Document of

The World Bank

FOR OFFICIAL USE ONLY

Report No. 9507-MA

STAFF APPRIASAL REPORT

MALAYSIA

POWER SYSTEM DEVELOPMENT PROJECT

JANUARY 22, 1992

Industry and Energy Operations DivisionCountry Departmi - IEast Asia and Pa_ific Regional Office

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

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

CURRENCY EQUIVALENTS(as of August 31, 1991)

Currency Unit Ringgit (M$)Ms$ 1 US$0 37US$1 = M$2.70

WEIGHTS AND MEASURES

km Kilometer (0.62 miles)kg Kilogram (2.205 pounds)Ton = Metric Ton (1,000 kilograms)kw = Kilowatt (1,000 watts)MW = Megawatt (1,000 kilowatts)kVA = Kilovolt-ampere (1,000 volt-amperes)MVA Megavolt-ampere (1,000 kVA)kWh = Kilowatt-hour(860 kilo-calories)GWh - Gigawatt hour (1,000,000 kwh)kV - Kilovolt (1,000 volts)BTU = British Thermal Unit (0.253 kilo calories)MMBTU Million BTUb/d = Barrels per day (1 barrel = 159 liters)TWh Tera watt hour (109 watt-hours)TOE = Tons of oil equivalentMMTOE = Million TOEMMCFD = Million cubic feet per daytcf = Trillion cubic feet

ABBREVIATIONS AND ACRONYMS

ADB Asian Development BankDOE Department of EnvironmentEPU Economic Planning UnitGDP Gross Domestic ProductIMF International Monetary FundMIS Management Information SystemMOETP Ministry of Energy,Telecommunications and Pe tsMOF Ministry of FinanceNEB National Electricity Board (now TNB)Petronas National Petroleum AgencyPGSB Petionas Gas Sdn. BerhadSEB Sabah Electricity Supply BoardSESCO Sarawak Electricity Supply CorporationTNB Tenaga Nasional Berhad

FISCAL YEARSeptember 1 to August 31

FOR OFFICAL USE ONLY

POWER SYSTEM DEVELOPMENT PROJECT

Loan and Projec: Summary

.Doer:z Tenaga Nasional Berhad (TNB)

Guarantor: Malaysia

Amount: US$200 million equivalent.

Terms: 17 years, including 5 years of grace, at the Bank's standard variable interest rate.

Proect ObWectltiveBand RacfQoi

The main objectives of the proposed project are to: (a) meet the growth in power demandover the medium-term at least cost; (b) support TNB's privatization; and (c) strengthenTNB's capabilities in environmental monitoring and evaluation. The project constitutes animportant part of TNB's investment program over FY92-93 and comprises: (a) expansion ofPaka power station by installation of a 300 MW combined-cycle gas-fired unit; (b)strengthening of TNB's main transmission system by construction of the 275 kV KampungAwah - Yong Peng transmission line; (c) strengthening the power supply to Kuala Lumpurby establishing the Pudu Ulu-Jalan Galloway 275 kV system; (d) consultancy services for (i)engineering, design and construction supervision for the Paka power station; (ii) financialmanagement information system; (iii) total quality management program; and (iv) demand-side management and electricity conservation; and (e) technical assistance for TNB'senvironmental division. The project supports the development and use of natural gas, anabundant and economic fuel resource of Malaysia.

Benefitand Rlsks: In supporting the timely development of the power system, the loan to TNB would help

sustain Malaysia's economic growth. The bulk of TNB's investments in power generationwould promote indigenous resources of natural gas and hydropower and this would lead tosubstantial savings in the import of fuel oil. The use of natural gas and hydro for powergeneration would also have significant benefits from the point of view of atmosphericpollution. There are no maior risks associated with the project. The power developmentplan i: ambitious but achievable. Though TNB has demonstrated organization capability inthe execution of large thermal, hydro and transmission projects, delays have occurred in thepast due to an excessively long decision-making and approval process on procurement. Thereis thus some risk of delay in implementation of the proposed expansion program and thiscould lead to the system operating at reduced leve!s of reliability. However, TNB's increasedautonomy is expected to improve its efficiency and effectiveness. Further, in order tominimize delays in implementation TNB would be making substantial use of consultancyassistance for its generation expansion projects, and using turkey concepts for generation andmajor transmission projects. As construction of the gas pipelines for supplying the powerplants would be completed by 1992, there is no risk foreseen due to the non-availability ofgas on time. Gas supply failure risks are minimal and would be mitigated by makingprovision for stocking distillate oil for use in internal combustion turbine and combined-cycleinstallations in an emergency. Conventional steam plants introduced in the program wouldrevert to heavy fuel oil.

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

Project CostLocal Foreign IQIAI

--- - (US$ million) - - - -

Paka Combined Cycle Plant 36.3 147.9 184.2275 kV Transmission Line 28.1 9.4 37.5275 kV Substations 19.0 31.9 50.9Institutional Strengthening 2.0 10.1 12.1Taxes and Duties 47.0 0.0 47.0

BaseCst (August 1991) 132.4 1993 33_12

Physical contingencies 13.2 19.9 33.1Price contingencies 11.2 24.7 35.9

Total Proiect, ost >t 18 43.9 40.7

Interest during construction 0.0 28.6 28.6

lotal Financing Reguired 156.8 272.5 A42M

Financlnw- Plan:

World Bank - 200.0 200.0Tenaga Nasional Berhad 1S6.8 72.5 229.3

TOTAL 1568 272.5 429.3

a/ Including taxes and duties equivalent to US$5S.9 million.

Estimated Disbursement.

Bank Fiscal Year FY92 FY93 FY94 FY95 FY96 FY97------ (US$ million) ------

Annual 6.0 14.0 40.0 48.0 48.0 44.0Cumulative 6.0 20.0 60.0 108.0 156.0 200.0

Economic Rate of Return: 12%

NMo: IBRD No. 23464

MALAYSIA

POWER SYSTEM DEVELOPMENT PROJECT

Table of ContentsPage No.

Loan and Project Summary ................................................. ......... i

I. The Energy SectorOverview .1Resource Endowment. 1Demand and Consumption Pattern. 2Sector Institutions. 2Sector Issues and Strategy. 3Privatization. 4Experience with Previous Loans .5Rationale for Bank Participation ............ ................................... 5

IL The Power Sub-Sector ........................... 6The Power Market ................................ 6Generation and Transmission Capacities ............ .................... 7TNB's Development Program ................................ 7

III. The Borrower ............................. 10Legal and Regulatory Framework ............................ 10Regulatory Arrangements ............................ 11Organization and Management ............................ 11Fmanciad Management ............................. 15

IV. The Project ............................. 17Project Objectives ............................ 17Project Description ............................ 17Project Components ............................ 18Cost Estimates ............................. 19Fmancing Plan ............................. 20Project Implementation ............................ 20Supervision Plan ......... 4 21Procurement .......... 22Disbursements .......... 23En ironment .......... 23

This report is based on the findings oi an appraisal mission consisting of Darayes Mehta (Principal PowerEngineer), Claudio Fernandez (Principal Financial Aralyst), Peter Cordukes (Senior Fmancial Analyst) andPeng Hing Tio (Environmental Consultant) who visited Malaysia in January-February 1991. Peer reviewers wereVatsal Thakor, Hossein Razavi and Jami Sopher. The project was deared by Mr. Callisto Madavo, DirectorEAI and Mr. Vineet Nayyar, Chief, EAIIE.

