Document of

The World Bank

FOR OFFICIAL USE ONLY FRE COPY

Report No. 3158-TH

STAFF APPRAISAL REPORT

THAILAND

POWER SUBSECTOR PROJECT

April 20, 1981

Projects DepartmentEast Asia and Pacific Regional Office

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

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CURRFNCY EQIJIVALENTS

Currency Unit - Thai Baht (B)

US$1.00 = B 20.5B 1.00 = US$0.0488

WEIGHTS AND MEASURES

1 meter (m) = 3.281 feet (ft)

1 cubic meter (cu m) = 35.315 cubic feet (cu ft)1 kilometer (km) - 0.621 miles (mi)1 square kilometer (sq km) = 0.386 square miles (so mi)1 hectare (ha) = 2.471 acres (ac)1 kilogram (kg) = 2.206 pounds (lb)1 metric ton (mt) = 1,000 kilograms (kg)1 cubic meter per second (cms) = 35.315 cubic feet per second (cfs)1 kilovolt (kV) = 1,000 volts (V)I kilovolt-ampere (kVA) = 1,000 volt-amperes (VA)1 megavolt-ampere (MVA) = 1,000 kilovolt-amperes (kVA)1 kilowatt (kW) 1,000 watts (W)1 megawatt (MW) - 1,000 kilowatts (kil)1 gigawatt hour (GWh) = 1 million kilowatt hours (kWh)1 kilocalorie (kcal) - 3.968 British thermal units (Btu)

ABBREVIATIONS

ADB - Asian Development BankCPPD - Committee for Power Policy and DevelopmentEDL - Electricite du Laos

EGAT - Electricity Generating Authority of ThailandIBC - International Board of ConsultantsKFAED - Kuwait Fund for Arab Economic DevelopmentMEA - Metropolitan Electricity AuthorityNEA - National Energy AdministrationNESDB - National Economic and Social Development BoardNEB - National Environmental BoardOECF - Overseas Economic Cooperation FundPEA - Provincial Electricity AuthorityPTT - Petroleum Authority of ThailandRTC - Royal Thai Government

UNDP - United Nations Development Programme

THAI FISCAL YEAR

October 1 - September 30

FOR OFFICIAL USE ONLY

THAILAND: ELECTRICITY GENERATING AUTHORITY OF THAILAND

POWER SUBSECTOR PROJECT

Table of Contents

Page No.

1. THE POWER SECTOR . . . . . . . . . . . . . . . . . . . . . . . 1

Energy Resources .... . . . . . . . . . . . . . . . .. 1Hydro Potential . . . . . . . . . . . . . . . . . . . . . . 1Oil ............ ... 2Coal .... . . . . . . . .. 2Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . 2

Energy Consumption . . . . . . . . . . . . . . . . . . . . . 3Role of the Sector in the Economy . . . . . . . . . . . . . . 4Sector Organization . . . . . . . . . . . . . . . . . . . . . 4General . .. . . . . . . . . . . . . . . . . . . . . . . 4The Electricity Generating Authority of Thailand. . 4The Provincial Electricity Authority . . . . . . . . . . . 4The Metropolitan Electricity Authority . . . . . . . . . . 5Private Franchises . . . . . . . . . . . . . . . . . . . . 5Government Agencies .... . . . . . . . . . . . . . .. 5

Sector Policy ..... . . . . . .. . . . . . . . . . . .. 6Sector Issues . . . . . . . . . . . . . . . . . . . . . . . . 6Sector Coordination .... . . . . .. 6Tariff Levels and Oil Subsidies .. 7Energy Pricing Policy . . . . . . . . . . . . . . . . . . . 9

Bank Participation in the Sector . . . . . . . . . . . . . . 10Power Market and Supply ... . . . . . ..... . . . . . . 10Access to Electricity ... . . . . . . . . . . . . . . .. 11Rural Electrification . . . . . . . . . . . . . . . . . . . . 12

2. THE BORROWER . . . . . . . . . . . . . . . . . . . . . . . . . 13

Organization and Performance .... . . . . . . . . . . . . 13Planning . . . . . . . . . . . . . . . . . . . . . . . . . . 14Engineering, Design and Construction . . . . . . . . . . . . 14Procurement . . . . . . . . . . . . . . . . . . . . . . . 14Management, Manpower and Training . . . . . . . . . . . . . . 15Accounting and Audit .15

This report was prepared by Messrs. K. C. Ling and A. Mejia on the basis ofan appraisal conducted in July 1980 and updated in February 1981.

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

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Page No.

Tariffs . . .. . . . . . . . . . . . . . . . . . . . . . . 16Energy Conservation . . . . . . . . . . . . . . . . . . . . 16Insurance . . . . . . . . .. . . . . . . . . . . . . . . . . 17Taxes . . . . . . . . .. . . . . . . . . . . . . . . . . . . 17Environmental Aspects . . . . . . . . .. . . . . . . . . . . 17Resettlement . . . . . . . . .. . . . . . . . . . . . . . . 17Present Facilities . . . . . . . . .. . . . . . . . . . . . 18Summary . . . . . . . . .. . . . . . . . . . . . . . . . . . 18

3. THE POWER MARKET .. . . . . . . . . . . . . . . . . . . . . . 18

Background . . . . . . . . . . . . . . . . . . . . . . . . . 18Load Forecast . . . . . . . . . . . . . . . . . . . . . . . . 19Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

4. THE PROGRAM AND THE PROJECT . . . . . . . . . . . . . . . . . . 22

General . . . . . . . . . . . . . . . . . . . . . . . . . . . 22System Strategy . .. . . . . . . . . . . . . . . . . . . . . 23The FY80-86 Program ... .. .. .. . . . . . . . . . . . . 23Justification of a Subsector Approach . .. . . . . . . . . . 23Scope of the Loan . .. . . . . . . . . . . . . . . . . . . . 24Cost Estimate . . . . . . . .. .. . . . . . . . . . . . . . 26Financing Plan . .. . . . . . . . . . . . . . . . . . . . . 27Selection of Subprojects . .. . . . . . . . . . . . . . . . 28Procurement . .. . . . . . . . . . . . . . . . . . . . . . . 29Disbursement . .. . . . . . . . . . . . . . . . . . . . . . 29Project Implementation . .. . . . . . . . . . . . . . . . . 29Risks . .. . . . . . . . . . . . . . . . . . . . . . . . . . 30Completion Report . .. . . . . . . . . . . . . . . . . . . . 30

5. FINANCIAL ANALYSIS . . . . . . . . . . . . . . . . . . . . . . 31

Past Performance . . . . . . . . . . . . . . . . . . . . . . 31Present Financial Position . . ... . . . . . . . . . . . . . 32Future Financial Position . . . . . . . . . . . . . . . . . 32Tariff Levels . . . . . . . . . . . . . . . . . . . . . . . . 34Future Operating Results . . . . . . . . . . . . . . . . . . 34Debt Control . . . . . . . . . . . . . . . . . . . . . . . . 35Liquidity Position . . . . . . . . . . . . . . . . . . . . . 35Financial Covenants ... . . . . . . . . ... .... . 35

6. JUSTIFICATION AND ECONOMIC ANALYSIS . . . . . . . . . . . . . . 36

General .... . . . . . . . . . . . . . . . . . . . . . . . 36Production and Benefits . . . . . . . . . . . . . . . . . . . 36Least Cost Analysis . . . . . . . . . . . . . . . . . . . . . 38Internal Economic Rate of Return . . . . . . . . . . . . . . 40

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Page No.

7. AGREEMENTS REACHED AND RECOMMENDATIONS . . . . . . . . . . . 41

Agreements Reached ... . . . . . . . . . . . . . . . . . . 41Recommendations .... . . . . . . . . . . . . . . . . . . . 42

ANNEXES

1. Highlights of EGAT, MEA and PEA Operations2. Organization Chart (No. 16772)3. Existing Generation Facilities4. Existing Transmission and Substation Facilities5. System Load Requirements and Capabilities6. EGAT-s Power Development Program (No. 22638)7. Long-term Study for Generation and Transmission Projects -

Terms of Reference8. Investment Program (FY80-86)9. Project Description, Cost Estimate and Financing Plan for

Selected Subprojects10. Loan Disbursement Schedule11. EGAT-s Income Statements, Funds Flow Statements and Balance Sheets,

FY72-8012. EGAT, MEA, PEA and Sector Financial Forecasts: FY81-8813. Assumptions in the Financial Forecasts14. Least Cost Analysis15. Internal Economic Rate of Return16. Related Documents and Data Available in the Project File

MAP IBRD No. 10402-R3

it

THAILAND

ELECTRICITY GENERATING AUTHORITY OF THAILAND

POWER SUBSECTOR PROJECT

I. THE POWER SECTOR

Energy Resources

1.01 The principal indigenous sources of energy in Thailand are hydro-power, natural gas, petroleum, lignite, large but as yet uneconomic oil shaledeposits, wood fuel, charcoal, paddy husk and bagasse. Geothermal explor-ation is being carried out in the northern part of Thailand near Chiangmai.

Hydro Potential

1.02 Hydro potential (excluding that of two international rivers, theMekong and the Salween) is estimated at about 9,300 MW of which 1,270 MW arenow in operation; 2,100 MW in thirteen projects are under construction orprogrammed for installation before 1991; 635 MW in 13 projects are in theprefeasibility or feasibility study stages and about 1,900 MW in 12 projectshave been selected by the Electricity Generating Authority of Thailand (EGAT)for conceptual studies. Ninety-three major sites with a potential of about3,290 MW have been preliminarily assessed by the National Energy Administra-tion (NEA). NEA is carrying out desk studies for about 25 mini-hydro sites.A mini-hydro study is included under the Second Accelerated Rural Electrifi-cation Project of the Provincial Electricity Authority (PEA), the loan agree-ment of which was signed in November 1980 (Loan 1871-TH).

1.03 The Mekong river, which forms the border between Thailand and Laosand then flows through Kampuchea and Viet Nam has a total hydro potential inseven projects of about 19,000 MW with an annual energy output of 110,000GWh. This would be equal to 9 times Thailand's electricity consumption in1979 and 3 times the consumption forecast for 1990. The Mekong's developmentis governed jointly by Laos, Kampuchea, Thailand and Viet Nam and construc-tion is likely to await the resolution of the current political problems inthe region. Substantial resettlement problems would arise from the develop-ment of the first major hydro site at Pa Mong on the Mekong, about 60 km westof Vietianne where the river forms the border between Laos and Thailand. Anorganizational and financial study of the Pa Mong project is being carriedout by consultants. In addition, the numerous tributaries to the MekongRiver in Laos are tentatively estimated to provide another 18,000 MW of hydropotential to the region.

1.04 Based on a desk study made by NEA, a dam site on the Salween riverat the border of Thailand and Burma has a hydro potential of 5,800 MW withan annual energy output of about 47,000 GWh. Recently there have been minis-terial level exchanges and the two Governments agreed in principle to coop-erate on the development of the Salween River. The Thai Government is con-scious of the fact that unless these international rivers are developed,Thailand's energy requirement for power generation in the 1990s would againdepend on imported energy.

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Oil

1.05 Thailand's proven petroleum reserves total about 1.1 million barrelsin the Fang province of Northern Thailand. Production at present is lessthan 100,000 barrels a year, about 0.1% of total domestic consumption.Intensive exploration is currently being undertaken in the northeast regionof the country and offshore in the Gulf of Thailand where natural gas hasalready been found (see para. 1.08). There are extensive oil shale reserves(about 2,500 million mt), mainly in the remote areas of Tak province but oi.lproduction from shale is still uneconomic. The Government is consideringthe establishment of a pilot shale oil extraction plant under a technicalcooperation agreement with countries possessing such technologies.

1.06 Thailand has large areas of sugar plantations and has initiatedstudies of the feasibility of making ethanol by using the alcohol that canbe produced from sugar cane. The studies are at an early stage but will befollowed with interest by the Bank.

Coal

1.07 Lignite (low-grade coal) reserves are currently estimated at around770 million mt located at Mae Moh (650 million mt), Krabi (100 million mt),and Li (20 million mt). Of the lignite reserves at the Mae Moh site,350 million mt are proven and probable reserves which are sufficient tosustain a total generating capacity of about 1,500 MW for about 25 years tobe developed during the 1980s. EGAT is constructing units 4 and 5 of 150 MWeach at Mae Moh (150 MW are currently installed) which the Asian DevelopmentBank (ADB) is helping finance and the Bank has recently made a loan ofUS$72 million for the complementary lignite development (Loan 1852-TH). TheDepartment of Mineral.Resources is undertaking a drilling program for allthe lignite bearing basins in the country with the exception of Mae Moh,which are still under the responsibility of EGAT. Preliminary indicationsare that the reserve potential at Mae Marat in the province of TAK could besubstantial but possibly at a considerable depth underground.

Natural Gas

1.08 Seven promising gas fields have been discovered in the Gulf: thetwo best-delineated being structure "A", about 425 km offshore, by the UnionGroup; and structure "B", about 595 km offshore, by the Texas Pacific Group.Union has four other fields close to structure "A", and total Union gasreserves (proven and probable) are about 5 trillion cubic feet (tcf); TexasPacific reserves from its "B" and "E" structures are about 8 tcf. Theconcessionnaires will undertake the development of these reserves, and thePetroleum Authority of Thailand (PTT) will take delivery at the offshoreproduction platforms. In the initial years much of the gas output will becontracted to EGAT, while a portion will be available to industries along theonshore pipeline route. The Bank made a loan of US$107 million (Loan 1773-TH)to PTT in February 1980 for the first phase of development of the pipelinewhich by late 1981 will carry the natural gas to the Bang Pakong station,

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currently under construction about 60 km southeast of Bangkok, and to theBangkok metropolitan area. The substitution of natural gas for imported oilwould considerably reduce the demand for fuel oil for power generation(para. 6.04). EGAT has in its development program 2,700 MW of generatingcapacity to be converted or newly installed in the next few years. It isexpected that by 1991 about 37% of EGAT's total generation would be fromthermal stations using natural gas.

1.09 Sponge iron smelting and petro-chemical plants are in thefeasibility study stage with a view to using the natural gas more economicallythan for power generation. However, it is anticipated that substantial quan-tities of gas will always be available for power plants. A gas utilizationstudy is being undertaken under Loan 1773-TH to determine the extent ofindustrial usage of natural gas.

Energy Consumption

1.10 Total energy consumption in the FY70-79 period increased from about7.4 million tons of oil equivalent (77.2 trillion kcal) to 15.6 million tons(162.8 trillion kcal), an average annual growth rate of 8.6%.

1.11 Energy consumption by forms of energy in FY79 is shown below:

Energy consumption Percent(trillion kcal)

Petroleum products 112.6 69.2Hydro 10.0 6.1Lignite 5.7 3.5Charcoal and wood 23.5 14.4Paddy husk and baggasse 11.0 6.8

Total 162.8 100.0

1.12 An energy master plan study is being undertaken by NEA, financedby the United Nations Development Programme (UNDP), with ADB as theexecuting agency. The objectives of the study are to define a program tomeet Thailand's energy requirements up to the year 2000. The study isexpected to be concluded by end 1981.

1.13 An energy sector review has been carried out by Bank staffincluding an analysis of the commercial energy sector as a whole. The draftreport (No. 2813-TH) was reviewed with the Government in July 1980. Thebroader institutional issues relating to the improvement and change of thepresent structure to take account of the changing role of energy in theeconomy have been addressed in the energy sector review and would bepursued by the Bank in the next integrated energy project.

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Role of the Sector in the Economy

1.14 Electricity revenue accounts for only about 1% of GDP. However,electricity provides motive power to the manufacturing and mining industrieswhich account for 19.3% and 2.4% of GDP respectively.

1.15 The growth of the power sector has kept pace with Thailand-seconomic development. Between FY70 and 79, when GDP grew at an average rateof about 7.3% in real terms, total electricity consumption grew at an averagerate of about 14.0%. The elasticity coefficient of 1.9 is reasonable andcomparable to countries at a similar stage of development.

Sector Organization

General

1.16 The power sector consists of eight government agencies, threestate utilities, the ministries to which they report, and four privatefranchises which are so small as to be insignificant (para. 1.22). Thethree state utilities supply nearly all of the electricity consumed in thecountry, the private franchises and self-generating industries representedabout 14.7% of the installed capacity in FY79 (para. 1.40).

1.17 The state-owned utilities are the Electricity Generating Authorityof Thailand (EGAT), the Metropolitan Electricity Authority (MEA), and theProvincial Electricity Authority (PEA). Highlights of the EGAT, MiEA and PEAoperations are shown in Annex 1.

The Electricity Generating Authority of Thailand

1.18 EGAT, the proposed Borrower, was established in 1968 as a wholly-owned Government corporation for the purpose of increasing the efficiency ofelectricity supply throughout the country and coordinating the generationand transmission systems and is responsible to the Prime Minister's Office.EGAT generated 95% of all electric energy in Thailand in FY79; the balancewas generated by PEA, NEA, private franchises and self-generating industries.

The Provincial Electricity Authority

1.19 PEA was established in September 1960 as a wholly-owned Governmentcorporation under the Ministry of Interior with responsibility for providingand distributing electricity in all provinces of the country except in theareas served by MEA. PEA purchases most of its energy in bulk from EGAT butalso generates small quantities in areas not yet connected to the grid. InFY79, PEA purchased, 4,678 GWh and generated 82 GWh; 4,254 GWh were sold to1,574,000 consumers. Compared with FY78, GWh sold and the number ofconsumers connected increased by 16.2% and 16.3%, respectively. Systemlosses were about 10.6% in FY79. This is acceptable considering the sizeand load density of its service areas.

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1.20 PEA is the Government agency responsible for implementing theaccelerated rural electrification program (para. 1.46). The program onlysubstantially began with Loan 1527-TH made by the Bank to PEA in 1978 forthe first major phase which will provide electricity to about 4,560 villagesby the end of 1982.

The Metropolitan Electricity Authority

1.21 MEA was established in 1958 as a wholly-owned Government corporationunder the Ministry of Interior with responsibility for supplying electricityto the Bangkok Metropolitan Area covering the provinces of Bangkok, ThonBuri, Nonthaburi and Samut Prakon. In FY79, 7,606 GWh were sold to 678,000consumers. Compared with FY78, energy sales and number of consumersincreased by 11.7%. Distribution losses were about 4.3% in FY79. All ofMEA's power is purchased from EGAT. The Bank has never been asked to assistMEA, as foreign fund requirements were provided by ADB, in the past.

Private Franchises

1.22 Following the fuel crisis and the Government's policy of restrict-ing tariff increases, most of the franchises asked to be taken over by PEA.Since FY76, 52 franchises have been purchased leaving four in private handsat the end of FY79; two of them purchase their power needs in bulk from PEAand one directly from EGAT.

Government Agencies

1.23 The eight Government agencies which have a direct interest in thepower sector (para. 1.16) are as under:

- Committee for Power Policy and Development (CPPD);

- Budget Bureauz

- Tariff Rate Committee (TRC);

- National Economic and Social Development Board (NESDB);

- Ministry of Finance (MOF);

- National Energy Administration (NEA);

- Foreign Loan Committee (FLC); and

- Petroleum Authority of Thailand (PTT).

These agencies review: tariff recommendations; capital project proposals andbudgets for submission to the Council of Ministers; annual financial perform-ance; and requests for Government equity and loans. None of them has overallpolicy responsibility, decisions on the sector being arrived at after all theagencies including the state utilities reach a consensus. The system isdesigned to ensure that sector capital expenditures are rigidly controlled,but the fiscal emphasis of the approval process has constrained sector deve-lopment in the past. The interest of PTT in the sector arises from the factthat EGAT, as the utility responsible for generation, will be the predominantcustomer for natural gas and is PTT's largest customer for fuel oil.

Sector Policy

1.24 The national policies in the power sector are:

(a) to ensure the sufficient production and supply of electricityin accordance with the economic growth throughout the kingdom;

(b) to diversify electricity generating sources by promoting theuse of new sources of energy such as natural gas and lignitein place of imported oil;

(c) to encourage international cooperation for the development ofwater resources and other natural resources for power generationand the establishment of an international transmission systeminterconnection; and

(d) to regulate the tariff within a reasonable range in order toencourage efficient use and conservation of electricity.

1.25 These policies are in line with the findings of a Bank energysector mission (para. 1.13). However, EGAT's emphasis on developing hydroand lignite and increasing the use of gas for power generation would reducethe demand of fuel oil and cause a major change in Thailand's refineryconfiguration. This is under study by consultants employed by theGovernment.

Sector Issues

1.26 Two sector issues were identified by the Sector Review in 1976(Report No. 1794-TH), institutional and financial. The institutional issueconcerns sector coordination; the financial issues concern tariff levels andpricing policy.

Sector Coordination

1.27 The need for sector coordination arose from the fact that too manyagencies had a part in sector decision-making causing decisions to be reachedas a compromise of views (para. 1.23) rather than the best decision in the

interests of the sector and Thailand as a whole. In 1977, the CPPD wasformed at cabinet level to oversee the functioning and development of thepower sector and provide overall control. However, CPPD has not developedinto a decision-making body with sufficiently broad competence to exercisecontrol or to provide the required focus for sector planning. A Ministry ofScience, Energy and Technology was established in 1979 to assume responsi-bility for the development of nonconventional energy and new uses of existingenergy sources, but so far, it has played a minor role in the larger sectorissues.

1.28 In the context of the loan for the Khao Laem Hydroelectric Project,it was agreed that a study of power sector coordination will be carried out byconsultants. Financing for the study is included in the loan for the KhaoLaem Hydroelectric Project which was not signed until June 17, 1980 due todelays in implementing the proposed tariff increases (paras. 1.31 and 1.32).The Government is in the meantime looking into the matter by itself and hasunder consideration a number of proposals, i.e., merging of MEA and PEA, thetwo distribution entities; merging of EGAT, MEA and PEA; or leaving thethree institutions intact but reporting to one ministry. Anotheralternative suggested by the Bank's energy sector mission would be thecreation of a separate energy ministry to which all the energy relatedinstitutions (EGAT, MEA, PEA, NEA and PTT) would report. The energy masterplan study (para. 1.12) being undertaken by NEA includes a review of theexisting institutional framework and organizational arrangement of theenergy sector as a whole and will recommend any changes as necessary. Itwas learned lately that the interim report of the study is dealing primarilywith the demand and supply aspects of the energy sector. The institutionalanalysis will not be completed until August 1981. It was decided duringnegotiations that the Government and the Bank should await the recom-mendations of this study on the institutional issues before undertaking studyfor power sector coordination.

