) Coos mill PERSON 1989190 497.0 479.7 1.0 40.12 44.86 57.8% 30.4% 11.9% 1990191 527.0 493.9 14.2 1.1 40.90 46.93 58.6% 29.9% 11.5% 1991192 558.9 508.5 14.6 1.1 41.70 49.28 59.3% 29.4% 11.3% 1992/93 592.6 523.5 I5.0 1.1 42.51 51.75 60.1% 28.8% 11.1% 1993194 628.4 538.9 15.5 1.2 43.33 54.36 60.9% 28.3% 10.8% 1994195 666.4 554.8 15.9 1.2 44.18 57.11 61.7% 27.7% 10.6% 1995/96 706.6 571.2 16.4 1.2 45.04 60.01 62.4% 27.2% 10.4% 1996/97 757.8 594.8 23.6 1.3 45.91 63.94 63.2% 26.6% 10.2% 1997/98 812.7 619.3 24.5 1.3 46.81 68.15 64.0% 26.0% 10.0% 1998U99 871.7 644.8 25.5 1.4 47.72 73.35 64.7% 25.4% 9.9% 1999/00 934.8 671.4 26.6 1.4 48.64 78.98 65.5% 24.8% 9.7% 2000/01 1002.6 699.1 27.7 1.4 49.59 85.06 66.3% 24.2% 9.5% 2001M02 1081.3 732.1 32.9 1.5 50.56 91.75 66.9% 23.8% 9.3% 2002/03 1166.2 766.5 34.5 3.5 51.54 91.99 67.6% 23.3% 9.1% 2003/04 1257.8 802.6 36.1 1.6 52.54 106.82 68.2% 22.9% 8.9% 2004105 1356.5 840.5 37.8 1.6 53.56 115.28 68.8% 22.4% 8.8% 2005106 1463.1 880.0 39.6 1.7 54.60 124.45 69.5% 22.0% 8.6% 2006M07 1577.9 921.5 41.5 1.7 55.67 134.36 70.1% 21.5% 8.4% 200708 1701.8 964.9 43.4 1.8 56.75 145.10 70.7% 21.1% 8.2% 2008/0 1835.5 1010.4 45.5 1.8 57.85 156.72 71.3% 20.6% 8.1% 2009/10 1979.6 1058.0 47.6 1.9 58.98 169.29 71.9% 20.2% 7.9% 2010/11 2135.0 1107.8 49.8 1.9 60.13 182.91 72.5% 19.1% 7.7% 155 ANNEX 5.4 (a) (ii) (ii) ELECTRICITY DEMAND FORECAST FOR ISOLATED RURAL SYSTEMS: BASE CASE FORECAST ASSUMPTIONS FOR FORECAST: HIGH ECONOMIC GROWTH, POPULATION ELASTICITY SET AT 3.0; GDP ELASTICITY AT 0.9 LOAD FACTOR ESTIMATED TO INCREASE FROM 26% TO 36.5% OVER PERIOD Long-Run GDP Growth Rates GDP Price 1989-91 1992-96 1997-2011 clast Elast Agriculture 2.3% 4.3% 6.0% Mining 4.6% 8.2% 8.5% Industry 7.0% 7.3% 8.5% 0.90 0.6 Services 3.8% 4.9% 6.5% 0.90 0.6 Total GDP 3.3% 5.0% 6.5% Residential Rural Population Growth POP elas 1.6% 1.6% 1.6% 1990-96 3.00 0.5 Growth in Use per Consumer 1997-2001 3.00 0.5 2.0% 2.0% 2.0% 2002-2011 3.00 0.5 A5MIC 5.4 (a) (H) a0 ELCTRIRIY DEMAND FORBCAST FOR ISOLATED RURAL SYSTEMS: BASE CAMS FOREC&ST GENEIAIOY BUEDI ELBCrRCITY DEMAND BY CATBQORY 3WHN TOTAL LLSJO GENERATI MAI M FISCAL OTHERI UNSERVED NON-TBCH DEMAND SALES HON-TECH TECH DEMAND LOAD DMAND YEAR INusTY RESIDENT SERVC DEMAKD LOSE TOTAL tROWT( OW S U own"S FACOR MW 1939190 29.0 S2.0 13.0 13.2 9.4 116.6 94.0 10% 22% 133.2 26.0S .7 1S99091 30.S 54.S 13.4 13.3 .9 121.0 3.8% S6.3 9S 26% 152.0 26.5% 65.3 ISSI/92 32.9 57.1 14.0 13.5 *.3 125.8 4.0% 104.0 Ss 26% 157.6 27.OS 46. 1992/93 35.0 59.9 14.7 13.7 7.7 130.9 4.0% 109.5 7% 26% 163.5 27.5S 67.9 1993194 37.3 Q27 15.3 13.8 6.9 136.1 4.0S 115.3 6S 26% 169.6 2.0% 0.2 194JS5 39.8 65.7 16.0 14.0 6.1 141.5 4.0% 121.5 5% 25% 173.5 28.5S 0.5 19SS96 42.4 6S.9 16.7 14.1 5.1 147.1 4.0S 327.9 4% 24% 177.7 29D.S 7.0 199697 45.6 72.2 17.7 14.2 4.1 153.S 4.5% 135.5 3% 23% 333.1 29.5S 70.8 1997193 49.1 75.7 1.7 14.3 2.9 160.7 4.5% 143.5 2% 22% 33Ls 30.0% 71.3 199699 52.9 79.3 19.8 14.4 3.0 169.4 5.4% 151.9 2% 20% 194.3 30.5% 72.9 1999A10 56.9 S3.3 20.9 14.5 3.2 3737 5.5% 161.0 2% IS% 203.2 31.0% 74.1 200010 61.3 37.1 22.2 14.5 3.4 133.4 5.5% 170.5 2% 16% 20.0 31.5% 75.4 200102 65.9 91.3 23.5 14.5 3.6 198.3 5.5S 130.7 2% 16% 220.3 32.0% 73.6 2D02103 71.0 95.7 24.8 14.4 3.3 209.7 5.5% 191.5 2% 16% 233.5 32.5S 30 2003104 76.4 100.2 26.3 14.2 4.1 221.2 5.5S 203.0 2% 16S 247.5 33.0% U.6 2405 n2.3 105.1 27.8 14.0 4.3 233.4 5.5% 215.2 2S 16% 26Z4 33.5S 39.4 200106 .6 110.1 29.5 13.7 4.6 246.4 5.5S 223.1 2% 16% 273.2 34.0% 93.4 2006107 95.3 115.4 31.2 13.3 4.3 260.0 5.6% 241-9 2% 16% 295.0 34.5% 97.6 2007103 102.6 120.9 33.0 12.3 5.1 274.5 5.6% 256.6 2% 16% 312.9 3.OX 102.0 20039 1I0.S 126.7 34.9 12.2 5.4 289.3 5.6% 272.1 2% 16% 331.9 35.5% 106.7 2009110 118.9 132.8 37.0 11.5 S.3 306.0 5.6% 23.7 2% 16% 352.1 36.0% 111.6 U 20S0113 123.0 139.2 39.1 10.7 6.1 323.2 5.6% 306.4 2S 16% 373.6 36.5% 116.3 AvgePAA 7.3% 4.3% 5.4% 4.9% 5.8% 4.35 1.6% 3.1S RURAL ELECRICTrY RESIDENTIAL SALES AND CONNECTIONS CONSUMFPlON PER PROPORTION OF SALES iied"ii mmcinc in RES CAPITA FISCAL RESU OW CminAu Cam per MWHt POP KWH/YRI IND RUS SERV YEAR amO) Yr OM) cm mill PERSON I93990 52.0 105.1 0.5 40.12 2.58 30.9% 55.3% 13.8% 1990193 54.5 107.9 2.9 0.5 40.90 2.63 31.2% 53.2% 13.6% 1991192 S7.1 310.9 3.0 0.5 41.70 2.69 31.6% 54.9S 13.5% 199293 599 113.9 3.0 0.5 42.S1 2.76 32.0% 54.7% 13.4% 1993194 62.7 117.1 3.1 O.S 43.33 2.S2 32.3% 54.4% 13.3% 1994195 65.7 120.3 3.2 0.5 44.18 2.S9 32.7% 54.iS 13.2% 199S/96 6S.9 123.6 3.3 0.6 45.04 2.f9 33.1% 53.8% 13.0% 1996V97 72.2 127.0 3.4 0.6 45.91 3.04 33.7% 53.3% 13.0% 1997/93 7S.7 130.5 3.5 0.6 46.81 3.13 34.2% 52.7% 13.0% 199199 79.3 134.0 3.6 0.6 47.72 3.25 34.8% 52.2% 13.0% 1999100 83.1 137.7 3.7 0.6 48.64 3.37 35.4% 31.6% 13.0% 200103 37.1 141.5 3.8 0.6 49.59 3.51 35.9% 51.1% 13.0% 2001/02 91.3 145.4 3.9 0.6 50.56 3.65 36.5% -D.5% 13.0% 20D2t03 95.7 149.4 4.0 0.6 531.54 3.79 37.1% 50.0% 13.0% 2003104 100.2 153.5 4.1 0.7 52.54 3.94 37.7% 49.4% 13.0% 20a4105 105.1 157.7 4.2 0.7 53.56 4.10 3X.2% 43.8% 12.9% 2005106 110.1 162.0 4.3 0.7 54.60 4.26 38.S% 4S.3% 12.95 20061W 115.4 166.5 4.4 0.7 55.67 4.43 39.4% 47.7% 12.9% 2007103 120.9 171.0 4.6 0.7 56.75 4.61 40.0% 47.1% 12.9% 200DS09 126.7 175.7 4.7 0.7 57.S5 4.80 40.6% 46.6% 12.3% 2009t10 132.8 330.6 4.8 0.7 58.98 4.99 41.2% 46.0S 12.8% 2D10/11 139.2 185.5 5.0 0.8 60.13 5.20 41.8% 45.4% 12.8% 157 ANNEX 5.4 (a)(iii) (iii) ELECTRICITY DEMAND FORECAST FOR THE JNTERCONNECTED SYSTEM: LOW DEMAND CASE ASSUMPTIONS FOR FORECAST: LOW ECONOMIC GROWTH RATES; LOW POPULATION ELASTICITIES FOR. RESIDENTIAL DEMAND AND HIGHER LOAD FACTOR; TARIFFS KEPT CONSTANT IN REAL TERMS. Long-Run GDP Growth Rates GDP Price 1989-91 1992-96 1997-2011 elast Elast Agriculture 1.6% 2.5% 2.5% Mining 3.3% 4.5% 4.5% Industry 4.0% 5.1% 5.1% 1.30 0.6 Services 2.1% 3.0% 3.0% 1.20 0.6 Total GDP 2.0% 3.0% 3.0% Residential Urban Population Growth POP elast 3.0% 3.0% 3.0% 1990-96 1.60 0.5 Growth in Use per Consumer 1997-2001 1.60 0.5 3.0% 3.0% 3.0% 2002-2011 1.60 0.5 Population Growth Rural 1.6% 1.6% 1.6% Total 1.9% 1.9% 1.9% ANNEX SA l) (lii) ELECTRKIIY DEMAND FORECAST FOR THE IITERCONNBCED SYSTEM: LOW DEMAND CASE GENERATION REOUIREME ENERGY ELECTRiCTY DEMAND BY CATEGORY (OWN) TOTAL LOSS FACORS GENERATION MAXamum k1SCAL OTHERI UNSERVED NON-TECH DEMAND SALES NON-TECH TECH DEMAND LOAD DEMND YEAR INDUSTRY RESIDENT SERVICES DEMAND LOSSES TOTAL GROWTH OWH s F GWHso FACTOR "w 19m919o 945.0 497.0 194.0 47.3 163.6 1.9 1636.0 10S 2 - w1.0 7-OS 37.9 1990191 994.1 521.0 198.9 59.6 154.3 1928.0 4A% 1714.0 9% 22% 2484.1 73.0% 38.5 ss91s2 1060.1 546.2 206.1 54.8 145.0 2042.2 5.9% 1812.4 Ss 22% 2589.1 75.0% 394.1 1992193 1130.3 57.6 213.7 90.4 134.2 2141.2 4.8% 1916.6 7% 22% 2699.4 75.0% 410.9 193194 1205.3 6S0.2 221.5 96.4 121.6 2245.0 4S% 2027.0 6% 22% 2815.3 75.0% 428.5 1994195 1255.2 629.3 229.5 90.0 107.2 2341.1 4.3% 2144.0 5% 21% 2897.3 74.0% 446.9 1995196 1370.4 659.7 237.9 82.2 90.7 2440.9 4.3% 2268.0 4% 20% 2984.2 73.0% 466.7 1996197 1461.2 691.5 246.6 7.1 72.0 2544A 4.2% 2399.4 3% 9s% 3076.1 72.0% 487.7 ss79s 1558.1 724.9 255.6 62.v 50.8 2651.8 4.2% 2538.7 2% l8% 3173.3 71.0% 510.2 19939 1661.4 760.0 264.9 49.8 53.7 2789.9 5.2% 2686.3 2% 17% 3316.4 70.0% 540.8 2999/00 1771.6 796.7 274.6 35.4 56.9 2935.1 5.2% 2342.9 2% 16% 3466.9 69.0% 573.6 2000101 I889.0 83s.2 284.6 18.9 60.2 3087.9 5.2% 3008.8 2% Is% 3625.i 68.0% 60S.6 2001/02 2014.3 87i.6 295.0 0 63.7 3248.5 5.2% 3184.8 2% 14% 3791.4 67.0% 646.0 2002/03 2147.8 917.9 305.7 u.O 67.4 3433.9 5.9% 3371.4 2% 14% 4013.6 67.0% 683.3 2003/04 2290.2 962.2 316.9 0.0 71.4 3640.7 5.9% 3569.3 2% 14% 4249.2 67.0% 724.0 2004105 2442.1 1008.7 328.4 0.0 75.6 3854.3 5.9% 3779.2 2% 14% 4499.1 67.0% 766.6 2005106 2604.0 1057.4 340.4 0.0 80.0 4081.9 5.9% 4001.9 2% 14% 4764.1 67.0% 811.7 2006/07 2776.6 1 108.5 352.8 0.0 84.8 4322.8 5.9% 4238.0 2% 14% 5045.3 67.0% s59.6 2007108 2960.7 1162.1 365.7 0.0 89.8 4578.3 5.9% 4488.5 2% 14% 5343.5 67.0% 910.4 2008/09 3157.0 1218.3 379.1 0.0 95.1 4849.4 5.9% 4754.3 2% 14% s659.9 67.0% 964.3 2009/10 3366.3 1277.1 392.9 0.0 100.7 5137.1 5.9% 5036.3 2% 14% 5995.6 67.0% 1021.5 ui 2010/11 3589.5 1338.8 407.2 0.0 106.7 5442.3 5.9% 533s.6 2% 14% 6351.9 67.0% 1062.2 m Avge PAA 6.6% 4.8% 3.6% 5.2% 5.8% 4.7% 5.1% TOTAL ELECTRICITY RESIDENTAL SALES AND CONNECTIONS CONSUMPTION PER Resdent Ic in RES CAPITA PROPORTION OF SALES FISCAL RES OWN Cosamwr Cons per MWH/ POP KWHIYE) DND RlES SERV YEAR (000) Yr (000) Cou mI PERSON 497.0 479.7 1.0 40.12 44.86 57.8% 30.4% 11.9% 1990/91 521.0 488.3 8.5 1.1 40.90 45.68 58.0% 304% 11.6% 1991/92 546.2 496.9 8.7 1.1 41.70 46.94 58.5% 30.1% 11.4% 1992193 572.6 505.8 8.8 1.1 42.51 48.24 59.0% 29.9% 11.1% 1993/94 600.2 514.8 9.0 1.2 43.33 49.5 59.5% 29.6% 10.9% 1994/95 629.3 523.9 9.2 1.2 44.18 50.96 59.9% 29.3% 10.7% 199S196 659.7 533.3 9.3 1.2 45.04 52.37 60.4% 29.1% 10.5% 1996197 691.5 542.7 9.5 1.3 45.91 53.83 60.9% 23.8% 10.3% 1997198 724.9 552.4 9.7 1.3 46.81 55.32 61.4% 28.6% 10.1% 199U99 760.0 562.2 9.8 1.4 47.72 57.42 61.8% 28.3% 9.9% 1999/00 796.7 572.2 10.0 1.4 48.64 59.61 62.3% 28.0% 9.7% 2000/01 835.2 582.4 10.2 IA 49.59 61.89 62.8% 27.8% 9.5% 2001/02 875.6 592.8 10.4 1.5 50.56 64.26 63.2% 27.5% 9.3% 200Q103 917.9 603.3 10.5 1.5 51.54 66.72 63.7% 27.2% 9.1% 2003/04 962.2 614.0 10.7 1.6 52.54 69.29 64.2% 27.0% 8.9% 2004105 1008.7 625.0 10.9 1.6 53. 