- iv-

V Finances ....................... ... 26Past and Present Finarncial Performance .26Fixed Assets Accounting .28Tariff aud Marginal Ccst .29Capital Expenditure Program .30Overall Financing Plan . 31Foreign Exchange Exposure ......... ........... .......... ................... 31Future Finances .................. ......................................... 32Ftnancial Sensitivity Analysis ................ ......................... 34Monitoring and Evaluation . ......................................... 35

VI. Project Justification .............. . ............................ 36Justification .36Economic Analysis ............................... 36Risks .37

VII. Agreements Reached and Recommerdation .38

ANNEXES

Annex 1 TNB's Actual Electricity Sales, Generation, Peak Demand, Installed Capacity, andNumber of Consumers .39

Annex 2 Forecast of Electricitv Sales by Consumer Category .40Annex 3 Forecast of TNB's Electricity Sales, Generation, Peak Demand and Installed Capacity .41Annex 4 TNB's Installed Generating Capacity and Energy Capability .42Annex 5 TNB's Transmission and Distribution Facilities .44Annex 6 Assumptions for TNB's Least-Cost Development Plan .45Annex 7 TNB's Generation Development Plan - Proposed Plant Additions and Rt^. -ments .46Annex 8 TNB's Integrated System Capacity Balance ..... .............. ............... 47Annex 9 Consulting Studies, Terms of Reference: A. Financial Management Info,,mation System;

B. Total Quality Management; C. Demand-Side Management and Electricity Conservation . 48Annex 10 Forecast of TNB's Capital Expenditures 1990-20.0. 57Annex 11 Project Cost Estimates .58Annex 12 Disbursement Schedule .60Annex 13 Paka Power Station Expansion: Environmental Assessment - Summary .61Annex 14 TNB's Financial Projections .73Annex 15 Tariff Structure and Marginal Cost .77Annex 16 TNB's Monitoring Indicators .78Annex 17 Assumptions for Financial Projections .79Annex 18 Economic Evaluation of TNB's Development Plan .83Annex 19 Review of Regulatory Arrangements .84Annex 20 Documents in Project File .89

Chart I Organization of Tenaga Nasional Berhad (EK/W48828)Chart 2 Implementation Schedule

MAP: IBRD No. 23464

L. THE ENERGY SECTOR

Overview

1.1 Over the last decade, Malaysia's commercial energy consumptionincreased at an average annual rate of 5.9% from 8.7 million tons of oilequivalent (MMTOE) in 1980 to 14.6 MMTOE in 1989. This was mainly due to growthin the economy (5.4% p.a.) and increasing industrialization. By 1989, the shareof industry in GDP increased to 40% from 26% in 1980 while the share ofagriculture declined from 30% to 26%. A major part of the growth in energyconsumption was accounted for by oil. In 1983, the share of petroleum in totalenergy consumption was 89%. With the advent of natural gas production insignificant quantit'es in 1983, and its substitution for oil (a relativelyscarce and readily exportable domestic resource), the share of petroleumdeclined by 1989 to 70%, while that ef natural gas reached 14%, with theremainder comprised -f hydropower (8%) and coal (8%). This trend is expected tocontinue and the share of petroleum in commercial energy production is projectedto decline to 45% and that of gas to increase to 50% by 2000. Appropriatepromotional and pricing policies are being put into place that would encouragethe utilization of natural gas (a relatively abundant, e-nomical andenvironmentally clean domestic resource) in all sectors of t1e economy andconcribute towards its export (para. 1.10). The Bank has assisted Government ofMalaysia (GOM) in firming up its gas utilization plans through a Gas Utilizationsector study, Report No. 9645-MA, completed in September 1991. The proposedproject wou1i help optimize the use of gas in the power sector.

Resource Endowment

1.2 The principal indigenous sources of energy in Malaysia are crudeoil, natural gas, hydropower and traditional fuels (palm oil wastes, fuelwoodand charcoal). Coal reserves are estimated at only 700 million tons, occurringmostly in Sarawak. Recoverable reserves of crude oil are estimated at 3.1billion barrels. Crude oil production which was insignificant before 1967,reached a level of 555,000 barrels per da- (b/d) in 1989. Although this issufficient to meet the domestic demand (currently about 240,000 b/d), thecountry depends on imported crude and petroleum products to satisfy about 30% ofits need. This is because Malaysia's crude oil (being light and low in sulphurcontent) fetches a premium in the world oil market but does not yield enough ofthe heavy fuel oil demanded in the country. Malaysia's net export of crn.de oilis currently about 390,000 b/d.

1.3 Proven and economically recoverable natural gas reserves inMalaysia are presently estimated at about 52 trillion cubic feet (tcf), almostfour times as large as the oil reserves in terms of thermal equivalence.Natural gas production is presently about 1,807 million cubic feet per day(MMCFD); of this about 70% is fed into an LNG plant (output sold to Japan on a20 year contract) and the ASEAN fertilizer plant, both located in Bintulu,Sarawak. About 5% is used in the methanol and hot-briquetted iron plants on theisland of Labuan, offshore Sabah, and about 9% is usea on the peninsula forpower generation at Paka and the steel mill at Terengganu.

1.4 In its efforts to maximize the use of natural gas, the GOM isimplementing a Second Peninsular Gas Utilization Project which comprises: (a)installation of gas pipelines from the eastern offshore fE.lds to the western

-2-

and southern regions of Peninsular Malaysia; and (b) the expansion of theexisting gas processing plant and the LPG terminal. Major oil-burning powerstations on the west and south of the peninsula will be converted to gasfollowing completion of the pipeline project in 1992. Further, about 200 MMCFDof gas will be sold to the Singapore Public Utilities Board, for which amemorandum of understanding has been si& 3d by the two governments. Theavailability of gas in the vicinity of major growth centers in the west andsouth will also be conducive to its use in the domestic and industrial sectors.In addition, an MMTBE plant will be commissioned in 1992 and a polyethyleneplant in 1994. In Sarawak, a middle distillate synthesis plant will, oncompletion in 1993, convert 100 MMCFD of gas into 120,000 barrels of oilproducts annually. The COM has recently completed a study for the utilizptionof gas for power and industrial development in Sabah and Sarawak under theSarawak Power Project (Loan 2942-MA) and several gas-based industrial projectsare expected to ensue in those states as a consequence. The Bank's GasUtilization study (para. 1.1) addresses issues of domestic gas consumption vis-a-vis exports of piped gas to Thailand and Singapore and LNG to Japan and SouthKorea. This will assist in the establishment of a policy framework, includingpricing mechanisms, for efficient utilization of Malaysia's substantial ge..-resources.

1.5 Malaysia has an immense hydropower potential assessed at 29,000MW (123,000 GWh p.a.). However, only about 13% of the hydro resources exist inPeninsular Malaysia where some 86% of the total populatior. resides and more than90% of the electricity is consumed. Present hydroelectric capacity inPeninsular Malaysia is 1,330 MW (5,100 GWh p.a.). On the other hand, Sarawakwith a population of only 6% has a hydro potential of 20,000 MW (87,000 GWhp.a.) while Sabah's major hydro sites are capable of producing 4,000 MW (20,000GWh p.a.). Harnessing of Sarawak's large and economical hydro potential forserving Peninsular Malaysia is currently uneconomical due to the largetransmission distance involved (760 km), a major portion of which is under-sea(Bank's 1987 sector study, Report No. 6466-MA). It also faces significantenvironmental issues. The development of Sarawak's hydro resources to servePeninsular Malaysia would be a major challenge.

Demand and Consunption Pattern

1.6 Malaysia's commercial energy consumption reached 14.6 MMTOE in1989. In this, the shares of the various sectors were: industrial - 27X,domestic/commercial - 15%, transport - 32% and power - 26%. The shares of thesesectors in the final energy consumption by the year 2000 is expected to be:industrial - 31%, domestic/commercial - 16%, transport - 33% and power -20X.The structure of demand in the residential/commercial sector which in 1989comprised 43% petroleum products anad taditional fuels, 53% electricity and 4Xnatural gas, is expected to chan&e substantially by 2000. This sector will draw36% of its energy from natural gas (LPG) and 38% from electricity, reducing itsdependence on kerosene and traditional fuels to 26%.

Sector Institutions

1.7 Energy planning and implementation are coordinated by a high-level Cabinet Committee or, Energy. The Committee, formed in 1980 and consistingof the Prime Minister, the Deputy Prime Minister, Ministers of Energy, Trade andIndustry, and Science and Technology, is responsible for developing the

-3-

country's long-term energy polict, and approving and supervising theimplementation of energy plans and projects. It is supported by a Committee ofEnergy Officials chaired by the Chief Secretary to the Government and havingrepresentatives from the Treasury, the Economic Planning Unit (EPU), theMinistries of Energy, Science and Technology, Trade and I,austry, the NuclearEnergy unit, the Tenaga National Berhad (TNB), (formerly the NationalElectricity Board, NEB) anid the National Fetroleum Agency (Petronas).