1.29 The most important function in sector coordination is the cross-funding between EGAT, MEA and PEA. To improve the financial soundness ofthe sector, EGAT's bulk tariff to MEA and PEA should be adequate to generatesufficient internal cash to finance its larger expansion program. A pro-vision has been included in the documents of the proposed loan (para. 5.16)to ensure that sector resources are shared among the three utilities accord-ing to their needs and that these tariff levels are reviewed periodicallyand adjusted as necessary.

Tariff Levels and Oil Subsidies

1.30 Tariff levels proved adequate throughout the late 1960s and theearly 1970s, and the financial position of the sector remained strong.During the sixties and early seventies, the electricity sector enjoyedsubstantial economies of scale, shifts to hydro and large steam generationcoupled with rapid increases in demand and numbers of consumers. Tariffswere reduced from time to time during these years. The fuel crisis in1973/74 and economic slowdown in 1974/75 necessitated large increases in

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tariffs but the political changes in Thailand, which coincided with thosedevelopments, left the country ill-prepared for fully implementing suchincreases. Tariff increases took place in 1974 (50%) and 1977 (29%) but werenot sufficient to ensure the financial viability of the sector.

1.31 During 1979, fuel oil prices increased some 115%./1 In an attemptto cushion the impact of accelerating inflation, the Government chose todelay passing through the rising costs of electricity to consumers. In1978, prices of petroleum products were adjusted so that a greater proportionof the oil price increases were borne by gasoline consumers to the benefit offuel oil consumers. However, by mid-1979 this arrangement proved inadequateto cover the increasing costs of fuel oil to EGAT, and the Government, facedwith mounting criticism of its handling of the economy, introduced directbudgetary subsidies, estimated to cost about US$9.0 million a month. TheGovernment s attempts to raise tariffs in November, 1979 by about 56% werethwarted by strong political opposition and widespread public demonstrations.Despite these difficulties, the Government managed in February 1980 toincrease the power tariffs by 50% at the bulk supply level and 38% at theretail level and increase the prices of gasoline, diesel, kerosene and cookinggas ranging from 24-51%.

1.32 The Government was aware of the need for timely tariff increases toeliminate the oil and other subsidies to the sector as soon as possible and toenable the investment program to continue unhindered by financial constraint.A plan of action was agreed under the Mae Moh Lignite Project (Loan 1852-TH)to remove subsidies and restore the sector s financial viability. It consistsof the following specific steps:

(a) adjustment of electricity tariffs for bulk power in two ormore steps to remove all oil subsidies to the sector not laterthan January 1, 1981;

(b) a further tariff increase for bulk power around April 1, 1981 toachieve a 2% rate of return for FY81;

(c) procedures to avoid infrequent and large-scale tariff adjustmentsin the future, whereby the Government, together with theBank and EGAT, would review every six months, commencing fromOctober 1980, the tariff requirements of the sector for thenext two quarters and introduce agreed adjustments; and

(d) adjustments to the tariff schedules of the three utilitiesthrough the respective fuel adjustment clauses, to beintroduced promptly after oil price increases are announcedby the Government.

/1 Oil-fired thermal units, diesel sets and gas turbines produce in aggre-gate about 75% of EGAT-s total generation.

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1.33 Based on tariff reviews in July/August 1980, the Governmentannounced power rate increases on September 30, 1980 on average of43.0% at the bulk supply level and 35.0% at the retail level to beimplemented in two stages; two-thirds of the increase was effoctive fromOctober 1, 1980 and one-third of which was implemented as planned onJanuary 8, 1981. These tariff increases had eliminated fuel oil subsidybased on fuel oil prices at that time.

1.34 However, fuel oil prices were further increased on January 20,1981. During negotiations, it was agreed that as a condition of Boardpresentation, the Government would need to implement tariff adjustments onApril 1, 1981 sufficient to (a) enable EGAT and the sector as a whole toearn a rate of return of 2% in FY81; and (b) remove oil subsidies caused bythe fuel oil price increase in January 1981, and that in case the tariffadjustments were to be made in two steps (April 1 and July 1), the implemen-tation of the second tariff adjustment (July 1, 1981) would be a conditionof loan effectiveness. The Government succeeded recently in implementingtariff increases by an average of about 19% at the retail level effectiveApril 1, 1981 in one step, thus fully fulfilling the requirements stipulatedin the plan of action. Only modest increases in tariffs would be requiredto achieve an 8% rate of return for FY82 (para. 5.16).

Energy Pricing Policy

1.35 After the removal of all oil subsidies, PTT will charge EGAT andthe consuming public at cost in accordance with international oil prices,so the current distortions in pricing would be eliminated. Any oil priceincreases in the future would be taken care of by the fuel adjustment clause.

1.36 The objective of natural gas pricing is to secure a suitablelinkage between the price of natural gas charged EGAT and the internationalprice of fuel oil to ensure that the gas is priced at close to its economicvalue in the future. A provisional agreement was reached between PTT andEGAT subject to RTG's confirmation that (a) the natural gas will be pricedat US$3.75 per million BTU from October 1, 1981; and in the subsequent years,the price of natural gas will be adjusted by taking into consideration theprice of gas purchased by PTT from the gas fields including additionalPTT's expenses for the operation of the gas pipeline system, provided thatthe gas sale price, in relation to the posted price of fuel oil inSingapore shall not fall more than 10 percentage points below the pricelevel applicable on October 1, 1981.

1.37 The same principle would also apply to the pricing of lignite, theeconomic cost of which should be the breakeven cost of imported steam coalwith 3% sulphur content on a plant-to-plant basis taking into account thedifferences in capital investment, transmission line penalty, transmissionlosses and heat rate. A study is being carried out by consultants under theMae Moh Lignite Project (Loan 1852-TH), to determine the long-term forecasttransfer price of lignite. The study is expected to be completed beforeDecember 31, 1981.

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Bank Participation in the Sector

1.38 The Bank has made ten loans to EGAT and its predecessor totallingUS$442 million to help finance power plants and transmission facilities andtwo loans totalling US$100 million to PEA to finance its Accelerated RuralElectrification Projects. The first six projects of EGAT have beencompleted and are all operating satisfactorily. The Seventh Power Project,Srinagarind (Ban Chao Nen) Hydroelectric Project, was completed in March1980 as scheduled. The implementation of the Eighth Power Project (PattaniHydroelectric Project) is on schedule. A loan of US$80 million for theNinth Power Project (Loan 1690-TH, Bang Pakong Thermal Power Project) wassigned on August 9, 1979 and became effective on May 23, 1980. A loan ofUS$80 million for the Tenth Power Project (Loan 1770-TH, Khao LaemHydroelectric Project) was signed on June 17, 1980 and became effective onSeptember 17, 1980. Both projects are proceeding satisfactorily. PEA'sFirst Accelerated Rural Electrification Project (Loan 1527-TH) is underimplementation with about 1,090 villages electrified and another 1,000villages entering into construction. A loan of US$75 million for PEA'sSecond Accelerated Rural Electrification Project (Loan 1871-TH) was approvedby the Bank on June 12, 1980 and signed on November 14, 1980. Another loanof US$72 million (Loan 1852-TH, Mae Moh Lignite Project) was made to EGATin June 1980 for lignite production (para. 1.07).

1.39 To date only one project performance audit report has been pre-pared in respect of EGAT's operations. This report dated March 1978 for theSouth Bangkok Thermal Unit No. 4 Project (Loan 790-TH) indicated that themain objectives of the project had been met and that the project wascompleted on time and within the original cost estimate. No difficultieswere encountered during project implementation. For this project somefinancial advantage to the Borrower resulted from exercising an option topurchase duplicate generating equipment provided in the contract for UnitNo. 3 at the same generating station. This action was previously agreedwith the Bank. No other particular lessons were learned from thisconventional thermal project that could be applied to the proposed loan.

Power Market and Supply

1.40 Total generating capacity installed by the various entities at endFY79 was as follows:

Ownership Installed capacity (MW) %

EGAT 2,883.1 83.2PEA & NEA 73.5 2.1Private franchises - /a -Self-generating industries 507.1 14.7

Total 3,463.7 100.0

/a With an installed capacity of 20 KW only.

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1.41 Total energy generated or purchased in FY79 was 14,676.6 GWh,broken down as follows:

Installed capacity Generation UtilizationPlant MW % GWh % factor (%)

Hydro 910.0 26.3 3,101.2 21.1 39.0Thermal 2,086.7 60.2 10,397.0 70.8 57.0/aDiesel 302.0 8.7 278.4 1.9 10.5Gas turbine 165.0 4.8 241.1 1.7 16.7Purchased from - - 658.9 4.5

EDL

Total 3,463.7 100.0 14,676.6 100.0

/a Due to shortage of fuel oil, the energy generated by thermal plantsin FY79 was below normal.

1.42 Total energy consumption was 12,492.0 GWh in FY79 or 271 kWh percapita: 2,715.0 GWh (21.7%) were used by residential consumers; 1,856.6 GWh(14.9%) by commercial consumers; 7,822.2 GWh (62.6%) by industrial consumersand 98.2 GWh (0.8%) by street lighting and others. Total system losses wereabout 14.9% including station services.

Access to Electricity

1.43 Regional imbalances exist in the access of the population toelectricity; per capita consumption and the degree of domestic electrificationfor FY79 vary by regions as follows:

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Population % of elec-Population Consumption Per capita with trifi-( 000) (GWh) (kWh) electricity cation

('o00)

MEA area 6,201 7,606.0 1,226.5 5,069 81.7

PEA area /aCentral andNorthern 17,788 3,449.7 193.9 6,103 34.3

Northeastern 16,409 700.4 42.6 2,956 18.0Southern 5,715 735.9 128.7 1,435 21.0

Subtotal 39,912 4,886.0 122.4 10,494 26.3

Total 46,113 12,492.0 271.0 15,563 33.8

/a Including self-generating industries and private franchises.

1.44 The percentage of households connected in the country at end-FY79was 29.3% as shown below:

1979 1978 Rate of increase

Population ('000) 46,113 45,221 2.0Total households ('000) 7,108 7,012 1.4Residential connections (-000) 2,103 1,935 8.7Households connected (%) 29.3/a 27.6 6.1Consumption (GWh) 12,492.0 11,348.5 10.1

/a This percentage is lower than that of population with electricity(33.8%) because it is not unusual in Thailand to have one meterconnection serving more than one household.

Rural Electrification

1.45 Provision of power to the provincial areas began on a planned basisonly in 1960 with the formation of PEA. Since 1968 the number of consumersincreased at an annual average rate of 13.5% and the energy sales rose by21.5% p.a. The proportion of population electrified increased from 9.5% in1968 to 26% in 1979. PEA expects the rapid growth rate to continue for some

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time due to its large village electrification program (para. 1.46) and theacceleration in conversion of diesel engines to electric power brought aboutby increases in fuel prices and shortages of diesel fuel.

1.46 RTG directed PEA to plan an Accelerated Rural ElectrificationProgram in 1973 and to give priority to the more backward areas. The annualrate of villages connected rose from 940 in 1974 to 2,980 in 1979. Inaccordance with the directive, PEA originally planned to electrify all thevillages (about 49,000) in Thailand in about 25 years but now plans to do soby the late 1980s. In view of the magnitude of PEA's rural electrificationprograms now under implementation, this target is believed to be notunrealistic. It is expected that by 1985 and 1987 respectively, PEA's peakdemand and energy sales will exceed those of MEA, reflecting the progressmade in the provincial areas in general and in rural electrification inparticular.

2. THE BORROWER

2.01 The Borrower would be EGAT, established in 1968 by a merger ofthree generation and transmission authorities. It is a well organized andoperated utility under the control of competent management. EGAT and itspredecessors have received a total of US$442 million in ten loans from theBank since 1957. Loan proceeds have helped finance the expansion of themain generation and transmission system in Thailand. Although the proposedloan will assist in financing the eleventh Bank project in partnership withEGAT, growth of demand continues at a high level; the rural electrificationprogram as well as agricultural and industrial development are increasingthe need for generation and transmission facilities; and concentration onthe development and use of indigenous non-oil resources for generationrequires substantial investment which cannot yet be financed from commercialsources alone. Continued Bank assistance is therefore required.

Organization and Performance

2.02 EGAT is organized and functions as a modern public utility with aconsiderable degree of autonomy and is charged with the operation of thepower generation and transmission installations under its jurisdiction andthe establishment of such new facilities as may be required for the Thaipower grid down to transmission voltages of 115 kV and 69 kV. It does nothave responsibility for isolated diesel or mini-hydro generation or fortransmission and distribution below 69 kV.

2.03 The Board of Directors consists of a Chairman and not more thanten other members, including the General Manager. All Board membersact in a part time capacity, with the exception of the General Manager,and they are appointed by the Council of Ministers.

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2.04 EGAT is a power utility which can compare its operating efficiencywith most of the better run utilities in the developing world. The pasttrend of EGAT's performance is indicated in Annex 1. It is a borrower thatin general requires little or no institution building assistance from theBank (see Annex 2, the Organization Chart). There are no major internalproblems that would be the subject of special treatment under a subsectorloan.

Planning

2.05 EGAT has a well-staffed planning department responsible for survey,site investigation, planning of generation and transmission projects; economicstudies; power development programming and system planning; and financialforecasting. It uses consultants whenever necessary to assist in the prepara-tion of feasibility studies of large hydroelectric or multipurpose projects.It reviews and revises if necessary, the load forecast and the power deve-lopment program at least once a year based on the principle of least cost tocope with the changing economic conditions and the known primary energyresources available to the country (see para. 3.03 on load forecast andparas. 4.01 and 4.03 on investment program).

Engineering, Design and Construction

2.06 EGAT uses consultants for the engineering and design of majorhydroelectric and thermal power projects. Construction of generationprojects is undertaken by contractors under the supervision of EGAT's staffassisted by consultants. EGAT installs the equipment for power stations andsubstations using its own work force under the supervision of the manufac-turers. Transmission lines are constructed by the suppliers on a supply anderect basis. EGAT has an excellent record on project implementation andmanagement. Its dam safety instrumentation and monitoring program isnormally prepared by the consultants, put into operation and inspected andreviewed periodically by EGAT's staff.

2.07 Since 1974, EGAT has retained the services of an InternationalBoard of Consultants (IBC) for geological investigation and foundationtreatment of a rockfill dam for the Srinagarind Hydroelectric Project, a 360MW installation on the Quae Yai river and subsequently for most of the majorhydroelectric projects in Thailand. The Board's services have beensatisfactory.

Procurement

2.08 EGAT has been borrowing from the Bank since 1957. During the past23 years, EGAT has followed the Bank's procurement guidelines. Processingof tenders and award of contracts is undertaken equitably and expeditiously.No problems are expected for the proposed subsector loan.

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Management, Manpower and Training

2.09 Management and staff are able, competent and well-qualified. EGAThad a total of 17,301 employees at end-FY79. Manpower has grown at anannual rate of about 8% to meet the needs of the system expansion. Thefollowing table shows the manpower evolution by categories during the lastfive years:

Increase1975-79

1975 1976 1977 1978 1979 % p.a.

University graduates 1,287 1,456 1,628 1,882 2,046 12,0Diploma and higherprofessional education 1,397 1,547 1,780 1,778 1,938 8.0

Higher vocational education 2,094 2,412 2,752 2,742 2,983 9.0Others 7,919 8,887 9,366 9,528 10,334 7.0

Total 12$697 14 302 15 526 15,930 17 301 8.0

2.10 The number of staff reflects the fact that EGAT carries out mostof field investigation, survey and geological exploration using its own staffand maintains a large construction force for access road construction, sitepreparation works and installation of equipment, etc. (para. 2.06).

2.11 Training is handled by the authority's training and developmentdivision which arranges courses and seminars for all levels of staff. About4,000 trainees attended different programs during FY79. Recent increases inthe number of projects under construction and the increased size ofgenerating units in thermal power stations, have caused temporary shortagesof some categories of staff but the problems are being resolved by an activeprogram of recruitment and training.

Accounting and Audit

2.12 Accounting is based on the US Federal Power Commission's systemwhich is operated and administered by a well-qualified and competent staffon EGAT's computer.

2.13 The audit is performed by the National Audit Council, the Govern-ment organization responsible for auditing all state enterprises. Theinternational accounting firm, Coopers and Lybrand, is retained as financialconsultants to cooperate with the Audit Council and issue a separate reporton the annual accounts. Reports have been submitted on time and theperformance of the consultants has been satisfactory. Provision for thecontinued employment of independent external auditors has been included inthe loan agreement.

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Tariffs

2.14 Under the Pattani Hydroelectric Project, the Government and EGATagreed to carry out a tariff study on a marginal cost basis using a teamfrom the various agencies and utilities that cover the power sector. Thestudy was substantially completed by mid-1979 with the following findings:

(a) the marginal costs of power supply are higher than the currentaverage tariffs; and

(b) though the long-run marginal cost based tariffs will be thelong-term target of the Government, it would be difficult toimplement such tariffs in the near term. The study recommendedinstead a series of tariff increases by steps which wouldrevitalize sector's earning power to the extent necessary tocomply with the Bank's covenant for financial viability. It alsorecommended the following structural changes most of which havealready been carried out in the recently implemented tariffadjustments:

(i) an increase in maximum demand charges to reasonably reflectthe higher cost of peak load generation;

(ii) the introduction of increasing energy block charges forresidential consumers to encourage energy conservation;

(iii) the elimination of declining block tariffs for industrialconsumers, or at least a reduction in the rate of declineof energy charges applicable to increasing consumption;

(iv) the application of the fuel adjustment clause to reflectchanges in international cost of fuel oil; and

(v) the initiation of a study to establish the feasibility of"time of day" metering to promote off-peak consumptions.This study is being carried out by consultants financed byADB under the Mae Moh (No. 4) Power Project.

Energy Conservation

2.15 Energy conservation measures are being carried out by the Govern-ment through the mechanism of the energy pricing policy, setting of realisticnational targets of economic development, promotion of less energy-intensiveproduction modes and also the launching of a major public education program.The Government has recently established a national energy policy committeeunder the chairmanship of a deputy prime minister. This Committee is nowplanning to formulate more substantial energy conservation measures bothshort and long term. During negotiations, it was agreed that EGAT's currentpublic information program should be expanded and an amount of USU0.3 millionhas been provided under the proposed loan to procure equipment necessary forcarrying out such program.

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Insurance

2.16 In FY79 EGAT shifted to a self-insurance program and established asinking fund with the amount that it would have paid for insurance premiums.The appraisal mission discussed with EGAT the advisability of an expert reviewof the adequacy of this policy. During negotiations an agreement wasreached that EGAT will hire an expert to evaluate its self-insurance policyand procedures and present for Bank's comments a report with the expert'srecommendations before December 31, 1981.

2.17 The need of a risk analysis by experienced and knowledgeableinsurance consultants for large, complex and high-risk projects to identifythe risks attendant to the project and to assess the most appropriate andeconomic insurance coverage and EGAT-s risk management program in generalwas discussed during negotiations. Since such a study is being carried outfor a major hydroelectric project in the East Asia and Pacific Region, itwas agreed that EGAT would review the findings of this study with the Bank.

Taxes

2.18 EGAT does not pay income taxes. Custom duties are paid andreimbursed by Government in the form of equity contributions.

Environmental Aspects

2.19 Thailand has an Office of National Environmental Board (NEB)responsible to the Prime Minister-s Office to review the environmentalaspects of power projects including the protection and management ofecological systems, control of pollutants and wastes and protection of thepublic-s health. Any projects to be undertaken by EGAT would have to bereviewed and cleared by NEB. During negotiations, it was agreed that anenvironmental training program will be implemented under the proposedloan. It would include US$0.4 million to procure necessary equipment forair monitoring station and laboratory, and US$0.6 million to provide 18 man-months of environmental consultant services estimated at US$12,500 per man-month inclusive of travel and other expenses and 100 man-months of on-the-job training for EGAT staff.

Resettlement

2.20 EGAT has carried out successful resettlement programs in the pastfor the Srinagarind and Pattani Hydroelectric Projects. The resettlementprogram for the Khao Laem Hydroelectric Project is being executed. The samepractices will be followed for the future power projects. Normally two com-mittees (Compensation Committee and Resettlement Committee) will be set upconsisting of members from related Government agencies and the localgovernments to ensure that the resettlement will be carried out successfullyin accordance with the Government policy.

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Present Facilities

2.21 EGAT had a total of 2,883 MW in service at the end of FY79made up of:

Type of Plant MW %

Hydro 909.0/a 31.5Thermal (steam) 1,777.5 61.7Gas turbine 165.0 5.7Diesel 31.6 1.1

Total 2,883.1 100.0

/a Srinagarind plant (360 MW) was commissionedin March 1980.

2.22 EGAT-s grid is modern and efficient. Power is transmitted atthree voltage levels; 230 kV, 115 kV and 69 kV with a total length of 9,580circuit kilometers at end-1979. One hundred substations were in operationwith an installed capacity of 4,474 MVA. Annexes 3 and 4 give additionaldetails and the map attached shows the location of generating plants andtransmission lines.

Summary

2.23 In conclusion, EGAT follows the various procedures required of aborrower by the Bank; it has demonstrated competence in the areas of planning,operation and project implementation. Its institutional capability is fullysuitable for a subsector loan.

3. THE POWER MARKET

Background

3.01 EGAT-s market covers all of Thailand and comprises the GreaterMetropolitan area of Bangkok served by MEA; the provincial areas served byPEA; and industries and other large scale or specialized consumers that ithas been directed to supply by Royal Decree, including Electricite du Laos(EDL)./l EGAT-s sales in FY79 were as follows:

/1 EGAT purchased 658.9 GWh of energy in FY79 from Nam Ngum hydro stationof EDL in Laos and sold 6.7 GWh to EDL for distribution in the Thakhekand Suvannakhet provinces.