71.97 64.6% 26.7% 8.7% 2005106 1057.4 636.1 11.1 1.7 54.60 74.75 65.1% 26.4% 8.5% 2006107 1108.5 647A I!.3 1.7 55.67 77.65 65.5% 26.2% 8.3% 2007108 1162.1 658.9 11.5 1.8 56.75 80.61i 66.0% 25.9% 8.1% 2008/09 1218.3 670.6 11.7 1.8 57.85 83.82 66.4% 25.6% 8.0% 2009/10 1277.1 6i82.5 11.9 1.9 58.98 87.10 66.8% 25.4% 7.8% 2010/11 1338.8 694.7 12.1 1.9 60.13 90.51 67.3% 25.1% 7.6% 159 ANNEX 5.4 (a) (iv) (iv) ELECTRICrTY DEMAND FORECAST FOR ISOLATED RURAL SYSTEMS: LOW DEMANI) CASE ASSUMPTIONS FOR FORECAST: SLOW OVERALL ECONOMIC GROWTH OF SOME 3%/YR; POPULATION ELASTICITY FOR RESIDENTIAL DEMAND AT AN ESTIMATED 2.5; IND GDP ELASTICITY AT 0.8; LOAD FACTOR ESTIMATED AT 26% RISING TO 31.3% Long-Run GDP Growth Rates GDP Price 1989-91 1992-96 1997-2011 elast Elast Agriculture 1.6% 2.5% 2.5% Mining 3.3% 4.5% 4.5% Industry 4.0% 5.1% 5.1% 0.80 0.6 Services 2.1% 3.0% 3.0% 0.80 0.6 Total GDP 2.0% 3.0% 3.0% Residential Rural Population Growth POP elast 1.6% 1.6% 1.6% 1990-96 2.50 0.5 Growth in Use per Consumer 1997-2001 2.50 0.5 2.0% 2.0% 2.0% 2002-2011 2.50 0.5 Population Growth Urban 3.0% 3.0% 3.0% Total 1.9% 1.9% 1.9% ANNEX 5.4 () (iv) fiv) ELECTRICITY DEMAND FORECAST FOR ISOLATED RURAL SYSTEMS: LOW DEMAND CASE GENERATION REOUIREMENTS ENERGY ELECTRICITY DEMAND BY CATEGORY (LGU ) TOTAL LOSS FACTORS GENERATION MAXIMUM FISCAL OTHER/ UNSERVED NON-TECH DEMAND SALES NON-TECH TECH DEMAND LOAD DEMAND YEAR INDUSTRY RESIDENT SERVICES DEMAND LOSSES TOTAL GROWFH IWH % GWHw FACTOR MWo im/90 29.0 52.0 13.0 13.2 9.4 116.6 94.0 10% 22% £38.2 26.0% 60.7 1990/91 29.9 54.1 13.2 13.4 8.8 219.3 2.4% 97.2 9% 26% 149.6 26.3% 65.0 1991192 31.1 56.2 13.3 13.6 8.1 122.6 2.8% 100.9 8% 26% 152.9 26.5% 65.9 1992193 32.4 58.5 13.9 13.9 7.3 126.0 2.7% 104.8 7% 26% 156.4 26.8% 66.7 1993194 33.7 60.8 14.2 14.1 6.5 129.5 2.7% 108.8 6% 26% 160.0 27.0% 67.6 1994/95 35.1 63.3 14.6 14.4 5.6 133.0 2.7% 112.9 5% 25% 161.3 27.3% 67.6 1995196 36.6 65.8 .4.9 14.7 4.7 136.6 2.7% 117.3 4% 24% 162.9 27.5% 67.6 1996197 38.0 68.4 15.3 14.9 3.7 140.3 2.7% 121.7 3% 23% 164.5 27.8% 67.7 1997/98 39.6 71.2 15.6 15.2 2.5 144.1 2.7% 126.4 2% 22% 166.3 28.0% 67.8 199Sf99 41.2 74.0 16.0 15.4 2.6 149.3 3.6% 131.2 2% 20% 168.1 28.2% 68.0 19991Q0 42.9 77.0 16.4 15.7 2.7 154.7 3.6% 136.3 2% 18% 170.3 28.5% 68.2 2000/01 44.6 80.1 16.8 15.9 2.8 160.3 3.6% 141.5 2% 16% 172.6 28.7% 68.5 2001/02 46.5 83.3 17.2 16.2 2.9 166.0 3.6% 146.9 2% 16% 179.2 29.0% 70.5 2002/03 48.4 86.6 17.6 16.4 3.1 172.0 3.6% 152.6 2% 16% 186.1 29.2% 72.6 2003/04 50.3 90.0 18.1 16.6 3.2 178.3 3.6% 158.4 2% 16% 193.2 29.5% 74.8 2004105 52.4 93.6 18.5 16.9 3.3 14.7 3.6% 164.5 2% 16% 200.7 29.8% 77.0 2005t06 54.5 97.4 19.0 17.1 3.4 191.4 3.6% 170.9 2% 16% 208.4 30.0% 79.3 2006/07 56.7 101.3 19.4 17.3 3.5 191.3 3.6% 177.5 2% 16% 216.4 30.3% 81.7 2007/08 59.1 105.3 19.9 17.5 .7 205.5 3.6% 184.3 2% 16% 224.7 30.5% 84.1 200ua9 61.5 109.6 20A 17.7 3.8 212.9 3.6% 191.4 2% 16% 233.4 30.8% 36.7 2009/10 64.0 )13.9 20.9 17.9 4.0 220.7 3.6% 198.8 2% 16% 242.4 31.0% 39.3 2010/11 66.6 118.5 21.4 18.1 4.1 228.7 3.6% 206.5 2% 16% 251.8 31.3% 92.0 o Avg. PAA 4.0% 4.0% 2.4% 1.5% 3.2% 3.8% 2.8% 2.0% RURAL ELECTRICITY RESIDENTIAL SALES AND CONNECTIONS CONSUMPTION PER PROPORTION OF SALES Rna Inc in RES CAPITA FISCAL RES GWH COnDs Cons per mWH/ POP KWH/YR/ IND RES SERV YEAR (00) Yr (000) Cons ml PERSON 1989/90 52.0 105.1 0.5 40.12 2.51 30.9% 55.3% 13.8% 1990/91 54.1 107.1 2.1 0.5 40.90 2.59 30.8% 55.6% 13.6% '991f92 56.2 109.2 2.1 0.5 41.70 2.61 30.9% 55.7% 13.4% 1992f93 58.5 111.4 2.1 0.5 42.51 2.64 30.9% 55.8% 13.2% 1993/94 60.8 113.5 2.2 0.5 43.33 2.66 31.0% 55.9% 13.1% 1994/95 63.3 115.8 2.2 0.5 44.18 2.68 31.1% 56.0% 12.9% 1995f96 65.8 118.0 2.3 0.6 45.04 2.71 31.2% 56.1% 12.7% 1996/97 68.4 120.3 2.3 0.6 45.91 2.73 31.2% 56.2% 12.5% 1997f9S 71.2 i22.7 2.4 0.6 46.81 2.75 31.3% 56.3% 12.4% 1998f99 74.0 125.1 2A 0.6 47.72 2.81 31.4% 56.4% 12.2% 19S9/00 77.0 127.6 2.5 0.6 48.64 2.86 31.5% 56.5% 12.0% 2000f01 80.1 130.1 2.5 0.6 49.59 2.91 31.5% 56.6% 11.9% 2001t02 83.3 132.6 2.6 0.6 50.56 2.96 31.6% 56.7% 11.7% 2002/03 86.6 135.2 2.6 0.6 51.54 3.02 31.7% 56.7% 11.6% 2003104 90.0 137.9 2.7 0.7 52.54 3.08 31.8% 56.8% 11.4% 2004105 93.6 140.6 2.7 0.7 53.56 3.13 31.8% 56.9% 11.2% 2005106 97A 143.3 2.8 0.7 54.60 3.19 31.9% 57.0% 11.1% 2006/07 101.3 146.1 2.8 0.7 55.67 3.25 32.0% 57.1% 10.9% 2007t08 105.3 149.0 2.9 0.7 56.75 3.31 32.0% 57.2% 10.8% 2006/9 109.6 151.9 2.9 0.7 57.85 3.37 32.1% 57.2% 10.6% 2009/10 113.9 154.9 3.0 0.7 58.98 3.44 32.2% 57.3% 10.5% 2010tI 1 11b.5 157.9 3.0 0.8 60.13 3.50 32.3% 57.4% 10.4% 161 ANNEX 5.4 (b) SUMMARY OF THERMAL GENERATION PLANNING PARAMERS USED IN WASPIENPEP STUDIES PlaI Name ENPEP Oputiwg H"t RAt Syim Pamueer Opeadt Cod Captl Cot ID Capaity Min. Averap Spin Mainenane Fixed VaL CODE L Max. Un Cap. I nrt Max Vul Rwv POR Sbod Cla 0*34 0* PC LC MW MW its kcalikWh E y Typ S S dtyr MW ShkW.m S lW SUSm SUSm FIXED SYSTEM (stlesi / Comlulled) ywams Steam Turbins YWIG 3.3 6.5 3 7815 4446 14.0S FOIL 0% IS% 30 10 4.77 4.00 6.3 3.0 YwsnaGT(Gas) YW20 9.3 13.5 2 400 2220 24.5% GAS 10% 10% 20 20 1.21 2.00 1.3 0.1 Kyuncham4 Gas Tuebin KGYT 9.1 18.1 3 480D 2220 24.5% OAS 10% 10% 20 20 t.21 2.00 2.0 0.2 MysoauagGT (Hitachl) MYGH 9.3 13.5 1 4800 2220 24.5% OAS 10% 10% 20 20 1.21 2.00 0.5 0.1 Myansuwg OT (Jolh Brown) MYJB 9.3 15.5 1 4800 2220 24.5% OAS 10% 10% 20 20 1.21 2.00 0.7 0.1 ManGs Tuebinee MANN 9.3 18.5 2 4800 2220 24.5S GAS 10% 1OS 20 20 1.21 2.00 1.5 0.2 Shwedaug GasTueoines SHVWE 9.3 15.5 3 4800 2220 24.5% OAS 10% 10% 20 20 1.21 2.00 2.5 0.2 Thaketa Gas Tubine, THA 9.5 19.0 3 480D 3000 22.1% DIES 10% 10% 20 20 1.21 2.LO 0.5 0.1 Tbhta. Gas Turbin THAI 5.5 17.0 1 4800 2400 23.9% FOIL I0% 10% 20 20 1.21 2.00 0.7 0.1 Thatot Steam Turbb THA2 3.3 6.6 3 4000 3060 24.4% POIL 10% 15% 25 6 4.77 4.50 0.5 0.1 Moulmein Steam Turbin MOUL 3.0 6.0 2 4000 2900 24.9% FOIL 10% 15% 25 6 4.77 4.30 0.5 0.1 Ywama CT (Diesel) YW2O 9.3 15.5 2 4800 246D 23.7% DIES 10% 10% 20 20 1.21 2.00 Total Pixed Theul Capacity 346.1 17.2 4.1 VARIABLE SYSTEM (Alternative Otions) SltW SaW C-C#R Shwedaxng SHWC 18.5 Q2.0 I 3510 1949 37.4% GAS 10% 10% 20 20 1.67 4.00 406 101 C-C#3 Myana,g 51 MYCH 16.4 73.0 1 3740 2089 35.0% GAS I0% 10% 20 20 1.67 4.0 352 151 C-C#4 Myanaung #2 MXYC 18.5 54.0 1 3510 1745 36.6% GAS 10% 10% 20 20 1.67 4.00 544 233 C-C#2 Maw MANC 16.5 80 1 3510 1999 36.%S GAS 10% 10% 20 20 1.67 4.00 482 120 C-C#S Thaketa THAC 19.0 65.0 1 3900 2159 33.8% GAS 10% 10% 20 20 1.67 4.00 359 154 Kalewa Cal FiredST KALE 23.0 50.0 6 3045 2557 30.7% MINE 10% 10% 30 50 2.15 6.20 15S 675 C-C#7 Kyaikit KYAC 17.0 50.0 10 3555 1470 39.4S GAS 10% 10% 20 20 1.67 4.00 652 279 Thaketa Dlcacthas Engine THAD 2.0 12.0 10 2389 2332 36.7% DIES 10% 10% 30 10 1.50 3.00 IOIS 262 Ahlone Coal Fird ST AHCO 25.0 100.0 3 3045 2557 32.1% COAL 10% 10% 30 50 2.15 6.20 840 360 Ablonc Fuel Oil Fird ST AHLO 25.0 50.0 6 3142 2752 29.2% FOIL 10% 10% 30 50 2.15 6.20 514 34 Notcs: (i) Rebabilitation Cua llocated to exidIfn pla lude new avaea nprovede orthe IDA lot tegeterith provision fot additional diesel orage and oU hading facIlitis at Mm Sweda.rg and Myana.uig. Rate cm uhOn fot the Variable syAM Plat aM ineluaVe of DC (te Duin Co ucton). (ii) For the WASP study It is asumed Tbaketa. nd Ywam would oprtc with dis uel bsll 1995 whn offshboe gan is avalUable. Paia using FPtt oil are epectad to reUre between 2030 ad 2005. (Wi)Convenion to Combined Cycle opemation at Thake, Shwodatag. Mm. and Myamig woud qrte te exting facillils by 25MW trHAK to THAC). 26.SMW (SHWE to SRvWC), 26.5MW (MANN to MANC). and 24MW (MYOH to MYCH) * 36.45MW (MYIB to UYCI). (Iv) A new 600MW combined cycle pltw Is propod atr Ym. psab at Kyalra e TIrm saep Is propoed as 6050MW compatable with the exidtig yem cdinftmo but the ler tag could be in 100MW inem a (v) Coal fired pi opton ltilde a 6MW Minsoath Maltm at Kaw eda 39100MW stain ust inmpoted coal possibly sited at AWloe. Alterntively a l1 Ud OM dam genating sallos could be ed is AMin. (vi) Only m"elm speed o fel dD(gasdIel) engas have been caedrr eabe. if offshore ga delayed beyond 1995 tOm optil devclopmnt hould cosider 425W skw spoed mulhifeml (hvy f*l,. s. dikes wlne. ANNEX 5.4 (c) GENERATION EXPANSION ALTERNATIVES-190-2010 Dan cow I1" Doused Cane I. Lw a 2. M sh D d - cub=m W-ml, MW MW MW mw s Mw mw MW MW S MW MW MW S Yea Poant Is11 TOW Reaw Y-a Ponge bid Tod Rsal Yew pma_ b1f TOW Roo ama 3m biakg m ew 399 399 0% 1909 3 '-z1i CapbWiy 3"9 399 0% 19 391 ExliIq Cspahft 399 199 0 I9O 37 399 4% 990 m 399 % 20 376 399 6 199 37 1bks_ X be laas fO 459 12% 1990 376 7%b3A CWWO10 60 459 21% I290 37b 1 acu t esbd 60 459 1U IW 39 459 13% 1931 339 459 1% 299 399 459 3 199I 399 459 13% 1991 339 459 15% 1991 399 459 13 1992 414 IiUWla_ Pegi 562 562 26% 1992 394 dabbkado Pego 562 562 30% I12 414 IahM2iW s6 562 26 S992 414 562 26% 1992 394 562 30% 1992 414 s52 26 193 433 562 19% 1993 411 S62 Vs 1993 453 S62 it I13 453 562 19% 2993 411 S62 Vs I93 4S3 562 19 IW9 489 562 US 1994 429 562 24% 1994 489 562 13 1994 489 C-CnJC-CU ShweSMM 71 633 23% 1994 429 C-CIIC-Cf s _rmkgib 71 633 32% 1994 439 C-C IC-Cd2M M iMM 71 633 23 2995 530 633 16% 2995 447 633 29S 2995 530 63 16 I25 S30 C-c5nw-m7 _b*aw 52 645 23% 2995 447 C-CIS Myang 24 657 32% 2995 530 C-C/C-I3 MymaM &2 6O 693 24 2996 566 45 17% 1996 467 657 29% I26 566 693 18 1996 546 C-l r K rA 50 735 23S 2996 467 657 29% 1996 S66 Aim C 1 100 793 2 1997 t05 735 ISS 1997 4U 657 26% 1997 605 793 26 1997 645 C-CA7 ryaa 50 735 23% 1997 48 C-Cu MyasiA 36 693 30% 1997 605 793 24 1993 656 735 16% 2993 50 693 26% 1996 636 793 17 1996 65 c- 7erKyalu SD W5 21% 1m 520 693 26% 1996 656 AMC o al2 20 893 271 an 1999 712 a35 is% 1999 542 693 22% 2999 711 893 20 t 1999 712 C-C r Kya2 1o0 935 24% 1999 41 Kacwa coal U s0 743 s 1999 711 abcaS3 48 941 2 2mo 772 Yo YWtG tuis -36 *99 14% 26O0 574 Ywa YWIO raro -36 707 19% 20o 772 Yw. YWIO udkes -36 90 IS 20 771 C-CIlKyraIst so 949 19% 200 S74 KakcWsCoadU 50 757 24% 26O 771 AiCodin 100 20 23 2001 349 949 Its 2r01 6f9 757 20% 2002 349 20 16 200 so49 C-7Kyad IO 1049 19% 2001 609 r.lm coa 51 S5 37 25% 200 49 Ktas Coda I&2 100 22O5 23 2002 9o2 1049 12% 2002 646 WI1 20S 2002 922 205 27 2M2 922 C-M7gya& r0 1149 20% 2W02 646 107 20% 2D02 922 C-Cs Thako Is 2190 23D 2003 2015 1149 122 2003 684 I7 Is5% MO 025 1190 15 203 2013 rasq1ac 230 1429 29% 20a3 684 ACto Coa 01 100 07 25% 2003 2025 Es ma Coa f&2 100 129D 21 2004 1116 1429 22s 2004 724 907 20s 204 1116 1290 14 204 1116 3aboas g3 48 1477 24% 2W4 724 907 20% 204 1116 ?rAw a 230 25 29 2005 122 AtIm T_ta.IM mIa -47 1430 14% 2a0s 767 Rhut TImtoaIMahI -47 360 lIt 2e o 2228 1a,' TIuoa2mho -47 1523 19 25 12233 1Im 240 1670 26% 200s 767 AhkicCoadgI 20 2060 28% 2M5 122 YCwya 400 2923 36 2006 2351 1670 19% 2&06 32 1060 23% 2006 2351 2923 30 2006 135 Y"w 400 2D70 35% 2006 312 1060 23% 2006 2351 I923 30 2007 1487 270 23% 2007 360 2060 19% 20D7 1437 2923 23 2007 2487 MenCUM 20a 227 34S 2C07 360 C- sThal is 1145 23% 20D7 1487 SWAM=.O ilU1 290 2223 33 201 2633 2220 n% 200 oJ0 2245 21S 201 2633 2223 261 2w0 263 awesye 60 2170 43S 2006 910 Bahi1a n3 45 2193 24S 2W06 2638 Ama 0 23.4 ISD 2363 31 2009 lw03 22 37% 2009 964 1293 19S 2009 Iw 2363 24 200g 2303 KM m 34 2954 39S 200 964 Kram CalDI 50 1243 22% 20 I 230 Dsm al 234 2647 32 2010 1996 2954 33% 2011) 1022 1243 23% 2010 1936 2647 25 2010 1936 Bike OT Cquily -1J0 234 29% 2D10 1022 R3 rq, OT Cswly -lsD 1093 75 2010 I93 Ret OT Opc*ty -150 P497 2D Tea7 l 2106 Av 22% TaTW l093 AV 23% T ENI ANNUAL PANT)L uN. USACE FM BAS FUEL CAMN 001 (IN lEiN CUBIC Ff E YU2G 3774 0.00 0.00 0.00 o.0o 0.00 3.77 1.77 1.99 2.10 2.06 2.06 2.06 2.06 .39 213 0.2 0.o2 0.3 O03 12 0.m 7mAC 2767 0.00 0.00 0.00 0.00 0.o 3.49 3.12 4.33 4.63 3.91 3.97 3.9 3.76 3.44 3s. 2.9 3.9 2.74 2.74 1S 3.4 KYAC 232 o.0 0.00 0O.C 0.00 0.00 0.00 2.9 5.3 o .