1.8 Petronas, established in 1974 as a wholly-owned governmentcompany, has operating responsibility for the oil and gas sector. Malaysia'sPetroleum Development Act gives it exclusive rights and interests in petroleumin the country. Consequently, it supervises work programs for exploration andproduction, and negotiates production-sharing agreements with contracting oilcompanies. Petronas also has its own exploration activities which areundertaken through a subsidiary company, Petronas Carigali Berhad, formed in1978. In addition, Petronas Gas Sdn. Berhad (PGSB), another subsidiary ofPetronas, was created in 1984 to implement and operate gas utilization projectsin Peninsular Malaysia and Sarawak. Its activities include the construction andoperation of gas processing plants and gas transmission/distribution facilities.

1.9 The responsibility for power sector development and operationlies with the Ministry of Energy, Telecommunications and Posts (MOETP) and thethree power utilities. The MOETP serves as the official channel between theutilities and the Cabinet Committee on Energy. TNB is responsible for powergeneration, transmission and distribution in Peninsular Malaysia, while theSarawak Electricity Corporation (SEC' and the Sabah Electricity Board (SEB) areresponsible for similar functions in the respective states on the island ofBorneo, which lies about 700 km east of Peninsular Malaysia.

Sector Issues and Strategy

1.10 The Malaysian economy is highly dependent on petroleum exportsboth for foreign exchange earnings and for financing of its public expenditures.In 1989, exports of petroleum generated about US$2.7 billion in foreign exchangeand supported more than 24% of all federal expenditures, or 100% of federalcapital spending. Concerned with the need to conserve petroleum and to optimizeutilization of energy resources for the country's development, the GOM'sstrategy calls for: (a) promotion of natural gas usage in all sectors of theeconomy and its export to countries in the region; (b) pricing of gas toencourage its use without wasteful consumption; (c) development of promisinghydropower sites (para. 2.4); (d) introduction of energy conservation measuresin the industrial sector; (d) conservation of electricity in the commercial anddomestic sectors (para. 4.2 (d)); (e) pricing of electricity at or abovelong-run marginal cost and through differential tariff levels encouraging itsuse in the productive industrial and commercial sectors rather than the domesticsector; and (f) an environmentally sound and sustainable development of thepower sector through effective enforcement of the en,vironmental assessment andregulatory processes (paras. 4.19 and 4.20). In the power sector, inparticular, the GOM pursues the policy of ensuring adequate electricity suppliesand a high degree of systen reliability through timely addition of generatingcapacity, and diversification of types of generation and fuel, so as not tojeopardize the country's planned rapid economic expansion due to powershortages. This strategy of GOM is supported by the Bank and is reflected inthe power development plan of TNB (para. 2.4).

4-

Pivatization

1.11 The GOM has an jimbitious program to privatize a number ofgovernment corporations and agencies. The Bank has been working closely with theEconomic Planning Unit (EPU) in reviewing the Master Plan on Privatization,identifying issues and options, defining further necessary steps and suggestingmeasures to assist in the privatization effort. Key objectives of privatizationare to increase efficiency of these enterprises, encourage competition, reducebudgetary burdens and restrain Goverunent involvement. An Inter-DepartmentalPrivatization Committee has been set up under the Prime Minister's Department tooversee implementation of the policy. Technical Committees have beenestablished for various sectors -co coordinate detailed studies, Privatizationhas been completed for several large enterprises (Telecommunications Department,Port Kelang Container Terminal) and is ongoing for the Postal Service.

1.12 The government has decided to privatize TNB by establishing it asa public corporation under the Companies Act and subsequently selling part ofits equity by issuing shares to the public. This would be the largestprivatization in Malaysia and the first privatization of a large integratedpower corporation in developing countries. Privatization alternatives werestudied by a team of consultants coordinated by the Bumiputra Merchant BankersBerhad. The study concluded that TNB should be privatized as an integratedutility (without breaking it up into separate generation, transmission anddistribution entities), but it should contract out services as much as possible.In 1990, a separate report was prepared for the government by another consultinggroup Peninsular Power Sdn Bhd (PPSB) which comprised consultants from Malaysia,UK and USA under the leadership of Morgan Grenfell & Co Limited (UK). Thisreport outlined the steps needed to incorporate TNB as limited public companyand subsequently to obtain stock exchange listing. The report also detailedproposals for regulation of the sector. The first step, the incorporation ofTNB as a wholly government-owned corporation, took place on September 1, 1990and required the resolution of several issues. These included a propervaluation of fixed assets, restructuring the board of directors, transferarrangements for staff of NEB, changes to accounting policies and assumption ofobligations of NEB under existing loans and contracts. Each issue waseffectively resolved enabling the incorporation of TNB. TNB is taking steps tomake an initial issue of shares comprising 750 million shares with a par valueof M$1.0 each. This number of shares will represent 25% of TNB's share capital.The issue will be allotted by ballot with 10% going to the public, 10% toapproved institutions and 5% to employees. Employees may also be able toparticipate in a share options scheme. The amount to be raised will depend onany premium approved by cabinet on the share issue price. Proceeds would beused to provide financing for TNB's large development expenditures. Thegovernment will for the time being retain 75% of the issued shares. The issueis being managed by local bankers, Commerce Internacional Merchant BankersBerhard (CIMB). The main issues decided by cabinet wexc Jhe future gas pricesto be paid by TNB, its eligibility for exemption on import duties and taxes andphased removal over four years of the discounts being provided to industrial andother consumers (para. 5.8). A copy of the draft prospectus and privatizationplan were reviewed by the Bank. The allotment of shares is expected to takeplace by April 1992 and listing on the I la Lumpur Stock Exchange is scheduledfor May 1992. Although the timing is .t, given the government's previousexperience and success with the public listing of shares for the telephone

company, the Bank is satisfied that the arrangements being made will assuresuccessful launching of TNB on the local capital market.

Experience with Past Loans

1.13 The Bank has made twelve loanr to NEB for fin&ncing the expansionof electricity generation and transmission capacity and development of ruralelectrification. The projects urder the first eleven loans have been completedand are operating satisfactorily. The implementation of the Energy Effic' jand Plant Rehabilitation Project (Loan 2772-MA), is about two years behindschedule, partly because of procurement delays and partly because GOM decided ata much later date to procure plant rehabilitation equipment throuAgh a solesource. The project is, however, now well under way and is expected to becompleted by end 1992. When completed, it will contribute substantially towardsimproving the operational efficiency of the power supply system.

1.14 The Project Completion Report for the Rural ElectrificationProject (Loan 2146-MA) noted the impre.._sive fina--cial and institutional progressmade by TNB over the years and pointed aut certain areas such as loss reductionin the transmission system, distribution system planning, and demand sidemanagement, where strengthening was required. These issues are being addressedunder the proposed project. The report also pointed out the need for reducingstaffing in the non-technical cadres (which has been addressed by a freeze onhiring). The main lessons learned from this proJect pointed to the need for:(a) improving coordination of implementation activities; (b) shortening thedecision time for procurement; and (c) making an early start in landacquisitiorn. These lessons have been taken into consideration in the proposedproject. The Bank's participation in the sector has helped TNB develop into atechnically competent and efficient power utility. Further, through itscontinuing dialogue with the sector institutions, the Bank has been inst-.mentalin promoting the use of natural gas and in assuring the overall adequacy oftariffs which has resulted in the power seccor's financial soundness.