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AnnualPeak demand Energy sales Load factor

(MW) (GWh) (%)

MEA 1,262.0 56.3% 7,938.8 61.3% 71.8

PEA 891.0 39.7% 4,542.2 35.2% 58.2

Industries & EDL 87.5 4.0% 452.7 3,5% 59.0

Total 21,240.5 100.0% 12,933.7 100.0% 65.9

3.62 The power market has had a long history of steady growth, theav-rage annvial increase in peak and energy demands being 13.6% and 15.4%respectively over the period FY70-79. Demands grew rapidly in the early 1 970sdue to rising investments, favorable world rice markets, and an expandingeconomy. As a result of the oil crisis and world economic recession, the lowpoint was reached in FY74 when peak and energy requirements increased by only4.8% and 5.6% respectively. However, system growth has recovered rapidly

since FY75. Peak and energy growth are shown below:

Fiscal Energy Generation Peak Generationyear GWh % Increase M4W % Increase

1970 4,095.3 21.6 748.3 17,31971 4,792.9 17.0 872.7 16.61972 5,711.2 19.2 1,028.8 17.9

1973 6,872.8 20.3 1,199.3 16.6

1974 7,258.6 5.6 1,256.3 4,81975 8,211.6 13.1 1,406,6 12.0

1976 9,414.5 14.6 1,652.1 17.5

1977 10,950.6 13.2 1,873.4 13.4

1978 12,371.7 13.0 2,101,0 12.21979 13,964.6 12.9 2,255.0 7,4

Average FY70-79 15.4 13.6

Load Forecast

3.03 EGAT's load forecast is based on the consolidation of forecastsmade by MEA, PEA and the direct consumers after taking into account theeffects of load diversity, system losses and station services. The loadforecasts for MEA and PEA were derived by a study of historial growth trendsof different categories of consumers by the time series analysis method.The major consumer categories were: (i) residential, (ii) small business;

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(iii) medium business; (iv) large business; (v) street lighting; and (vi)others. PEA's load forecast had already taken into consideration the powerrequirements of the accelerated rural electrification program and its impacton PEA's annual load factor.

3.04 The previous load forecast was made in August 1980 by a LoadForecast Working Group consisting of representatives from NESDB, NEA and thethree utilities./l This load forecast was recently revised by EGAT as aninterim approach by taking into account the actual load growth in 1980 andthe impact of energy conservation and price elasticity. The revised loadforecast from FY81-90 is shown below:

Fiscal Energy Generation Annual Peak Generationyear GWh % Increase load factor MW % Increase

1980 14,753.7 (actual) 5.7/a 69.7 2,417.4(Actual) 7.2/a1981 16,512.0 11.9 70.0 2,692.8 11.41982 18,950.0 14.7 70.0 3,090.3 14.71983 21,315.9 12.5 70.0 3,476.2 12.51984 23,735.9 11.5 70.0 3,870.8 11.51985 26,465.5 11.5 70.0 4,316.0 11.51986 29,509.0 11.5 68.0 4,953.8 14.81987 32,624.0 10.5 67.1 5,551.8 12.11988 35,254.2 8.0 67.3 5,978.5 7.71989 38,034.8 7.9 67.5 6,428.6 7.51990 40,967.1 7.7 67.7 6,902.9 7.4

Average FY80-90 10.6 10.9

/a Load was suppressed due to constraints in generating capacity andeffects of energy conservation.

3.05 EGAT's peak and energy generation would increase from 2,417 MW and14,754 GWh in FY80 to 6,903 MW and 40,967 GWh in FY90. The average annualgrowth rates would be about 10.9% for peak generation and 10.6% for energygeneration which would level off to about 7.4% and 7.7% by FY90, respectively.It was agreed by EGAT and the Bank that this revised load forecast will beused as an interim basis for formulating the power development program and theconsequent financial projections. An in-depth review of the load forecast isbeing carried out by consultants in the long-term study for future generationand transmission projects subject to review by NESDB (para. 4.03).

/1 The Working Group, besides the normal micro-analysis, uses also themacro approach by correlating the load forecast with the projectedgrowth of GDP as an independent check.

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Supply

3.06 To meet the increasing generation requirements, EGAT-s system hasto be expanded continuously. The system load requirement and the capabilityavailable to meet the demand is given in Annex 5 and shown graphically inAnnex 6.

3.07 The reserve margin in the past was based on the criterion that thesystem will maintain supply to consumers with the largest unit out ofservice. EGAT had been able to maintain this criterion because annualscheduled maintenance of large thermal units can be carried out when systempeaking capability is ample and because it has hydro plants with largereservoirs which can be drawn down in the event of the forced outage oflarge thermal units. It has been decided, however, that with a greaternumber of large thermal units being added to the system, a modification ofthe reliability criterion will be necessary. EGAT has therefore decidedthat reserve requirements would be based on the largest and the secondlargest units being out of service simultaneously which will provide agross reserve margin of about 25%-35% of the system peak load over theperiod FY80-86 (See Annex 5). An analysis by EGAT indicates thatloss-of-load probability (LOLP) /1 in FY82 and FY83 is about three days peryear, improving to about one day in three years for FY85 and thereafter.This level of reliability is subject to review under the long-term study ofgeneration and transmission projects (paras. 3.05 and 4.03).

3.08 The system will be short of energy by about 3% of the total energygeneration required from March to June in 1983, if it happens to be a dryyear; the commissioning of the first 550 MW unit at the Bang Pakong thermalpower station scheduled for July 1983 will improve the situation from July1983 and thereafter. A well-planned maintenance program for the generatingunits coupled with special measures to reduce electricity consumption atcritical periods should be able to reduce the adverse impact on the economyto a minimum.

/1 LOLP is the probability of not being able to meet the load due toshortage of generating capacity under emergency conditions.

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4. THE PROGRAM AND THE PROJECT

General

4.01 EGAT's power development program is based on the principle of theleast-cost sequence of development, following an extensive study of thealternative generation and transmission projects using the computer programsavailable in-house. This program as demonstrated in the appraisal report ofKhao Laem Hydroelectric Project, is firm up to FY84 only; beyond that yearfurther studies and optimization are necessary contingent on the availabilityof primary energy resources. EGAT's power development program up to 1990 isformulated in accordance with the national policy: (a) to minimize thedependence on imported oil, indigenous natural gas and lignite resourceswill be fully developed; (b) hydro development will be accelerated to theextent that it is economically justified and within EGAT's implementationcapability in planning and construction; (c) imported coal will be used in thelate 1980s for the purpose of diversifying the energy sources. Since naturalgas and lignite are required by the system, they are supplemental to eachanother, no comparison between the two would be necessary. The justificationof hydroelectric projects and the comparison of lignite and imported coal arecompared on a program basis as shown in Annex 14. It indicates that both LangSuan and Chiew Larn hydroelectric projects are economically justified and thatearlier lignite development is the least cost solution inspite of the highcapital investment and long transmission line involved.

4.02 This program has been independently reviewed by a Bank energysector mission in the context of long-term national priorities and found tobe the optimum program, concentrating on renewable hydropower and indigenousresources of natural gas and lignite.

4.03 EGAT, however, considers that there are areas where consultancyservices might be helpful in the optimization of the program. Under theBang Pakong thermal power project (Loan 1690-TH), EGAT agreed to undertake along-term system study for future generation and transmission projectsincluding: an in-depth review of the load forecast; comparison of thermalalternatives including imported coal, indigenous lignite-fired thermal unitsand nuclear power development; a review of reserve margins and reliabilitycriteria; and formulation of a comprehensive development program for a periodof 20 years. The terms of reference of this study were finalized duringappraisal of this proposed loan (see Annex 7). The study is being carriedout by Chas T. Main International, Inc. of Boston in association with a localfirm, Team Consulting Engineers Co., Ltd. and is expected to be completedby late 1981.

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System Strategy

4.04 The present power system in Thailand is divided into four regionsas shown on the map attached. While Region 1, 2 and 4 are interconnected,Region 3 operated in the past in isolation. All generation in Region 3(South) is predominantly thermal (oil-fired, lignite-fired, diesel and gasturbines), but Pattani hydro (3 x 24 MW), which the Bank helped to finance,is under construction. A 150 kV transmission line has been completedrecently to link Region 3 to the main grid, financed under an ADB loan;reinforcement of the interconnection is also planned by constructing a 230kV line from Ban Pong 2 to Prachuap Khiri Khan. In Regions 1 (Central/west)and 4 (North), base-load is provided by the thermal plants located aroundBangkok, the major load center, and by the Mae Moh lignite plant in theNorth; hydro generation (Bhumibol, Sirikit and Srinagarind from 1980) coversthe intermediate and peak load requirements. Region 2 (Northeast) is mainlyserved by local hydro generation and by energy imported from the Nam Ngumhydro plant in Laos. A 230 kV tie line between Region 2 and 4 is underconstruction to improve the reliability of the power supply for Region 2.Although load dispatching and control is being performed on a nation-widebasis, regional balances in demand and supply would reduce transmissionlosses and a strong link between regions would result in operationalflexibility and economy. An extra high voltage (EHV) transmission linestudy is being carried out by consultants for the Mae Moh-Bangkok line.

The FY80-86 Program

4.05 EGAT's FY80-86 power development program comprises the followingcomponents:

(a) ongoing projects under construction with financial arrangementsfinalized;

(b) new generation and transmission projects to be completed beforethe end of FY86, with financing being sought; and

(c) future generation and transmission projects to be initiated inthis period but completed after FY86.

4.06 The details of EGAT's power development program, FY80-86, includingongoing projects totalling 2,498 MW, new projects totalling 768 MW, andfuture projects totalling 2,471 MW, are summarized in Annex 8.

Justification of a Subsector Approach

4.07 The justification of a subsector approach is based on thefollowing assessments:

(a) EGAT's investment program FY 80-86 is well formulated and is theleast cost to meet the country's development needs (para. 6.07);

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(b) Over the years, EGAT has demonstrated its competence inplanning, operation and project implementation to carry out itsdevelopment program (paras. 2.05 and 2.06);

(c) EGAT will select individual projects or subprojects for Bankfinancing based on agreed investment criteria (para. 4.15); and

(d) EGAT follows Bank's procurement and disbursement procedures(para. 2.08).

4.08 The proposed loan would be made only to EGAT to support thegenerating and transmission subsector because: (i) EGAT accounts for morethan 83% of the sector investment; (ii) MEA has never borrowed from the Bankand sees no need to do so; and (iii) PEA has just obtained a loan of US$75.0million for the Second Accelerated Rural Electrification Project (Loan1871-TH).

Scope of the Project

4.09 The proposed project consists of three subprojects (para. 4.16),selected in accordance with criteria agreed with the Bank (para. 4.15),from EGAT's new generation and transmission program to be completed beforethe end of FY86, as shown in Table 4.1 and EGAT's energy conservation andenvironmental training programs.

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Table 4.1: EGAT'S NEW GENERATION AND TRANSMISSION PROJECTS

ScheduledUnit Type of Capacity completionnumber plant (MW) date

A. Generation Projects

Sirindhorn StationExtension No. 3 Hydro 12 Dec. 1983

Mine for Mae MohThermal Station No. 5 - - July 1984

Srinagarind StationExtension No. 4 Hydro 180 July 1985

Minor Hydro Projects Hydro 51.5 Dec. 1985

Lang Suan Hydro Nos. 1-3 Hydro 135 April 1986

Chiew Larn Hydro Nos. 1-3 Hydro 240 June 1986

Mae Moh Thermal Lignite-Station Extension No. 6 fired 150 Sept. 1986

Mine for Mae MohThermal Station Nos. 6-7 Sept. 1986

Total 768.5

B. Transmission Projects

Transmission System Expansion No. 5 Sept. 1984

Transmission System Expansion No. 6 Sept. 1986

4.10 The proposed Bank loan of US$100 million would help finance athree-year time slice (FY82-84) of EGAT's expenditures and commitments forexpenditures for subprojects (para. 4.16) undertaken by EGAT during thisperiod, selected in accordance with the agreed investment criteria (para.4.15) and EGAT's energy conservation and environmental training programs(paras. 2.15 and 2.19). This arrangement would allow greater flexibility toEGAT and disbursements would be faster than under a normal project loan.

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Cost Estimate

4.11 The estimated cost of the new generation and transmission projectsto be completed before the end of FY86 is B 33.2 billion (US$1,621.4 mil-lion) excluding interest during costruction, of which B 16.8 billion(US$820.8 million) is foreign cost and B 16.4 billion (US$800.6 million)local cost. The total cost is summarized in Table 4.2.

Table 4.2: COST ESTIMATE

Foreign Local Total Foreign Local TotalProject ---- (B million) ---- --- (US$ million) ---

Sirindhorn StationExtension 86.1 43.0 129.1 4.2 2.1 6.3

Mine for Mae Moh ThermalStation No. 5 Unit 576.1 670.3 1,246.4 28.1 32.7 60.8

Srinagarind StationExtension 522.7 178.4 701.1 25.5 8.7 34.2

Minor Hydro Projects 537.1 264.5 801.6 26.2 12.9 39.1Lang Suan Hydro 1,500.6 2,617.8 4,118.4 73.2 127.7 200.9Chiew Larn Hydro 2,007.0 1,760.9 3,767.9 97.9 85.9 183.8Mae Moh Thermal StationExtension No. 6 2,252.9 945.1 3,198.0 109.9 46.1 156.0

Mine for Mae Moh ThermalStation Nos. 6-7 1,211.5 1,744.6 2,956.1 59.1 85.1 144.2

Transmission SystemExpansionNo. 5 project 1,125.5 826.1 1,951.6 54.9 40.3 95.2No. 6 project 1,685.1 1,271.0 2,956.1 82.2 62.0 144.2

Total base cost 11,504.6 10,321.7 21,826.3 561.2 503.5 1,064.7

ContingenciesPhysical 1,098.8 684.7 1,783.5 53.6 33.4 87.0Price 4,223.0 5,405.8 9,628.8 206.0 263.7 469.7

Subtotal 5,321.8 6,090.5 11,412.3 259.6 297.1 556.7

Total cost 16,826.4 16,412.2 33,238.6 820.8 800.6 1,621.4

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4.12 The cost estimate is based on end-1980 price levels. Physicalcontingencies were included in accordance with EGAT's experience for diffe-rent types of projects ranging about 20% for civil works, 5% for equipmentand 10% for transmission facilities. The price contingencies for foreigncosts were calculated on the basis of assumed annual rates of escalation:9% for 1981, 8.5% for 1982, 7.5% for 1983-85 and 6.0% for 1986 and there-after. The price contingencies for local costs were assumed to be 16% for1981, 12% for 1982-83, 10% for 1984, 9% for 1985 and 8% for 1986 and there-

after.

Financing Plan

4.13 The financing plan for the new generation and transmission pro-jects to be completed before the end of FY86 is shown in Table 4.3.

Table 4.3: FINANCING PLAN FY80-86

Baht US$ %------------ (million)------------

IBRD proposed loan 2,023.4 98.7 /a 6.1Export credit 5,350.5 261.0 16.1Commercial banks 4,475.1 218.3 13.5ADB 2,726.5 133.0 8.2KFAED 410.0 20.0 1.2OECF 1,840.9 89.8 5.5EGAT, Government Equity

and local borrowings 16,412.2 800.6 49.4

Total Sources 33,238.6 1,621.4 100.0

/a Net of US$ 1.3 million allocated for environmental training and energyconservation programs.

4.14 It is EGAT's normal practice to use suppliers'/export creditsfor the financing of major equipment such as boilers and turbine-generators;bilateral credits or loans from international institutions such as ADB andthe Bank for the financing of civil works, engineering services and equip-ment and materials which are not suitable to be financed by suppliers'/export credits. The balance of the foreign fund requirement will be met byloans from commercial banks.

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Selection of Subprojects

4.15 The following criteria were discussed and agreed duringnegotiations:

(a) technical soundness - consultants with qualifications and underterms acceptable to the Bank have been used in the feasibilitystudy, engineering and design studies for major hydro and thermalprojects. The Bank would also review the work done by consultantsemployed by EGAT;

(b) economic justification - any subprojects to be selected forBank financing should be the least cost when compared with otheralternatives with an equalizing discount rate of not less than12%;

(c) financing arrangements - appropriate financing arrangements forthe subprojects have been made; and

(d) Government's prior approval has been obtained, signifying that thesubprojects form part of the national development program.

4.16 The subprojects proposed by EGAT for Bank financing consist ofthe following:

(a) Chiew Larn Hydroelectric Project (3 x 80 MW);

(b) Lang Suan Hydroelectric Project (3 x 45 MW); and

(c) Transmission System Expansion Project No. 5.

4.17 The feasibility study and engineering design for the Chiew Larnand Lang Suan projects were prepared by reputable consultants acceptableto the Bank and these studies and designs have been reviewed by the Inter-national Board of Consultants. An independent review by the Bank staffconfirmed that these hydroelectric projects are technically sound andeconomically justified and the works carried out by the Consultants weresatisfactory. The resettlement plan for the Chiew Larn Hydroelectric projecthas been reviewed by the Bank and found to be satisfactory.

4.18 Project description, cost estimate and financing plan for the threeproposed subprojects are given in Annex 9. These subprojects meet the agreedcriteria with the exception of the Lang Suan Hydroelectric Project for whichthe environmental and ecological investigations are still being updated, theresettlement program is under preparation and therefore the Governmentapproval of the project is pending. A provision has been made in the legaldocuments

/1 Major hydro projects: 50 MW or above in installed capacity or forprojects where dams are to be constructed. Major thermal projects:120 MW or above.

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(Schedule 2 of the Loan Agreement) that any of the subprojects may be replacedby agreement between EGAT and the Bank (para. 4.24) by any of the othersubprojects included in Table 4.1 as long as the agreed criteria (para. 4.15)are met. The Government has agreed to provide funds or cause such funds to beprovided to EGAT which would be requim.k d for carrying out the project.

Procurement

4.19 The proposed loan would be used to cover payments of foreign costof the following items for the selected subprojects:: (a) civil works; (b)equipment and materials; and (c) consultant services and training.

4.20 Civil works and equipment and materials to be financed under theproposed Bank loan will be procured under international competitive biddingin accordance with the Bank's procurement guidelines. For contracts forcivil works and equipment and materials expected to cost above US$2.0 mil-lion, prior review of the tender documents and prior approval of bid awardby the Bank would be required. For equipment and material contracts lessthan US$2.0 million, prior review would be at the option of the Borrower.A preference of 15% (or custom duties, if less) will be granted to localmanufacturers of equipment and materials. In the case of minor items ofequipment and materials expected to cost less than US$250,000 equivalent eachand not exceeding, in the aggregate, the equivalent of US$2.5 million,contracts may be awarded in accordance with local procurement proceduresacceptable to the Bank.

Disbursement

4.21 Disbursements for equipment and materials would be made against100% of the foreign exchange cost of directly imported equipment; 100% ofex-factory cost for equipment manufactured locally; and 85% of total expendi-tures for imported equipment procured locally off-the-shelf. Disbursementson civil works would be 55% of total expenditures. For consultant servicesand training, disbursements would be against 100% of the foreign expenditures.The disbursement schedule is given in Annex 10. The loan closing date will beJune 30, 1985. Disbursements will be made against full documentation in res-pect of EGAT's expenditures or commitment for expenditures made prior to theend of EGAT's FY84.

4.22 No withdrawals will be made in respect of payments made for expen-ditures prior to loan signing, except that withdrawals in an aggregate amountnot exceeding US$1.0 million may be made on payments incurred after April 1,1981 for environmental monitoring equipment, equipment for public informationprograms, consultant services and training. No disbursement will be made inrespect of Lang Suan Hydroelectric Project prior to Governmental approval ofthe said project.

Project Implementation

4.23 EGAT will be responsible for implementing all the subprojectsfinanced under the proposed loan. During negotiations it was agreed that

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where dams are to be constructed for hydroelectric projects, the layout anddesign of the project will be reviewed by an international board ofconsultants acceptable to the Bank. IBC would also inspect the site fromtime to time throughout the construction period of the project.

4.24 It was also agreed that:

(a) EGAT will, not later than August 31, 1981 submit for the Bank'sreview and comment an environmental and ecological investigationreport and a resettlement plan for the Lang Suan HydroelectricProject; and

(b) Should the Government not approve the Lang Suan HydroelectricProject before June 30, 1982, EGAT will seek the Bank's agreementto replace the said project by September 30, 1982 with any of theother subprojects that meets the agreed criteria (para. 4.15).

Risks

4.25 EGAT uses extensively the services of IBC whose advice will besought should any unusual technical problems arise in connection with theconstruction of hydroelectric projects. To minimize problems duringconstruction for hydroelectric projects, EGAT has initiated socioeconomicsurveys to develop comprehensive resettlement programs and to establishacceptability by the communities involved. The Government has actedpromptly to adjust tariffs to reflect increases in production cost,particularly fuel prices. Remaining risks are judged not to be significantenough to preclude proceeding with the loan.

Completion Report

4.26 In order to inform the Bank and the Borrower about the performanceof the project, and the lessons learned during its execution, a completionreport is required. EGAT should undertake not later than six months aftercompletion of the subprojects financed by the Bank or such later date as maybe agreed for this purpose between the Borrower and the Bank, to prepare andfurnish to the Bank a report, of such scope and in such detail as the Bankshall reasonably request, on the execution of the loan, the performance bythe Borrower and the Bank of their respective obligations under the loanagreement and the accomplishment of the purposes of the loan.

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5. FINANCIAL ANALYSIS

Past Perfornaace

5.01 The financial performance of EGAT over the last 5-year period issummarized in Table 5.1 and shown in detail for FY72-80 in Annex 11.

Table 5.1: SUMMARY OF EGAT's FINANCIAL PERFORMANCE, FY76-80

1976 1977 1978 1979 1980 /d

Energy Sales (GWh) 8,696 10,149 11,516 12,934 13,673Ave. Price (B/kWh) 0.4397 0.4579 0.5631 0.5585 0.7523

(Baht Millions)Revenues 3,833 4,666 6,511 7,238 10,406Operating Expenses

Fuel/Bulk Power 1,679 2,683 4,157 4,396 8,074Operations & Depreciation 1,451 1,607 1,761 2,186 2,873

Net Income before interest 703 376 593 656 (541)Long-Term Debt (net) 8,303 8,965 11,849 13,167 18,540Total Equity 12,640 13,106 14,655 18,370 22,856Rate of Return /a 4.4 2.2 3.2 3.0 (1.9)Operating Ratio (%) /b 81.6 92.0 90.9 90.9 105.2Current Ratio 1.5 0.9 1.0 1.0 0.6Debt Service Coverage 2.2 1.5 1.4 1.4 0.7Contribution toConstruction /c 56.7 13.2 59.0 9.6 (5.0)

/a On net revalued fixed assets.

/b Operating expenses, including depreciation, as a percentage of revenue.

/c 3-year average.

/d Unaudited.

5.02 During the period FY76-79 EGAT consistently generated operatingsurpluses in spite of large increases in fuel costs and the Government-imposed constraints on tariff adjustments as a part of the Government'santi-inflationary measures. Before FY80 EGAT's debt service coverage on anannual basis was not lower than 1.4 times. EGAT managed to accomplish thisperformance through greater efficiency resulting from increases in hydrogeneration and larger steam plants.