-6 13.16 16.36 20.61 25.94 25.24 3.17 27.09 2M 3.32 27.72 30.7n 34.06 PAYA OOItIATAUNTOrAL 0.00 0.00 0.00 0.00 000 7.2 9.64 12.50 33.33 19.13 2240 26.67 32.76 30.26 33.33 30.91 32.74 32. 33.A 3S.6 3S3 KMG 3774 sit 6.00 6.06 SAI 3.46 2.39 2.43 2.31 2.36 2.81 3.20 3.04 3.07 2.37 2.44 0.00 0O. OO 0.00 OCO O0 MANN 3774 3.33 3.42 3.37 3.27 0.00 0.00 0.00 0.00 0.00 o.o0 0.00 0.00 0.00 0.00 o.o0 0.00 0.00 0.00 0.00 0.00 0.ao MANC 2316 0.00 0.00 0.00 0.00 3.73 3.47 3.37 3.31 3.31 3.14 3.16 3.12 3.11 2.02 2.92 1.63 .3 I. 2.4.0 2.1 3.13 MANINIC74A3UrAL 9.36 9.42 9.03 6.6 7.23 3.96 3.30 5.62 6.19 3.94 0.29 .16 6.12 A.99 5.36 31.3 1.36 1.9 2.40 2.41 3.23 960H 3774 3.72 3.60 3.60 3.09 2.65 0.00 O.O O.O O.O O.O 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 mm 377 .6 3. 82 2.05 3.3 1.24 0A4. 0.00 0.00 o.o0 o.oo 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 SHWE 3774 3.0 4.81 4.31 4.23 0.00 o.o0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0. CH 2372 0.00 0.00 0.00 o.o0 0.00 2.63 2.69 2.63 L66 2.an 2.60 2.37 2.57 2.97 2.0e 0.93 0.67 1.33 1.70 2.02 2.71 hffo 2372 0.00 o.o0 o.o0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 3.30 2.00 SuWC 2372 0.00 0.00 0.00 0.00 4.30 3.91 3.53 3.32 3.30 3.0U 3.12 3.03 3.01 2.65 2.66 2.30 3.52 2.26 2.27 2a9 3.1 - PROOEJr?6TAL 10.63 10.23 10.46 9.11 6.09 6.6 6.22 S.96 3.9 5. .6 5.72 3.60 5.56 4.63 4.94 2.93 2.19 3.40 3. 9 6.40 039 TOTAL GU 19.99 19.65 20.09 17.30 23.33 19.67 21.35 24.29 27.47 30.72 3.43 33.44 43.32 39.J 43.62 33.49 36.29 3.92 37.79 44.60 31.25 (Waxidfig bwx2usGA 2300 Krn2MCF) FUEL OUJDESE. FUN GENERATORS ANNUAL PLAN FtIEL WACE FOR EASE FUEL CASE 003 aN k M.ON BARELS) THAI 3322 0.00 0.00 O.AS 0.11 0.23 0.20 0.10 0.20 0.22 0.22 0.13 0.12 0.12 0.10 0.02 0oo 0.00 0.00 0.00 o.0o 0.00 in"2 3321 0.00 00 O.2S 0.12 0.12 0.00 O.0O 074 0.00 0.00 0.00 o.o0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 o.o0 MoON 3322 0.00 0.00 0.30 0.07 0.07 o.o0 o.o0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 o.0o 0.00 000 0.00 0.00 0.00 0.00 TOrALFUELOL 0.00 0.00 0.40 0.30 030 0.10 0.10 0.21 0.12 0.32 0.13 0.23 0.13 0.0 0.002 .00 0.00 0.00 0.00 0.0o o.o0 d F 2 ~~~~~~1532X0 roW gbf_ 11AZ 2516 0.00 0.36 0.32 0 26 0.27 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.0 0.00 0.00 0.00 0.00 0.00 YWIG 412 0.00 0.02 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.4a 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 YW20 277 0.22 0.17 0.17 0.21 0.16 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 a 2306 0.22 0.24 0.25 0.a6 0 0.37 0.2 0.29 0.30 0.32 0.32 0.33 0.35 0.37 039 0.41 0.44 0.47 0.4 0.32 0.3s TOtAL OEM . 0.44 0.76 0.74 0.64 0.70 0.2 0.23 0.29 0.30 0.31 0.32 0.33 0.35 0.37 0.39 0.41 0.44 0.47 0.49 0.52 OJ. (Ww12 Whsod D_i 1463000 K213U) rAM TOTALDIESFELOL 0.44 0.76 1.24 0.94 2.00 0.36 0.39 0.40 0.42 0.42 0.45 0.46 0.4 0.47 0.42 OAI 0.44 0.47 0.49 0.52 0.36 ANT TYme UNrI DAILY FUEL REQURMENT FPE PLANT FOR EASE FUEL CASE iOl lAs s8 546 33.6 35.1 46.8 42.0 33.9 59.9 66.6 75.3 34.2 94.3 105.3 119.2 109.3 1229. 97.2 99.4 103.9 103.3 122.7 14.1 FELOL 2pd 1202.4 2137.9 2034.2 1740.5 1926.3 761.1 777.2 6O0.3 927.1 647.7 679.5 901.7 951.4 JOU.4 1066.9 1133.6 2201.4 1274.0 135133 1433.3 3S20.6 165 ANNEX 5.5 SUMMARY OF TRANSMISSION AND SUBSTATION INVESTMENT PROPOSALS $000/ Codt US$000 Year $000/ cod US= Qty Unit FC LC+tax 0% FC U/S Qty Unit PC LC+tax I Intercnoctlon Thaton Sytem 4 Ayarwardy 66kV Subranmlaason 132kV OIHines, km * 100 90 5400 3600 230kV Substation bays 6 360 1296 864 230kV Substation bays * 1 360 216 144 230kV O/H lnes, km 15 120 1080 720 132kV Substadion bays * 3 280 504 336 230/66kV Transformer MVA 250 IS 2250 1500 230/132kV Tranformer MVA * 50 15 450 300 66kV Substation bays 2 180 216 144 132/66kV Trasnformer MVA * 50 16 480 320 Buildins, Lan & Civil 1 600 120 600 66kV SubAtion bays * 1 180 108 72 Total Ayarwardy Project 4962 3828 Buildings, Land & Civil * 2 600 240 1200 Total Thaton project 7398 5972 5 Monya/Kyunchaung/Mandalay 132kV System 132kV OH lines, km 180 90 9720 6480 2 Yangon 66kV Reinforcement 132kV Substation bays 6 280 1008 672 230kV O/H line, km * 20 120 1440 960 66/1 IkV Transformer MVA 100 18 1080 720 230kV Subiation bays 5 360 1080 720 132/33kV Transformer MVA S0 16 480 320 230/66kV Transfomer MVA 200 15 1800 1200 Buildings, Land & Civil 3 600 360 1800 66kV O/H lines, km * 130 40 3120 2080 Total Monya Project 12648 9992 66kV U/G cable, km * 12 150 1080 720 66kV Substaion bays 72 180 7776 5184 6 General Subation Upgrading 66/11kV Transformer MVA * 330 18 3564 2376 230kV Substaion bays 10 360 2160 1440 Buildings. Land & Civil 8 600 960 4800 132kVSubstationbays 10 280 1680 1120 Total Yangon project 20820 18040 66kV Substaion bays 6 180 648 432 132/33kV Transformer MVA 200 16 1920 1280 230/132kV Transformer MVA 200 15 1800 1200 3 Upgrading System Control Faciities 230/66kV Transformer MVA 400 15 3600 2400 Communications * 4000 1600 33/1IkV Switchger Exteniona * 60 50 1800 1200 Outsataons * 55 80 2640 1760 Buildings, Land & Civil 10 100 200 1000i System Control Center * 3000 1200 Total Substations projet 13808 10072 Buildings, Land & Civil 1 600 120 600 Total SCC Pfojle 9640 4560 Total Transmision Projets $69,276 $52.464 166 ANNEX 5.6 SUMMARY OF DISTRIBUTION INVESTMENT PROPOSALS s000/ Cost US$000 Year $000/ cost US 0 Qty Unit FC LC+t&x @ 0% FC I/ Qty Unrt FC LCtx I Yangon 11/0.4kV Reabiltaon 3 New Towns Projects 33kV Swltebjeer. feedr * 10 20 140 60 33kV Switchgear. feedas 10 20 140 60 33kV OHmain Hum, km ' 25 18 270 180 33FV OM/H minnes, km 100 18 1080 720 llkVO/Hms nu1a .km ' 175 12 1260 840 llkVO/Hmailn lia.km 300 12 2160 1440 1lkVO/HTeeoffs,km $ 225 9 1215 810 lIkVOMHTeeoffs,km 100 9 540 360 1IkVO/H swiche0@3km * 133 3 360 40 11kVO/Hswitche 03km 133 3 360 40 IkV U/O Cablua,k * IS0 45 472S 2025 11/,4kV Trafo., MVA 40 IS 648 72 111,4kV Trfos, MVA ' 300 18 4860 540 1 lkV Switchgear, feeders 20 12 168 72 llkV Swcgear, feeders * 60 12 504 216 LV O/H Lines, km 400 8 1920 1280 LV OH Liner. km ' 500 8 2400 1600 Consumer Connes ,000 60 48 1728 1152 LV U/G Cables, km * 390 40 10920 4680 Tools & Equipment 1000 30 Consumer Connects .000 * ISO 48 5184 3456 Buildings, Land & Civil 5 20 80 100 lndustrl Conects 60 20 840 360 ToW New Towns Projea 431 9764 S326 Tools & Equipment e 1000 0 E£ldin. Land & Civil * 50 20 200 1000 4 Other Divisions/States MW $/kW Total Yangon Projoct 19OMW@$/kW 382 33878 15807 Ayeyarwady 28-68MW 35 431 9764 S326 Bago 75-182MW 85 431 23713 12935 2 Mandalay Division Magwe 90-218MW 100 431 27897 15217 33kV Switchgear, feeders 30 20 420 180 SiagLng 25-60MW 30 431 8369 4565 33kVO/Hmain lnes.km 168 18 1814 1210 SixStates/2Divn 25-60MW 30 431 8369 4565 1 kV O/H mainlines. km 300 12 2160 1440 Total States/Divisions Project 78112 42608 l IkV O/H Teeoffs. km 100 9 540 360 lIkVO/H witches@t3km 133 3 360 40 5 RuralElctrification Il/l4kVTrafos. MVA 60 18 972 108 33kV O/H main lines, km 200 18 2160 1440 llkVSwitchgear. feden 40 12 336 144 IIkVO/HTeeoff .km 100 9 540 360 LVO/HLines km 400 8 1920 1280 IlkVO/Hswitches@3km 33 3 2160 10 Consumer Connects .000 50 48 1440 960 1/1.4kV Trafos. MVA 40 18 648 72 IndustriAl Connet ' 60 8 336 144 1 lkV Switchgeus, feeders 20 12 168 72 Tools & Equipment 1000 0 LV O/H Lines. km 400 8 1920 1280 BuDdings.LandLCivil 5 20 20 100 ConumerConnect, 000 60 48 1728 1152 Tol Mandalay Project. 3SMW /kW 494 11318 5966 Tools & Equipment 1000 30 Bugdings, Land & Civil 5 20 20 100 Total Distribution Project $143.416 $74,223 Total First RE Projet 425 10344 4516 167 ANNEX 5.7 CAPITAL INVESTMENTS FOR PLANT GENERATION/REHABILITATION. TRANSMISSION AND DISTRIBUTION GENERATION/REHABILITATION 1991-2000 1991-1995 1995-2000 Year TOT FC TOT FC TOT FC Rehabilitation Proiect I/S Ms m$ mS m$ mS mS LAwpita Rehabilitation 1993 55.09 31.24 55.09 31.24 Baluchaung#1 1994 65.50 41.66 65.50 41.66 Ywama Steam turbines 1993 9.79 7.29 9.79 7.29 Spares for Gas Turbines 1994 15.23 12.84 15.23 12.84 Total Rehabiltation 145.61 93.03 145.61 . 