Rationale for Bank Participation

1.15 The Bank has a close working relationship with TNB and the EPUand is often approached for advice on sectoral issues. The Bank's sector studyof 1987 (Report 6466-MA) contributed towards development of gas infrastructure(para. 1.4) for power sector's use and the power sector investment review of1989 (para 2.3) assisted in optimizing investment decisions for the powersector. The Gas Utilization sector study (para. 1.4) would set the policyframework for the efficient utilization of Malaysia's natural gas resources fordomestic consumption and export to neighboring countries. Thus, Bank'scontinued involvement with the power and gas sectors would contributesignificantly towards their efficient development. Further, Bank's involvementin the proposed project would lay to the fore environmental issues concerningthe power sector and assist in strengthening the sector's capabilities in thisfield (para. 4.7 (a)). The Bank's advisory role in Malaysia's privatizationprogram and in particular the privatization of TNB would assist in thedevelopment of a sound corporation (paras. 3.12 and 3.18), a workable regulatoryframework (paras. 3.2 to 3.8) and an efficient implementation of theprivatization program including public listing. Finally, the Bank's involvementin financing TNB's investment program would enhance investor confidence at thetime of listing of TNB on the stock exchange.

11. THE POWER SUB-SECTOR

The Power Market

2.1 Past Power Sales. The population of Peninsular Malaysia has beengrowing at about 2.5% p.a. over the last two decades reaching 14.7 millioninhabitants in 1990, Electricity supply, fueled by rapid economic developmentgrew at an average rate of ..bout 11% p.a. during this period, and the growthrate reached a record 14% in 1990. TNB's power sales and per capitaconsumption increased from 2,171 GWh and 247 kWh respectively in 1970 to17,394 GWh and 1,186 kWh in 1990. The industrial sector, gtowing at anaverage rate of 14% p.a., has been increasing its share continuously andaccounted for 48% of the sales in 1990. Commercial (30%), domestic (19%), andmining and lighting (3%) represent the balance. The growth in electricity wasstrong (8%) even during the 1983-86 recessionary period, and the economicrecovery thereafter resulted in increases in power sales averaging 10% p.a.during the last five years. Annex 1 presents che historical growth ofelectricity sales, generation, peak demand, installed capacity, number ofconsumers and number of employees.

2.2 Future Demand. TNB updates annually a sophisticated demand forecastmodel, based on different statistical techniques related to population,industrial and commercial growth and the expected GDP growth forecasted by thegovernment for the Peninsula. The latest load forecast prepared in August1991 is based on GDP projections averaging 7.5% p.a. up to 1995 and 7% p.abetween 1995-2000 and forecasted electricity sales growth rates of 12.1% p.a.between 1991-95 (comp red with 13% between 1989-91), and 9.2% p.a. from 1995to 2000. This is the Base Case forecast used. Annex 2 presents the forecast ofsales by consumer category, which reflects 1991-95 growth rates of 14.0% forthe industrial sector, 10.1% for the commercial sector and 11.1'. for theresidential sector. Annex 3 shows t;'e forecast of TNB's energy sales,generation mix and installed capacity over the 1991-2000 period. TNB's loadforecast reflects the current surge in foreign investments in the country.However, considering recent recessionary trends in key trade partners notablythe USA and the potential competition of- gas, it seemed prudent to analyze theimpact of lower growth rates in the near to medium term, for assessing TNB'sfinancial performance. A Low Case forecast was also used, which results insales growth rates of 10.1% p.a. between 1993-95, and 8.2% p.a. from 1995 to2000. Financial and economic evaluations (paras. 5.18 and 6.2) have been donebasing TNB s investments on its Base Case load forecast, and evaluating theperformance for both the Base Case and the Low Case load forecasts.

Generation and Transmission Capacities

2.3 TNB's installed generating capacity in FY91 was 4,845 MW(allowing for plant derating) comprising: oil-fired steam - 37%, hydro - 26%,

-7-

natural-gas-fired combined cycle - 17%, coal-fired steam - 12% anddistillate/diesel-fired peaking capacity - 7%. With GOM's emphasis on the useof natural gas and exploitation of promising hydro potential, the generationcapacity mix would undergo a major change and by FY2000 the capacity mix wouldbe: gas-fired - 69%, hydro - 22%, oil-fired - 3%, coal-fired - 5% and diesel -

1%. The share of natural gas in energy generation would increase from 24% inFY91 to 69% in FY2000, while the share of oil would change from 44% to 2%,coal from 16% to 20% and hydro from 16% to 9% over the same period (Annex 3).The generation capacity expansion and its fuel mix is shown in Figure 2.1.Annex 4 provides details of TNB's existing installed generating capacity andenergy generating capability, while Annex 5 presents the evolution of TNB'stransmission and distribution facilities over the last 20 years.

TOTAL CUMULATIVE CAPACITY GA,S S 5 lHE I* P ENTAGE ON TOTAL G*

12 0 g 4% |

11 .. t

t ¢ ,~~~~~~~~~~~~~~~~~~~~~~~~~~ S -7

1992 1994 1996 1999 200Q

YEARS

GAS t HfD01 x COAL v ALL OIL

Figure 2.1

lBs Development Program

2.4 Th. Bank has been working closely with TNB in developing itsexpansion program and at Government's request in late 1989 it assisted TNB informulating its power sector investment strategy. The long-term generationexpansion program has been developed by TNB using the WASP least-costgeneraticn development package. The assumptions made wit'i regard to plantcharacteristics and costs, fuel costs and loss of ijad probability are givenin Annex 6. The issue of gas pricing for :he power sector is currently underreview between TNB, Petronas and the government. The gas pricing formula usedin the analysis is based on the Bank's recommendation under the recently

- 8 -

completed sector study (para. 1.1). In line with its policy to promotedevelopment of promising hydro resources (para. 1.10), the GOM has decided toimplement the Pergau hydropower project in FY96 and has obtained its financingunder the British Overseas Development Assistance (ODA) program. Further, inorder to meet TNB's and GOM's concerns regarding the security of gas supplyand inadvisability of relying totally on combined-cycle plants, it was decidedto include some alternative form of thermal power generation (and one whichcould switch-over to heavy fuel oil in the event of gas supply disruption;combined-cycle plants would need to burn costly distillate in this event).Accordingly, TNB included two conventional gas/oil-fired steam generating setsof 500 MW rating in FY96 (300 MW units were found to be less economical). Theleast-cost development plan was started with 7xlOO MW internal combustionturbine sets which were programmed to be brought into service by FY92 (as noother plant could be commissioned in such a short time) to meet theanticipated severe capacity shortage in the system. These sets are alreadyunder manufacture. The ensuing least-cost development plan comprises a mix of300 MW combined-cycle plants and 100 MW internal combustion turbine sets, bothusing natural gas as the fuel.

2.5 Annex 7 gives the plant additions and retirements in the proposeddevelopment plan till FY2000 while Annex 8 presents the system capacity vis-a-vis demand and the reserve margin. Aggregate net generating capacityadditions (including plant rehabilitation and retirement) by type of fuel andplant in the Sixth and Seventh plan periods are summarized in Table 2.1 below:

Table 2.1: Summary OF TNB's GENERATION EXPANSION PROGRAM(Incremental Capacity in MW)

Primary Sixth Plan Seventh PlanFuel (1991-95) (1996-2000)

Hydro 85 1,331

Natural GasCombined-cycle 2,006 2,100Conventional steam 40 790Combustion turbine 836 30

Oil 0 0

Coal 0 0

Total 2,967 4.251

- 9 -

2.6 As a substantial portion of the capacity additions comprisescombined-cycle and internal combustion turbine plants which require lowconstruction lead times, the plan is flexible and would allow TNB to advanceor postpone capacity additions to suit actual demand growth. It would also befeasible for TNB to convert internal combustion turbine plant tocombined-cycle plant should it become necessary to operate the former athigher than its optimum plant factor. In any case, it would be necessary for

TNB to closely monitor its system demand growth and update annually itsgeneration development program.

2.7 Associated with the generation expansion program described above is

the transmission expansion program, summarized in Table 2.2. This program was

developed with the assistance of Westinghouse's Transmission Planning Software(TPS) which creates the least-cost sequence of development under specifiedcriteria. The major portion of transmission expansion is at the 275kV and 132kV voltage levels. A detailed study carried out by consultants in 1988established that the next higher voltage level of 500 kV will not be requiredtill after the turn of the century. However, it would be necessary toperiodically update this study taking into account t.e evolving pattern of

generation and load centers and system security and efficiency considerations.TNB would also need to bring to conclusion the study currently being pursuedby the ASEAN group concerning strengthening of interconnection betweenMalaysia and Thailand. Agreement was reached at negotiations that TNB wouldfurnish to the Bank by June 30 of each year its generation and transmissiondevelopment programs.