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5.03 From FY78 EGAT started to feel the impact of several externalfactors, namely reduced water availability for generation, higher operatingcosts due mainly to large fuel price increases and for some time limitedavailability of fuel. EGAT's financial results for FY79 reflect thissituation. Government attempts to raise tariffs to the required level metwith strong public opposition and only a modest increase of 38% at theretail level (50% at the bulk supply level) was implemented in February 1980(para. 1.31).

Present Financial Position

5.04 EGAT-s operating loss for FY80 was B 541 million and net loss (afterinterest charges) at B 1.17 billion. To help solve EGAT's temporaryliquidity problems the Government granted it equity contributions in theamount of B 1.2 billion ($58 million), short-term loans of B 0.5 billion($24 million) and arranged a transfer of funds from MEA and PEA to EGAT of B100 million ($5 million). These funds ensured that EGAT's normal operationsand investment program were not affected.

5.05 A plan of action to restore the sector financial soundness wasagreed with the Government during negotiations of Loan 1852-TH (para. 1.32).Under it, budgetary oil subsidies were removed in January 1981 and electricitytariffs were increased on April 1, 1981 to yield a minimum rate of return,for the sector, of 2% in FY81 (para. 1.34).

Future Financial Position

5.06 Economic expansion and the additional generation and transmissioncapacity required to support Thailand's development needs will cause EGAT toexpand its asset base four times from FY80 to FY86. Expenditures to meetthe required construction program for the period FY82-86 are estimated tototal B 114.7 billion (US$5.6 billion) at current prices including interestduring construction. EGAT plans to borrow 70% abroad to cover foreigncosts; 11% will be borrowed locally, 1% would come from Government equity;and 18% would be self-financed, on the assumption that not less than 8% rateof return on revalued net fixed assets will be earned by EGAT and the sectorfor FY82 and thereafter (para. 5.16). The financing plan for the periodfrom FY82 through FY86, based on these assumptions, is shown in Table 5.2.Financial forecasts for EGAT, MEA, PEA and the sector are shown in Annex 12and the assumptions incorporated in these forecasts are shown in Annex 13.

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Table 5.2: EGAT AND SECTOR FINANCING PLAN FY82-86

EGAT Power sectorB US$ B US$(billions) % (billions) %

Financial RequirementsInvestment program 101.3 4.9 84.7 121.7 5.9 84.9Interest during construction 13.4 0.7 11.2 16.1 0.8 11.2

Total Investment 114.7 5.6 95.9 137.8 6.7 96.1

Working capital requirements 4.8 0.2 4.1 5.5 0.3 3.9

Total Requirements 119.5 5.8 100.0 143.3 7.0 100.0

SourcesInternal cash generation 55.5 2.7 46.4 73.9 3.6 51.6Less: Debt service /a 33.5 1.6 28.0 43.1 2.1 30.1Net Internal cash generation 22.0 1.1 18.4 30.8 1.5 21.5Borrowings 96.6 4.6 80.8 111.3 5.4 77.6Equity 0.9 0.1 .8 1.2 0.1 0.9

Total Sources of Funds 119.5 5.8 100.0 143.3 7.0 100.0

/a Excluding interest during construction.

5.07 EGAT has no difficulty in raising funds in foreign markets. It hasa long standing association with the Asian Development Bank (ADB), and theOverseas Economic Cooperation Fund (OECF) of Japan and more recently withthe Kuwait Fund for Arab Economic Development (KFAED). No difficulties havearisen in the past in obtaining bilateral financing and suppliers credits.Since funds were first obtained from commercial banks in 1978 for cofinan-cing the Pattani project with the Bank, EGAT has made increasing use ofEuro-dollar and other sources and has obtained several commercial bank loansfor its projects. Commercial bank loans are now raised annually to coverany financing gap.

5.08 In the future, EGAT should charge MEA and PEA adequate tariffs forbulk power, to ensure an equitable division of sector resources among thethree utilities according to their investment requirements. A provision tothis effect has been incorporated in the legal documents (see para. 5.16).

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Tariff Levels

5.09 The bulk power prices that EGAT charges and the average tarifflevels of MEA and PEA have been estimated on the basis that the sector asa whole earns the covenanted RORs for FY81 and thereafter. EffectiveApril 1, 1981, EGAT's average tariff increased from B 1.20 (US¢5.8) toB 1.45 (US¢7.1) and the sector's average tariff increased from B 1.50(US¢7.3) to B 1.79 (US¢8.7) per kWh, equivalent to 21% and 19% respectivelyto generate the required 2% rate of return./l On this basis, the averagetariff levels that EGAT and the sector would charge per kWh at currentprices and the percentage increases required to achieve them are as follows:

EGAT SectorFY B US¢ % of Increase B US¢ % of Increase

1979 0.56 2.7 - 0.80 3.9 /a1980 0.75 3.7 37.0 1.01 4.9 25.61981 1.31 6.4 73.0 1.60 7.8 59.21982 1.48 7.2 12.5 1.85 9.0 15.41983 1.61 7.8 8.3 2.01 9.8 8.91984 1.69 8.2 5.1 2.14 10.4 6.11985 1.74 8.5 3.6 2.23 10.9 4.81986 1.88 9.2 8.2 2.41 11.8 8.21987 2.05 10.0 8.7 2.67 13.0 10.21988 2.17 10.6 6.0 2.76 13.4 3.1

/a For comparison purposes the average tariffs per kWh (in IJS¢)in other countries in the area in 1979 are as follows:Malaysia 6.9; Indonesia 4.4; Korea 6.2.

Future Operating Results

5.10 EGAT's energy sales are estimated to increase from 13,673 GWh inFY80 to 32,948 GWh in FY88, an average annual growth rate of 11.6%. Underthe assumptions followed, revenues are forecast to increase from B 10.4 bil-lion (US$0.51 billion) in FY80 to B 71.4 billion (US$3.48 billion) inFY88, an average annual growth rate of 27%; operating expenses excludingdepreciation are expected to grow from B 9.4 billion (US$0.46 billion) forFY80 to B 45.1 billion (US$2.2 billion) in FY88 giving an average annualgrowth rate of 21%.

/_ See para. 1.34.

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5.11 A downward trend in the operating ratio from 105% in FY80 to 77%in FY88 indicates the improved financial situation over the forecast period.This is reflected in an increasing proportion of revenues made available tohelp finance construction expenditures; the self-financing ratio increasesfrom a negative figure in FY80 to 21% in FY88.

5.12 To achieve a more rational use of the sector-s resources thefinancial projections assume that some cross funding will take place in thefuture among EGAT, PEA and MEA. This would result in higher rates of returnfor EGAT (about 9%) than PEA and MEA while the sector as a whole complieswith the present rate of return covenant (para. 5.16).

Debt Control

5.13 The capital structure will remain satisfactory throughout theforecast period; the debt equity ratio is estimated to vary between 44/56(FY80) and 59/41 (FY86). EGAT-s current debt control test providesfor Bank review of borrowings when the debt equity ratio exceeds'60/40 orwhen medium term debt /1 aggregates to 15% of total debt. It was agreed tocontinue these tests for the proposed loan.

Liquidity Position

5.14 Under the assumptions followed, during the forecast period (FY81-88) EGAT-s working capital will increase by B 8.6 billion (US$0.42 billion).Its current ratio will recover from a minimum of 0.6 in FY80 due to cashbalances being lower than desirable in the early years of the forecast periodand will remain above 1.0 after FY82. Additionally, EGAT has access toshort-term borrowing in an emergency; the position is therefore acceptable.

5.15 Consumer accounts receivables at end FY79 were about 2.4 monthsbilling which is high for a bulk power supplier. This situation started toimprove in FY80 (2.2 months) and will be further improved because recentlythe Government instructed PEA and MEA to pay their bills to EGAT within 30days. The cash flow benefits to EGAT from this action will be partiallyoffset because EGAT will have to pay PTT-within the same period.

Financial Covenants

5.16 The following covenants concerning corporate financial performanceand agreed under previous loans have been continued in the proposed loan:(a) EGAT furnish to the Bank financial statements and accounts audited byconsultants satisfactory to the Bank within six months of the end of eachfinancial year; (b) the long-term debt to equity ratio should not exceed60:40 and medium term debt should not exceed 15% of total debt for theduration of the loan; (c) EGAT and the sector will achieve a rate of return

/1 Debt which on issue matures within 5 years.

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on average revalued net fixed assets in operation of not less than 2% forFY81 and 8% thereafter; and (d) the Government will review periodically andmake frequent adjustments as necessary, the adequacy of EGAT, PEA and MEAtariffs required to produce: (i) the covenanted rates of return for thecurrent and next following fiscal years and (ii) accomplish the requiredcross funding among the three utilities to enable them to carry out theirinvestment programs. EGAT will maintain in its tariff schedule a provisionfor fuel and power purchase adjustments to compensate for changes in theprice of all fuels and purchased power.

6. ECONOMIC JUSTIFICATION AND ANALYSIS

General

6.01 The power demand in Thailand is expected to increase at an annualrate of about 10% for the next decade (para. 3.05). The proposed loan isintended to help finance EGAT's power development plan from FY80-86 on aprogram basis. This chapter will deal with the comparison of alternativeprograms to meet the projected demand growth at the least cost and theinternal economic rate of return expected to be achieved for the specifictime slice of the expansion program.

6.02 The discounted cash flow method was used in the least costanalysis for comparison of alternative programs. The cost-benefit analysiswas made on a program basis, rather than project basis.

Production and Benefits

6.03 Only new projects to be completed during the period FY80-86 weretaken into consideration. The installed capacity, peaking capability andenergy outputs of these new plants are listed in Table 6.1.

6.04 The main objective of EGAT's development policy is to convert theoil-based generation to other renewable and indigenous energy sources suchas hydro, natural gas and lignite. Based on the program as shown in Annex6, the composition of energy generation and sources of energy aredemonstrated in Table 6.2. Therefore, oil-based generation would reducefrom about 72% in FY81 to 11% in FY86 and 6% in FY91.

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Table 6.1: INSTALLED CAPACITY, PEAKING CAPABILITY ANDENERGY OUTPUTS OF NEW PLANTS

DependableInstalled peaking Energy outputcapacity capacity Average Firm

Power plants (MW) (MW) ------ (GWh)…

Hydro Plantssrinagarind units #1-3 360.0 358.5 1,178.7 888.1Bhumibol extension unit #7 133.0 110.8 - -Pattani units #1-3 72.0 53.5 208.8 116.8Lower Quae Yai units #1-2 38.0 38.0 170.5 140.0Khao Laem units #1-3 300.0 241.1 765.3 457.6

Sirindhorn extension unit #3 12.0 11.4 - -Sinagarind extention unit #4 180.0 180.0 - -Lang Suan units #1-3 135.0 135.0 333.9 225.6Chiew Larn units #1-3 240.0 220.0 553.7 499.0

Subtotal 1,470.0 1,348.3 3,210.9 2,327.1

Thermal PlantsBarge plant 75.0 71.3/a 525.0/b -Bang Pakong combined cycle 1 360.0 342.0 1,890.0 -Bang Pakong combined cycle 2 360.0 342.0 1,890.0 -Bang Pakong thermal unit #1 550.0 522.5 3,950.0 -Bang Pakong thermal unit #2 550.0 522.5 3,950.0 -Mae Moh lignite unit #3 75.0 71.3 490.0 -Mae Moh lignite unit #4 150.0 142.5 985.0 -Mae Moh lignite unit #5 150.0 142.5 985.0 -

Subtotal 2,270.0 2,156.6 14,665.0 -

Gas Turbine PlantsSouth Bangkok units #1-3 100.0 80.0 88.0 -

Subtotal 100.0 80.0 88.0 -

Total 3,840.0 3,584.9 17,963.9 -

/a The dependable peaking capacity of thermal plants is calculated at 95%of the rated capacity.

/b The average energy output of thermal plants is calculated at thefollowing annual capacity factors: Barge - 80%, Combined cycle - 60%,Bang Pakong thermal - 82%, Lignite units - 75%.

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Table 6.2: COMPOSITION OF ENERGY GENERATION AND SOURCES OF ENERGY

Energy generation (GWh)Type of plant FY81 FY86 FY91

Hydro 2,305 (14.0%) 5,416 (18.4%) 8,281 (18.8%)

ThermalOil 10,751 (65.1%) 3,216 (10.9%) 826 (1.9%)Lignite 1,487 (9.0%) 3,635 (12.3%) 11,350 (25.7%)Natural gas - - 15,527 (52.6%) 16,249 (36.8%)Imported Coal - - 985 (3.3%) 4,925 (11.1%)

Gas turbine & diesel 1,179 (7.1%) 5 1,845 (4.2%)

Purchased energy 790 (4.8%) 725 (2.5%) 650 (1.5%)

Total 16,512 29,509 44,126

Least Cost Analysis

6.05 As demonstrated in the Appraisal Report of Khao Laem HydroelectricProject (Report No. 2568a-TH), EGAT-s power development program is definiteup to FY84 upon the completion of Bang Pakong Thermal Unit No. 2. The knownreserves of natural gas will be fully committed by that time. To find theleast cost program of system development from FY85-93 the following foursequences, including the transmission systems required to carry the powerto the grid, were compared on a program basis (Table 6.3). Sequence A isthe base program; Sequence B is used to compare Lang Suan and Chiew Larnhydroelectric projects included under Sequence A with their thermalalternatives; Sequence C is used to compare Lang Suan and Chiew Larnhydroelectric projects with a larger thermal unit in the central region andgas turbines in the South; and Sequence D is used to find the economicsequence of development of lignite-fired units at Mae Moh with coal-firedunits at Si Racha using imported coal (Annex 14 provides further details).

6.06 The comparison was made on a constant price basis by comparing thetotal present value of capital investment, operation, maintenance and fuelcosts. The fuel costs were calculated by merit-order operation of generatingplant on a system basis. Efficiency prices were applied as follows:

(a) taxes and duties were excluded;

(b) foreign exchange costs were shadow priced by a factor of 1.1; and

(c) the conversion factor for skilled and unskilled labor wasassumed to be 1.0.

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Table 6.3: ALTERNATIVE PROGRAMS OF SYSTEM DEVELOPMENT, FY85-93

Year Sequence A Sequence B Sequence C Sequence D

Apr. 1986 Lang Suan Hydro Oil-fired Oil-fired Lanig Suan Hydro(3x45 MW) (75 MW) (150 MW) (3x45 MW)

Gas turbines(3x25 M4W)

June 1986 Chiew Larn Hydro Oil-fired Gas turbines Chiew Larn Hydro(3x80 MW) (75 MW) (9x25 MW) (3x80 MW)

Gas turbines(6x25 MW)

Aug. 1987 Mae Moh #8 Mae Moh #8 Mae Moh #8 Coal-fired #1(300 MW) (300 MW) (3U0 MW) (6U0 MW)

Mar. 1988 Mae MIoh #9 M5ae Moh #9 Mae Moh #9 -

(300 MW) (300 MW) (300 MW)

Sept. 1988 Mae Moh #10 Mae Moh #10 Mae Moh #10 Coal-fired #2(300 MW) (300 MW) (300 MW) (600 MW)

Oct. 1989 Coal-fired #1 Coal-fired #1 Coal-fired #1 -(600 MW) (600 MW) (600 MW)

Oct. 1990 - - - Coal-fired #3(600 MW)

Oct. 1991 Coal-fired #2 Coal-fired #2 Coal-fired #2 Coal-fired #4(600 MW) (600 MW) (600 MW) (600 MW)

Apr. 1992 - - - Mae Moh #8(300 MW)

Oct. 1992 Coal-fired #3 Coal-fired #3 Coal-fired #3 Mae Moh #9(600 MW) (600 MW) (600 MW) (300 MW)

Apr. 1993 Coal-fired #4 Coal-fired #4 Coal-fired #4 Mae Moh #10(600 MW) (600 MW) (600 MW) (300 MW)

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6.07 The total present value of the four sequences at several discountrates are shown in Table 6.4. Sequence A is the least-cost program for alldiscount rates up to 16%. This demonstrates that the Lang Suan and ChiewLarn hydroelectric projects are economically justified when the opportunitycost of capital is below 16%. A sensitivity test analysis between sequenceA and sequence B indicates that even with a 20% increase in the cost of LangSuan and Chiew Larn hydroelectric projects and 20% decrease in fuel cost(assuming that natural gas would become available for the southern area inthe future), Sequence A is still the least-cost solution up to a discountrate of about 14%. Between sequence A and sequence X, the equalizingdiscount rate is 22% which means that early lignite development is moreeconomical than late lignite development.

Table 6.4: TOTAL PRESENT VALUE, SEQUENCES A-D

Discountrate Sequence A Sequence B Sequence C Sequence D

() ------------------------ (B million) ------------------------

10 146,416 152,972 151,313 147,51012 115,511 119,387 117,966 116,30714 94,345 96,534 95,275 94,90516 79,211 80,303 79,164 79,58618 67,984 68,344 67,301 68,21420 59,393 59,255 58,291 59,508

Internal Economic Rate of Return

6.08 The internal economic rate of return (IERR) was calcuated byequalizing the present value of the economic costs and benefits of theSector's least-cost development program from FY80 through FY86. The costsincluded are capital investment for generation, transmission and distri-bution projects to market the power to the retail consumers, operation andmaintenance costs, operating costs for distribution and fuel costs.Efficiency prices were used. Revenues were calculated from incremental salesand average tariffs at the retail level adjusted to end-1980 level as aminimum estimate of the power benefits. Savings due to fuel replacementwere also taken into consideration. The IERR thus calculated is about 12%(further details are provided in Annex 15).

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7. AGREEMENTS REACHED AND RECOMMENDATIONS

Agreements Reached

7.01 During negotiations, agreement was reached on the following:

(a) With the Government

(i) Government will make available to EGAT any funds needed forcarrying out the project (para. 4.18);

(ii) the sector will earn rate of return of not less than 2% forFY81 and 8% for FY82 and thereafter (para. 5.16); and

(iii) Government will review tariff levels periodically and estab-lish the price for bulk supply that EGAT will charge MEA andPEA (para. 5.16).

(b) With EGAT

(i) the recommendations of the Energy Master Plan Study will beawaited before undertaking the study for power sectorcoordination (para. 1.28);

(ii) EGAT will continue using financial consultants for independentauditing (para. 2.13);

(iii) EGAT will use consultants to evaluate its self-insurance policyand procedures (para. 2.16);

(iv) EGAT will review with the Bank the findings of a risk analysisstudy for a major hydroelectric project in the East Asia andPacific Region (para. 2.17);

(v) EGAT will submit for the Bank's review an environmental andecological investigation report and a resettlement plan(para. 4.24);

(vi) EGAT will seek the Bank's agreement to replace the Lang SuanHydroelectric Project with other subprojects, should theGovernment not approve the said project (para. 4.24);

(vii) EGAT will earn rate of return not less than 2% for FY81 and8% for FY82 and thereafter (para. 5.16); and

(viii) the existing debt control covenants under Loan 1770-TH willbe continued (para. 5.16).

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Recommendations

7.02 With the agreements reached on the above, the project forms asuitable basis for a loan to EGAT of US$100.0 million for a period of 20years including 5 years' grace, with the guarantee of the Royal ThaiGovernment.

- 43 -ANNEX 1

THAILAND

POWER SUBSECTOR PROJECT

Electricity Generating Authority of Thailand

Highlights of EGAT, MEA and PEA Operations

FY75 FY76 FY77 FY78 FY79

1. EGAT

Peak generation (MW) 1,407 i,652 1,873 2,101 2,255Energy generation (GWh) 8,212 9,414 10,950 12,372 13,964Energy sold (GWh) 7,642 8,696 10,149 11,534 12,934Losses in GWh 570 718 801 838 1,030Losses in % 6.9 7.6 7.3 6.8 7.4Annual load factor 66.6 65.0 66.7 67.2 70.70 /aNumber of employees 12,697 14,302 15,526 15,930 17,301Sales per employee (MWh) 602 608 653 720 747Employee per MW installed 5.2 5.9 6.4 5.7 6.0Average fuel consumption

(liter/KWh) N.A. 0.259 0.263 0.257 0.260

2. MEA

Peak demand (MW) 833 958 1,058 1,171 1,268Energy purchased (GWh) 5,051 5,607 6,392 7,146 7,951Energy sales (GWh) 4,790 5,285 6,054 6,807 7,606Losses (GWh) 261 322 338 339 345Losses (as % of purchases) 5.2 5.7 5.3 4.7 4.3Number of consumers ( 000) 506 541 580 607 678Sales/consumer (kWh) 9,466 9,769 10,510 11,214 11,218Residential sales, x of total 17.0 17.4 17.8 18.2 n.a.Small business sales, % of total 15.0 14.3 14.0 14.4 n.a.Medium and large business

sales, % of total 67.0 67.8 67.7 66.3 n.a.Street lighting, % of total 1.0 0.5 0.5 0.6 n.a.Annual load factor (%) 69.2 66.8 68.9 69.7 71.5Number of employees 8,420 8,704 8,862 9,033 9,316Number of consumers/employee 60 62 65 67 72Sales per employee (MWh) 569 607 683 753 816

3. PEA

Peak demand (MW) 517 640 741 852 949Energy purchased (GWh) 2,199 2,758 3,416 4,037 4,678Energy generated (GWh) 110 118 98 84 82Energy available (GWh) 2,309 2,876 3,514 4,121 4,760Energy sold (GWh) 2,120 2,617 3,174 3,650 4,254Losses in GWh 189 259 340 471 506Losses as % of available 9.2 9.0 9.7 11.4 10.6Consumers (-000) 780 927 1,144 1,350 1,574Average energy sales/

consumer (kWh) 2,179 2,822 2,774 2,704 2,702Residential sales, % of total 26.0 24.0 25.0 27.0 27.7Small and general business,

% of total 29.0 30.0 31.0 34.1 34.0Medium and large business and

other sales, % of total 44.0 45.0 43.0 38.4 37.9Street .lighting, % of total 1.0 1.0 1.0 0.5 0.4Annual load factor (%) 53.2 51.3 54.1 55.2 57.3Number of employees 7,502 8,023 8,883 10,620 12,274Number of consumers/employee 104 116 129 127 128Sales per employee (MWh) 282 326 357 344 346

/a On a generation basis.