3.03 Gooeration Proiets mw SHW C-C#1 Swedaung 82 1994 41.50 33.30 41.50 33.30 MAN C-C#2 Mann 82 1994 49.40 39.50 49.40 39.50 MYC C-C#3 Myanaung#1 65 1995 36.60 25.70 36.60 25.70 THAC C-C#5 Tbaketa 85 1995 43.S0 30.40 43.50 30.40 YAN C_C#1 50 1996 46.60 32.60 46.60 32.60 YAN C_C#2 50 1997 46.60 32.60 32.90 23.00 13.70 9.60 YAN C_C/3 S0 1998 46.60 32.60 5.20 3.60 41.40 29.00 YAN C C#4 100 1999 93.10 65.20 0.00 0.00 93.10 65.20 YAN C=C#5 50 1999 46.60 32.60 0.00 0.00 46.60 32.60 Total Goncration 614 450.5 324.5 255.7 188.1 194.8 136.4 Generation Piants inc Rehabilitation 596.11 417.53 401.31 281.13 194.80 136.40 TRANSMISSION Year 1991-2000 1991-1995 1995-200 I/S TOT FC TOT PC TOT FC InterconnectionThatonSystem 1994 15.18 8.62 15.18 8.62 0.00 0.00 Yangon 66kV Reinforcement 1996 44.08 24.25 44.08 24.25 0.00 0.00 Upgrading System Control Facilities 1997 16.24 11.23 14.89 9.87 1.35 1.35 Ayarwardy 66kV Subtransmission 1997 9.99 3.78 2.52 0.99 7.46 4.79 Monya/Kyunchaung/Mandalay 132kV Sys 1999 25.71 14.73 0.00 0.00 25.71 14.73 General Substation Upgrading 200C 27.15 16.08 0.00 0.00 27.15 16.08 Total Transmission PropEcts 138.35 80.69 76.66 43.74 61.68 36.96 DISTRIBUTION Year 1991-2000 1991-1995 1995-2000 I/S TOT FC TOT FC TOT FC Yangon 11/0.4kV Rehabilitation 1995 57.04 37.74 57.04 37.74 0.00 0.00 Mandalay Division 1996 19.89 12.61 19.89 12.61 0.00 0.00 New Towns Projects 1998 17.38 10.88 13.10 9.58 4.28 1.30 Other Divisions/Staes I 1999 69.52 43.51 42.54 33.59 26.99 9.92 Other Divisions/States I 2000 69.52 43.51 0.00 0.00 69.52 43.51 Rural Electrification 2000 17.04 11.52 0.00 0.00 17.04 11.52 Totl Distribution Projects 250.41 159.78 132.58 93.52 117.83 66.26 AN~NEX5.1 Ccm3fatita cSOil md LIAN RWmMa,MII C001,43111OI: DIMe Ca, Peca 12M.Aft."124 A.W.. To"h A.IkWO- T~..V~m.m. 9. PC LC PC Le Lab A.t Fe IC 1998 gm9 It"1 3992 3to" 898141 38911 311 low am coUAUuSNo.Ct NW MV MW .s *e1 T. F . .11 J; Fe Le PC IC PC LIC PC IC PC IC PC IC Fe IC Fe IC f IC .c- IC L I To84&84balif 89 a". tat8 2 0.3274889 334 m03 A0l 84 a0" 5. 32 5* 84`2 1A 30. 5A 80. IA SU2 IA 9. La CI." -111" la 40.A I03. to" u." to 30 10.mmuU111 30 Is 43 83. 41 3.3 4.5 IS 4.1 3.8 Ui 8.8 42 £ U U KM*89cC392 a 4111.21 SW30.489 NJ to.1 .4 04.13233 go 212 85 8 . 5.8 35 33LS 1.3 3.1 iSiL 1 8 Ls 13 135 MYCE C-mIw qune is *153.3 IS 399 a1. 33.0 3 0.313811114 5 23 IA I3. 8.4 314 34 3.5 La Ai 84 8.1 8.3 8. ThA C C U f aS aN.? 352.? 893 mi 13. 3 00A31307 a 38 4.3 3.7 4.3 L.S 4.I 3.1 4Ca 8.? 4.3 8.5 4. 3.? ETAC C-CilE1db 30 all. SW$3 nu9 M4 84. 2 0.320,91115 a5 7 42 3.S 4.2 IA6 42 is 42 Ii 4. is9 KYAC C-CI8K1ft 19 451 219.5 gm9 319 84.0 2 0.81849I A 20 43 3.2 4.2 is 4.) 8* 4.5 Si NOWC r-cpa,K,.a so "Ls. SM9 so99 12. 842 21 0.)4894 14 30 412 8* 4.2 33 4. LI9 NOWC c-a1Kim me 452. 2n19. 898 45.2 3*k 25 0.1214944 84 43 6. A 1.3 IA 11WC C-aIE,.sah 30 $14518 219.13 ISA 84. 21 0.3214998 44 30 4.1 3*6 11WC c-cngon. 8W 452. 21.J, 30 42 23.0 25a 4821484 It 1 NOWC C-CONabW4 MS "is. 273 3M 45.2 Mi. II 0.8214998 72 52 LcgO Fwosm no 1311.4 83013 IM 111* 854. 40 0.3333014511 SW 323 NW gashobas% 10 3320.3 87119.) M2 IN. 49.9 a 0.8323304 40 1 MO1 Tern. 95 330 1 3.9?M1 M$ 421.4 n2. 48 0.821345 358 28) LOMa u M% 4 8413.3 99.3 33 511. 230. a 0,321301 2la 345 Lemo 23ck W0 2344. 3391. MN 419. S39VA 4 0.321134 21 3I" MT .ome 95 41330 29303 2 24513Un 144.4 40 0.32113K4 SW 541 LaOM £-Cbq no lout 8043.) MN 340 3. do 0.311304 311 23 8 Told 0-vake t...3*wMaC.uM SM0 31 a 0 0 0 to 4 30 21 it 12 Is 14 Is so 31 a1 0 8) 8 fmh 3s940 4 TwAGM.Fmp.11100l M875.? Fi Vbs a1 30 84.8 92. Ito 415 710 33.3 92.5 80.2 133.2 tea rwmIsoeb4 84. 399w 9 3.8 0.4 0.4 3.3 2.9, to 20 2.9 3.8 2IS 1 0p.84.a U..m 6520 3020 33D a -It 83.0 -3.8 92.9 -ad a28 -04 NA -3.8 4153 -1. We -&40 91.8 -2.0 913 -2.2 801.2 -3.8 332.3 -2.7 * 3Wh . C 1- . 1 841 89.91 -9.8 0.0 0.0 0.0 0.0 0.0 9.8 30.1 U. 7.1 4.9 34.1 1.2 28A6 12 a". 4.4 18.8 1.3 91.9 4.8 7INFOnwp w wod . 3ot213 83r 113ti son 0.0 0.0 0.0 0.0 M30. 84.2 41.1 34.8 35.3 38.-2 45.1 30.3 514 22.0 84 21*0 339.3 V21. 330.8 231.4 * Tod T8nm" hg 12 23 0.0 0.0 0.2 0.3 0.9 0.9 IA Li 5.S 8 L.5 4.3 1.8 La3 2.9 47 *91W 0in"4p.,h.T,kCw 8234 314 0.0 0.0 0.8 00 302 34.2 494 84.9 its1 33.9 49.3 25.3 45. Kg. 82. 21. 124.4 55.2 819.1315.3 30 ol ? wAbw3 rp 4 85 21 0 0.0 0 0.0" 0. 4.1 2.0 5.2 2.3 5.s 2.2 1.0 3.5 32.0 ". 833 08s 33rra Mik. i sae imf 33) 82 0.0 0.0 (M0 0. 0.3 84.2 a44 34.9 82.2 39t9 52. 12. 45.7 DJ5 8253 238. ins4 KS. 34 19.9 31 ?GW ome.T .8. i..&avidbs 329 11 OD0 0.0 00 0.0 30.2 342 494 34.9 40.4 3D.9 15.3 23.3 OA. 59 149.0 PD.A 82* 39.4 311.3 4.4 NW 03.3 MW 0.3 MW 0.3, dW W 0. b 0.3 MW 0.3 KW 0.3, MW 0.3 KW 0.3 MW 0.3 38 I AMW41 WbOswsu 19.3 USI2 433.1 7218.9 452.2 2M1.1 499A 134. 9A 337.1 5293 23. 43.7 8480.8 454. 23114.3 454.2 313. 1130454.4G M11. 42980 eWOWOsni1 .. .2333 83194 13 mm5 8114.3 343.1 541.54 2354. 1"Xs 4254 4292. lW~~~~..MW.qs~~~~~~~.gii.w 842~~~~~~~t IOU 314A 45.2 xi. 111 SA 88 19.9 MIMIPI 95Wi mm. Li16110 Ahmp .ift.3 law Id95 .3080 b*3IM PA- L.Fmhli. All-doe3*3ftek 30I20aulI b.MW I-u Im PM& Bmw LM" 1111 If INW E-w8t Lam No fItrim cmr e&wk GM1 M1101101 . 3 .41131 L-m &e [hDw.I- Cm 43 ..0 41 .4.1402Wb "Wm of .4,11 MP1, ubs b 0emoes as t.o 4.40 0.3 VI1 2.30 0.84 G-m*e. as 1.(0 4.1) CLIO 30 2.ID 0.59 Tnomita019332%42V5 Ss Was O."1 0.31 145 0.41 SU) Sw 0.21 Te.Mm.C3011132%VS as 30% 0.19 0.31 5.84 O."4 130 5. 0.41 sawwnwwooagv) is 800 C.19 0.07 4. 0.23 352 8.8 0.14 01MIim.ift1U&V) as *0l 0.30 0.09* 4.1 0.91 2M S."5 am MedmVAMPgg.vaA5 40 350 0.ds 0.30 '.94 3.45 s4o C"1 0.65 Mei.6V I p(133 dk7% is Is% 0.42 0.35 1.94 8.33 845 4.119 0J84 8.e Veb.W 4MwS 30 13o; 0.14 0.14 84.0 9.82 459 974 3.34 L-..V.bp(23024V5 40 10 041 047 08 U1.3 14. 41 4.713 2.8 IsAd 140 "MO 0." A, LAW 3040 3321 423 4.51 6.11 4 I I "30 0.3 LA.LIVM 4.05 94.0 aS4 34 1.43 169 ANNEX 5.9 SUMMARY OF MEPE TAREFFS Effectlve Seetember 1.1981 Effective November 1.1988 CATEGORY Energy Chrge. Pya/ Cap- dty C nag Kyab Eneg Chargeu Pya/ Capity Chrge Kyas kWh Fixed Charge Kys /HP kWh Fixed Charge Kyals /HP I General Purpowe Firt lOOkWh 46 Single Phae I Fla Rate 50 Single Phase 2 Exces 42 Three Phas 3 Three Phas 5 2 Dometc Power Fht SOkWh 23 Single Phas I Fat RAd 50 Single Phas 2 (Yangon) EXCes 19 Three Phe 3 Three Phase S 3 Small Power Flat Rate 25 Single Phas 6 1 Fla Rate SO Single Phase 8 Thre Pha 15 4 Induratrl Min 2000kWh (a) Yangon First 40kWh/kW MD 17 Three Phase 12 Flat Rue 4S Three Phae 15 min 50kW Exceu IS Three Phase 25 Three Phase 25 (b) Elsewhere First 200kWh 25 Three Phae 15 1 Three Phase IS I min 2000kWh Exces 20 5 Large Industry Flat Rate 12 Three Phae 25 Min 4GWh Three Phas 25 1 6 Bulk (a) Yangon Fit 40kWh/kW MD 40 Three Phas 25 Min 2000kWh Three Phase 25 1 min SOkW Exec 24 Flat Rate 45 (b) Elsewhere First SOkWh 54 three Phas 15 Three Phase 15 min 5OOkWh Excess U4 7 Street Lights min40 =At Flatrae 8 Flatrme 8 Excess /addt IOW 2 Exces /adda IOW 2 8 Temporary Lighting As for Gen Purp. 46 Excec 42 ANNEX 6.1 ESTMA&TES OF WOODFUEL STANDING STOCK BY DMSION/STIATE (milin ADT) Closed Degraded Under Forest Forest gnywh Roadside, Division/ Cled Affected by Degrd. Affced by Sawmill Nomoow Vi11ges, State Forest Shift.CuIt Fores SbiftCulL Residues Tre Plantation Farm Trees Total Ayeyarwaly 30.83 0.00 4.02 0.00 26.47 0.005 0.10 1.30 62.71 Yangon 5.25 0.22 0.32 0.09 4.56 0.001 0.12 1.30 11.87 Bago 90.63 1.40 3.02 0.85 76.13 0.015 0.88 3.20 177.13 Shan 11.25 60.70 7.64 13.20 68.19 0.015 0.32 3.10 164.40 Rakhine 61.75 6.43 3.12 0.74 56.58 0.011 0.04 1.80 130.48 o Mamnduly 30.00 4.48 4.06 0.60 29.87 0.006 0.45 1.00 70.47 Sagaing 18.00 24.08 8.35 0.45 39.32 0.008 0.20 1.05 91.46 Mon 2.08 1.76 1.70 0.71 4.11 0.001 0.08 1.25 11.69 Tanindmryi 35.00 6.68 3.02 2.60 35.72 0.007 0.02 0.70 83.75 Chin 12.00 12.60 5.48 12.18 23.53 0.005 0.03 0.10 55.92 Kayah 0.75 6.48 1.60 0.68 7.13 0.002 0.02 0.10 16.76 Kayin 18.75 15.92 1.42 2.03 29.98 0.006 0.08 1.00 69.18 Kachin 17.50 28.96 0.98 1.38 40.06 0.007 0.03 0.75 89.66 Magway 35.00 1.55 13.32 0.72 35.50 0.008 0.24 0.85 87.18 Tota 368.78 172.26 58.05 26.24 477.12 0.100 2.61 17.50 1122.65 ANNEX 6.2 CROP RESIDUES AVAILABLE FOR FUEL (1080 ADT) _ adh Maiz Sea.mimn cott. TCro Crop R. RedL Crop Res. ReaL Crop Ru. Read. Crop Re. Red Crop Re. Red Cro Pm Re Cro Re Re. Rd Stt Prod Prod Avai Prd Prd Avail Prod Prod Avai Po Po Avail Po Pd Avag Po Pr Avai Pd Prod Avau. Aval. Ayyarw 3937 4134 1378 0 0 0 13 30 12 5 20 5 0 0 0 31 6 1 0 0 0 196 Ymawi 445 1517 506 0 0 0 1 2 1 4 16 4 0 0 0 46 9 2 0 0 0 512 Bago 2Q-3 2754 918 0 0 0 20 46 18 37 148 37 2 7 7 785 IS7 31 0 0 0 1012 Shan w 848 283 0 0 0 67 154 60 2 8 2 0 0 0 234 47 9 0 0 0 354 Rakhiae 831 873 291 0 0 0 1 2 1 0 0 0 0 0 0 41 t 2 0 0 0 293 Mmdaay 571 600 200 21 143 31 46 l06 41 23 92 23 33 119 119 786 157 31 26 130 130 6 Sagalg 1067 1120 373 14 39 8 58 133 52120 80 20 12 43 43 92 It 4 7 35 35 544 Mae 6SI 684 228 0 0 0 2 5 A t 4 1 0 0 4 10 30 6 0 0 0 237 Tmnalot 210 221 74 0 C 0 0 0 0 0 0 0 0 0 0 IS 3 1 0 0 0 74 Chin S0 53 18 0 0 0 32 74 29 0 0 0 0 0 0 5 I 0 0 0 C 47 Kaya Ss5 58 19 2 6 1 4 9 4 0 0 0 0 0 0 0 0 0 0 0 C 25 Kayin 280 294 98 0 0 0 1 2 1 1 4 1 0 0 0 SS 11 2 0 0 0 102 Kachi 240 225 84 0 0 0 7 16 6 0 0 0 0 0 0 62 12 2 0 0 0 93 Msgway 292 307 102 34 95 20 61 140 55 49 196 55 13 47 47 14 3 1 7 35 35 329 Totra 13060 13713 4S71 101 283 61 313 720 282 142 568 142 60 216 216 2316 463 93 40 200 562 200 Somean Mbam Eam_ ANE 6.3 WOODY & NON-WOODY BIOMASS CONSUMPTION ESTiMATES Rurd Urban Houwlld Noe-Hbold Total Houald No*-Hbold Totl Totl DlvlalSte Populaion 1983 PFoptadoa 1990 Howchld Houabd Woodfl'd Woodfuel Woodfue Na-Wdfl No-Wd Bio Non-Wd Bbi Biolul Woodfue Woodfiwd Cuompn Coeu mpt Cmmi Coammpi C aINIt Co_MMpt C oamu_ Rrl Urban Ra Urban Coasumpt. Consumpt 1990 1990 1990 1990 1990 1990 1990 (Malian) (million) (mm ADI) (mill AD) (mi ADT) (mi AM) (mM ADT) (mill A7) (ml ADT) 'mifl ADT) (mill ADT) Ayyarwady 4.25 0.74 4.87 0.35 3.34 0.59 3.92 0.07 3.99 0.08 0.05 0.13 4.12 Yrgo 1.28 2.69 1.47 3,10 1.01 2.13 2.07 0.63 2.70 0.02 0.42 0.44 3.14 BDp 3.06 0.74 3.50 0.85 2.40 0.59 2.99 0.13 3.12 0.06 0.09 0.IS 3.27 Shen 3.06 0.66 3.50 0.76 2.40 0.52 2.93 0.05 2.98 0.06 0.03 0.09 3.07 Rakhln 1.74 0.3 1.99 0.35 1.37 0.24 1.60 0.03 1.63 0.03 0.02 0.05 1.63t Manday 3.37 1.21 3.86 1.40 2.65 0.96 3.60 0.19 3.79 