Table 2.2: SUMMARY OF TNB'S TRANSMISSION EXPAuNSION PROGRAM(Cumulative)

Year 1990 1991 1992 1993 1994 1995

Transmission lines (circuit-km)275 kV 3,876 4,086 4,906 4,994 5,164 5,364132 kV 5,139 5,252 5,627 6,365 6,492 6,59266 kV 323 259 238 126 126 126

Substations (MVA)275 kV 7,990 8,170 9,130 10,450 11,650 11,650132 kV 9,486 10,311 11,311 13,296 14,964 16,44066 kV 1,264 1,182 1,008 910 910 910

fi. THE BORROWER

3.1 The borrower of the proposed loan would be the Tenaga NasionalBerhad (TNB), the recently incorporated electric utility responsible forgeneration, transmission and distribution on the Malay Peninsula. TNB wouldbe regulated by the Director General of Electricity Supply (DGES) who has beenappointed by the Minister of Energy, Telecommunications and Posts. Thedetailed regulatory arrangements and conditions are contained in a licenseissued for a 21 year term by the DGES with the approval of the Minister. Thelicense may be revoked but only after provision of 10 years notice in writing.

Legal and Regulatory Framework

3.2 Legal Framework. Under the Electricity Supply (Successor Company)Act 1990 (Act 448 assented to August 22, 1990), the fixed assets, rights andliabilities (including those under existing loans from the World Bank) of theformer National Electricity Board (NEB) were transferred to TNB, a whollygovernment-owned, limited liability company, incorporated under Malaysiancompany law. The above-mentioned Act also protected the former employees ofNEB by requiring the new company to offer continued employment to all NEBstaff on terms and conditions no less favorable than those previously providedby NEB. This was important to gain support of NEB employees forincorporation. TNB assumed all obligations under previous Bank loans andother loans, and Government renewed its guarantee for these loans. In theuture, however, TNB is expected to mobilize funds on its own, without GOMguarantees.

3.3 On August 22, 1990, a new Electricity Act (No. 447) 1990 replacedthe Electricity Act of 1949 which was repealed by the aforementionedlegislation. The new legislation provided for the appointment of a regulator,the DGES, and set out the regulator's powers and functions. The mostimportant of the regulator's functions are to issue licenses to electricitysuppliers and to set performance standards. The regulator is also expected torecommend adequate pricing, provide for registration, inspection and standardsof electrical installations. The Minister of Energy remains responsible forfinal approval of electricity prices. Foreign borrowing will continue to besubject to scrutiny and regulation by the Ministry of Finance and the CentralBank. TNB's development program will be reviewed and approved by thegovernment. In the event of a dispute between the regulator and the powerutility, the legislation allows the matter to be referred to the Minister ofEnergy who may set up an enquiry (comprising a chairman and two assessorsappointed by the Minister). Some matters can also be referred to arbitration.Under Section 5.3 of the Act, MOETP can issue regulations relating to a widevariety of other matters.

3.4 TNB's Memorandum and Articles of Association set out its objectivesand establish its authorized capital at three billion shares (M$l each) withone lgcGden share" held by the Minister of Finance. This special shareenables the Minister of Finance to restrict the company from, inter-alia,amending its articles of association, voluntarily winding itself up, disposing

- 11 -

off major assets or disrupting power supply. TNB's main objective is to carryon all its existing activities in connection with electricity supply inPeninsular Malaysia. It is granted specific powers to borrow and invest, andis allowed to engage in a wide range of activities including consulting andadvisory services, research, and plant and machinery manufacturing.

3.5 Under TNB's Articles, the number of Government appointed directorsis limited to six, i.e. from within Government (Minister of Financeappointees) including the chairman, the managing director and a representativefrom each of the Ministries of Finance and MOETP. A third of the directorsare expected to be retired each year (following a three-year term), but can bere-elected. Following incorporation of TNB, the board of directors has beenrestructured from fourteen to eleven members, most of them are new, since onlythree previous members were retained. The chairman and three of the newdirectors are from the private sector which should strengthen the commercialfocus of the company. A new managing director (the former general manager)was appointed from within the company but has recently retired. A newappointment is expected to be announced early in 1992. The articles alsopermit the company to pay dividends from profits if approved at a generalmeeting of the company. Audited financial statements are required to beissued within six months of the close of the financial year. The Board isempowered to appoint general managers to the company and fix theirremuneration.

Regulatory Arrangements

3.6 The DGES issued TNB a license to operate as an electricity supplieron September 1, 1990. The Bank reviewed and commented on the conditions ofthe license especially a complex pricing formula, which would have peggedelectricity prices on a consumer price index (CPI). Tariff increases wouldhave been approved within the limits of the CPI minus a factor, which wouldinduce TNB to seek higher efficiency. An automatic fuel cost mechanism (alsosubject to adjustment) to ensure part of any savings from increased fuelefficiency was shared with consumers is proposed to be incorporated as part ofthe pricing formula. The pricing formula has not been finalized, butconsultants are preparing final recommendations, which will be furnished tothe Bank for its review and comment by May 1992.

Organization and Management

3.7 Central Organization. Following its incorporation as a publiccompany, TNB's organization and management have been restructured. The neworganization is satisfactory, and is expected to foster the delegation ofauthority and entrepreneurship. TNB central management (see Chart 1) includesa Managing Director and seven divisions. Each division is headed by a generalmanager - Business Development, Finance, Operations, Customer Services, MajorProjects, Corporate Services and Human Resources. The financial function hasbeen given prominence and includes separate divisions for cost/managementaccounting, treasury management, investments, taxation and budgeting. Theformer administration department was split into corporate services(information, procurement and management services) and human resources

- 12 -

(personnel, training and industrial relations). The internal audit groupwhich previously reported to the general manager will now report to the Board.The general managers are responsible for appointing their respective staff.Overall, thege changes will strengthen TNB, encourage the adoption of a morecommercial approach and facilitate its privatization.

3.8 Field £Qfigeg. TNB's field activities are organized into sixregional operations, which are subdivided into district offices and stations;the regions are identifihl as Northern, Perak, Selangor, Southern, Eastern andFederal Territory. Some of the responsibilities of the district officesinclude billing and collections, erection and maintenance of distributionlines, and operation and maintenance of diesel and mini-hydro plants withinthe district. Station offices are generally units which operate and maintainparticular generating facilities or substations, or provide special servicesto a particular local area. All remaining operational functions, includingload dispatch, are centralized and housed at the main office in Kuala Lumpur.Separate from its utility operations, TNB has small subsidiary companies whichmanufacture transformers and cables primarily for its own needs. These arenow responsible to the General Manager, Business Development.

3.9 Management. TNB'sBoard and management are now TNB S POWEP LOSSES C INCL PLANT LUSE)targeting to introduce more X -GEERTD WT O)

decentralization, business- 24%

like decision making, andenhanced efficiency andprofitability. Since there is - - -

a change in emphasis vis-a-visprevious practices, special 12-

training (to encourage a more -_

commercial approach) would be 9 ………_

provided at all levels. Under _…_

the new organization '. _-structure, the general 2…=

managers will have …, ism I -…- , 95 X . 2010

considerable autonomy overtheir respective departments,and are expected to encourage Figure 3.1decentralization anddelegation of authority. Inorder to further decentralize the decision-making process it is necessary toimprove its management information systems. A Distributed Source DataGeneration System has been completed and a Consumer Information and BillingSystem, when completed in 1992, will allow information exchange on revenuesbetween districts, station offices and the head office. Even more importantchanges are needed to strengthen the financial management. This would beachieved by the establishment of a fully integrated on-line FinancialManagement Information and Reporting System (FMIS) which will be implementedas part of the project (paras. 3.16 & 4.7 (b)). FMIS would provide financialand budgeting information to managers at all levels, thereby enabling them tobe held accountable for their respective costs and performance. TNB has beenable to reduce considerably its power losses, but an important management

- 13 -

objective should be to further reduce them, with the target to reduce totallosses (inclueing plant use) from 15.8% in 1990 to 13% by 1996 (Figure 3.1).