THAILANDELETRICITY GENRATING AUTHORITY OF THAILAND

ORGANIZATION CHART

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ANNEX 3- 45 -

THAILAND

POWER SUBSECTOR PROJECT

Electricity Generating Authority of Thailand

Existing Generation Facilities(As of September 1979)

Installed capacityLocation Unit Num- Total Commission-

Type Plant (region) size ber (MW) ing date

Hydro Bhumibol 4 70 6 420 May 1964-Aug 1969Sirikit 4 125 3 375 Jan 1974-Jul 1974Ubolratana 2 8.3 3 25 Feb 1966-Jun 1968Sirindhorn 2 12 2 24 Nov 1971Chulabhorn 2 20 2 40 Nov 1973Nam Pung 2 3 2 6 Oct 1965Kang Krachan 1 19 1 19 Aug 1974

Subtotal 19 909

Oil-fired North Bangkok 1 75 2 150 Mlar 1961-Jun 1963steam 1 87.5 1 87.5 Nov 1968

South Bangkok 1 200 2 400 Nov 1970-Nov 19721 300 3 900 Jul 1974-Nov 1977

Surat Thani 3 30 1 30 Feb 1973

Subtotal 9 1,567.5

Lignite- Mae Moh 4 75 2 150 Mar 1978fired Krabi 3 20 3 60 Jun 1964-Jun 1968steam

Subtotal 5 210

Gas turbine South Bangkok 1 15 1 15 Apr 1969-Jan 1970Nakhon Ratchasima 2 15 1 15 Jun 1968Udon Thani 2 15 1 15 Jun 1969Hat Yai 3 15 3 45 Aug 1971-Nov 1977Surat Thani 3 15 5 75 N.A.

Subtotal 11 165

Diesel 28 31.6 N.A.

Total 66 2,883.1

- 46 - ANNEX 4

THAILAND

POWER SUBSECTOR PROJECT

Electricity Generating Authority of Thailand

Existing Transmission and Substation Facilities(As of September 1979)

Transmission linesSubstations (circuit - kilometers)

Region and Transformer /a Double- Single-system voltage Number capacity (MVA) circuit circuit Total

Region 1230 kV 9 2,553 1,324 18 1,342115 kV 27 720 137 964 1,10169 kV 8 133 - 287 287

Subtotal 44 3,406 1,461 1,269 2,730

Region 2115 kV 17 306 1,193 1,257 2,45069 kV 6 16 - 318 318

Subtotal 23 322 1,193 1,575 2,768

Region 3115 kV 12 201 321 922 17,243

Subtotal 12 201 321 922 1,243

Region 4230 kV 3 200 1,258 219 1,477115 kV 9 223 352 623 97569 kV 9 122 7 380 387

Subtotal 21 545 1,617 1,222 2,839

All Regions230 kV 12 2,753 2,582 237 2,819115 kV 65 1,450 2,003 3,766 5,76969 kV 23 271 7 985 992

Total EGAT 100 4,474 4,592 4,988 9,580

/a Station service and generator unit transformers are excluded.

THAILAND

POWER SUBSECTOR PROJECT

Electricity Generating Authority of Thailand

Balance of System Load Requirements and Capabilities

Requirement - Capability. and, Reserve- Margin_Peak gen- Energy gen- Capacity (MW). Energy - GWh)h)-

Fiscal eration eration Reserve Capacity Reserve from

year (MW) (GWh) Installed Dependable Gross Net Average Firm Firm

1980 2,417.4 14,753.7 3,296.1 3,013.3 595.9 120.9 17,172.7 15,896.3 1,142.6

1981 2,692.8 16,512.0 4,056.1 3,721.9 1,029.1 554,1 19,645.1 18,368.6 1,856.6

1982 3,090.3 18,950.0 4,419.1 4,038.2 947.9 472.9 21,643.2 20,269.6 1,319.6

1983 3,476.2 21,315.9 5,089.1 4,674.7 1,198.5 391.0 23,456.3 22,057.3 741.4

1984 3,870.8 23,735.9 6,251.1 5,734.7 1,863.9 1,056.4 28,509.7 26,931.2 3,195.3

1985 4,316.0 26,465.5 6,266.1 5,766.2 1,455.2 642.7 33,094.4 31,387.7 4,922.2

1986 4,953.8 29,509.0 6,842.6 6,263.7 1,309.9 502.4 33,529.7 31,616.4 2,107.4

1987 5,551.8 32,624.0 7,527.6 6,771.2 1,219.4 411.9 36,255.6 34,172.0 1,548.0

1988 5,978.5 35,254.2 8,887.6 8,103.2 2,124.7 1,317.2 41,904.7 39,358,8 4,104.6

1989 6,428.6 38,034.8 9,013.6 8,222.9 1,794.3 986.8 44,856.0 42,308.6 4,273.8

1990 6,902.9 40,967.1 9,733.6 8,909.9 2,007.0 914.5 49,022.1 46,474.4 5,507.3

EGAT'S POWER DEVELOPMENT PLAN 1980- 1993 (PROGRAM A)

0~~~~~~~~~~~~

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- - MONTHLY ENERG~~Y GENATION

0 ~I 11111 till j 111111 lii lii 111111111111111111111111111111111111.....111 jii liIIl......111 ...... II

7 0 7 A 7 7 0 Z 0 0 Z A 4 0~~~~~~~~~~~~~~~~~j--LkLLL -L

ANNEX 7Page 1

- 49 -

THAILAND

ELECTRICITY GENERATING AUTHORITY OF ThAILAND

LONG-TERM STUDY OF GENERATION AND TRANSMISSION PROJECTS

TERMS OF REFERENCE

Objectives

1. The objectives of the study are: to optimize EGAT's power develop-ment program up to 1990, to formulate a comprehensive plan based onalternative sources of energy up to year 2000 and to identify long rangeenergy policy options.

Basic Studies

2. The following studies are being carried out by EGAT to establishthe technical and economical soundness of individual projects to be inclu-ded under the development program up to 1990:

(a) feasibility study for Upper quae Yai hydroelectric project;

(b) feasbility study for Mae Koh Lignite plant extension;

(c) feasibility study for EHV transmission line from Mae Moh toBangkok; and

(d) site selection for coal-fired plant using imported coal.

Scope of Works

3. To optimize the program up to 1990, the consultants will carry out:

(a) an in-depth review of the load forecast prepared by the Load Fore-cast Working Group;

(b) a review of the reserve margin and reliability criteria now adoptedby EGAT;

ANNEX 7- 50 - Page 2

(c) a review of transmission network by 1990;

(d) an optimization of EGAT's proposed development program based onresults of studies as mentioned in paragraph 2, particularly themaximum allowable size of lignite units and relative economybetween lignite units at Mae Moh and coal-fired units along coastusing imported coal; and

(e) sensitivity analysis to test the optimality of sequence for devia-tions in capital cost, fuel cost, load growth and reliabilitystandard.

4. To formulate the comprehensive program from 1990 to 2000, theconsultants will:

(a) project load growth up to year 2000 by macro economic analysis;

(b) review and incorporate the interim findings of the energy masterplan study carried out by ADB (it is necessary that EGAT takesactive role in the task force set up for EMP);

(c) study and compare the following options:

(i) coal fired thermal units using imported coal (size 500-600MW);

(ii) nuclear units (size 900-1,000 MW);

(iii) international river development;

(iv) domestic hydro resources; and

(v) any new development in indigenous resources.

(d) optimize the long-term development program for generation andtransmission.

(e) recommend long-range energy policy for power generation withspecial emphasis on renewable energy and diversification ofsources of supply.

- 51 - ANNEX 7page 3

5. Further development of hydroelectric resources such as Salween andIng-Yom trans-basin diversion schemes will be carried out by independentstudies using bilateral aids and sources.

Schedule

6. The study will be started in early 1981 to be completed in abouttwelve months.

ANNEX 8

- 52 -

THAILAND

ELECTRICITY GENERATING AUTHORITY OF THAILAND

POWER SUBSECTOR PROJECT

EGAT's Development Program (FY8O-86)

Scheduled Capital Investment /aUnit Type Capacity completion Foreign Local Total

Projects no. (MW) date ----- (US$ million) ----

A. Power Project Under Construction(including associated transmission)

Bhumibol Extension 7 Hydro 133.0 May 1982 15.5 4.5 20.0Pattani 1-3 72.0 October 1981 62.9 72.3 135.2Lower Quae Yai 1-2 38.0 August 1982 22.3 29.4 51.7Khao Laem 1-3 300.0 March 1984 173.2 217.0 390.2Mae Moh Extension 3 Thermal 75.0 July 1981 36.1 26.9 63.0Mae Moh Extension 4 150.0 January 1984 134.6 119.0 253.6Bang Pakong Combined Cycle

Block 1 1-4 Gas turbine (240.0) CompletedCombined cycle 120.0 April 1982 47.0 24.4 71.4

Block 2 5-8 Gas turbine & 360.0 October 1982 85.4 47.6 133.0Combined cycle

Bang Pakong (gas/oil dual-fired) I Thermal 550.0 July 1983 181.8 163.9 345.7Mae Moh Extension 5 150.0 July 1984 90.6 64.3 154.9Bang Pakong Extension (gas/oil dual-fired) 2 550.0 August 1984 128.2 117.4 245.6Mae Moh Mine for Mae Moh Thermal Unit 4 - - September 1983 72.0 58.2 130.2Transmission System Expansion No. 3

Parts A&B - - - September 1982 31.5 21.5 53.0Part C - - - September 1982 13.8 11.0 24.8

Transmission System Expansion No. 4 - - - September 1983 36.3 27.2 63.5Transmission System for Industry - - - September 1982 18.2 16.2 34.4230 kV Ban Pong 2 - Prachuap Khiri Khan - - - September 1983 28.7 23.6 52.3

Total 2,498.0 1,178.1 1,044.4 2,222.5

B.1 New Generation ProjectsSirindhorn 3 Hydro 12.0 December 1983 5.0 2.5 7.5Srinagarind Extension 4 180.0 July 1985 32.4 14.6 47.0Chao Phraya Project 2 40.0 December 1985 20.0 15.0 35.0Lam Ta Kong 1 3.5 December 1985 3.4 2.6 6.0Mae Ngat 2 9.0 December 1985 7.5 5.0 12.5Chiew Larn 1-3 240.0 June 1986 158.8 228.9 387.7Lang Suan 1-3 135.0 April 1986 110.3 255.6 365.9Mae Moh Extension 6 Thermal 150.0 September 1986 151.6 124.4 276.0Mae Moh Mine for Mae Moh Thermal Unit 5 - - - September 1986 47.4 38.1 85.5Mae Moh Mine for Mae Moh Thermal Units 6, 7 - - - September 1986 89.8 143.5 233.3

Total 768.5 626.2 830.2 1,456.4

8.2 New Transmission ProjectsTransmission System Expansion No. 5 September 1984 79.8 79.6 159.4Transmission System Expansion No. 6 September 1986 114.8 114.5 229.3

Total 194.6 194.1 388.7

C. Projects to be Initiated(but completed after FY86)

Kud Project 1-2 Hydro 100.0 June 1987 84.6 207.7 292.3Pak Nun Project 135.0 September 1987 99.6 153.0 252.6Upper Quae Yai Project 1-2 580.0 October 1987 242.1 290.5 532.6Nam San Project 1-2 58.0 December 1988 57.9 98.6 156.5Nam Man Project 1-2 26.0 December 1988 27.1 37.4 64.5Nam Loei Project I 18.0 December 1988 20.0 32.8 52.8Upper Pa Sak 1-2 24.0 December 1988 28.2 50.2 78.4Mae Moh Extension 7 Thermal 150.0 December 1986 121.2 93.8 215.0Mae Moh Extension 8 300.0 August 1987 202.4 233.9 436.3Mae Moh Extension 9 300.0 March 1988 217.6 238.4 456.3Region 3 Thermal 1 180.0 November 1987 90.0 28.7 118.7Coal Fired 1 600.0 October 1989 440.8 486.3 927.1Mae Moh Mine for Mae Moh Thermal Unit 8 - - September 1987 96.4 153.0 249.4Transmission System Expansion No. 7 - - September 1989 109.1 115.9 225.0EI'V for Mae Moh Project - - September 1986 198.8 231.5 430.3Mae Moh Mine for Mae Moh Thermal Unit 9 - - September 1988 102.2 163.4 265.6

Total 2,471.0 2,138.0 2,615.1 4,753.1

/a Including interest during construction.

ANNEX 9- 53 - Page 1

THAILAND

POWER SUBSECTOR PROJECT

Project Description, Cost Estimate and Financing Planfor Selected Subprojects

Project Description

A. Chiew Larn Hydroelectric Project

1. Construction of a rockfill dam of about 90 meters high with a totalembankment volume of about 6.4 million cubic meters.

2. Construction of an open chute spillway controlled by three radialgates.

3. Construction of an intake structure and three penstocks.

4. Construction of a surface powerhouse for three generating units of80 MW each and of a switchyard.

5. Installation of a 230 kV double circuit transmission line betweenChiew Larn switchyard and Surat Thani switchyard and a 115 kV doublecircuit transmission line between Chiew Larn switchyard andPhungnga substation.

6. Implementation of a resettlement program for about 315 familiesin the reservoir area.

B. Lang Suan Hydroelectric Project

1. Construction of a rockfill dam of about 91.5 meters high with a totalembankment volume of about 8.5 million cubic meters.

2. Construction of a spillway tunnel of about 6 meters in diameter.

3. Construction of an intake structure and power conduit.

4. Construction of a surface powerhouse for three generating unitsof 45 MW each and of a switchyard.

5. Installation of a 115 kV double circuit transmission line from LangSuan switchyard to the Center-South tie line and a 115 kV singlecircuit transmission line between Lang Suan switchyard and Ranongsubstation.

ANNEX 9- 54 - Page 2

6. Implementation of a resettlement program for about 1,950 families inthe reservoir area.

C. Transmission System Expansion (No. 5 Project)

1. Installation of the following 115 kV transmission lines:

a. Hat Yai 2 - Sungkhlab. Samut Sakhon 2 line terminationc. Ang Thong 2 - Suphon Burid. Ayuthaya-Bang Pa-ine. Ban Pong 2 - Kamphaeng Saen

2. Installation of 11 substations.

3. Extension of communication system.

- 55 - ANNEX 9Page 3

Cost Estimate

Foreign Local Total Foreign Local TotalProject ------ (B million) ------- ------ (US$ million) -----

Chiew Larn HydroPreliminary & resettlement 10.0 281.0 291.0 0.5 13.7 14.2Civil works 1,113.8 961.6 2,075.4 54.3 46.9 101.2E&M equipment 511.7 72.7 584.4 25.0 3.5 28.5Transmission system 265.0 106.0 371.0 12.9 5.2 18.1Engineering & administration 106.0 184.0 290.0 5.2 9.0 14.2Duties & taxes - 156.0 156.0 - 7.6 7.6

Base Cost 2,006.5 1,761.3 3,767.8 97.9 85.9 183.8

ContingenciesPhysical 190.1 123.2 313.3 9.3 6.0 15.3Price 1,058.4 1,665.5 2,723.9 51.6 81.2 132.8

Subtotal 3,255.0 3,550.0 6,805.0 158.8 173.1 331.9

Lang Suan HydroPreliminary & resettlement 30.0 1,505.0 1,535.0 1.5 73.4 74.9Civil works 772.6 658.0 1,430.6 37.7 32.1 69.8E&M equipment 529.9 80.0 609.9 25.8 3.9 29.7Transmission system 97.0 53.0 150.0 4.7 2.6 7.3Engineering & administration 70.0 197.0 267.0 3.5 9.6 13.1Duties & taxes - 125.4 125.4 - 6.1 6.1

Base Cost 1,499.5 2,618.4 4,117.9 73.2 127.7 200.9

ContingenciesPhysical 140.0 79.1 219.1 6.8 3.9 10.7Price 620.5 1,237.5 1,858.0 30.3 60.4 90.7

Subtotal 2,260.0 3,935.0 6,195.0 110.3 192.0 302.3

Transmission System Expansion(No. 5 project)

Transmission lines 215.0 134.0 349.0 10.5 6.5Substations 869.0 325.0 1,194.0 42.4 15.9Communications 42.0 9.0 51.0 2.0 0.4 2.4Engineering & supervision - 111.0 111.0 - 5.4 5.4Duties & taxes - 247.3 247.3 - 12.1 12.1

Base Cost 1,126.0 826.3 1,952.3 54.9 40.3 95.2

ContingenciesPhysical 112.0 57.0 169.0 5.5 2.8 8.3Price 397.3 504.4 901.7 19.4 24.6 44.0

Subtotal 1,635.3 1,387.7 3,023.0 79.8 67.7 147.5

Total 7,150.3 8,872.7 16,023.0 348.9 432.8 781.7

Financing Plan /a

Sources of Funds Chiew Larn Lang Suan Transmission Total(No. 5 Proj.)

ForeignIBRD - First subsector

loan 58.2 15.3 25.2 98.7/bCommercial banks 49.7 59.8 3.3 112.8

KFAED 20.0 - - 20.0Export & suppliers' credits 30.9 35.2 11.6 77.7ADB - - 39.7 39.7

Subtotal 158.8 110.3 79.8 348.9

LocalEGAT, Govt. Equity & localborrowings 173.1 192.0 67.7 432.8

Total 331.9 302.3 147.5 781.7

/a Excluding interest during construction./b Net of US$1.3 million allocated to environmental training and energy conservation

programs.

ANNEX 10

- 56 -

THAILAND

ELECTRICITY GENERATING AUTHORITY OF THAILAND

POWER SUBSECTOR PROJECT

Loan Disbursement Schedule(US$ million)

Cumulative disburse-IBRD fiscal year Disbursements ments at the end

& semester during semester of semester

1982December 31, 1981 1.4 1.4June 30, 1982 8.4 9.8

1983December 31, 1982 13.2 23.0June 30, 1983 13.2 36.2

1984December 31, 1983 18.2 54.4June 30, 1984 20.1 74.5

1985December 31, 1984 25.5 100.0

- 57 - ANNEX 11page 1 of 3

THAILAND

ELECTRICITY GENERATING AUTHORITY

Financial Statements, 1972-80

Income Statement(Baht, millions)

1972 1973 1974 1975 1976 1977 1978 1979 1980/b

Sales increase (%) 18.32 18.49 6.82 13.49 14.59 16.71 13.47 12.31 5.71

Energy sales (GWh) 5,283 6,260 6,687 7,589 8,696 10,149 11,516 12,934 13,673

Average price/KWh 0.2917 0.2930 0.3736 0.4488 0.4397 0.4579 0.5631 0.5585 0.7523

Energy revenue 1,541 1,834 2,498 3,406 3,824 4,647 6,485 7,224 10,286

Other revenue 7 6 11 8 9 19 26 14 120

Total Revenues 1,548 1,840 2,509 3,414 3,833 4,666 6,511 7,238 10,406

Operating ExpensesFuel/bulk power 389 548 1,022 1,707 1,679 2,683 4,157 4,396 8,074Operations 304 322 424 586 676 784 836 1,130 1,323Depreciation /a 308 399 535 644 775 823 925 1,056 1,550

Total Expenses 1,001 1,269 1,981 2,937 3,130 4,290 5,918 6,582 10,947

Net income beforeinterest 547 571 528 477 703 376 593 656 (541)

Interest 256 320 365 446 504 552 696 855 1,197IDC 63 108 131 135 153 177 267 331 564

Operational Interest 193 212 234 311 351 375 429 524 633

Net income 354 359 294 166 352 1 164 132 (1,174)

Rate base 6,759 8,585 11,808 14,373 15,808 16,930 18,221 21,980 28,143

Rate of return (%) /a 8.1 6.6 4.5 3.3 4.4 2.2 3.2 3.0 (1.9)

Operating ratio (x) /c 64.6 68.9 78.9 86.0 81.6 92.0 90.9 90.9 105.2

/a On revalued assets./b Unaudited.77 Including depreciation.

- 58 -

ANNEX 11Page 2 of 3

THAILAND

ELECTRICITY GENERATINC AUTHORITY

Financial Statements, 1972-80

Funds Flow Statement(Baht, millions)

1972 1973 1974 1975 1976 1977 1978 1979 1980/h

Internal Sources of FundsOperating income 547 571 528 477 703 376 593 656 (541)Depreciation 308 399 535 644 775 823 925 1,056 1,550Consumer contributions 0 0 80 67 339 -25 1,541 - -

Subtotal 855 970 1,143 1,188 1,817 1,174 3,059 1,712 1,009

Less:Interest charged

operations 193 212 234 311 351 375 429 524 633Debt repayment 253 315 345 316 320 409 640 705 797Other payments -11 -5 7 76 -47 -20 -36 - -

Internal funds available 420 448 557 485 1,193 410 2,026 483 (421)

RequirementsConstruction 1,534 1,856 1,224 1,550 1,760 2,304 4,881 2,184 8,762Interest during con-

struction 63 108 131 135 193 177 267 331 564

Total Construction 1,597 1,964 1,355 1,685 1.922 2,481 _5,14 2,515 9,326

Increase (decrease) inworking capital 16 49 50 213 211 (198) (276) 628 (2,346)

Total FinancialRequirements 1,613 2,013 1,405 1,898 2,133 2,283 4,872 3,143 6,980

Balance to be financed 1,193 1,565 848 1,413 940 1,873 2,846 2,660 7,401

Financed by:Borrowings 969 1,270 904 1,251 1,432 1,194 2,706 2,214 6,153Equity 194 345 0 0 54 208 552 0 1,202

Total CapitalSources 1,163 1,615 904 1,251 1,486 1,402 3,258 2,214 7,355

Cash increase/(decrease) (30) 50 56 (162) 546 (471) 412 (446) (46)

Cash at beginning of year 152 122 172 228 66 612 141 553 107

Cash at year end 122 172 228 66 612 141 553 107 61

Annual debt servicecoverage (%) 1.9 1.8 1.8 1.8 2.2 1.5 1.4 1.4 0.7

Self-financing ratio:laannual (%) 26.0 22.2 39.6 25.5 55.9 17.9 41.6 15.3 (6.0)

3 year average (x) 27.5 26.7 31.4 26.7 56.7 13.2 59.0 9.6 (5.0)

/a Internal funds available as a percentage of total financial requirements.

/b Unaudited.