0.07 0.13 0.20 3.99 SaplnU 3.33 0.53 3.81 0.61 2.62 0.42 3.03 0.16 3.I9 0.06 0.11 0.17 3.36 Magway 2.75 0.49 3.15 0.56 2.16 0.39 2.55 0.09 2.64 0.05 0.06 0.11 2.75 Mmo 1.21 0.47 1.39 0.54 0.95 A.37 1.32 0.02 1.35 0.03 0.02 0.04 1.39 TaidA 0.70 0.22 0.80 0.25 O.SS 0.17 0.72 0.01 0.74 0.01 0.01 0.02 0.76 chin 0.31 0.05 0.35 0.06 0.24 0.04 0.28 0.01 0.30 0.01 0.01 0.02 0.31 Kayah 0.13 0.04 0.I5 0.05 0.10 0.03 0.13 0.00 0.14 0.00 0.00 001 0.14 Kqin 0.95 0.11 1.09 0.13 0.75 0.09 0.83 0.01 0.85 0.02 0.01 0.03 0.87 Kahin 0.72 0.18 0.12 0.21 0.57 0.14 0.71 0.04 0.74 0.01 0.02 0.04 0.78 Totals 26.86 8.43 30.75 9.72 21.09 6.67 26.70 1.45 28.15 0.52 0.97 1.49 29.64 Sour= Minion Edmatu 173 ANNEX 6,4 CHARCOAL PRODUCTION AND TRANSPORT COSTS A221 Cost/Item Cuting & Transport of Wood kyats 100-110 ADT Loading Kiln kyats 10 per ADT Piriag & Watching kyats 10 per ADT Unloading Kyats 0.2 per viss (1) Kiln Licnce kyats 0.01 per viss Cost of Bag/Basket kyats 0.2 per viss for baskets (kyats 2-2.5 each) kyats 0.55 per vies for bags (kyats 3.5-7 each) Transport to Packer (Ayoyarwady) kyats per 0.12 per viss (150 miles) Packing in Basket/Bag kyat 0.06 per viss Transport to Yangon: By Ship kyat S per basket (2) (kyats 0.4 per viss; kyats 1.4/ton/mile) plus an average of kyats 1 each for loading and unloading By Road kyat 40 per bag (3) (kyats 1.6 per viss; kyats 4.5/ton/mile) plus kyats 3 per bag for loading/unloading Local Transport kyat 0.6 per vise (1) Viss is equivalent to 3.6 lb. (2) Baskets varied in size from 7.5 to 15 viss (27 to 54 lb), but the average and most common size as seen and measured by the mission was 12.5 vies (45 lb.) (3) Bags observed w¢re dther 16.5 or 25 viss (60 to 90 Ibs.), but the most common appeared to be the latter. The trucks are grossly overloaded with 6-ton trucks carrying as much as 9.5 tos (240 90 lb bags). In some instances charcoal was carried in bulk by truck to Yangon. SOURCE: Mission 174 ANMX6.S COST OF PUELWOOD COLLECTION AND TRANSPORT km DtM (kvts/ADT) Cutting & Carrying of Wood 10S Loding 20 Transport by Ship 240 (kcyts 2.S/ADT/mile) Transport by Road 140 (kyats 7.0/ADT/mile) Unloading 30 SOURCE: Mission 175 Fiaure 6.1 T.ade of Woodfuels in Yangon Catchment. 1990 (m4llion ADT) HagvAY 0.2 las0 a A.vyarvady 0 Yangon Rakhino g 0 Tanincharyi Yangon consumption in 1990 estimated at 2.7 million ADT of which 1.8 miUlion ADT imported. 176 Figure 6.2 Trade of VJoodfuels in Yangon Catchmenc, 2005 (millLon ADT) saga Rakhine 0.7 o.3 0 Yangon j0 TaMnnharyt In 2005, Yango woofud aontmption is projeod to be 4.7 m1Ilion ADT of whic 2.4 million ADT is WVorted 177 ANNE 7.1 (a) HYDROCARBON FUEL MCES. IN 1989 IN MYANMAR FUEL UNIT PRICE Crudo Oil & Condensate (MOGE/MPE) Ky/B 110.00 Ky/IG 3.14 Gas (MOGE to Consumers) Ky/MCF 7.50 CNG Ky/150 CF 10.00 Ky/MCF 66.67 LPG Ky/B 297.50 Ky/IG 8.50 Petrol Ky/JG 16.00 Kerosene Ky/JG 13.50 Aviation Fuel KylIG 13.50 Diesel Ky/lG 10.50 Cooldng Gas/Oil Ky/IG 8.50 Petroleum Coke Ky/JG 8.50 Methanol Ky/JG 8.50 Metaol with Petrol Ky/IG 11.00 SOURCE: MOGE ANE 7.1 (b BASE YEAR PRICES OP KEY ENERGY PRODUCTS IN MYANMAR (1991 1dosr ESTDA1ED iERNMATIONAL PRICES ;AN 1991 IdYANMAR OPICOSQ TUNn[LX VALUES MXliM Kyat USS EquIv O Kyaa US$ Fnl O 50 KfUS$ so KRJSS CndeOil US$/B 26 3.145 /1o 0.06 /na 36.60 /10 O.n /10 Diued LUSS/B 32 IO.50 na0 0.21 IIG 45.44 Q0 0.91 /10 Hevy Fed Ol US$1B 25 850 no 0.17 /10 35.13 fl0 0.70 fi1 Not Ou (cast) US$IMCF 2 7.50 IMCF 0.15 /MCF 100.00 IMCF 2.00 IMCF LNG US$MCP 4 Codl USS$/on 39 365.00 /too 7.30 Atm 1957.00 hom 39.14 1A PARAMETEtS AND CONVERSION FACTORS (Pramtr with er drivu pa*m* ers) B equas 34.9726 IG I equa 0.219969 10 I equab 0.006289SI B crubd 1512 ml cal/n Dicud 1463 m catiB HeEVY Fud Oil 1532 mi1 cdlB MCF gS 252 mIi callMCF MCF equiv 0.167 Bcrue on Kalew Coal 5600 mm cal_to_ INTERNATIONAL 1991 Dlyv ENERGY PRICES FOB Pric LiNkg Ri * Ce4 Crude On 1 20.60 US$B S US$1B Died 26.78 US$1B Died/crude 1.300D 5 US$/B Heavy Fad Oil 19.57 US1B HFO/Crnde 0.9500 5 US$/B Nt Ga Coat * 2.00 US$fMCF LNG (ddhred) 3.69 US$/MCF LNG/1HO 0.1500 Stem Coa 29.14 US$Aou CoJ/HFO 2.0000 10 /to OTHER ASSUMPTlONS (PARMETERS} EffectEie dc Rat * SO KIUSS Escalatlio Is 0 Price 3.00% yr to 2000 dea fa 179 ANNEX 7.1 (b) (cont'd) BASE YEAR PMCES OF KEY ENERGY PRODUCS IN MYANAR FORECAST OPPORTUNITY VALUE PRIC ES FOR MYAN-MAR ENERGY PRO!UCTS Fuel Natural Crudo Oil Dha Ol Ca" LNG coal End Fob Cif Cif Cif Cif Cif Cif Yewr (1991 Doluls) US$IB US$1B US$SB USSIB USS/MCF US$/MCF US$STON 1990 20.00 25.00 31.00 24.00 2.00 3.60 38.00 1991 20.60 25.60 31.78 A4.57 2.00 3.69 39.14 1992 21.22 26.22 32.58 16 2.00 3.77 40.31 1993 21.85 26.85 33.41 6 2.00 3.86 41.52 1994 22.51 27.51 34.26 &-.38 2.00 3.96 42.77 1995 23.19 28.19 35.14 27.03 2.00 4.05 44.05 1996 23.88 28.88 36.05 27.69 2.00 4.15 45.37 1997 24.60 29.60 36.98 28.37 2.00 4.26 46.74 1998 25.34 30.34 37.94 29.07 2.00 4.36 48.14 1999 26.10 31.10 38.92 29.79 2.00 4.47 49.58 2000 26.88 31.88 39.94 p3.53 2.00 4.58 51.07 2001 27.00 32.00 40.10 30.65 2.00 4.60 51.30 2002 27.00 32.00 40.10 30.65 2.00 4.60 51.30 2003 27.00 32.00 40.10 30.65 2.00 4.60 51.30 2004 27.00 32.00 40.10 30.65 2.00 4.60 51.30 2005 27.00 32.00 40.10 30.65 2.00 4.60 51.30 2006 27.00 32.00 40.10 30.65 2.00 4.60 51.30 2007 27.00 32.00 40.10 30.65 2.00 4.60 51.30 2008 27.00 32.00 40.10 30.65 2.00 4.60 51.30 2009 27.00 32.00 40.10 30.65 2.00 4.60 51.30 2010 27.00 32.00 40.10 30.65 2.00 4.60 51.30 Source: Parammters, Converdon Rat, and Assumptions in Table 7.1 (b) 180 ANNEX 7.2 (a) PE3TROLEUM pRODUCT PRICES MAIN ASSUMPTIONS International Crude Price 17.75 USS/B at 6.20 kWUS$ MOGE handover Price Crude 110 kIB Best estimat of costs, prices and tax rates in late 1990 EXISTING SITUATION IN MYANMAR, LATE 1990 PETROLEUM PRODUCT PRICING (kIcl) TOTALS/ Patrol Kero Diojso Fuel Oil Av Fuel AVGES. Ex MOGE(crude) 3.14 3.14 3.14 3.14 3.14 3.14 Cost of Refining 2.03 2.15 1.32 2.00 2.15 1.64 Factory cost 5.17 5.29 4.46 5.14 5.29 4.79 Profit Margir 5.0% 0.26 0.26 0.22 0.26 0.26 0.24 ex ref coat without tuxes 5.43 5.56 4.69 5.40 5.56 5.03 Commodity Tax Rate 170% 80% 90% 35% 115% 102% Commodity Tax 8.80 4.24 4.02 1.80 6.09 4.91 Total Cort ex refinry 14.23 9.79 8.70 7.20 11.65 9.94 Excess coat to MPE over handover price 2.43 -0.21 1.10 1.20 1.65 1.45 1990 Fixed Handover Price 11.80 10.00 7.60 6.00 10.00 8.49 Distribution Costa 3.06 2.58 2.14 1.85 2.58 2.34 Profit Margin 2.0% 0.30 0.25 0.19 0.16 0.25 0.22 Sales Tax on o 5.0% 0.80 0.68 0.5Z 0.42 0.68 0.58 Total Cost ex distrib 15.96 13.51 10.45 8.43 13.51 11.63 Excess cost to MPPE over sales price -0.04 0.01 -0.05 -0.07 0.01 -0.05 1990 Fixed Consumer Sales Price 16.00 13.50 10.50 8.50 13.50 11.68 AU Taxes 9.59 4.91 4.54 2.22 6.76 5.50 Taxas % ConsPrice 60.0% 36.9% 39.1% 22.9% 44.4% 41.81% Consumption 1990 MM IO 38.06 2.21 83.82 24.56 4.64 153.29 Tax Revenues MM kyat 365.1 10.9 380.6 54.6 31.4 842.48 Tax Revenues MM USS at k6.2/US$ 58.9 1.8 61.4 8.8 5.1 135.97 atassumed FX rate 58.9 1.8 61.4 8.8 5.1 135.97 at kSO/US$ 7.30 0.22 7.61 1.09 0.63 16.85 COST AND TAXES ON TRUE COST-PLUS BASIS Costs (k/10) 8.79 8.39 7.02 7.41 8.39 7.58 Commodity Tax 8.80 4.24 4.02 1.80 6.09 4.91 Sales Tax on cost-plus price 0.93 0.66 0.58 0.48 0.76 0.66 Total Price on Cost-Plus Basis 18.52 13.29 11.62 9.69 15.24 13.15 The refinery cost allocations are as given by MPE to MOE in late 1990 In refinery operation tbe Profit margin is S% of factory cost, and commodity tax is calculatod on factory cost ex argin In distribution the 2% margin is on handover price plus dist costs without taxes. The sals tax is 5% times the official consumer price 181 ANNEX 7.2 (b PETROLEUM PRODUCT PRICEiS MAIN ASSUMPTIONS Ilnteratonal Crude Price 25.00 USS/B at 6.20 k/USS MOGE handover Price Cdoe 155 k/B Cnude oil price incroead to US$25/B Fuel oil commodity tax decreased to 30%, as in oerly 1991 ILLUSTRATION OP COST-PLUS PRICES, ON BASIS OF US$25/B CRUDE AS AT EARLY 1991 PETROLEUM PRODUCT PRICING (kIG) TOTALS/ Petrol Kro Diosol Fuel Oil Av Fuel AVOES. Ex MOGE(crude) 4.43 4.43 4.43 4.43 4.43 4.43 Cost of Rofining 2.03 2.15 1.32 2.00 2.15 1.64 Factory cost 6.46 6.58 5.75 6.43 6.58 6.07 Profit Margin 5.0% 0.32 0.33 0.29 0.32 0.33 0.30 ex ref cost without taxes 6.78 6.91 6.04 6.75 6.91 6.38 Conumodity Tax Rate 170% 80% 90% 30% 115% 101% Commodity Tax 10.98 5.26 5.17 1.93 7.57 6.17 Total Cot ox refiney 17.76 12.17 11.21 8.68 14.47 12.54 Distribution Costs 3.06 2.58 2.14 1.85 2.58 2.34 Profit Margin 2.0% 0.42 0.30 0.27 0.21 0.34 0.30 Sales Tax on cost-plus price 5.0% 1.12 0.79 0.72 0.57 0.92 0.80 Total Cost ox distrib 22.36 15.84 14.33 11.30 18.32 15.98 All Taxes 12.10 6.06 5.89 2.49 8.48 6.97 Tax a % Cons Price 54.1% 38.2% 41.1% 22.1% 46.3% 41.40% Consumption 1990 MM IG 38.06 2.21 83.82 24.56 4.64 153.29 Tax Revenues MM k,at 460.5 13.4 493.8 61.3 39.4 1068.23 Tax Revenues MM US$ at k6.2/US$ 74.3 2.2 79.7 9.9 6.35 172.41 at asumed FX rate 74.3 2.2 79.7 9.9 6.35 172.41 at kSO/US$ 9.21 0.27 9.88 1.23 0.79 21.36 COST AND TAXES ON TRUE COST-PLUS BASIS Costs (kIG) 10.26 9.79 8.44 8.81 9.83 9.01 Commodity Tax 10.98 5.26 5.17 1.93 7.57 6.17 Sales Tax on cost-plus price 1.12 0.79 0.72 0.57 0.92 0.80 Total Price on Cost-Plus Basi 22.36 15.84 14.33 11.30 18.32 15.98 The refinery cost allocations are as given by MPE to MOE in late 1990 In refinery operation die Profit margin is 5% of factory cost, and commodity tax is calculated on factory cost ox margin In distribution the 2% marin is on handover price plus dist costs witnout taxes. The sales tax is 5% times the cost-plus consumer price 182 ANNE 7.W PET^9EUJM PRODUCPlRICEWS MAIN ,? - - 'ePTIONS Intem'q. Jnudis Price 25.00 US$/B at 50.00 ktUSs MOGE hr .ver Price Crude 1250 k/B Crude ol pe Iincresed to US$2S/B. und fuel oil ecnauodity tax decreased to 30% u at early 1991 mad shadow exchango rate of k50/USS ILLUSTRATION OF