3.10 Under the previous Bank project (Loan 2772-MA, 1987), technicalassistance was provided to NEB's Management Services and Development (nowBusiness Development) department to strengthen its role as an in-houseconsultant on systems, procedures and organizational matters. It has beenresponsible for the preparation of an Information Systems Strategic Plan whichprovides an overall plan for greater integration of computerized systemsdevelopment over the next five years. Development of the priority systems inthis plan will also provide information to managers for more effectivedecision making and accelerate the development of a com-nercial environment atTNB. A Steering Committee has been set up to support the incorporation andthe privatization of the company, and the establishment of a Total QualityManagement Program (TQM) which has been included as part of the Project.Assistance would be provided by an overseas electric utility & ,erienced inTQM.

3.11 Staffing and Training. TNB on incorporation had a staffestablishment of 23,108 persons, which due to continuous efforts to increaseits efficiency is 8% lower than in 1985. The number of connections peremployee increased from 80 in 1984 to 126 in 1990. The relative efficiency ofpower utilities in this regard cannot be judged without qualification, becauseit is dependent on several factors such as: (a) the extent of the transmissionand distribution network (which is lower in high-density countries like Korea,Taiwan and Japan); (b) the level of investment in automation and equipmentredundancy; and (c) the historical background of the utility and the cultureof the country. Figure 3.2 compares the performance of TNB with otherutilities in the region and is indicative of the potential scope forimprovement. TNB expects to achieve improvement in this regard throughprivatization.

3.12 TNB'sobjective is to continue CONNECTIONS PEP EMPLOYEEto reduce its currentstaff level consistent 450

with the need to run its 400 - JAP. 4-5 O

system efficiently.Since the legislation - - - -

establishing TNB 300 _

provides job security to - - - - - - -

all staff for five years 0

after incorporation, TNB I 2 APRE 82

initially expects to iso - - - -_achieve staff reduction -00 -…… -

by continuing a I

moratorium on hiring 5 _ [(the natural attrition 0 1934 1' X 1990 19S'2 1994 1995 1998 200

rate is about 1.2% per YEASS

year). TNB also expects O T OERA

to lose some staff tothe private sector which Figure 3.2offers better

- 14 -

remuneration. It also proposes to minimize the need for additional staffthrough more extensive contracting out of services as is partially being donefor construction, maintenance, security, office cleaning, meter reading andbilling.

3.13 In termsof energy sale per ENERGY SOLD PER PERSONemployee, TNB is eNE%W SoX AeR INA61 TANT & eOG STAFP

reasonably efficient as 60 ssnown in Figure 3.3. 6 45More advanced countries 5 0 … _

have better performancefigu:res because of 4 0_

larger generating Ifacilities and higher 3 0per capita electricityuse (Figure 3.3). _0

3.14 TNB has beenovercoming, through LO,=i-b8t Ot 21 9} olovercoming, through 00 ~~1994 isb 1998 1880 1992 1984 1.996 1999 2000

training and multi-skilling, the shortage a T. Mh/PERSN O T. GSTASF a OTR PERSN

of professional andtechnician level staff Figure 3.3(93% of all staff aresemi-skilled orunskilled workers). Most of the 1,333 persons responsible for management andadministration are engineers. In 1982, NEB constructed an outstandingtraining institute capable of accommodating about 800 participants. This isstill one of the largest institutes of its kind in developing countries. Itoriginally focused on all phases of utility operations particularly tradestraining but is now more oriented towards technical, supervisory managementand commercial training. Currently about 5,000 staff receive training of somekind at the institute each year. The average period of attendance is about1.5 weeks. It has recently installed a state-of-the-art 300 MW power plantsimulator (under Bank Loan 2438-MA) and plans to instal a larger simulator forthe 500 MW units. Many of the newer courses at the center are linked tocareer development and successful completion of a course is a prerequisite forpromotion. Following incorporation, TNB is establishing training programssupporting a commercial approach, particularly for customer services. In thelonger term, TNB intends to operate the institute as a separate business unitand offer courses to external students and lease facilities to otherorganizations wishing to conduct their own training. Already, the institutehas sought accreditation of some of its courses by the Malaysian Institute ofEngineers and is seeking to arrange university level courses with a UKuniversity. Students would complete later year training at the UKinstitution. In parallel with the institute's programs, TNB has a program ofoverseas training for its staff. The facilities and arrangements for trainingare fully satisfactory.

-15 -

Financial Management

3.15 Accounting and Budgeting. Financial functions at TNB have beenupgraded to divisional status and the former chief accountant has become oneof the new general managers in recognition of the enhanced role of financialmanagement under incorporation. The old accounts section has been reorganizedas six departments; financial accounting, budgets, cost/management accounting,taxation, treasury management, and funds investment. The increased emphasison cost accounting in particular reflects its importance in providing timelyinformation to managers at all levels to control costs of each business unitright down to each power plant, transmission substation and distributiondistrict. Also, est.^.blishing a treasury management function duly reflects theneed for well informed and highly skilled foreign exchange risk managementpersonnel to minimize losses on foreign borrowing.

3.16 Data processing which was formerly under the chief accountant isnow managed by the corporate services division. This change is appropriatesince systems development for all divisions is not a financial function.However, all user divisions will be involved in cystems development underTNB's information systems strategic plan. Most of the key accountingfunctions are computerized and financial data is being transmitted from fieldoffices as a result of previous Bank assistance. However, since the systemsoperate in batch mode, and are not fully integrated, financial and managementinformation is often not able to be produced in a timely manner formanagement. A new costing and general ledger system is required to provide anintegrated on-line financial information and reporting system, to providetimely reports required by managers. The proposed project would provideconsultants to revise the present chart of accounts, determine the systemhardware and software requirements, and propose an implementation plan for anew financial management information system. The diagnosis and planning stageis expected to take one year and implementation of the new system, anadditional year. The scope and terms of reference for consultants for thefinancial management information system study 'have been reviewed with the Bank(Annex 9).

3.17 Audit. Audit of the annual financial statements of NEB was theresponsibility of Malaysia's Auditor General under the Audit Act 1957. Inpractice, the Auditor General commissioned the audit of the accounts toprivate auditors (Price Waterhouse). Under current loan covenants, NEB was toprovide unaudited accounts to the Bank within six months of the end of thefiscal year and audited accounts within nine months. However, the auditreports have been received late. mainly because of delays at the AuditorGeneral's office. Under TNB's articles of association and the stock exchangerequirements for publicly listed companies, audited accounts are required tobe submitted within six months of the end the fiscal year. Auditors will nowbe selected by TNB's board of directors. Agreement was reached with TNB atnegotiations that within six months of the end of its fiscal year (i.e. by28th February of each year), it will send to the Bank an audit report on itsannual financial statements and on the project expenditures, as prepared byindependent auditors acceptable to the Bank.

- 16 -

3.18 Taxes and Dividends. Prior to incorporation, NEB was exempt frompaying income tax (at least until 1987), development tax and customs duties.Following incorporation, TNB is now liable for sales, fuel, custom duties andproperty taxes which would initially create a heavy burden for its financialplan (para. 5.10). TNB has been paying corporate income tax (35% of taxableincome) and a 3% development tax (which will be phased out over three years).Its liability for income taxes for fiscal years 1987-90 is still under reviewand is affected by issues relating to returns it has filed dating back to1972. Resolution of TNB's taxation liability was not an issue for itsincorporation and would be resolved prior to its listing on the stockexchange. TNB will be expected to pay dividends out of profits on its issuedshare capital. Its practice so far has been to pay dividends not exceeding 6%of its paid-in capital, this is expected to continue after its privatization,but taking into account the market value of shares.

3.19 Insurance. TNB is expected to maintain commercial insurancecoverage against major risks similar to that held by NEB. Agreement wasreached with TNB at negotiations that it would continue to maintain adequateinsurance and will undertake annual reviews of its insurance program to ensurethat coverage is adequate.