- 59 - ANNEX 11

Page 3 of 3

THAILAND

ELECTRICITY GENERATING AUTHORITY

Financial Statements, 1972-80

Balance Sheet(Baht, millions)

1972 1973 1974 1975 1976 1977 1978 1979 1980/b

ASSETS

Fixed Assetsplant in service /a 9,111 12,110 17,400 19,312 22,335 23,634 27,213 33,630 45,854

Less: Depreciation /a 1,665 2,386 3,507 4,459 5,579 6,530 7,874 9,856 13,343

Operating Plant 7,446 9,724 13,893 14,853 16,756 17,104 19,339 23,774 32,511

Work in progress 1,866 2,595 1,625 2,985 3,345 5,025 7,192 7,591 11,301Insurance fund 20 42

Current AssetsCash 122 172 228 66 612 141 553 107 61Inventories 132 149 187 305 262 275 416 450 846Receivables 460 503 972 1,066 1,658 1,578 1,547 2,422 2,511

Total 714 824 1,387 1,437 2,532 1,994 2,476 2,979 3,418

TOTAL ASSETS 10,026 13,143 16,905 19,275 22,633 24,123 29,007 34,364 47,272

EQUITY & LIABILITIESEquity

Paid-in capital 2,628 2,973 2,973 2,973 3,027 3,235 3,787 3,787 4,989Retained earnings 1,042 1,401 1,695 1,861 2,213 2,214 2,378 2,510 1,336Revaluation reserve 808 2,101 4,590 5,833 6,908 7,190 6,482 9,617 14,075Consumers contribution 6 6 86 153 492 467 2,008 2,456 2,456

Total Equity 4,484 6,481 9,344 10,820 12,640 13,106 14,655 18,370 22,856

Insurance reserve 20 42

Long-Term Debt (net) 4,751 5,830 6,301 7,192 8,303 8,965 11,849 13,167 18,540

Current LiabilitiesPayables 476 487 944 943 1,281 1,412 1,798 1,891 4,206Bank overdraft 0 0 0 0 0 0 0 190 706Current maturities 315 345 316 320 409 640 705 726 922

Total CurrentLiabilities 791 832 1,260 1,263 1,690 2,052 2,503 2,807 5,834

TOTAL EQUITY &LIABILITIES 10,026 13,143 16,905 19,275 22,633 24,123 29,007 34,364 47,272

Increase in grossplant (%) 25.3 32.9 43.7 11.0 15.5 5.8 15.1 23.6 36.3

Debt % of debt + equity 51.6 47.3 40.3 39.9 39.6 40.6 44.7 41.7 44.8

Current ratio 0.9 0.9 1.1 1.1 1.5 0.9 1.0 1.0 0.6

/a Revalued.

/b Unaudited.

-EGAT INCOME STATEMENT MILL. BAHT

1981 1982 1983 1984 1985 1986 1987 1988

VOLUME SOL'- QWH 15226.00 17531.54 19736.39 21977.07 24504.41 27322.38 30489.71 32947.88

AVERAGE ENERGY TARIFF /KWH 1.31 1.48 1.61 1.69 1.74 1.88 2.05 2.17

ENERGY REVENUES 19925.16 25913.78 31762.70 37234.66 42689.43 51319.30 62590.85 71368.62OTHER OPERATIONAL REVENUE 17.00 19.00 20.00 22.00 25.00 27.00 30.00 33.00

TOTAL REVENUES 19942.16 25932.78 31782.70 37256.66 42714.43 51346.30 62620.85 71401.62

FUEL/POWER 15193.00 16898.00 20333.00 22428.00 24843.00 31010.00 37190.00 39159.00OPERATIONS 2182.00 2558.00 3070.00 3602.00 4148.00 4618.00 5302.00 5945.00

DIRECT COSTS- 17375.00 19456.00 23403.00 26030.00 28991.00 35628.00 42492.00 45104.00======== ======== ======== ======== ======== ======== ======== ======== I

TOTAL COSTS 17375.00 19456.00 23403.00 26030.00 28991.00 35628.00 42492.00 45104.00 CY- - - - - - - - - - - - - - - -- -- -- - - - - - - -o-- - - - - -

INCOME BEFORE DEPRECIATION 2567.16 6476.78 8379.70 11226.66 13723.43 15718.30 20128.85 26297.62DEPRECIATION 1800.71 2321.91 2867.46 4010.36 4978.81 5630.06 7207.66 10209.44

INCOME BEFORE INTEREST 766.45 4154.87 5512.24 7216.30 8744.62 10088.24 12921.19 16088.18INTEREST CHARGED OPER. 1115.00 1991.00 2601.00 3991.00 5527.00 6500.00 8641.99 11244.00

NET SURPLUS (+) -348.55 2163.87 2911.24 3225.30 3217.62 3588.24 4279.20 4844.18

AVERAGE RATE BASE 38322.80 48810.94 60477.85 80560.39 96457.97 111629.86 144480.59 181318.b8*OPERATING RATIO % 96 84 83 80 79 80 79 77*RATE OF RETURN % 2.00 8.51 9.11 8.96 9.07 9.04 8.94 8.87

(D (DH

0Id)H

(DC'

-EGAT FLOW OF FUNDS MILL.BAHT

----------------------------------------------------------------- __----------__------------------------------------------------

1981 1982 1983 1984 1985 1986 1987 1988

SOURCES OF FUNDS

INCOME BEFORE DEPRECIATION 2567.16 6476.78 8379.70 11226.66 13723.43 15718.30 20128.85 26297.62

GROSS INTERNAL GENERATION 2567.16 6476.78 8379.70 11226.66 13723.43 15718.30 20128.85 26297.62

INCREASE IN RESERVES 18.40 20.00 20.00 20.00 20.00 20.00 20.00 20.00

EQUITY INCREASE 1088.00 545.00 365.00 29.00 0.00 0.00 0.00 0.00

IBRD LOAN 0.00 200.90 541.20 785.15 522.75 0.00 0.00 0.00

OTHER LOANS 12349.83 14982.00 12231.80 20909.50 19648.25 26807.00 20808.00 19273.00

TOTAL LOANS 12349.83 15182.90 12773.00 21694.65 20171.00 26807.00 20808.00 19273.00

TOTAL SOURCES 16023.39 22224.68 21537.70 32970.31 33914.43 42545.30 40956.85 45590.62

APPLICATIONS OF FUNDS

INVESTMENT IN PROJECT 0.00 4521.27 7803.32 9114.30 7213.95 4585.86 0.00 0.00

CAPITALIZED INTEREST 927.99 1642.00 2401.00 2521.00 2397.00 4431.00 3337.00 2205.00

OTHER INVESTMENT 10340.00 8498.73 9282.68 11773.70 16911.05 21609.14 21261.00 19393.00

TOTAL INVESTMENT 11268.00 14662.00 19487.00 23409.00 26522.00 30626.00 24598.00 21598.00

FOREIGN LOAN AMORTIZATION 0.00 0.00 0.00 0.00 0.00 68.33 136.67 136.67 1

OTHER LOANS AMORTIZATION 922.00 1185.00 1550.00 2742.00 3726.00 3628.67 5259.33 7574.00 H

TOTAL AMORTIZATION 922.00 1185.00 1550.00 2742.00 3726.00 3697.00 5396.00 7710.67

OPER.INTEREST LONG T.DEBT 1115.00 1991.00 2601.00 3991.00 5527.00 6500.00 8641.99 11244.00

rOTAL OPERATIONAL INTEREST 1115.00 1991.00 2601.00 3991.00 5527.00 6500.00 8641.99 11244.00

TOTAL DEBT SERVICE 2037.00 3176.00 4151.00 6733.00 9253.00 10197.00 14037.99 18954.67

INCREASE IN WORK.CAPITAL 2699.99 4366.68 -2120.30 2808.31 -1880.57 1702.30 2300.86 5017.95

INSURANCE FUND 18.40 20.00 20.00 20.00 20.00 20.00 20.00 20.00

TOTAL APPLICATIONS 16023.39 22224.68 21537.70 32970.31 33914.43 42545.30 40956.85 45590.62

DEBT SERVICE RATIO 1.26 2.04 2.02 1.67 1.48 1.54 1.43 1.39

% CONTRIBUTION TO INVESTMENT 3.6 16.9 24.8 17.3 17.9 17.5 18.3 21.3

(DC

OR)

H

-EGAT BALANCE SHEET MILL.BAHT

1981 1982 1983 1984 1985 1986 1987 1988

A 5 S E T S

FIXED ASSETS IN OPER. 61012.44 74375.69 93312.26 125833.36 138997.03 172141.82 223687.75 270715.89

MINUS ACCUM-DEPRECIATION 16878.25 20887.99 25844.25 32180.60 39733.86 48145.28 58723.11 73043.17

NET FIXED ASSETS 44134.18 53487.70 67468.01 93652.77 99263.18 123996.54 164964.64 197672.73

WORK IN PROGRESS 13372.00 20772.00 28760.00 28046.00 51471.00 58682.00 43784.00 34012.00

CASH AND BANKS 119.99 1240.67 1641.37 2352.67 3319.11 3232.40 7011.27 10516.22

ACCOUNTS RECEIVABLE 5474.00 5477.00 6370.00 6360.00 7232.00 7493.00 8939.00 9112.00

INVENTORIES 1808.00 4795.00 2289.00 5561.00 2984.00 6266.00 4252.00 7742.00

TOTAL CURRENT ASSETS 7401.99 11512.67 10300.37 14273.67 13535.11 16991.40 20202.27 27370.22

INSURANCE FUND 60.00 80.00 100.00 120.00 140.00 160.00 180.00 200.00

TOTAL ASSETS 64968.18 85852.37 106628.38 136092.44 164409.28 199829.94 229130.90 259254.95

EQUITY AND LIABILITIES

EOUITY 6077.00 6622.00 6987.00 7016.00 7016.00 7016.00 7016.00 7016.00

CONTRIBUTIONS 2008.00 2008.00 2008.00 2008.00 2008.00 2008.00 2008.00 2008.00

REVALUATION SURPLUS 18750.42 23163.84 28512.61 34584.73 42076.95 49025.37 57705.13 69252.65

OPERATIONAL SURPLUS 986.93 3150.80 6062.04 9287.33 12504.95 16093.20 20372.40 25216.58 1

TOTAL EQUITY 27822.35 34944.64 43569.65 52896.06 63605.90 74142.57 87101.52 103493.23 R

LONG TERM DEBT(NET) 29704.83 43337.73 53368.73 71337.38 87811.38 109222.38 122319.71 132632.05

ACCOUNT PAYABLES 5971.00 5940.00 6848.00 8013.00 9155.00 10909.00 11819.00 13969.00

BANK OVERDRAFT 225.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

CURRENT MATURITIES 1185.00 1550.00 2742.00 3726.00 3697.00 5396.00 7710.67 8960.67

TOTAL CURRENT LIABILITIES 7381.00 7490.00 9590.00 11739.00 12852.00 16305.00 19529.67 22929.67

RESERVES 60.00 80.00 100.00 120.00 140.00 160.00 180.00 200.00

TOTAL LIABILITIES 37145.83 50907.73 63058.73 83196.38 100803.38 125687.38 142029.38 155761.71

TOTAL EQUITY-LIABILITIES 64968.18 85852.37 106628.38 136092.44 164409.28 199829.94 229130.90 259254.95 t

*WORKING CAPITAL-MILLION 1205.99 5572.67 3452.37 6260.67 4380.11 6082.40 8383.27 13401.22 X

*CURRENT RATIO 1.00 1.54 1.07 1.22 1.05 i.04 1.03 1.19 U j

% DEBT/(DEBT+EQUITY) 51.64 55.36 55.05 57.42 57.99 59.57 58.41 56.17 0 [M

(Dw

-PEA INCOME STATEMENT MILL.BAHT

1981 1982 1983 1984 1985 1986 1987 1988

VOLUME SOLD GWH 5590.00 6456.00 7718.00 9037.00 10645.00 12304 no 14413.00 15858.00

AVERAGE ENERGY TARIFF /KWH 1.61 1.87 2.02 2.16 2.24 2.41 2.64 2.73

ENERGY REVENUES 8993.00 12074.90 15624.63 19553.65 23806.18 29598.70 37984.72 43235.18OTHER OPERATIONAL REVENUE 498.00 544.00 597.00 614.00 739.00 810.00 869.00 955.00

TOTAL REVENUES 9491.00 12618.90 16221.63 20167.65 24545.18 30408.70 38853.72 44190.18

POWER 7234.00 9192.00 12190.00 15132.00 18588.00 23297.00 30537.00 34572.00OPERATIONS 1503.00 1871.00 2410.00 2998.00 3649.00 4394.00 5294.00 6338.00

DRTCT83. 11063.00 14600.00 18130.00 22237.00 27691.00 35831.00 40910.00

DIRECT COSTS 8737.00 11063.00 14600.00 18130.00 22237.00 27691.00 35831.00 40910.00

IOTAL COSTS 8737.00 11063.00 14600.00 l8130.00 22237.00 27691.00 35831.00 40910.00 1

INCOME BEFORE DEPRECIATION 754.00 1555.90 1621.63 2037.65 2308.18 2717.70 3022.72 3280.18 wDEPRECIATION 620.49 821.06 1033.78 1272.57 1521.45 1787.59 2070.03 2339.17

INCOME BEFORE INTEREST 133.51 734.84 587.85 765.08 786.73 930.11 952.69 941.01INTEREST CHARGED OPER. 216.00 398.00 481.00 599.00 687.00 739.00 735.00 699.00

NET SURPLUS (+) -82.49 336.84 106.85 166.08 99.73 191.11 217.69 242.01

AVERAGE RATE BASE 6678.04 9185.59 11973.14 15038.52 18146.52 21251.43 24408.55 26762.74*OPERATING RATIO % 9 .o 94.2 96.4 96.2 96.8 96.9 97.5 97.8*RATE OF RETURN % 2.00 8.00 4.91 5.09 4.34 4.38 3.90 3.52

(D (D

X\

(D

-PEA FLOW OF FUNDS MILL.BAHT

------------------------------------------------------------- __--------------__----------------------------

1981 1982 1983 1984 1985 1986 1987 1988

SOURCES OF FUNDS

INCOME BEFORE DEPRECIATION 754.00 1555.90 1621.63 2037.65 2308.18 2717.70 3022.72 3280.18

GROSS INTERNAL GENERATION 754.00 1555.90 1621.63 2037.65 2308.18 2717.70 3022.72 3280.18OTHER CONTRIBUTIONS 89.00 88.00 85.00 81.00 75.00 67.00 61.00 46.00EQUITY INCREASE 218.00 111.00 47.00 45.00 15.00 5.00 5.00 5.00IBRO LOAN 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

OTHER LOANS 2780.00 2084.00 2890.00 3208.00 2056.00 1585.00 350.00 940.00

TOTAL LOANS 2780.00 2084.00 2890.00 3208.00 2056.00 1585.00 350.00 940.00

TOTAL SOURCES 3441.00 3838.90 4643.63 5371.65 4454.18 4374.70 3438.72 4271.18

APPLICATIONS OF FUNDS

INVESTMENT IN PROJECT 0.00 3286.00 3686.00 3968.00 2591.00 2304.00 0.00 0.00CAPITALIZED INTEREST 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00OTHER INVESTMENT 3473.00 0.00 0.00 0.00 0.00 0.00 1063.00 1680.00 1

-------- ~~~~~~~ - ------ -------- -------- -------- -------- -------- -----

TOTAL INVESTMENT 3473.00 3286.00 3686.00 3968.00 2591.00 2304.00 1063.00 1680.00FOREIGN LOAN AMORTIZATION 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

OTHER LOANS AMORTIZATION 351.00 356.00 407.00 755.00 994.00 1175.00 1454.00 1660.00

TOTAL AMORTIZATION 351.00 356.00 407.00 755.00 994.00 1175.00 1454.00 1660.00OPER.INTEREST LONG T.DEBT 216.00 398.00 481.00 599.00 687.00 739.00 735.00 699.00

TOTAL OPERATIONAL INTEREST 216.00 398.00 481.00 599.00 687.00 739.00 735.00 699.00

TOrAL DEBT SERVICE 567.00 754.00 888.00 1354.00 1681.00 1914.00 2189.00 2359.00INCREASE IN WORK.CAPITAL -600.00 -201.10 69.63 49.65 182.18 156.70 186.72 232.18

-===_ ===== = === = == == = = = = = == = == == = == = == == == _= = == == == =

TOTAL APPLICATIONS 3441.00 3838.90 4643.63 5371.65 4454.18 4374.70 3438.72 4271.18

DEBT SERVICE RATIO 1.3 2.06 1.83 1.50 1.37 1.42 1.38 1.39% CONTRIBUTION TO INVESTMENT 9. 27.1 22.0 21.2 22.6 4o.6 47.9 58.5

0 t\O

(Drn

-PEA BALANCE SHEET MILL.BAHT

1981 1982 1983 1984 1985 1986 1987 1988

A S S E T S

FIXED ASSETS IN OPER. 14174.25 18240.11 22964.52 28188.92 33647.50 39486.83 45769.91 50909.80

MINUS ACCUM.DEPRECIATION 4380.24 5650.27 7234.95 9140-58 11416.13 14002.85 17053.08 20585.96

NET FIXED ASSETS 9794.01 12589.84 15729.57 19048.33 22231.37 25483.98 28716.82 30323.83

WORK IN PROGRESS 2984.00 3657.00 4397.00 5150.00 4608.00 3428.00 972.00 716.00

CASH AND BANKS 837.00 894.90 1178.53 1522.18 1796.36 2169.06 2536.78 3105.96

ACCOUNTS RECEIVABLE 1014.00 1223.00 1482.00 1769.00 2084.00 2522.00 3169.00 3577.00

INVENTORIES 2219.00 2093.00 1920.00 1734.00 1577.00 1439.00 1387.00 1207.00

TOTAL CURRENT ASSETS 4070.00 4210.90 4580.53 5025.18 5457.36 6130.06 7092.78 7889.96

OTHER ASSETS 72.00 72.00 72.00 72.00 72.00 72.00 72.00 72.00

TOTAL ASSETS 16920.01 20529.74 24779.10 29295.51 32368.73 35114.04 36853.60 39001.79

EQUITY AND LIABILITIES

EQUITY 1046.00 1157.00 1204.00 1249.00 1264.00 1269.00 1274.00 1279.00

CONTRIBUTIONS 89.00 177.00 262.00 343.00 418.00 485.00 546.00 592.00

REVALUATION SURPLUS 3362.50 4366.39 5593.90 6970.23 8541.72 10097.92 11881.79 13891.97

OPERATIONAL SURPLUS 1929.51 2266.35 2373.20 2539.28 2639.01 2830.12 3047.81 3289.82_ _ _ _ _ _ _ _ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - ________-________-________-

TOTAL EQUITY 6427.01 7966.74 9433.10 11101.51 12862.73 14682-04 16749.60 19052.79

LONG TERM DEBT(NET) 7156.00 8833.00 10968.00 13182.00 14063.00 14194.00 12884.00 12243.77

ACCOUNT PAYABLES 998.00 1259.00 1619.00 2012.00 2455.00 3085.00 4045.00 4571.00

OTHER CURRENT LIABIL 1513.00 1519.00 1384.00 1305.00 1032.00 838.00 574.00 528.00

CUSTOMERS DEPOSITS 470.00 545.00 620.00 701.00 781.00 861.00 941.00 1026.00

CURRENT MATURITIES 356.00 407.00 755.00 994.00 1175.00 1454.00 1660.00 1580.23

TOTAL CURRENT LIABILITIES 3337.00 3730.00 4378.00 5012.00 5443.00 6238.00 7220.00 7705.23

TOTAL LIABILITIES 10493.00 12563.00 15346.00 18194.00 19506.00 20432.00 20104.00 19949.00

TOTAL EQUITY-LIABILITIES 16920.01 20529.74 24779.10 29295.51 32368.73 35114.04 36853.60 39001.79 m O(D X

*WORKING CAPITAL-MILLION 1089.00 887.90 957.53 1007.18 1189.36 1346.06 1532.78 1764.96 0r

*CURRENT RATIO 1.22 1.13 1.05 1.00 1.00 0.98 0.98 1.02

% DEBT/(DEBT+EOUITY) 52.68 52.58 53.76 54.28 52.23 49.15 43.48 39.12

aq(Dtn)

-MEA INCOME STATEMENT MILL.BAHT

-------------------------------------------------------- __-------------------__---------------------------

1981 1982 1983 1984 1985 1986 1987 1988

VOLUME SOLD GWH 8443.00 9422.00 10172.00 10952.Y) i'762.00 12602 anO 13471.00 14371Q00

AVERAGE ENERGY TARIFF /KWH 1.61 1.8l 2.01 2.15 2.25 2.45 2.74 2.82

ENERGY REVENUES 13629.31 17403.97 20489.67 23549.35 26508.59 30872.67 36871.07 40550.76

OTHER OPERATIONAL REVENUE 80.00 75.00 75.00 75.00 75.00 75.00 75.00 75.00

TOTAL REVENUES 13709.31 17478.97 20564.67 23624.35 26583.59 30947.67 36946.07 40625.76

POWER 12285.00 15588.00 18260.00 20802.00 23156.00 26873.00 32105.00 35004.00

OPERATIONS 826.00 1038.00 1295.00 1601.00 1964.00 2387.00 2900.00 3453.00

DIRECT COSTS 13111.00 16626.00 19555.00 22403.00 25120.00 29260.00 35005.00 38457.00 1

TOTAL COSTS 13111.00 16626.00 19555.00 22403.00 25120.00 29260.00 35005.00 38457.00

INCOME BEFORE DEPRECIATION 598.31 852.97 1009.67 1221.35 1463.59 1687.67 1941.07 2168.76

DEPRECIATION 499.00 616.31 730.29 856.07 986.50 1114.79 1255.16 1408.21

INCOME BEFORE INTEREST 99.31 236.66 279.38 365.28 477.09 572.88 685.91 760.55

INTEREST CHARGED OPER. 97.00 155.00 213.00 285.00 384.00 479.00 592.00 646.00

NET SURPLUS (+) 2.31 81.66 66.38 80.28 93.09 93.88 93.91 114,55

AVERAGE RATE BASE 4965.82 6083.73 7242.70 8441.52 9589.17 10661.55 11699.48 12757.60

*OPERATING RATIO % 99.3 98.6 98.6 98.4 98.2 98.1 98.1 98.1*RATE OF RETURN % 2.00 3.89 3.86 4.33 4.98 5.37 5.86 5.96

XD (Dx

H0 N)