COST-PLUS PRICES, ON BASIS OF US$25/B CRUDE AND EXCHANGE RATE OF k50/US$, AS AT EARLY 1991 PETROLEUM PRODUCT PRICING (kIO) TOTALS/ Pguob Kero _jojW Fuel Oil Av Fuel AVOES. Ex MOGE(crude) 35.74 35.74 35.74 35.74 35.74 35.74 Cct of Refining 2.03 2.15 1.32 2.00 2.15 1.64 Factory cost 37.77 37 89 37.06 37.74 37.89 37.38 Profit Marg 5.0% 1.89 1.89 1.85 1.89 1.89 1.87 ex ref cost without taxes 39.66 39.79 38.92 39.63 39.79 39.25 Comnmodity Tax Ate 170% 80% 90% 30% 115% 101% Commoxdty Tax 64.21 30.31 33.36 11.32 43.58 37.75 Tota Cost ex rfinery 103.87 70.10 72.27 50.95 83.36 77.01 Distribution Costs 3.06 2.58 2.14 1.85 2.58 2.34 Profit Marg 2.0% 2.14 1.45 1.49 1.06 1.72 1.59 Sales Tax o 5.0% 5.74 3.90 3.99 2.83 4.61 4.26 Total Cost ox distrib 114.82 78.04 79.89 56.69 92 28 85.19 All Taxs 69.95 34.22 37.35 14.16 48.19 42.01 Tax as % Cons Price 60.9% 43.8% 46.8% 25.0% 52.2% 46.91% Consumption 1990 MM IG 38.06 2.21 83.82 24.56 4.64 153.29 Tax Revenues MM kyat 2662.4 75.6 3130.7 347.7 223.6 6440.08 Tax Revenues MM USS at k6.2/US$ 429.7 12.2 505.3 56.1 36.1 1039.39 at assumed FX rate 53.2 1.5 62.6 7.0 4.5 128.80 at kS0/US$ 53.25 1.51 62.61 6.95 4.47 128.80 COST AND TAXES ON TRUE COST-PLUS BASIS Costs (k/lG) 44.86 43.82 42.54 42.53 44.09 43.18 Commodity Tax 64.21 30.31 33.36 11.32 43.58 37.75 Sales Tax on cost-plus price 5.74 3.90 3.99 2.83 4.61 4.26 Total Price on Coot-Plus Basis 114.82 78.04 79.89 56.69 92.28 35.19 The refinery coot allocations an as given by MPE to MOE in late 1990 In refinery popration the Profit margin is 5% of factory cost, aWn commodity tax is calculated on factory cost ex margin In distnbtion the 2% margin is on handover price plus dist costs without taxes. The sales tax is 5% tims the cost-plus consumer price 183 ANNEX 7.2 (d) PE3RQISEuM UPRO.UCT PRIME MAIN ASSUMIONS lterational Crude Price 25.00 US$/B et 50.00 k/US$ MOGE hanover Price Cmde 1250 k/B Crde oil price increasd to US$2S/B, an shadow o-change rate bf cSOfUSS; with decreases in all commodity tax rates ILLUSTRATION OF COST-PLUS PRICES, ON BASIS OF US$2S/B CRUDE EXCHANGE RATE OF kS0/US$, AND COMMODITY TAX REDUCTIONS, AS AT EARLY 1991 PETROLEUM PRODUCT PRICING (kIcG) TOTALS/ Potrol Koro 12iBoe Fuel Oil Avue AVOES. Ex MOGE(crude) 35.74 35.74 35.74 3S.74 3S.74 35.74 Coat of Refining 2.03 2.15 1.32 2.00 2.15 1.64 Fr'tory cost 37.77 37.89 37.06 37.74 37.89 37.38 Profit Margin 5.0% 1.89 1.89 1.8S 1.89 1.89 1.87 exrofcostwithouttamx 39.66 39.79 38.92 39.63 39.79 39.2S Commodity Tax Rate 100% 55% 60% 2S% 70% 65% Commodity Tax 37.77 20.84 22.24 9.44 26.52 24.15 Total Cost ox refinery 77.43 60.63 61.15 49.06 66.31 63.41 Distribution Costs 3.06 2.58 2.14 1.85 2.58 2.34 Profit Margin 2.0% 1.61 1.26 1.27 1.02 1.38 1.31 Sale. Tax on cost-plus price 5.0% 4.32 3.39 3.40 2.73 3.70 3.53 Total Cost ox distrib 86.43 67.87 67.95 54.66 73.97 70.S9 All Taxes 42.09 24.23 25.63 12.17 30.22 27.68 Tax as % Cons Price 48.7% 35.7% 37.7% 22.3% 40.9% 38.04% Consumption 1990 MM IG 38.06 2.21 83.82 24.56 4.64 153.29 Tax Revenues MM kyst 1602.1 53.6 2148.7 298.9 140.2 4243.47 Tax Revenues MM USS at k6.2/US$ 258.6 8.6 346.8 48.2 22.6 684.87 at assumed FX ra 32.0 1.1 43.0 6.0 2.8 84.87 at kso/USS 32.04 1.07 42.97 5.98 2.80 84.87 COST AND TAXES ON TRUE COST-PLUS BASIS Costs (kilO) 44.34 43.64 42.32 42.50 43.75 42.91 Commodity Tax 37.77 20.84 22.24 9.44 26.52 24.15 Sales Tax on cost-plus price 4.32 3.39 3.40 2.73 3.70 3.53 Total Price on Cost-Plus Basis 86.43 67.87 67.95 54.66 73.97 70.59 The refinery cost aliocatiosu are as given by MPE to MOE in late 1990 In refinery operation the Profit margn is 5% of factory cost, and commodity tax is calculated on factory cost ox margin In distribution the 2% margin is on handover price plus dist costs without taxes. The sales ta. is 5% times the cost-plus consumer price ANNEX 7.3 (a) BASE CASE - HIGH DEMAND AT OFFICIAL EXCHANGE RATE Mba : lo. S^msa BASE CASE (HM# dd)n FY 1979 1980 1981 1982 1953 1984 1985 1986 19S7 1988 199 1990 1991 1992 3 1994 Owh Geneabtd nat 9567 1060.0 120S.7 1370.4 1526.9 1646.6 1863.1 2062.3 2207.6 2281.1 2193.3 2371 2552 2717.1 289.7 30.7 Owh Sold 690.1 762.6 853.5 949.6 1050.0 1121.5 1263.6 1458.3 1543.0 1580.0 1428.2 1636.0 1760.9 190 2055.9 2222.4 Sulddencrated % 72.1% 71.9% 70.3% 69.3% 68.8% 68.15 67.8% 70.0% 69.9% 69.3% 65.1% 69.0% 69.0% 70.0% 71.0% 72. emss In ale s 10.5% 11.9% 11.3% 10.6% 6.8% 12.7% 15.4% 5.S% 2.4% -9.6% 14.5% 7.6% 1.0% t.1% $.1 Av. Pyalkwh aod 24.85 25.01 25.17 27.82 29.83 30.13 30.00 27.25 27.49 28.02 37.25 48.73 48.73 43.73 48.73 48.73 -KyMb mUlon- Opertng revene 171.5 190.7 214.8 264.2 313.3 337.9 379.2 397.4 424.3 442.8 532.0 797.2 M5S.1 927.1 1001.9 1063.0 OpurIftg cxpam Sahies&wages 30.1 30.5 30.6 44.5 44.7 46.7 47.0 49.5 51.1 56.7 58.2 131.8 133.5 133.5 133.5 U33.5 Maita_nce 31.2 34.7 36.1 34.2 41.9 43.1 37.5 38.5 49.S 46.7 44.8 62.7 63.1 63.1 63.1 63.1 Fuel I 35.5 34.3 50.3 49.0 54.0 6S.9 75.7 76.3 80.8 103.8 163.7 234.5 301.1 362.5 314.0 312.9 Power purwdses 1.2 2.3 0.9 IA 2.7 3.6 4.2 4.5 3.9 1.2 1.3 1.S 1.9 1.9 1.9 1.9 Dercptio 25.7 27.8 31.1 36.8 41.4 48.7 60.3 89.9 116.0 131.4 144.7 144.5 151.7 158.3 186.7 224.1 Commodty/serv Tax 7.0 7.8 8.7 11.1 13.1 14.3 15.9 14.4 15.6 17.2 23.5 31.2 33.5 35.7 38.1 40.6 Totl expenes 130.7 137.4 IS7.7 176.9 197.9 222.2 240.6 273.1 316.9 357.0 436.2 606.5 684.9 75S.1 737.3 776.1 Netopeatg cm 40.7 53.3 57.1 87.3 115.4 115.7 138.6 124.3 107.3 85.8 95.8 190.7 173.1 171.9 2.645 36.9 Od°r Incone 3.3 2.6 2.9 6.3 4.9 4.4 4.7 5.8 8.9 38.3 12.1 14.7 16.2 16.2 16.2 16.2 Interetdchaged 7.2 7.5 14.8 20.6 38.8 52.3 60.6 112.2 112.4 125.2 148.6 43.2 5'.8 72.9 153.3 315.4 Net ProfitLos 36.9 48.4 45.2 73.0 83.S 67.8 82.8 18.0 3.9 (1.1) (40.7) 162.2 138.5 115 127 8 State ceuib 7.4 14.5 13.6 21.9 24.4 20.3 24.8 5.4 1.2 0.0 0.0 162.2 138.5 135 ir I Net surplus (Deficit) 29.5 33.9 31.6 51.1 57.0 47.4 57.9 12.6 2.7 (1.1) (40.7) 0.0 0.0 0 0 0 Rate of Return on Av. not FAn 0s per Bookvlu sedusad 10.8% 10.1% 13:9% 15.9% 13.1% 14.7% 10.9% 6.9% 4.3% 45% 8.5% S.9% 5.1% 7.7% 8.5 a mision eMtat- MEPE aounts for FY 90 am ready in Nov 90. I Fue cost are high In FY 92, 93 & 94 due to shorItfain gms being mnad good by died oil. Asumed exchans rate k6.2USS 185 ANNEX 7.3 (a) (cout'd) BASE CASE - HIGH DEMAND AT OFFICIAL EXCHANGE RATE FUEL USE IN BASF CASE (High demand} 1990 1991 1992 1993 1994 1995 Gs use bcf 19.99 19.65 20.09 17.80 15.35 19.67 Fuel Oil Use mmb 0.00 0.00 ).40 0.30 0.30T 0.10 Diesel Use mmb 0.44 0.78 0.74 0.64 0.70 0.28 Price of gas k/mcf 7.50 7.50 7.50 7.50 7.50 7.50 Price of Fuel Oil USS/b 24.00 24.57 25.16 25.76 26.38 27.03 Price of diesel US$/b 31.00 31.78 32.58 33.41 34.26 35.14 Value of as mill kyat 149.93 147.38 150.68 133.50 115.13 147.53 Value of Fuel Oil mill kyat 0.00 0.00 62.40 47.91 49.07 16.76 Value of diesel mill kyat 84.57 153.69 149.48 132.57 148.69 61.00 TOTAL FUEL BILL (mill kyat) 234.49 301.06 362.55 313.98 312.88 225.29 Notes: kyat converted at k6.2/US$ Fuel use from WASP analysis ANNEX 7.3 LOW DEMAND AT OFFICIAL EXCHANGE RATE MP: lce S_Mua LOW DEMAND CASE 0 0 0 0 0 FY 1979 1980 1981 1982 1983 1984 1985 1986 1967 198 1919 I9M0 1991 1992 1993 1994 iOwh Genrated net 956.7 1060.0 1205.7 1370.4 1526.9 1646.6 1863.1 2082.3 2207.6 2211.1 2193.3 2371 2484.1 2519.1 2699.4 2315.3 IGwh Sold 690.1 762.6 853.5 949.6 1050.0 1121.5 1263.6 1458.3 1543.0 1510.0 1428.2 1636.0 1714.0 1312.4 1916.6 20Q7.0 IScodl/mnerated % 72.1% 71.9% 70.8% 69.3% 68.8% 68.1% 67.8% 70.0% 69.9% 69.3% 65.1% 69.0% 69.0% 70.e% 71.0% 72.0% Increase in sal % 10.5% 11.9% 11.3% 10.6% 6.8% 12.7% 15.4% 5.8% 2.4% -9.6% 14.5% 4.8% 5.7% 5.7% 5.8% Av. Pyas/kwh sohl * 24.85 2S.01 25.17 27.82 29.83 30.13 30.00 27.25 27.49 23.02 37.25 48.73 4L73 48.73 48.73 48.73 ---Kyats million- Opeating revenue 171.S 190.7 214.8 264.2 313.3 337.9 379.2 397.4 424.3 442.8 mo 797.2 335.2 6S.2 933.9 987.8 Operating expenses Salaries & wages 30.1 30.5 30.6 44.5 44.7 46.7 47.0 49.5 51.1 56.7 S8.2 131.8 133.5 133.5 133.5 133.5 Maintenawco 31.2 34.7 36.1 34.2 41.9 43.1 37.5 38.5 49.5 46.7 44.8 62.7 63.1 63.1 63.1 63.1 Fuel # 35.5 34.3 50.3 49.0 54.0 65.9 75.7 76.3 30.3 103.S 163.7 234.5 301.1 362.5 314.0 312.9 Power purchses 1.2 2.3 0.9 1.4 2.7 3.6 4.2 4.5 3.9 1.2 1.3 1.3 1.9 1.9 1.9 1.9 Dreciation 25.7 27.8 31.1 36.8 41.4 48.7 60.3 89.9 116.0 131.4 144.7 144. 151.7 158.3 186.7 224.1 Commoditylserv Tax 7.0 7.8 8.7 11.1 13.1 14.3 15.9 14.4 15.6 17.2 23.5 31.2 32.7 34.0 35.5 37.0 Total experscs 130.7 137.4 157.7 176.9 197.9 222.2 240.6 273.1 316.9 357.0 436.2 606.5 684.0 753.5 734.7 772.5 Net opentg income 40.7 53.3 57.1 87.3 115.4 115.7 138.6 124.3 107.3 35.8 95.8 190.7 151.2 129.7 199.2 215.2 Other income 3.3 2.6 2.9 6.3 4.9 4.4 4.7 5.8 8.9 3S.3 12.1 14.7 16.2 16.2 16.2 16.2 Intrest charged 7.2 7.5 14.8 20.6 38.8 52.3 60.6 112.2 112.4 125.2 148.6 43.2 50.8 72.9 153.3 315.4 Not Profit/LAss 36.9 48.4 45.2 73.0 81.5 67.8 82.8 18.0 3.9 (1.1) (40.7) 162.2 116.5 73 62 -3 State Contribution 7.4 14.5 13.6 21.9 24.4 20.3 24.8 5.4 1.2 0.0 0.0 162.2 116.5 73 62 0 Net sarplus (Deficit) 29.5 33.9 31.6 51.1 57.0 47.4 57.9 12.6 2.7 (1.1) (40.7) 0.0 0.0 0 0 -34 Rate of RtatnanonAv. net PAminOper Rook valusedas sea 10.8% 10.1% 13.9% 15.9% 13.1% 14.7% 10.9% 6.9% 4.3% 4.5% 3.5% 5.2% 3.7% 5.1% 4.5 a Mission estimates- MEPE acwcount for FY 90 not ready in Nov 90. # Fuel cos are high in PY 92, 93 & 94 di to shotfal ins being mud good by diesel oil. Assumed exchange ra 6.2 k/US$ ANNEX 7.3 (c) BASE CASE - HIGH DEMAND AT SHADOW EXCHANGE RATE MEPE: Income Statemnrt BASE CASE (High dsimd) FY 1979 1980 1981 IM 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 Gwh G ratr^'ed net 956.7 1060.0 1205.7 1370.4 1526.9 1646.6 1863.1 2082.3 2207.6 2281.1 2193.3 2371 2552 2717.8 2895.7 3086.7 Gwh Sold '30.1 762.6 853.5 949.6 1050.0 1121.5 1263.6 1458.3 1543.0 1580.0 1428.2 1636.0 1760.9 1902.5 