IV. THE PROJECT

Project Objectives

4,1 The upsurge in economic activity in the late 1980s has resulted inmuch higher than expected electricity demands in 1990 and 1991. Baso-d oncontinued robust GDP growth expectations in the medium-term, the demand forelectricity is projected to increase from a level of 3,440 MW and 20.7 TWh in1990 to 5,898 MW and 34.1 TWh by 1995. The current generating capacity wouldbarely suffice to meet demand and the system would operate with unacceptablemargins of safety in FY91 and FY92 till substantial base and peakinggenerating capacity is added from FY92 onwards. Commensurate expansions ofthe system's transmission and distribution capacities would be required toensure stable, reliable and efficient operation of the system. The proposedproject has the following main objectives:

(a) meet the growth in power demand over the medium-term at least costconsistent with GOM's policy of diversification of types of generationand fuel to enhance supply reliability, with emphasis on the use ofindigenous resources;

(b) support TNB's privatization by promoting an adequate regulatoryframework, improving the management and the financial managementcapabilities of TNB and ensuring TNB's sound financial performance; and

(c) strengthen TNB's capabilities in environmental monitoring and evaluationthrough the creation of an adequately staffed environmental unit,provision of technical assistance to its staff, and acquisition ofenvironmental monitoring equipment (para. 4.7 (a)).

Project Description

4.2 The project constitutes an important part of TNB's investmentprogram over FY92-93 and comprises the following specific components:

(a) Generation Expansion. Installation of a 300 MW combined-cycle powerblock at the existing Paka power station;

(b) Transmission Expansion. Construction of 275 kV, 236 km long, double-circuit transmission line from Kampung Awah to Yong Peng;

(c) Strengthening Supplv to Kuala Lumpur. Establishment of an indoor gas-insulated (GIS), 275/132 kV substation at Pudu Ulu with 2x250 MVA,275/132kV auto-transformers; expanding the existing Jalan Gallowaysubstation with 2x500 MVA, 275/132kV auto-transformers; andinterconnecting the two stations through 2x500 MVA, 275 kV, 4.5 km longunderground cable circuits; and

(d) Consulting Services. Consulting services for: (i) engineering, designand construction supervision of the Paka power station; ('i) financial

- 18 -

management information system; (iii) total quality management program;and (iv) demand-side management and electricity conservation study.

(e) Environmental Strengthening. Technical assistance to environmental unitstaff and procurement of environmental monitoring equipment.

4.3 The above components have been appraised and found to be acceptablefor Bank funding and are briefly discussed below.

Project Components

4.4 Expansion of the Paka Thermal Power Station. The Paka powerstation is built in the state of Terengganu on the east coast, wherePeninsular Malaysia's major offshore associated natural gas fields arelocated. The station is only about 6 km from the onshore natural gasprocessing plant of Petronas at Kerteh and is currently the only power stationof TNB using natural gas in 3x300 MW combined-cycle power blocks. The sitecan comfortably accommodate up to three additional 300 MW combined-cycleblocks. The proposed project would comprise addition of a fifth 300 MWcombirned-cycle block (in the configuration of 2xlO0 MW gas turbines, lxlOO MWsteam turbine and two heat recovery boilers), the fourth block being installedunder a different project. About 48 hours of distillate oil storage capacitywould be provided to tide over outages of gas supply. Comparative economicsite selection studies (taking into consideration fuel and transmission costs)made by TNB have shown Paka to be ranked third by a small margin behind PasirGudang and Port Klang which are nearer the load centers. However, due to theundesirability I concentrating generation at only two power stations fromstrategic considerations, expansion of Paka is being implemented alongsidewith capacity additions at Port Klang and Pasir Gudang. An EnvironmentalImpact Assessment (EIA) carried out by TNB's consultants, University ofMalaysia has found the expansion of Paka by 3x300 MW to be environmentallyacceptable (para. 4.22).

4.5 Transmission Expansion. Based on transient stability studiescarried out by TNB using the WESTCAT simulation program, it has beenestablished that the 275 kV Kanjung Awah-Yong Peng line is required to allowtransmission of full generation from the eastern stations of Paka, Kenyr andPergau to the load centers in the west and the south. The alternative to thisline would be reinforcement of the existing 275 kV lines between Kanjung Awahand Kuala Lumpur (Center-East) and between Serdang and Yong Peng (West-South),which is not only more expensive but has lower transmission security.

4.6 Strengthening Supply to Kuala Lumpur. The 275 kV Pudu Ulu/JalanGalloway expansion is necessary to upgrade the existing 132 kV system betweenthose stations for meeting the rapidly increasing demand growth in KualaLumpur city. This is the least-cost alternative that is environmentallyacceptable. Use of 275 kV instead of 132 kV cable circuits would causeminimum disturbance to the city roads during construction, while indoor GIS(gas-insulated) substation design would be aesthetically more attractive thanlarge outdoor substations within the city area. The project thus poses noenvironmental impacts of consequence.

- 19

4.7 Institutional Development. The project includes institutionalstrengthening of TNB in several key areas. Agreement was reached with TNB atnegotiations that consultants, under Terms of Reference acceptable to the Bankwoula complete by December 31, 1994 the studies (b), (c) and (d) explainedbelow.

(a) Strengthening TNB's Environmental CaRability. As advised by the Bank,TNB established in October 1991 an Environmental Unit with a core groupof six persons. TNB would now implement the following measures: (a)prepare an organizational environmental policy and objectives statementand get it approved by its Board; (b) develop environmental impactassessment (EIA) and environmental auditing procedures; (c) devise andimplement an environmental training program; and (d) engage expertassistance on rain acidity to analyze available data and providerecommendations for further work. Agreement was reached at negotiationsthat TNB would maintain the Environmental Unit with staff, resources andresponsibilities satisfactory to the Bank, and implement measures tostrengthen the capabilities of the Environmental Unit, in accordancewl8h a program satisfactory to the Bank.

(b) Financial Management Information System. TNB would engage consultantsto develop systems to upgrade TNB financial management information andenable more timely provision of reports to management as required by aprivate corporation. The system will inter alia provide on-line costingand financial information, improve corporate planning and provide theinformation required for tariffs and regulatory purposes (Terms ofReference are shown in Annex 9, Part A);

(c) Total Ouality Management Program. TNB would engage consultants,preferably an overseas utility, to assist it in developing methods andsystems to improve the efficiency and productivity of TNB's organizationand facilitate change in the corporate culture (Terms of Reference areshown in Annex 9, Part B); and

(d) Demand-Side Management and Electricity Conservation. TNB would engageconsultants to undertake a study to analyze ways to improve TNB's demandmanagement and promote energy conservation (Terms of reference are shownin Annex 9, Part C).

Cost Estimates

4.8 TNB's total capital expenditures for the period 1990 to 2000 areshown in Annex 10 and its overall financing plan is shown in Table 5.2. Theproject cost of M$1,082 million (USS401 million), includes a foreign componentof US$244 million, 61% of the total. Taxes and duties are M$151 million(US$55.9 million). The base cost is expressed in August 1991 prices. Theproject cost is summarized in Table 4.1 and details are shown in Annex 11.Physical contingencies have been applied to all items at 10% of base cost.Price contingencies are 9.8% of the base cost plus the physical contingenciesand are estimated using (a) an escalation factor of 3.6% p.a. for the foreign

- 20 -

cost component; and (b) escalation factors of 3.5% p.a for 1991 and 4% p.a.thereafter for the local cost component.

Table 4.1: Summary of Project Cost

M$ (millionn) USS (millions) Fx as X

Local Foreign Total Local Foreign Total of total

Paka combined-cycle plant 98,0 399.3 497.3 36,3 147.9 184.2 80.3

275 kv transmission line 75.9 25.4 101.3 28.1 9.4 37.5 25.1

275 kv system for K. L. 51.3 86.1 137.4 19.0 31.9 50.9 62.7

Consulting servicesPaka Power Station 2.7 16.2 18.9 1.0 6.0 7.0 85.7

Financial Management 0.5 4.9 5.4 0.2 1,8 2.0 90.0

Quality Menagement 1.4 3.2 4.6 0.5 1.2 1.7 70.6

Pemand-side Management 0.3 1.3 1.6 0.1 0.5 0.6 83.3

Environment TA 0.5 1.6 2.1 0.2 0.6 0.8 75.0

Duties and Taxes 126.9 0.0 126.9 47.0 0.0 47.0 0.0

Base Cost (In August 1991 Prices) 357.5 538.0 895,5 132.4 199.3 331,7 60.