(Dw

MEA FLOW OF FUNDS MILL.BAHT

1981 1982 1983 1984 1985 1986 1987 1988

SOURCES OF FUNDS

INCOME BEFORE DEPRECIATION 598.31 852.97 1009.67 1221.35 1463.59 1687.67 1941.07 2168.76

GROSS INTERNAL GENERATION 598.31 852.97 1009.67 1221.35 1463.59 1687.67 1941.07 2168.76OTHER CONTRIBUTIONS 280.00 315.00 344.00 390.00 421.00 454.00 491.00 530.00IBRD LOAN 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

OTHER LOANS 331.00 478.00 755.00 504.00 569.00 587.00 629.00 671.00

TOTAL LOANS 331.00 478.00 755.00 504.00 569.00 587.00 629.00 671.00

TOTAL SOURCES 1209.31 1645.97 2108.67 2115.35 2453.59 2728.67 3061.07 3369.76

APPLICATIONS OF FUNDS

INVESTMENT IN PROJECT 0.00 1280.00 1600.00 1462.00 1457.00 1540.00 0.00 0.00CAPITALIZED INTEREST 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00OTHER INVESTMENT 1287.31 0.00 0.00 0.00 0.00 0.00 1666.00 1792.00

TOTAL INVESTMENT 1287.31 1280.00 1600.00 1462.00 1457.00 1540.00 1666.00 1792.00 1FOREIGN LOAN AMORTIZATION 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

OTHER LOANS AMORTIZATION 63.00 133.00 159.00 174.00 181.00 189.00 173.00 212.00

TOTAL AMORtIZATION 63.00 133.00 159.00 174.00 181.00 189.00 173.00 212.00OPER.INIEREST LONG T.DEBT 97.00 155.00 213.00 285.00 384.00 479.00 592.00 646.00

TOTAL DEBT SERVICE 160.00 288.00 372.00 459.00 565.00 668.00 765.00 858.00INCREASE IN WORK.CAPITAL -238.00 77.97 136.67 194.35 431.59 520.67 630.07 719.76

TOTAL APPLICATIONS 1209.31 1645.97 2108.67 2115.35 2453.59 2728.67 3061.07 3369.76

DEBT SERVICE RATIO .7 2.96 2.71 2.66 2.59 2.53 2.54 2.53% CONTRIBUTION TO INVESTMENT 6 . 60.0 62.0 67.7 68.8 71.0 72.6 75.8

Ot (D C

To

-MEA BALANCE SHEET MILL -BAHT

1981 1982 1983 1984 1985 1986 1987 1988

A S S E T S

FIXED ASSETS IN OPER. 12453.56 14885.05 17640.34 20497.87 23505.95 26508.36 29800.95 33387.01MINUS ACCUM.DEPRECIATION 4234.00 5284.29 6529.80 7957.23 9600.20 11387.01 13439.26 15788.22

NET FIXED ASSETS 8219.56 9600.76 11110.54 12540.64 13905.74 15121.35 16361.68 17598.80WORK IN PROGRESS 1177.00 1302.00 1598.00 1746.00 1886.00 2069.00 2298.00 2590.00CASH AND BANKS 708.00 254.97 311.64 476.99 915.58 1397.25 t948.32 1360.08ACCOUNTS RECEIVABLE 2480.00 3174.00 3738.00 4289.00 4820.00 5607.00 6689.00 7348.00INVENTORIES 762.00 839.00 935.00 1023.00 1110.00 1203.00 1303.00 1710.00

TOTAL CURRENT ASSETS 3950.00 4267.97 4984.64 5788.99 6845.58 8207.25 9940.32 10418.08

TOTAL ASSETS 13346.56 15170.73 17693.18 20075.63 22637.32 25397.60 28600.00 30606.88

EQUITY AND LIABILITIES

EQUITY 362.00 362.00 362.00 362.00 362.00 362.00 362.00 362.00CONTRIBUTIONS 1724.00 2039.00 2383.00 2773.00 3194.00 3648.00 4139.00 4669.00REVALUATION SURPLUS 3722.25 4564.75 5500.83 6473.00 7507.60 8481.01 9539.50 10684.82 1OPERAT-IONAL SURPLUS 2221.31 2302.97 2369.35 2449.63 2542.72 2636.60 2730.50 2845.06 o

_ _ _ _ _ _ _ _ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - C0

TOTAL EQUITY 8029.56 9268.73 10615.18 12057.63 13606.32 15127.60 16771.00 18560.88 1

LONG TERM DEBT(NET) 1565.00 1884.00 2465.00 2788.00 3168.00 3582.00 3999.00 4471.79

ACCOUNT PAYABLES 3374.00 3594.00 4154.00 4744.00 5349.00 6170.00 7253.00 6991.00CUSTOMER DEPOSITS 245.00 265.00 285.00 305.00 325.00 345.00 365.00 385.00CURRENT MATURITIES 133.00 159.00 174.00 181.00 189.00 173.00 212.00 198.21

TOTAL CURRENT LIABILITIES 3752.00 4018.00 4613.00 5230.00 5863.00 6688.00 7830.00 7574.21

TOTAL LIABILITIES 5317.00 5902.00 7078.00 8018.00 9031.00 10270.00 11829.00 12046.00

TOTAL EQUITY-LIABILITIES 13346.56 15170.73 17693.18 20075.63 22637.32 25397.60 28600.00 30606.88

*WORKING CAPITAL-MILLION 331.00 408.97 545.64 739.99 1171.58 1692.25 2322.32 3042.08 m

tCURRENT RATIO 1.05 1.06 1.08 1.11 1.17 1.23 1.27 1.38 D X% DEBT/(DEBT+EQUITY) 16.31 16.89 18.85 18.78 18.89 19.15 19.25 19.41

ORN)

CDFd

-POWER SECTOR INCOME STATEMENT MILL-BAHT

--------------------------------------------------------- __------------------__----------------------------

1981 1982 1983 1984 1985 1986 1987 1988

VOLUME SOLD- GWH 14527.00 16619.00 18747.00 20863.00 23297.00 25983.00 28978.00 31339.00

AVERAGE FNERGY IARIFF /AWH 1.60 1.85 2.01 2.14 2.23 9.41 2.67 2.76

ENERGY REVENUES 23311.98 30664.90 37598.88 44706.88 52012.88 62702.87 77394.87 86420.87OTHER OPERATIONAL REVENUE 595.00 638.00 692.00 711.00 839.00 912.00 974.00 1063.00

IOTAL REVENUES 23906.98 31302.90 38290.88 45417.88 52851.88 63614.87 78368.87 87483.87

FUEL 15471.23 16927.70 20503.93 22788.83 25724.73 32268.28 38991.96 40253.19OPERATING COST 4511.00 5467.00 6775.00 8201.00 9761.00 11399.00 14496.00 15736.00

DIRECT COSTS- 19982.23 22394.70 27278.93 30989.83 35485.73 43667.28 53487.96 55989.19= == == = == == = ==z= == = == == = == = == == = == = = = =-= == = == == = == = == == = == = == == == =

TOTAL COSIS 19982.23 22394.70 27278.93 30989.83 35485.73 43667.28 53487.96 55989.19 1-------- -------- -------- -------- -------- -------- -------- -------- ON

INCOME BEFORE DEPRECIATION 3924.77 8908.20 11011.95 14428.05 17366.15 19947.59 24880.91 31494.68 \DDEPRECIATION 2923.82 3772.20 4644.45 6145.23 7493.15 8545.50 10546.87 13975.23 1

INCOME BEFORE INTEREST 1000.95 5135.99 6367.51 8282.82 9873.00 11402.09 14334.03 17519.45INTEREST CHARGED OPER. 1428.00 2544.00 3295.00 4875.00 6598.00 7718.00 9968.99 12589.00

NET SURPLUS (+) -427.05 2591.99 3072.51 3407.82 3275.00 3684.09 4365.04 4930.45

AVERAGE RATE BASE 50046.31 64199.89 79593.81 103535.30 123412.53 142526.l2 179A75.43 218!93.09*OPERATING RATIO % 95.8 83.6 83.3 81.7. 81.3 02.1 ol.7 oO.0*RATE OF RETURN % 2.00 8.00 8.00 8.00 8.00 8.00 8.00 8.00

( >nfD (D

x

O H

0

r\n

H .TX

CJ

-POWER SECTOR FLOW OF FUND" MILL-BAHT

------------------------------------------------------------__---------------_ ----------------------------

1981 1982 1983 1984 1985 1986 1987 1988

SOURCES OF FUNDS

INCOME BEFORE DEPRECIATION 3924.77 8908.20 11011.95 14428.05 17366.15 19947.59 24880.91 31494.68

GROSS INTERNAL GENERATION 3924.77 8908.20 11011.95 14428.05 17366.15 19947.59 24880.91 31494.68

OTHER CONTRIBUTIONS 369.00 403.00 429.00 471.00 496.00 521.00 552.00 576.00

INCREASE IN RESERVES 19.70 21.90 18.40 20.00 20.00 20.00 20.00 20.00

EQUITY INCREASE 1306.00 656.00 412.00 74.00 15.00 5.00 5.00 5.00

IBRD LOAN 0.00 200.90 541.20 785.15 522.75 0.00 0.00 0.00

OTHER LOANS 15537.22 17544.00 158/6.80 24621.50 22273.25 28979.00 21787.00 20884.00

TOTAL LOANS 15537.22 17744.90 16418.00 25406.65 22796.00 28979.00 21787.00 20884.00

TOTAL SOURCES 21115.09 27734.00 28289.35 40399.70 40693.15 49472.59 47244.91 52979.68

APPLICATIONS OF FUNDS

INVESTMENT IN PROJECT 0.00 4521.27 7803.32 9114.30 7213.95 4585.86 0.00 0.00

CAPITALIZED INTEREST 927.99 1642.00 2401.00 2521.00 2397.00 4431.00 3337.00 2205.00

SECTOR INVESTMENT 15583.00 13064.73 14568.68 17203.70 20959.05 25453.14 23990.00 22865.00

TOTAL INVESTMENT 16511.00 19228.00 24773.00 28839.00 30570.00 34470.00 27327.00 25070.00

FOREIGN LOAN AMORTIZATION 0.00 0.00 0.00 0.00 0.00 68.33 136.67 136.67 °

OTHER LOANS AMORTIZATION 1336.00 1674.00 2116.00 3671.00 4901.00 5542.67 8086.33 11298.30

TOTAL AMORTIZATION 1336.00 1674.00 2116.00 3671.00 4901.00 5611.00 8223.00 11434.97

OPER.INTEREST LONG T.DEBT 1428.00 2544.00 3295.00 4875.00 6598.00 7718.00 9968.99 12589.00

TOTAL DEBT SERVICE 2764.00 4218.00 5411.00 8546.00 11499.00 13329.00 18191.99 24023.97

INCREASE IN WORK.CAPITAL 1861.99 4266.09 -1913.05 2994.70 -1395.85 1653.59 1705.92 3865.71

OTHER ASSETS -21.90 21.90 18.40 20.00 20.00 20.00 20.00 20.00

TOTAL APPLICATIONS 21115.09 27734.00 28289.35 40399.70 40693.15 49472.59 47244.91 52979.68

DEBT SERVICE RATIO 1.42 2.11 2.04 1.69 1.51 1.50 1.37 1.31

% CONTRIBUTION TO INVESTMENT 8.3 20.6 26.9 20.4 21.3 22.0 25.0 27.7

(Da D

oH

0

CDw2

-POWER SECTOR BALANCE SHEET MILL-BAHT

1981 1982 1983 1984 1985 1986 1987 1988

A S S E T S

FIXED ASSETS IN OPER. 87893.67 107932.77 134205.22 174600.18 196551.69 238566.31 299717.95 355504.21MINUS ACCUM.DEPRECIATION 25429.40 31808.12 39553.86 49160.05 60708.90 73504.03 89196.18 109415.15

NET FIXED ASSETS 62464.26 76124.65 94651.36 125440.13 135842.79 165062.29 210521.77 246089.06WORK IN PROGRESS 17533.00 25731.00 34755.00 34942.00 57965.00 64179.00 47054.00 37318.00CASH AND BANKS 1664.99 2413.08 3155.03 4277.72 5867.88 5909.46 9195.39 10577.11ACCOUNTS RECEIVABLE 3579.00 4543.00 5403.00 6256.00 7113.00 8404.00 10171.00 11250.00INVENT*RIES 4789.00 7727.00 5144.00 8318.00 5671.00 8908.00 6942.00 10659.00

TOTAL CURRENT ASSETS 10032.99 14683.08 13702.03 18851.72 18651.08 23221.46 26308.39 32486.11OTHER ASSETS 19.70 41.60 60.00 80.00 100.00 120.00 140.00 160.00

= ===== == ======== === ===2= == === === == === === == == =z=== ======== = == =====

TOTAL ASSETS 90049.95 116580.33 143168.39 179313.85 212559.67 252582.75 284024.16 316053.17

EQUITY AND LIABILITIES

EOUITY 7485.00 8141.00 8553.00 8627.00 8642.00 8647.00 8652.00 8657.00CONTRIBUTIONS 1813.00 2216.00 2645.00 3116.00 3612.00 4133.00 4685.00 5261.00 1REVALUATION SURPLUS 25721.61 32124.19 39546.35 47828.34 58177.15 67686.15 79240.51 93977.03OPERATIONAL SURPLUS 7078.43 9670.42 12742.93 16150.75 19425.75 23109.84 27474.89 32405.34 H

TOTAL EQUITY 42098.03 52151.61 63487.27 75722.09 89856.90 103575.99 120052.39 140300.37

LONG TERM DEBT(NET) 38502.22 54131.12 66878.12 87383.77 104568.77 125324.77 135676.80 145822.14

ACCOUNT PAYABLES 7756.00 8140.00 9072.00 11226.99 12423.00 15338.99 16720.00 19032.00CURRENT MATURITIES 1674.00 2116.00 3671.00 4901.00 5611.00 8223.00 11434.97 10738.67

TOTAL CURRENT LIABILITIES 9430.00 10256.00 12743.00 16127.99 18034.00 23561.99 28154.97 29770.67RESERVES 19.70 41.60 60.00 80.00 100.00 120.00 140.00 160.00

TOTAL LIABILITIES 47951.92 64428.72 79681.12 103591.76 122702.77 149006.76 163971.77 175752.80

TOTAL EQUITY-LIABILITIES 90049.95 116580.33 143168.39 179313.85 212559.67 252582.75 284024.16 316053.17

*WORKING CAPITAL-MILLION 2276.99 6543.08 4630.03 7624.73 6228.88 7882.47 9588.39 13454.11 8*CURRENT RATIO 1.06 1.43 1.08 1.17 1-03 0.99 0.93 1.09 Hro o DEBT/(DEBT+EQUITY) 47.77 50.93 51.30 53.57 53.78 54.75 53.05 50.96 \

0

H

ro)

CD02

- 72 -ANNEX 13Page 1

THAILAND

POWER SUBSECTOR PROJECT

Assumptions in the Financial Forecast of EGAT

Revenues

1. Revenues for EGAT, PEA and MEA were first calculated at the levelrequired to yield rates of return of 2% in FY81 and 8% thereafter. Thisallowed the calculation of average tariffs at the consumer level for each oneof the utilities. Next, keeping these tariffs unchanged, the excess cashin MEA and PEA was transferred to EGAT by increasing EGAT's bulk tariff toMEA and PEA. This should produce a more rational use of the sector finan-cial resources. The following table highlights the results of thissimulation:

EGAT FY81 FY82 FY83 FY84 FY85 FY86 FY87 FY88

EGATRate of return 2.0 8.5 9.1 8.9 9.1 9.0 8.9 8.9Self-financing ratio/a 3.6 16.9 24.8 17.3 17.9 17.5 18.3 21.3Cash balance (billion B.) 0.1 1.2 1.6 2.3 3.3 2.6 5.2 6.9

PEARate of return 2.0 8.0 4.9 5.1 4.3 4.4 3.9 3.5Self-financing ratio/a 9.8 27.1 22.0 21.2 22.6 40.6 47.8 58.5Cash balance 0.8 0.9 1.2 1.5 1.8 2.1 2.5 3.1

MEARate of return 2.0 3.9 3.8 4.3 5.0 5.4 5.9 5.9Self-financing ratio/a 68.6 60.0 61.0 67.7 68.0 71.0 72.6 75.8Cash balance 0.7 0.2 0.3 0.4 0.9 1.4 1.9 1.3

/a On the average investment of the previous year, the current and thenext following year.

2. Revenues for FY81 were estimated on the basis that EGAT-s tariffswere raised on April 1, 1981 to yield a 2% rate of return on net revaluedfixed assets in operation. The following are the resulting tariffs for EGATand the Sector.

- 73 -ANNEX 13Page 2

New tariff level (B/KWh) and percentage increaseon previous level

1981 EGAT % Sector %

April 1 Tariff increase toproduce ROR of 2% forFY81 1.4556 21 1,7914 19

Fuel Costs

3. Fuel oil and diesel prices adjustments to EGAT have been assumedto eliminate oil subsidies by April 1, 1981 to a price level of aboutUS$34.50/bbl crude equivalent for FY81; thereafter costs would be increasedat 3% p.a. in real terms.

4. Lignite prices have been assumed at cost through FY83 and atUS$15.20/ton escalated at 1% p.a. in real terms after FY83.

5. Gas prices have been assumed at 75% of the fuel oil equivalenteach year.

Operating Costs

6. Operating costs have been estimated based on FY80 unit costs andescalated at 12.5%, 10.25%, 9.75%, 8.75%, 8.25% and 7.0% for FY81, FY82,FY83,84,85, and FY86-88, respectively. The rates are the latest projectionsassuming 50/50 foreign and local expenditures.

Capital Investment

7. Construction costs are those estimated to provide the additionalplant and equipment required to meet the demand forecast escalated inaccordance with the latest projection of inflation rates.

Equity

8. Equity to be received is that to be provided to PEA and EGATfor ongoing and future projects, to cover cash shortages.

- 74 -ANNEX 13Page 3

Borrowings

9. Foreign loans have been assumed at annual interest rates varyingfrom 2% to 15%, and for terms varying from 30 years including 10 years graceto 10 years including 3 years grace. Local borrowings have been assumed atannual interest rates varying from 10% to 15%, and for terms varying from 10years including 5 years grace to 20 years including 5 years on theassumption that the long-term debts will be rolled over.

75 - ANNEX 14Page 1

THAILAND

ELECTRICITY GENERATING AUTHORITY OF THAILAND

POWER SUBSECTOR PROJECT

Least Cost Analysis

Alternative Sequences

1. The least cost analysis was made on a program basis. Thefollowing four sequences, each of which would satisfy the projected demandup to 1993, were compared:

Year Sequence A Sequence B Sequence C Sequence D

Apr. 1986 Lang Suan Hydro Oil-fired Oil-fired Lang Suan Hydro(3x45 MW) (75 MW) (150 MW) (3x45 MW)

Gas turbines(3x25 MW)

Jun. 1986 Chiew Larn Hydro Oil-fired Gas turbines Chiew Larn Hydro(3x80 MW) (75 MW) (9x25 MW) (3x80 MW)

Gas turbines(6x25 MW)

Aug. 1987 Mae Moh #7 Mae Moh #7 Mae Moh #7 Coal-fired #1(300 MW) (300 MW) (300 MW) (600 MW)

March 1988 Mae Moh #8 Mae Moh #8 Mae Moh #8 -(300 MW) (300 MW) (300 IW)

Sept. 1988 Mae Moh #9 Mae Moh #9 Mae Moh #9 Coal-fired #2(300 MW) (300 MW) (300 M4W) (600 MW)

Oct. 1989 Coal-fired #1 Coal-fired #1 Coal-fired #1 -(600 MW) (600 MW) (600 MW)

Oct. 1990 - - - Coal-fired #3(600 MIW)

Oct. 1991 Coal-fired #2 Coal-fired #2 Coal-fired #2 Coal-fired #4(600 MW) (600 MW) (600 MW) (600 MW)

April 1992 - - - Mae Moh #7

(300 MW)

Oct. 1992 Coal-fired #3 Coal-fired #3 Coal-fired #3 Mae Moh #8(600 MW) (600 MW) (600 MW) (300 MW)

Apr. 1993 Coal-fired #4 Coal-fired #4 Coal-fired #4 Mae Moh #9(600 MW) (600 MW) (600 MW) (300 MW)

- 76 - ANNEX 14page 2

2. Sequence A was the basic program, Sequence B was used to compareLang suan and Chiew Larn hydroelectric projects under Sequence A with theirthermal alternatives (two hydro projects together would contribute about 890GWh of energy output and 355 MW of dependable peaking capacity), Sequence Cwas used to compare Lang Suan and Chiew Larn hydroelectric projects with alarger thermal unit in the central region and gas turbines in the South, andSequence D was used to find the most economical sequence of development oflignite-fired units at Mae Moh mine mouth with coal-fired units at Si Racha

using imported coal.

3. Associated transmission facilities were taken into consideration inthe comparison including the 500 kV transmission line required for the Mae Mohextension. Capital and O&M costs for projects common to all four sequenceswere not included with the exception of those which would otherwise affectthe fuel cost calculation.

Methodology of Comparison

4. The comparison was made on a constant price basis by the discountedcash flow method. Only actual expenditures on goods and services wereincluded. Financial charges such as interest, depreciation and amortizationwere excluded. The length of period compared was (i) the-first periodcovering the years of expansion of the system until the full utilization ofthe power capacity of the hydro projects, and (ii) the second periodextended until differences in costs of operating the alternative sequencesbecome insignificant.

5. The economic life of power plants and transmission system wasassumed to be:

Hydro plant ............ 50 yearsThermal plant .......... 25 yearsGas turbine ............ 20 yearsTransmission line ...... 40 yearsSubstation ............. 25 years

Interim replacements required for equipment having a life shorter than 50years were taken into consideration.

Capital Costs

6. All costs were at end-1980 price levels. Efficiency prices wereused as follows: (i) taxes and duties were excluded; (ii) foreign exchangecosts were adjusted by applying a standard conversion factor of 0.91 (ormultiplying foreign costs by 1/0.91 = 1.1); (iii) the conversion factor forskilled and unskilled labor was assumed to be 1.0.