2055.9 2222.4 Sold/generated % 72.1% 71.9% 70.8% 69.3% 68.8% 68.1% 67.8% 70.0% 69.9% 69.3% 65.1% 69.0% 69.0% 70.0% 71.0% 72.0 Increaw imnsle % 10.5% 11.9% 11.3% 10.6% 6.8% 12.7% 15.4% 5.8% 2.4% -9.6% 14.5% 7.6% 3.0% 8.1% 5.1 Av. Pyas/kwh sold * 24.85 25.01 25.17 27.82 29.83 30.13 30.00 27.25 27.49 28.02 37.25 75.34 102.53 121.36 104.55 111.25 -Kysts milion- Operatig revenue 171.5 190.7 214.8 264.2 313.3 337.9 379.2 397.4 424.3 442.8 532.0 1232.5 1805.3 2308.8 2149.5 2472.4 Operating xpses Salaries & wages 30.1 30.5 30.6 44.5 44.7 46.7 47.0 49.5 51.1 56.7 58.2 131.8 133.5 133.5 133.5 133.5 Mainenant e 31.2 34.7 36.1 34.2 41.9 43.1 37.5 38.5 49.5 46.7 44.8 62.7 63.1 63.1 63.1 63.1 Fuel # 35.5 34.3 50.3 49.0 54.0 65.9 75.7 76.3 80.8 103.8 163.7 831.9 1386.8 1859.3 1589.0 1709.9 Power purcases 1.2 2.3 0.9 1.4 2.7 3.6 4.2 4.5 3.9 1.2 1.3 1.8 1.9 1.9 1.9 1.9 Depreciation 25.7 27.8 31.1 36.8 41.4 48.7 60.3 89.9 116.0 131.4 144.7 144.5 151.7 158.3 116.7 224.1 Comrodity/serv Tax 7.0 7.8 8.7 11.1 13.1 14.3 15.9 14.4 15.6 17.2 23.5 31.2 33.5 35.7 38.1 40.6 2 Total expenses 130.7 137.4 157.7 176.9 197.9 222.2 240.6 273.1 316.9 357.0 436.2 1204.0 1770.7 2251.9 2012.4 2173.2 Net operatg icome 40.7 53.3 57.1 87.3 115.4 115.7 138.6 124.3 107.3 85:8 95.8 28.5 34.7 56.9 137.1 299.3 OCthr income 3.3 2.6 2.9 6.3 4.9 4.4 4.7 5.8 8.9 38.3 12.1 14.7 16.2 16.2 16.2 16.2 Interest cbrged 7.2 7.5 14.8 20.6 38.8 52.3 60.6 112.2 112.4 125.2 148.6 43.2 50.8 72.9 153.3 315.4 Net ProfitLos 36.9 48.4 45.2 73.0 81.5 67.8 82.8 18.0 3.9 (1.1) (40.7) 0.0 0.0 0 0 0 Stote Contribution 7.4 14.5 13.6 21.9 24.4 20.3 24.8 5.4 1.2 0.0 0.0 0.0 0.0 0 0 0 Net splus (Deficit) 29.5 33.9 31.6 51.1 57.0 47.4 57.9 12.6 2.7 (1.1) (40.7) 0.0 0.0 0 0 0 Rate of Reton on Av. net PA in Oper Book valuosadassets 10.8% 10.1% 13.9% 15.9% 13.1% 14.7% 10.9% 6.9% 4.3% 4.5% 1.3% 1.2% 1.7% 4.0% 3.3 0 Mission estias- MEPE awconts for FY 90 not ready in Nov 90. I Fuol cos arn bigh in FY 92, 93 & 94 due to short&U inaVs being made good byI diesl oil. Assumed exchan rate k5ouss 188 ANNEX 7.3 (c) (cont'd) BASE CASE - HIGH DEMAND AT SHADOW EXCHANGE RATE FUEL USE IN BASE CASE (High demand) 1990 1991 1992 1993 1994 1995 Gas use bof 19.99 19.65 20.09 17.80 15.35 19.67 Fuel Oil U.. mmb 0.00 0.00 0.40 0.30 0.30 0.10 Diesel U80 mmb 0.44 0.78 0.74 0.64 0.70 0.28 Price of gas k/mcf 7.50 7.50 7.50 7.50 7.50 7.50 Price of Fuel Oil US$/b 24.00 24.57 25.16 25.76 26.38 27.03 Price of diewsl US$/b 31.00 31.78 32.58 33.41 34.26 35.14 Value of gas mill kyat 149.93 147.38 150.68 133.50 115.13 147.53 Value of Fuel Oil mill kyat 0.00 0.00 503.20 386.40 395.70 135.15 Value of diesel mill kyat 682.00 1239.42 1205.46 1069.12 1199.10 491.96 TOTAL FUEL BILL (mill kyat) 831.93 1386.80 1859.34 1589.02 1709.93 774.64 Notes: kyat converted at 50.00 k/US$ Fuel use from WASP analysis PRICE OF CH-IARCOAL IN YANGON Rea 1 1986 Ik per 14 Kg f3ag 35 - 34 33 32 - 31 - 30 - 29- 28 -c %0 26- 25- 24 23 !_ _ 1981 1992 1983 1984 1985 19U6 1998? 1988 19C9 1990. EJ Price of Cliarcoa IA Of E NE fQ`' EPO M OCE i IPE iPP ...MEPE EOONOMIC PL ANNINIG PLANNING PL ANN1I4G OPE RATION PL ANNING PROOUCTION EXPLORATION ADMINISTRArION FII*ANCE PLANNING PL ANt4ING OENERAL ORILL'NG CRUDE aaTRIRBUrION HYORO-ELEC PLANNING MOVEMENT & 8 ALES COHSarN CN(IOINEERIN FINANCE GENERAL ADMINISTRATION AOMINISTRATION rlIELO8 PROOUCTION FINANCE ADMINISTRATION RESEARCH O DEVELOPMENT FINANCE OF FSHORE Note: EPD - Energy Planning Department MOGE - Myanmar Oil and Gas Enterprise MPE - Myanmar Petrochemical Enterprise X MPPE - Myanmar Petroleum Products Enterprise EPC - Myanmar Electric Po'6r Enterpris 191 ANNE 8.2 Myanmar Oil and Gas Enterprise Income Statement: 1991 terms FY 1986 1987 1988 1989 1990 1991 1992 1993 1994 199S -Estima Crude oil- Quantity MM 7.01 6.00 5.13 3.87 4.82 4.89 4.24 6.13 7.34 9.96 Nat Gas - Cluntity BCF 30.89 35.86 38.11 36.02 36.89 33.30 X1.90 23.50 23.70 23.60 5.71 S.69 4.92 6.70 7.91 10.53 Price/crudelbbl/lkyats av. a 42.78 42.73 42.69 74.34 110.00 110.00 136.28 166.47 170.56 174.78 Price/gas/MCF/kyats av. 0 1.92 1.94 2.90 5.04 7.50 7.50 11.50 15.S0 1S.50 .S50 INCOME Kyats million Sale of crude oil 299.84 256.26 218.98 287.51 529.74 538.12 578.37 1021.13 1251.91 1740.63 Sale of nat. gas 59.41 69.56 110.61 181.46 276.71 249.75 320.85 364.25 367.3S 365.80 Other income 0@ 14.73 18.98 27.71 23.07 307.76 78.53 69.87 69.87 69.87 69.87 Total Revenue 373.98 344.79 357.30 492.04 1114.21 866.40 969.09 1455.25 1689.13 2176.30 EXPENSES Kyats million Salary & wages 84.20 86.22 85.99 83.93 130.17 130.17 130.17 136.98 145.27 163.18 Materials 130.06 91.40 56.45 45.57 71.43 71.43 71.43 75.17 79.72 89.54 Schiumberger charges 72.13 48.55 38.02 38.32 37.24 37.24 37.24 39.19 41.56 46.68 Repairs/ maintain 17.04 15.35 15.86 15.74 20.7 20.70 20.70 21.78 23.10 2S.9S POL 17.20 18.06 16.02 23.08 36.79 36.79 36.79 38.72 41.06 46.12 Depreciation 134.11 133.45 124.31 112.00 112.25 129.47 165.63 211.32 269.06 315.5S Royalty & Taxes 6.13 5.24 4.69 3.66 5.01 5.09 4.42 6.38 7.64 10.36 Administration 17.55 17.03 19.33 21.02 30.73 30.73 30.73 31.53 32.51 34.63 Experimental 0.53 2.21 2.47 3.78 3.64 3.64 3.64 3.74 3.8S 4.10 others 51.89 52.80 58.72 30.42 79.79 68.80 63.39 63.39 63.39 63.39 Total Optg. expenses 530.84 470.31 421.86 377.52 527.75 534.06 564.13 628.20 707.16 799.50 Successfil woe costs defe-red # (88.87) (45.88) 26.36 38.89 (41.98) (41.96) (40.24) (41.98) (41.98) (41.98) Incompkle weU cost +' 14.36 a: 5.41 14.83 Net Optg. expenses 427.61 424.43 442.81 401.58 485.77 492.10 523.89 586.22 665.18 757.S2 Financial Cost Foreign loan interest 12.15 15.12 IS.1S 26.39 27.39 41.08 65.75 117.56 183.03 265.76 Local Bank interest 141.05 156.64 167.05 174.75 Other non-optg cost 3.52 23.56 5.69 44.44 85.50 44.44 8S.50 44.44 8S.50 44.44 Total Cost 584.33 619.75 630.70 647.16 598.66 577.62 675.14 748.21 933.70 1,067.73 Net Profit (210.35) (274.96) (273.40) (155.12) 515.5S 288.78 293.95 707.03 7S5.43 1,108.58 (Continued) 192 ANNEX 8.2 LAu Income Tax applicablo from FY 91 0.00 86.63 88. 19 212.11 226.63 332.57 Contibution to State ** 0.00 0.00 0.00 0.00 515.55 202.15 205.77 494.92 528.80 776.00 Net profit after State Take (210.35) (274.96) (273.40) (155.12) 0.00 (0.00) (0.00) (0.00) (0.00) (0.00) @ Prices arm assmed at border parity for crude oil from October 1991; for gs at economic' price. O Other income in FY 90 represents mostly sigature bonus from 10 foreign oil compaies. This is strictly not an income relevant to operations of the yor. Other income from FY91 is mostly for services to foreign oil companies offset by othor expenditur. # If a woll is successful, the coat of the woll is deducted and thn written off in 10 years. The net of the year's successful woU costs ad write offs (10%) of atl successful wells is shown here. ++ Cost is deducted pending determination if successful or not. ** The net profit is contnbuted to the State from FY 90; from Fy 91 a 30% tax is the first charge. 193 ANNEX 8,2 MEPE: Ilcome Statement a 0 a 0 0 a FY 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 ----ActUl- -Estimatc - - Gwh Gonerated net 2082.3 2207.6 2281.1 2193.3 2371.0 2552.0 2717.8 2895.7 3086.7 3247.0 Gwh Sold 1458.3 1543.0 1580.0 1428.2 1636.0 1760.9 1902.5 2056.0 2222.4 2403.0 Sold/goerated % 70.0% 69.9% 69.3% 65.1% 69.0% 69.0% 70.0% 71.0% 72.0% 74.0% Increase in male % 15.4% 5.8% 2.4% -9.6% 14.5% 7.6% 8.0% 8.1% 8.1% 8.1% Av. Pyaslkwh sold * 27.25 27.49 28.02 37.25 48.73 48.73 53.60 68.22 68.22 68.22 ---Kyats million- Operating revenue 397.4 424.3 442.8 532.0 786.3 858.1 1019.8 1402.6 1516.1 1639.3 Operating expenSeS Salaries & wages 49.5 51.1 56.7 58.2 131.8 133.5 133.5 133.5 133.5 133.5 Maintenace 38.5 49.5 46.7 44.8 62.7 63.1 63.1 63.1 63.1 63.1 Fuel # 76.3 80.8 103.8 163.7 272.8 434.0 536.5 571.2 555.6 427.1 Power purchass 4.5 3.9 1.2 1.3 1.8 1.9 1.9 1.9 1.9 1.9 Depreciation 89.9 116.0 131.4 144.7 180.9 230.9 290.9 360.9 440.9 540.9 Commodity/serv Tax 14.4 15.6 17.2 23.5 31.2 34.3 40.8 56.1 60.6 65.6 Total expenses 273.1 316.9 357.0 436.2 681.2 897.8 1066.7 1186.7 1255.7 1232.2 Net operatg income 124.3 107.3 85.8 95.8 105.0 (39.7) (47.0) 215.8 260.4 407.1 Other income 5.8 8.9 38.3 12.1 14.7 16.2 16.2 16.2 16.2 16.2 Interest charged 112.2 112.4 125.2 148.6 42.7 77.8 119.8 168.8 224.8 294.8 Not Profit/Loss 18.0 3.9 (1.1) (40.7) 77.0 (101.3) (150.6) 63.3 51.9 128.6 State Contribution 5.4 1.2 0.0 0.0 77.0 0.0 0.0 63.3 51.9 128.6 Not surplus (Deficit) 12.6 2.7 (1.1) (40.7) 0.0 (101.3) (150.5) 0.0 0.0 0.0 * Tariff increase are required as indicated, namely by 40% from October 1991. An accouning break even position will then result in the five years PY 91-95. * Mission estimates- MEPE accounts for FY 90 not ready in Nov 90. # Fuel costs are high in FY 92-95 due to shortfall in gas being made good by diesel oil. New prices for gas and fuel products as recommended in the EPIR Report are assumed to come into effect from October 91. It is importnt to note that diesel & fuel oil supplied to MEPE to substituto for gs in FY92-95 are presumed to be taxes exempt, so that the prices are not unduly high compared to that of ga. Price of crudo /bbbl 110 136.3 166.5 170.6 174.8 Gas use bef 19.7 20.1 17.8 15.4 19.7 Fuel oil rmb 0.0 0.4 0.3 0.3 0.1 Diemi mmb 0.8 0.7 0.6 0.7 0.3 Price of gas k/mef 7.5 11.5 15.5 15.5 15.S Pnce of fuel oil k/bbl 297.5 334.8 372.1 376.3 380.8 Price of Diesel k/bbl 367.5 459.6 551.6 555.9 560.3 Fuel bill with taxes 434.0 705.0 740.5 740.0 499.9 Fuel bill w/ tax (applied from FY 92) 319.4 536.5 571.2 555.6 427.1 194 ANNEX 8.2 MPE: Rofjneie- Income Stateme Kyatb MM FY 1988 1989 1990 1991 1992 1993 1994 1995 -A tusl -------Estimate--- Crude oil refined Barls miion 5.11 4.47 4.78 4.89 4.24 6.13 7.34 9.96 Sa 5SO.58 918.76 1546.75 1583.68 1603.46 2349.17 2774.49 3685.08 Cost of goods 439.01 543.31 906.20 873.88 912.51 1360.00 1593.80 2089.07 Unit cost/price/bbl/kts crud+prodn cost 85.85 121.53 189.66 178.64 215.01 221.71 217.14 209.77 cmde oil only 42.66 62.39 110.00 110.00 136.28 166.47 170.56 174.78 refining only 43.19 59.14 79.65 68.64 78.73 55.24 46.58 34.99 product sold 103.76 205.5: 323.73 323.73 377.82 382.97 378.00 370.02 GCrou profit/lu 91.57 375.45 640.56 709.79 690.95 989.17 1180.70 1596.01 Admin. expes AdministrAt 28.50 24.56 29.93 35.03 35.03 42.81 50.36 66.77 SOeing & Distr. 3.03 10.75 11.76 13.77 13.77 16.83 19.80 26.24 R & D 0.37 0.19 0.35 0.41 0.41 0.50 0.59 0.78 Comm.& Serv. tes 210.57 357.92 668.34 684.29 593.65 858.03 1026.72 1393.07 Profit/ LOs (5% of cost from FY 92) (150.91) (17.97) (69.83) (23.71) 48.09 71.01 83.23 109.14 Other Income 9.80 10.57 2.70 10.57 10.57 10.57 10.57 10.57 Interest 121.28 137.82 70.00 70.00 70.00 70.00 70.00 70.00 Not profit/ los (262.38) (145.22) (137.13) (83.14) (11.34) 11.58 23.80 49.71 Optg. ratio 128% 102% 105% 101% 97% 97% 97% 97% Rofinry marginwbbl (before interest) (29.51) (4.02) (14.61) (4.85) 11.33 11.58 11.34 10.96 Foei lons rcoivod by =PE Lender LoAn LAnn currency lot rate Grace Repayment -Amount defaulted- - Beneficiury Conversion Date Amoun MM No of Yrs instam Princip Interest I Fe- Kts KFW FRG 31.3.79 64 DM 0.020 6 12 semi 4 Fertilizer DM 3.63 KFW FRO 31.3.79 128 DM 0.008 6 12 semi I Fortilizer AS 0.55 KFW FRG 31.3.79 33 DM 0.075 6 12 semi 8 3 Fertilizer Yen 0.0486 IBA 1980 510 A.Sch 0.070 2 20 somi 59 42 Fortilizer KFW FRO 1982 25 DM 0.070 3 20 smi 3 1 Methanol MEHIqJpn 680 Yen 0.078 end 1984 16 semi 1700 179 LPG OECF 7960 Yen 0.025 end 1994 319 Refinery OECF 7100 Yen 0.025 end 1994 494 LPG OECF 1977 29950 Yen 0.030 7 37 smi 3237 615i Refinery Totl in MM Kts 3708.26 310.50 135.47 Totl in $ MM 598.11 50.08 21.85 195 ANEX.2 MPPE: lb oSatemtnt FY 1988 1989 1990 1991 1992 1993 1994 1995 Actual Estimat Sams Qty Indx 105.2 80.4 100.0 125.2 134.0 ISI.2 153.6 208.3 Sls income b ya MM 570.99 983.34 1897.21 2374.90 2473.91 2806.22 2805.7S 3692.13 Cost of Goxds 489.1S 717.52 1345.66 1684.48 2104.09 2406.42 2412.75 3204.61 Freit & Handling 34.51 44.03 6S.73 82.28 70.35 74.16 66.77 89.19 Service Tax 26.22 44.93 87.00 95.11 115.60 131.13 131.11 172.53 GOs Profitt Los 21.12 176.86 398.82 513.03 183.86 194.51 195.11 225.80 Adminisrtion 11.13 14.18 20.15 21.16 21.52 22.21 22.31 24.S2 Distribution 54.76 66.80 108.72 114.19 116.11 119.84 120.36 132.28 Finnial Expenes 0.00 1.65 0.00 0.00 0.00 0.00 0.00 0.00 Profit/ LOs (2% of costs fo. FY 92) (44.77) 94.23 269.95 377.67 46.24 S2.45 S2.44 69.01 Contributioa to State 0.00 29.26 269.95 377.67 46.24 52.45 S2.44 69.01 Not Susphw/ (Deficit) (44.77) 64.97 0.00 0.00 0.00 0.00 0.00 0.00 Gasoline Kerosne Diosel Fuel Oil Total Product Mix 10 FY 1988 49.26 5.94 72.01 34.08 161.29 FY 1989 34.28 4.76 66.23 17.92 123.19 Fl 1990 38.06 6.85 83.82 24.56 153.29 191.88 205.37 35 imports) 231.71 35 imports) 235.38 35 imports) 319.37 MPE Unit Costs FY 1988 1989 1990 1991 1992 1993 1994 199S Unit cost/priceIG/ts crudeproda cst 2.4S 3.47 5.42 5.10 6.14 6.33 6.20 5.99 crUdo oil ony 1.22 1.78 3.14 3.14 3.89 4.76 4.87 4.99 refining only 1.23 1.69 2.28 1.96 2.25 1.58 1.33 1.00 pcrdts sold 2.96 5.87 9.25 9.25 10.79 10.94 10.80 10.57 admin expees 0.18 0.23 0.25 0.29 0.33 0.28 0.28 0.27 commodity tax aveng 1.18 2.29 4.00 4.00 4.00 4.00 4.00 4.00 commodity tacosas % 44.7% 61.8% 70.5% 74.1% 61.7% 60.4% 61.7% 63.8% commodity tax/sl % 39.7% 39.0% 43.2% 43.2% 37.0% 36.5% 37.0% 37.8% 196 ANNEX 8.3 Total Iavotmts in the nor=v Sector ( S million-1991 prices) 1991 -2000 1991-1995 1995-2000 1 Total F.E Total F.E Total F.E Coal Sector Exploration 5.00 4.00 5.00 4.00 Feasibility study 1.00 1.00 1.00 1.00 Total coal sector 6.00 5.00 6.00 5.00 Oil and Gas Sector Rehabilitation/oil fields 119.00 71.40 119.00 71.40 0.00 0.00 Pndeveloped/proven/probable 579.00 329.40 399.00 239.40 150.00 90.00 Total oil fields 698.00 400.80 518.00 310.80 150.00 90.00 Possible res'vs (excluded) not included 575.00 273.00 288.00 172.80 167.00 100.20 Rehabilitation/Gas 71.00 42.60 71.00 42.60 0.00 0.00 Unproven Probable 86.50 51.90 66.50 39.90 20.00 12.00 Possible reserves(excluded) 86.50 51.90 66.50 39.90 20.00 12.00 Gas pipeline-Yangon-Moattanm 173.00 125.00 173.00 125.00 Total oil sector 1028.50 620.30 828.50 518.30 170.00 102.00 Possible reserves Refinery Investments Spare parts 6.00 6.00 6.00 6.00 P/Cb&ul/Thanlyn 4.00 3.00 4.00 3.00 Rebab'n/ tug fleet 50.00 25.00 10.00 7.00 40.00 18.00 Moderization/distribution/comp 5.00 4.00 5.00 4.00 Loss control/efficiency 25.00 18.00 5.00 4.00 20.00 14.00 Yangon depot 20.00 10.00 20.00 10.00 Mann refinery 15.00 11.00 15.00 11.00 Rehabilitation/fortlizor plants 11.00 10.00 11.00 10.00 Total Refinery sector 136.00 87.00 61.00 44.00 75.00 43.00 Power Sector Investmlents Rehabilitation 145.61 93.03 145.61 93.03 Generation 450.50 324.r3 255.70 188.10 194.80 136.40 Transmission projects 138.35 80.69 76.66 43.74 61.68 36.96 Distributien Projects 250.41 159.78 132.58 93.52 117.83 66.26 Total power Actar 984.87 658.00 610.55 418.39 374.31 239.62 Traditional Energy Sector 51.47 12.87 25.74 6.43 25.74 6.43 TOTAL ENERGY SECTOR 2206.84 1383.17 1531.79 992.12 645.05 391.05 1 iSz . 4 V KA C4§IN ~~~~~~~~ rkE :_ SA G A Kit tISHAN CHIN S0T $ 5rATE -b.i DIRT ~ ROAD j $. MN R SAG G6 O7RS MOUNTISJN ~ ~ ~ ~ M4 Va kANGCES ANDN FOETD RA PRINCIPAL~ RIE-RONN AREA M TAIN OR DIS° RUNARe ci ~ ~5 - 22ERCD \ 22 INTAVEN AOADS B A c, -- DIRT ROADS - SINGiLE TRACK RAILWAY p J DOUERLR TRACK RAILWVAY \se i - MAIN RIVERS \ t . R MOLINTI RANGES ND fORESTED AREAS PRINCIPAL RICE-GROWING ARAS STA7F OR DIVISION SOUNDARIRS }H - -INTERNATIlONAL ROLfNDARIRS b-i ~10 ft iS E' 92' Ti' 15' j3 92' 96- A~~~~~~~~~~ ,A LNS ; V o -rIIHUKAWNG K X.JN\ KCHN i ..,\w t*P_ . \ i EA5FERN PLATFORM ' ' / N 1) '-' . ' IVAYEYATRWALDY.DEIA .1" -' / < ' COFFSHORE ',r , _ ,' *z z A , . V INLE GCASLN . ,. /\ 1-' w>- VI' B-I CiH1 2 / 8 A \ I '-AS I N ; I WNIAMLYIN O . X jSin22|^uij N > s S / { ( ~~~~~~~~X W.L-YMG 26i>- $7AF~~~5 krTENIASSAR0 M /1 C~~~~~~~~~~ /0 . '/ f,\C / G / h1/, , - / ?, / S 9 0~~~~~~~IAO -M IF'f a/ -- 22t t 1 1- t ~~5 9: ' Et V^, ( . oY' T / FlOWStLNGO9j; \ tS i D MYANMhAR F p;s &iEOLOGIC BASINS / / i i _W OILOR GAS FIEIDS J/ ME SO ZO f/PALtOZIChl //)9M ;VOLCANK OUTCROPS /X -- FAULT IINES A' Ng\ 6, I& A- A' LINES OF CROSS SECTI1>4I K PAVED ROADS j ' I - GRAVELWOAD v ¢\ S - -- -01IRT ROADS I SINGLE TRACK PRAiSvAN S nnit DObUBLE TRAK PAILWAY IKkIN RIVMR f SlAT Ort DISIN BO UND ARIES . MiTERNAnONAL OLVIC /ES , - 1 A0 ROA D r ACD OS / 1 C o 5o 1J 1o 2w0 2 1LES ) BRAIN hSStisfhwsbJrtz-IVEES ¢fo w~e c_>* s 1ts1aI>Yevi4oorasfolotEtt*Vhe9X ib s~~~~~~- C 421~~~~~~~~~~~~Il OR DIISO BOUNDARIES 1 ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~O-l P2'~~( 1 1 (. St.'t. J ' { ~~KACPN j, Athik ' W ./+ 11S SA /SA:tGAM C EOCENT . CEOL i SHAN / 527 ,I) ' % Q JQ \ < U STATE TA TE CHIN i I9 3 Th.!~~~~~~dw />Tawr1 a Ky.Ap yg w 2 T KAVAH% EXISTINC; MINE$TATE KrlLPYf 't ft ' O g. Y \ 7 4t X FsAG oa 15 ' MYANMAR ' XONA E COAL DEPOSITS ABOLARIES COA20DEPOSITS AN YANGON IC, 3Tkeindow / K..obyio MON E: 6 Mokbudoon6 \i t 7 ThIOIbJPS - -1101oyi , iyon 1kio 02goMLE 13. SI-gyil XlEXISTlhG MINFS IE$ K~~~~~~~~ ._STATE OS DMSION BOUNDARIES 4fi -- - INTERNATIONAL 30UNDARIES 1 o IS 2 o 0 S L s 2 2O iT O K W lE I S ) c ohv .........Rd c ..SoIa..a. ol b,, oIThp,Wfi ..d..&...al.Ji.o...,c a C.yo$a T.da,.a -o.dSoaJ., .-~ ~M dn*.-e- *- c *,o .Ih _ $SM4 noT Oo-e,o'oa ,L ' C".on 7H*o!*7 ' YANGON 96. t_ AREA Il,iAwaa.E.r .dbyTh. WeMd ik' .' / se~ ~ ~~dA o A..... Wfi. A dd,e o"p4 1 t E ^ :S. - = _nOlF. < d se- - d i pciT. . W.dd OS 56 WW,.M,o R6.6 . 2 ( J1 MYANMAR ThLd\o .-5'- POWER SYSTEM I I'iUSTh -!22| TRANShMSSION UNES: Kik I N ~~~~~~~~230 kV _ . _ _ 132kV U HIYDRO POWER PLANTS I'-) 1 l X ; * THERRAL POV- 'R PLANTS Al A SUBSTATIONS RIVERS MAIN ROADS t.. S.d A G < ; \ X - SECONDARY ROADS RAIL WAYS SAG .N0- STATE OR DIVISION ROUNDARIESS 2C -24° t_ *vr l St, J' INTERNATIONAL BOUNDARIES CIIT /s'w1u ISJND? FALl ' I E~~~S 7, STAT,= 200MW' k!` T \ STAT0.2, IC- *D-_~~~~~~~~~~~~~~~~T Ok. A. 2Vr I YAH ' 0j r" . '' '\Xr { _r f ,_A;A: NW,~~~~~~~~~ m ___~~~~~~~~~~~~ ff . . 1h { 3044~~~~~~~~~~~~ f.~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~I 16 16D320 1I6ETE4 1W -;~~~~~~~~~~~~~~~~~~~~~~~~~~~~o Oho r_ - E"WD T he 55'e5, .a t oSa,. 'Z%dsZ%rX 8MYANMAR ->>v> - ~~~~~~~~~~~FOREST RESOURCES Tidal, Beach, and Swamnp Forests Evergreen Forests Mixed Decidous Fore1ts Dry Forests Deciduous Dipteracarp or IndMirs9 Fos H+11 andrTemprte Rvergs -Main Roads Seconsdary Roads -.--'- > 8iRaoilways Stale or Divson Bounduries 24 f4 -- intertional Boundaries 0~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~0 16"~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~i l0 100 20 KILMETER -r~~~~~~~~~~~~~~~~~6 100"" N 2J I ... - -a t_o A~~~~~~~~~~~ I e 96.~~~~~~~~~~~~~~ 2r- -2aEr4w- ,r e MYANMAR n,o !( -. -nHYDROCARBON RESOURCES M w~~~~~~~~ rO~~~~~T 4do p,,,,1 , / %jJ C.} t O Well Tested Gas ( f~ is* _ Well Tested Oil/Gs 3- S K A C h I N ) - Cnrde Pipeline 4 . > /j Pumping Slatiarm 5 T 5T brE { - - Gas Pipeline * WIlG=s Fields U Refineries , r X S~~~~MySkEino P fRers - \ ~S4, J Main Roads Secondary Roads Railwayp / S A G kNt G c } g ;7 - 'itae or Division Boundaries 24 2i' 24t >~~~~v~~ t Kewlin2 2 i y 9 , . .-._. I~~~~~~~~~~~ntemnotiona: aounduries E) ukpIoIs I h z J . )A N CHIN~~~~~~~~~ STAE /STAT t~~~~~ohi Mo-}yBlghi6n 4? YAGO 7 / OfNOW04 ds 1: 'AMonyw l i*J MO t MiT ._ 2r ot; (wu (1/- y 0; v I \ \ ' D b! - ~ >/i YAH~~~~~~~6 , Sioy < ,<,. ¢ e J r lXq 20-~P. G- d I I wnir ) rJ - \\ ~1D AY P" Ir 'n 12 12' - + /i \ BAO t >. j =\ > \~~~~~~~ T.T~ C. ~ ~ ~ ~ ~ ~ ~ ' O ~ ~~~ fcm tOO11 15 MIlE F/E I t 5 t j) m Npun 41r b it -|ioon : Tooe i Kl _ o lox 2aeTERSWgrLp Z~~~~~~~~~~~~~~yuAy 9Dlhsul n6 > SSol h