- 77 - ANNEX 14Page 3

7. The capital costs estimated for various projects without shadowpricing were as follows:

Associatedtransmission

Plant facilities Total Cost/kw---------- (B million) --------- (US$)

Lang Suan hydro 4,047.7 165.0 4,212.7 1,520Chiew Larn hydro 3,514.7 410.7 3,925.4 800Oil-fired thermal (75 MW) 1,100.0 88.0 1,188.0 772Oil-fired thermal (150 MW,

using cost allocated froma 500 MW unit) 1,061.0 136.5 1,197.5 390

Gas turbines (25 MW) 75.1 - 75.1 147Mae Moh extension (3x300 MW) 14,392.0 5,973.0 19,365.0 1,050Coal-fired thermal (4x600 MW) 34,708.8 923.0 35,631.8 724

Operation and Maintenance (O&M) costs

8. The O&M costs for different types of plants were estimated on thebasis of a fixed percentage of capital cost as follows:

O&M cost(% of

capitalPlant cost)

Hydro plant 1.0Oil-fired thermal plant 2.5Coal-fired thermal plant 3.0Lignite-fired thermal plant 3.0Gas turbine 3.0Transmission line 1.0Substation 1.5

Fuel Cost

9. The fuel consumption of alternative programs was calculated by anenergy balance study on a system basis, taking into consideration thefollowing factors:

- T8 ANNEX 14Page 4

(a) maximum generation or energy capability of various thermal plants;

(b) scheduling of energy generation according to merit order operationso as to minimize fuel costs; and

(c) characteristics of system load.

10. Fuel costs used in the analysis for various thermal plants beforeshadow pricing were as follows (it was assumed that the prices of oil,lignite and coal would be increased at the annual rates of 3%, 1% and 1%,respectively, in real terms from 1980):

Plant Type of fuel B/liter B/kWh

South Bangkok power plant Heavy oil 4.1406 1.0706Natural gas 3.7520 0.7504

Oil-fired power plant, 75 MW Heavy oil 4.4211 1.2379Oil-fired power plant, 150 MW

(derived from 500 MW unit) Heavy oil 4.2256 0.9972Gas turbine power plant, 25 MW

(at Khanom site) Diesel oil 5.8457 2.6307Gas turbine power plant, 25 MW

(at Region 1 site) Diesel oil 5.6507 2.5429Mae Moh lignite power plant, 300 MW Lignite - 0.3075/aCoal-fired power plant, 600 M4W Coal - 0.4483/b

/a Lignite cost was assumed to be US$15.0/ton; heating value of lignite =2,500 kcal/kg; heat rate of Mae Moh 300 M4W units = 2,500 kcal/kWh.

/b Cost of coal was assumed to be US$65.0/ton; heating value of coal =

6,717.30 kcal/kg; heat rate of coal-fired 600 MW units = 2,260 kcal/kWh.

Results of Analysis

11. The cost streams of sequences are shown in Table 1. The presentvalues of four alternative sequences at different discount rates are givenbelow:

- 79 - ANNEX 14Page 5

PRESENT VALUES(B million)

Discount rate (%)10 12 14 16 18 20

Sequence ACapital cost 24,925 21,540 18,844 16,644 14,815 13,270O&M cost 4,590 3,297 2,433 1,836 1,411 1,103Fuel cost 116,901 90,674 73,068 60,731 51,758 45,020

Total 146,416 115,511 94,345 79,211 67,984 59,393

Sequence BCapital cost 21,404 18,205 15,691 13,666 12,002 10,613O&M cost 4,648 3,343 2,470 1,867 1,437 1,125Fuel cost 126,920 97,839 78,373 64,770 54,905 47,517

Total 152,972 119,387 96,534 80,303 68,344 59,255

Sequence CCapital cost 20,372 17,261 14,818 12,851 11,237 9,892O&M cost 4,422 3,170 2,334 1,758 1,349 1,052Fuel cost 126,519 97,535 78,123 64,555 54,715 47,347

Total 151,313 117,966 95,275 79,164 67,301 58,291

Sequence DCapital cost 24,247 20,838 18,134 15,940 14,124 12,600O&M cost 4,529 3,241 2,382 1,790 1,371 1,066Fuel cost 118,734 92,228 74,389 61,856 52,719 45,842

Total 147,510 116,307 94,905 79,586 68,214 59,508

12. Between Sequence A and B, Sequence A is the least cost solutionfor discount rates up to 19% which demonstrates that the Lang Suan and ChiewLarn hydroelectric projects are economically justified on a program basiswhen the opportunity cost of capital is below 19%.

13. Between Sequence A and Sequence D, the equalizing discount rate is22%, which means that the early lignite development is more economical thanits alternative of late lignite development. However, this is only apreliminary result; further refinement is necessary pending upon thefollowing studies:

- 85 - ANNEX 14Page 6

(a) unit size of Mae Moh lignite plant extension;

(b) cost of coal unloading and handling facilities; and

(c) cost of imported coal.

Sensitivity Tests

14. Sensitivity tests between Sequence A and Sequence B for variationsin capital cost and fuel cost were made with the results shown below:

Equalizingdiscountrate (%)

Capital Cost VariationsAt base cost 19.310% increase 17.720% increase 16.4

Fuel Cost Variations /aAt base cost 19.310% reduction 18.220% reduction 16.9

Capital Cost and Fuel Cost Variations /a10% increase in capital cost and 10% reduction in fuel cost 16.620% increase in capital cost and 10% reduction in fuel cost 15.420% increase in capital cost and 20% reduction in fuel cost 14.3

/a Provided natural gas would become available in the South in the future.

ANNEX 14

Table 1

THAILAND

ELECTRICITY GENERATING AUTHORITY OF THAILAND

POWER STBSECTOR PPOJECT

Cost Streams of Alternatives(B million)

Sequence A Sequence B Sequence TlCapital Capital Capital

Year cost O&M Fuel cost cost O&M Fuel cost cost O&M Fuel cost

1980 75.70 - - - - - 75.70 - -

1981 180.80 - 9,830.26 118.80 - 9,830.26 180.80 - 9,830.26

1982 1,222.80 - 7,089.01 424.80 - 7,089.01 1,222.00 - 7,089.01

1983 2,144.0 - 7,396.26 749.60 - 7,396.26 2,144.00 - 7,396.26

1984 3,296.10 - 6,472.63 2,523.40 - 6,472.63 3,283.80 - 6,472.63

1985 4,777.00 - 4,616.41 3,360.30 - 4,616.41 4,297.70 - 4,523.51

1986 5,587.50 33.40 6,861.07 4,871.20 62.50 7,296.56 3,230.00 33.40 6,861.07

1987 5,977.50 121.90 8,485.86 5,977.50 129.30 9,252.50 3,911.50 88.30 8,695.24

1988 4,352.20 360.20 7,307.24 4,352.20 367.60 8,282.25 4,632.40 382.80 7,457.29

1989 2,663.60 571.30 7,333.76 2,663.60 578.70 8,494.87 4,477.80 382.80 9,392.17

1990 5,541.30 583.60 8,515.87 5,541.30 591.00 9,819.51 7,495.80 382.80 10,915.69

1991 4,622.40 583.60 11,426.18 4,622.40 591.00 12,950.85 6,779.10 660.70 11,848.28

1992 5,090.60 583.60 13,181.81 5,090.60 591.00 14,791.07 4,792.30 759.00 12,972.70

1993 2,015.00 1,000.50 14,894.38 2,015.00 1,007.90 16,551.93 1,022.80 1,068.80 14,321.411994 - 1,139.40 17,801.77 - 1,146.80 19,509.04 - 1,139.40 17,801.77

1995 - 18,099.38 - 19,857.87 - 18,099.38

1996 - 18,403.56 - I 20,214.80 - 18,403.56

1997 - 18,714.47 - 20,580.05 - 18,714.47

1998 - 19,032.30 - 20,953.85 - 19,032.301999 - 19,357.23 - 21,336.42 - 19,357.23

2000 - 19,689.44 - 21,728.01 - 19,689.442001 - 20,029.14 - 22,128.87 - 20,029.14

2002 - 20,376.52 - 22,639.24 - 20,376.522003 - 20,731.78 - 22,959.38 - 20,731.782004 - 21,095.14 - 23,389.57 - 21,095.14

2005 - 21,466.82 118.80 23,830.08 - 21,466.82

2006 44.60 21,847.03 424.80 24,281.19 44.60 1 21,847.03

2007 280.10 22,236.02 749.60 24,743.20 280.10 22,236.02

2008 1,578.20 22,634.01 2,523.40 25,216.41 1,565.90 22,634.01

2009 3,330.80 23,141.24 3,360.30 25,701.12 2,851.50 23,041.24

2010 3,910.90 23,457.98 3,761.80 26,197.65 2,521.50 23,457.98

2011 4,162.40 23,884.47 4,162.40 26,706.33 3,588.80 23,884.47

2012 3,122.30 i 24,320.99 3,122.30 27,227.50 4,355.50 24,320.99

2013 2,340.90 24,767.80 2,340.90 27,761.51 4,477.80 24,767.80

2014 5,264.40 25,225.19 5,264.40 28,308.71 6,386.40 25,225.19

2015 4,622.40 25,693.44 4,622.40 28,869.47 4,964.00 25,693.44

2016 5,090.60 i 26,172.86 5,090.60 29,444.17 3,703.70 26,172.86

2017 2,015.00 26,663.74 2,015.00 30,033.19 1,022.80 26,663.742018 - 27,166.41 - 30,636.94 - 27,166.41

2019 - 27,681.19 - 31,255.83 - 27,681.19

2020 - 28,208.40 - 31,890.29 - 28,208.40

2021 - 28,748.40 - 32,540.74 - 28,748.40

2022 58.10 29,301.54 - 33,207.65 58.10 29,301.54

2023 58.10 29,868.18 - 33,891.47 50.10 29,868.18

2024 123.70 30,448.69 - 34,592.69 123.70 30,448.69

2025 35.80 31,043.47 - 35,311.78 35.80 31,043.47

2026 - 31,652.90 - 36,049.26 - 31,652.90

2027 - 32,277.39 - 36,805.65 - 32,277.39

2028 - 32,917.37 - 37,581.47 - 32,917.37

2029 - 33,573.27 _ 38,377.29 - 33,573.27

- 82 - ANNEX 15Page 1

THAILAND

THAILAND: ELECTRICITY GENERATING AUTHORITY OF THAILAND

POWER SUBSECTOR PROJECT

Internal Economic Rate of Return

General

1. The internal economic rate of return (IERR) was calculated byequalizing the present value of the cost streams and the benefit streams ofEGAT-s least cost development program from FY80 through FY86. The analysiswas made on an incremental basis using 1979 as the base year.

Costs

2. Same method of calculation as detailed in the least cost analysiswas used.

3. Capital Costs. Capital expenditures between FY80 and FY86 on allprojects to be commissioned during this period were included. Annualexpenditures with shadow pricing are shown below:

Generation and transmission DistributionYear --------------- (B million) ----------------

1980 19,098 2,5341981 9,865 4,3351982 9,878 4,5661983 10,175 5,2861984 6,349 5,4301985 3,441 4,0481986 1,631 3,844

Total 60,437 30,043

4. O&M Costs. Incremental O&M costs were calculated for newgeneration and transmission facilities which would be put into operationduring FY80-86. Basis of estimating O&M costs for generation andtransmission was given in Annex 14. Operating costs for the distributionsystems including MEA and PEA were estimated at B 0.15 per kWh based on FY80operation analysis, but excluding depreciation.

- 83 - ANNEX 15Page 2

5. Fuel Costs. It was assumed that the system would be operated insuch a way as to minimize the fuel cost. All hydro plants would generateenergy to their full capability and the balance of energy requirements wouldbe met by thermal plants based on merit-order operation. The fuel costsused were same as Annex 14 with the exception that the economic cost ofnatural gas was used in the analysis (excluding royalty and taxes). The fuelcosts of various power plants completed during the period FY80-86 wereestimated as follows:

EnergyFuel cost cost

Plant Type of fuel (B/unit) (B/kWh)

South Bangkok gas turbine Distillate 5.6207/liter 2.3253(4x25 MW) Natural gas 51.2/MBtu 0.8200

Bang Pakong combined cycle Distillate 5.6507/liter 2.2471(4x60 MW + 120 MW) Natural gas 51.2/MBtu 0.4658

Bang Pakong thermal plant Natural gas 51.2/MBtu 0.4678(550 MW)

Barge thermal plant (75 MW) Heavy oil 4.4211/liter 1.2379

Mae Moh lignite plant75 MW Lignite 307.5/ton 0.3321150 MW 307.5/ton 0.3167

Benefits

6. Incremental Energy Sales. Benefits were calculated bymultiplying incremental sales in each year over FY79 by an averageprice of electricity sold at the retail level. A study of systemenergy balance (Table 1) indicated that in the early years from FY80-83part of the incremental sales should attribute to generation made bythe existing plants in operation before FY80 and in years from FY87and afterward part of the incremental sales should attribute togeneration made by new plants in operation after FY86. The incrementalsales of these years would be therefore controlled by the generationmade by these plants commissioning from FY80-86 after adjusting forgeneration and transmission losses (about 7.4%) and distribution system

- 84 - ANNEX 15Page 3

losses (about 6.7%). Only in three years, FY84, FY85 and FY86 incrementalsales at the retail level were applied and there was excess generation whichwould be used for fuel replacement. The incremental sales and generationavailable for fuel saving are shown below for a total operating period of 25years:

Incre- Incrementalmental Incre- salessales mental attributable Generationat the generation to genera- availableretail by new tion of for fuellevel plants new plants replacement…-------- (GWh) ---------- …______________

1979 - - - -

1980 817.4 83.6 71.7 -1981 2,214.7 1,687.0 1,457.5 -1982 4,307.7 4,491.0 3,880.0 -1983 6,435.7 7,020.0 6,065.0 -1984 8,550.7 10,966.0 (9,474.2) 1,068.91985 10,984.7 15,903.0 (13,739.5) 3,188.61986 13,670.7 16,789.0 (14,505.0) 965.71987 16,665.7 17,039.0 14,721.0 -1988 19,028.7 16,589.0 14,332.2 -1989 19,028.7 17,123.6 14,793.6 -1990 19,028.7 17,109.0 14,781.5 -1991-2011 19,028.7 17,156.0 14,822.1 -

7. Revenue. In the absence of an established methodology to quantifybenefits of power supply, revenues from the sales of electricity at theretail level were used as a substitute measure of the economic benefits.This is considered to represent the minimum economic benefits because itshows consumers' willingness to pay but takes no account of consuemrs'surplus; people may value service by more than the amount they pay to obtainit. The average tariffs used were based oIn the results of financialprojection required to produce the covenanted 8% rate of return for the sectoras a whole on revalued net fixed assets basis and adjusted to end-1980 pricelevel.

Internal Economic Rate of Return

8. The internal economic rate of return (IERR) is the discount ratewhich equalizes the present values of the economic costs and benefits. TheIERR of EGAT's development program FY80-86 thus calculated would be 12%.Detailed calculation is given in Table 2.

- 85 -

ANNEX 15

Table 1

THAILAND

ELECTRICITY GENERATING AUTHORITY OF THAILAND

POWER SUBSECTOR PROJECT

Energy Balance Study (Gwh)

Fiscal year

Power plants 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990

A. Hydro Power Plants

1. Bhumibol 817 800 950 1,100 1,200 1,300 1,500 1,500 1,500 1,500 1,550

2. Sirikit 492 896 900 850 850 900 900 900 900 900 900

3. Ubolratana 72 63 73 44 50 50 50 50 65 65 65

4. Sirindhorn 61 60 60 60 60 60 73 73 73 73 73

5. Chulabhorn 69 90 72 60 70 70 70 75 75 75 75

6. Nam Pung 10 12 12 12 12 12 15 15 15 15 15

7. Kang Krachan 49 44 36 70 70 70 70 70 70 70 70

8. Srinagarind 83 340 650 660 780 914 1,080 1,190 1,285 1,320 1,290

9. Pattani - - 180 120 170 200 200 200 200 200 200

10. Lower Quae Yai - - 10 107 120 130 150 170 176 178 180

11. Khao Laem - - - - 348 611 928 806 494 891 805

12. Lang Suan - - - - - - 150 200 250 300 300

13. Chiew Larn - - - - - - 100 150 200 300 40014. Upper Quae Yai - - - - - - - - 993 1,337 1,03215. Miscellaneous bydro plants - - - - - - - - - 200 293

16. Cha Phaya, Mae Nyat,Lam Takhong - - - - - - 130 161 161 161 161

17. Kud - - - - - - 71 241 214 214

18. Pak Mun - - - - - - - - 462 462 462

Subtotal 1,653 2,305 2,943 3,083 3,730 4,317 5,416 5,631 7,160 8,261 8,085

B. Thermal Plants

1. North Bangkok 1,494 1,700 1,630 1,181 985 985 985 985 985 985 985

2. South Bangkok 8,992 8,347 8,338 8,446 7,176 4,869 7,170 7,834 5,409 4,309 3,2823. Surat Thani (30 MW) 185 210 210 210 200 200 - - - - -

4. Bang Pakong TH. #1-2(2x550 MW) - - - 1,080 4,000 7,500 7,500 7,500 7,500 7,500 7,500

5. Barge thermal (75 1IW) - 270 540 560 500 300 428 539 200 200 2006. R3 thermal (2xl5O MW) - - - - - - - - 920 920 1,150

Subtotal 10,6

7 110,527 10,718 11,477 12,861 13,954 16,083 16,858 15,014 13,914 13,117

C. Thermal Plants (Lignite)

1. Krabi 335 325 325 300 300 300 200 200 200 200 200

2. Mae Moh #1-3 (3x75 MW) 933 1,227 1,470 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500

3. Mae Moh #4-5 (2x150 MW) - - - - 920 1,970 1,970 1,970 1,970 1,970 1,970

4. Mae Moh #6-10 (2xl5O +

3x300 MW) - - - - - - - 2,135 5,090 7,880 7,880

Subtotal 1,328 1,552 1,795 1,800 2,720 3,770 3,670 5,805 8,760 11,550 11,550

D. Combined Cycle

1. BPK. GT. block 1 (240 MW) - 601 1,082 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200

2. BPK. GT. block 2 (240 MW) - } 1,082 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200

3. Combined cycle 1 (120 MW) - - 310 600 600 600 600 600 600 600 600

4. Combined cycle 2 (120 MW) - - - 600 600 600 600 600 600 600 600

Subtotal - 601 2,474 3,600 3,600 3,600 3,600 3,600 3,600 3,600 3,600

E. Gas Turbine & Diesel

1. Gas turbine RI } 10 36 4 96 5 5 - - - - -

2. Gas turbine R2 63. Gas turbine R3

(or SB 4x25 MW) 275 661 216 400 35 35 10 10 10 10 10

4. Diesel R4 1 1 1 10 5 5 5 5 5 5 5

5. Diesel R3 63 39 3 60 10 10

Subtotal 349 737 230 566 55 55 15 15 15 15 15

F. Coal fired (4x600 MW) - - - - - - - - - - 3,940

G. Purchase (Nam Ngum) 750 730 730 730 720 720 700 690 680 670 660

li. Purchase (NEB) - 60 60 60 50 50 25 25 25 25 -

Total Energy

Generation 14,754 16,512 18,950 21,316 23,736 26,466 29,507 32,624 35,254 38,035 40,967

- 86 -ANNEX 15Table 2

THAILAND

ELECTRICITY GENERATING AUTHORITY OF THAILAND

POWER SUBSECTOR PROJECT

Internal Economic Rate of Return(B million)

Cost streams Benefit streamsCapital Distri-

Generation bution& trans- Distri- operating Fuel

Year mission bution O&M costs Fuel Revenues saving /a

1980 19,098.0 2,534.0 102.3 10.8 - 73.1 -

1981 9,865.0 4,335.0 181.5 218.6 2,797.8 2,338.8 -

1982 9,878.0 4,566.0 317.2 582.0 2,299.9 6,208.1 -

1983 10,175.0 5,286.0 413.2 909.7 3,829.8 9,704.0 -

1984 6,349.0 5,430.0 775.3 1,282.6 5,312.6 13,681.1 677.7

1985 3,441.0 4,048.0 983.1 1,647.7 7,319.3 17,575.5 2,010.9

1986 1,631.0 3,844.0 1,042.0 2,050.6 7,578.4 21,873.1 664.4

1987 - - 1,071.0 2,208.1 7,848.3 23,553.6 -

1988 - - 1,071.0 2,149.8 7,376.8 22,931.5 -

1989 - - 1,071.0 2,219.0 7,447.3 23,669.7 -

1990 - - 1,071.0 2,217.2 7,539.3 23,650.3 -

1991-2010 - - 1,071.0 2,223.3 7,622.0 23,715.3 -

to 9,414.52011 -10,823.3 /b - 1,071.0 2,223.3 9,521.8 23,715.3 -

Internal economic rate of return: 12.0%

/a Estimated at B 0.688/kWh for North Bangkok thermal plant and B 0.605/kWhfor South Bangkok thermal units 1 & 2.

lb Estimated salvage value for hydroelectric plants.

- t - ANNEX 16Page 1

ThAILAND

ELECTRICITY GENEIATING AUTHORITY OF THAILAND

POWER SUBSECTOR PROJECT

Related Documents and Data Available in the Project File

A. General Report and Documents Related to the Sector and the Borrower

1. EGAT's Annual Report, 1979

2. PEATs Annual Report, 19793. Oil and Thailand, 1978-19794. EGAT's Power Development Plan (1979-1993)5. Estimate of EGAT's Fule Requirement (1980-1993)6. EGAT's Monthly Peak Capacity and Energy Balance7. Consultants' Audit Report, 19798. EGAT-s Financial Data9. PEA's Financial Data10. MEA's Financial Data

B. General Reports and Documents Related to the Loan

1. Alternative Programs for Power Development Plan by EGAT2. Economic Rate of Return by EGAT3. Feasibility Report for Lang Suan Multi-purpose Project Vol. I-V by

Salzgitter and Lahmeyer, Sept. 19774. Study on Economic and Financial Aspects of Lang Suan Multi-purpose Pro-

ject by EGAT, Feb. 19805. Feasibility Report of Chien Larn Project by Electro-consult, June 19806. Summary Report of Chiew Larn Project by EGAT, Dec. 19797. Transmission System Extension Project No. 5 (1980-84) by EGAT, Jan. 19808. Detailed Cost Estimate - Lang Suan Project9. Detailed Cost Estimate - Chiew Larn Project10. Bang Pakong-Thermal Power Project - Unit No. 2 by EGAT, Oct. 197911. EGAT's Annual Operation and Maintenance Costs12 Appraisal Report of Mae Moh No. 4 Power Project by ADB, Nov. 1979

C. Appraisal Working Papers

1. Worksheets for Disbursement Schedules and Financing Plan2. Computer Printouts for Least Cost Solution and IERR Calculation3. Worksheets for Financial Forecasts.

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