Physical contingencies 35.7 53.8 89,5 13.2 19.9 33.1 60.1

Price contingencies 30.2 66.7 96.9 11.2 24.7 35.9 68.8

Total Prolect Cost 423.4 658.5 1081.9 156.8 243.9 400.7 60.9

Interest during construction 0,0 77.2 77.2 0.0 28.6 28.6 100.0

Total Financing Recruired 423.4 735.7 1159.1 156,8 272.5 429,3 63.5

Financing Plan

4.9 The proposed financing plan for the project includes a Bank loan ofUS$200 million financing about 82% of the foreign component. The Bank loanwould finance about 50% of the total project cost and 46.6% (53.6% excludingtaxes of $55.9 million) of the total financing requirements of US$429.3million, including interest during construction. The remaining US$229.3million (53.4%) will be financed by TNB's internal cash generation.

Project Implementation

4.10 As in previous projects, TNB will be fully responsible for theimplementation of its investment program. At the head office, implementationof all project components will be under the overall charge of the GeneralManager for Major Projects. The respective Assistant General Managers will beresponsible for the thermal, transmission, environmental and institutionalcomponents of the project. TNB will engage the services of well-qualifiedconsulting firms for design, procurement and construction supervision of theproject, except internal combustion turbine installations which would, ingeneral, be engineered in-house. Site offices headed by an experiencedResident Engineer from TNB and staffed with qualified TNB personnel will beorganized for all generation projects. In general, the generation projectswill be contracted out on a semi-turnkey basis with limited packaging, toachieve faster construction times and better contract coordination. TNB hasadequate experience in the operation and maintenance of combined-cycle andinternal combustion turbine plants and will arrange for training of designatedstaff during construction with the contractors and the consulting firms, in

- 21 -

its existing power plants and on the training simulators installed at itstraining center. Later on, when the first 500 MW conventional thermal powerplants are under construction, TNB will send some of its personnel overseasfor training in operation and maintenance on similar large units. Thetransmission system projects will be engineered in-house and will beconstructed on a fully turnkey basis as per TNB's current practice. Land forthe expansion of Paka power station and the Pudu Ulu and Jalan Gallowaysubstations is already available. Right-of-way for the Kampung Awah-Yong Pengtransmission line will have to be acquired; preliminary route reconnaissancehas established that there would be no difficulty in this acquisition. Theimplementation arrangements are considered to be sound and would result intimely implementation of the investment program. However, this would requirea substantial improvement and streamlining oi the procurement functions, whichafter its incorporation would be properly delegated within TNB.

4.11 Chart 2 gives the project implementation schedule and milestonesfor key activities. The consultants for the Paka pover station are expectedto be appointed in early 1992 i.nd the main plant contract is scheduled to beawarded in November 1992. The gas turbines would be in operation by December1993, while the combined-cycle plant (with the steam turbines) would beoperational by September 1994. Contract for the Kampung Awah - Yong Pengtransmission line has already been awarded. The line is scheduled to becommissioned by June 1993. Bies for the power supply system for Kuala Lumpurare expected to be progressively invited during 1992 and the system isexpected'to be commissioned by the middle of 1994. Satisfactory proceduresfor reports on the physical implementation of the project components andadditional financial reports (para. 5.19) have been agreed with TNB, whichwill furnish semi-annual reports. The project will be completed by June 30,1997. Parts I and III of the Project Compi,.don Report (PCR) will be draftedby the Bank not lacer than six months afte: completion of the project. TNBwill review Parts I and III and prepare Part. II of the PCR within three monthsthereafter.

Supervision Plan

4.12 Supervision of this project will be undertaken along with theBank's ongoing projects in Malaysia. The key ssues that would be focusedupon are: (a) periodic reviews of TNB's power dlu'relopment plan in keeping withchanges in the economic s.'enario; (b) support svr the privatization of TNB;(c) monitoring of compliance with financial covenants to assure the financialhealth of TNB while undertaking a large investment program; (d) closemonitoring of the various consultancy studies for strengthening INB'sorganization; (e) monitoring of the implementation of the environmental impactmitigation plans for the Paka project; (f) adequate technical supervision forthe Paka power and transmission expansion projects; and (g) active follow upon procurement decisions. Bank missions would particularly assist TNB and thegovernment in their efforts towards privatization and energy conservation andprovide advice on environmental issues. Supervision of the project wouldrequire expertise in power engineering, economic and financial analysi. andenvironmental engineering. Two missions annually for a period of four yearsare foreseen for adequate supervision of this project. The total estimatedstaff inputs are: (a) power engineer, economist and financial analyst -- 20

- 22 -

staff-weeks (on the basis of sharing with other projects in Malaysia); and (b)environmental specialist -- 8 staff-weeks.

Procurement

4.13 All contracts for materials or for supply and erection of equipmentfinanced by the Bank with an estimated cost of US$200,000 equivalent or morewould be awarded on the basis of International Competitive Bidding (ICB) inaccordance with the Bank's procuremcat guidelines. Contracts for materials orfor supply and erection of equipment expected to cost less than US$200,000equivalent may be procured under Local Competitive Bidding (LCB) procedureswhich are acceptable to the Bank. Local suppliers and contractors areexpected to be competitive for such contracts. Contracts expected to costless than US$200,000 equivalent and not exceeding in the aggregate US$2million equivalent may be awarded following Local or International Shopping.Specialized equipment such as environmental monitoring instruments and controlequipment and items of proprietary nature, not exceeding US$2 millionequivalent in the aggregate, may be procured directly from suppliers. TNBwill furnish in advance lists of proprietary items to be procured directly forreview and approval by the Bank.

4.14 Procurement following ICB procedures is expected to aggregate toabout 90% of the loan amount. In the evaluation of bids obtained followingICB procedures, domestic price preference would be applicable for specificcomponents as approved by the Bank. A margin of preference equal to 15% ofthe CIF bid price of imported goods or the actual customs duties and importtaxes, whichever is less, will be allowed for domestic manufactures. PriorBank review of bid documents and approval of contract awards would bemandatory for all contracts expected to cost the equivalent of US$2 million ormore. This would cover over 80% of total contract value. Contracts for thespecific components of the project (para. 4.4) that would be financed out ofthe Bank loan would be: (a) Paka -- one main contract for supply andinstallation of the entire power plant and about three contracts for ancillaryworks and equipment; (b) Kampung Awah-Yong Peng transmission line -- onemajor contract for the supply and installation of the line (conductors for theline would be reserved for local procurement and will not be financed by theBank); (c) Power supply for Kuala Lumpur -- one contract for supply andinstallation of substations including switchgear, one contract for supply andinstallation of transformers and one contract for supply and installation ofcable circuits; and (d) Specialized equipment including environmentalmonitoring equipment -- about three contracts.

4.15 Consulting service for engineering, debign and supervision of thePaka power station would be procured by TNB following invitation of bids fromreputed foreign consultants, in consultation with the Bank. The followingconsulting services would be engaged by TNB either following negotiations witha suitable fi-i.1 or inviting proposals from short-listed firms: (a) FinancialManagement Information System - US$2.5 million (90 foreign and 75 localperson-months, respectively); (b) Total Quality Management Program - US$2.1million (90 foreign and 35 local person-months, respectively); (e)Environmental strengthening US$0.8 million (30 foreign and 35 local person-months respectively); and (f) for demand-side management and electricity

- 23 -

conservation - US$0.6 million (25 foreign and 20 local person-months,respectively). The Bank would not be financing any of the consultingservices.

4.16 Table 4.3 summarizes the procurement arrangements and amountsexpected to be financed by the Bank loan.

Table 4.3 Procurement Arrangements(US$ Million)

Project Component Procurement Method

ICB LCB Others /a NA /b Total

Combine-cycle Power Plant 192.8 19.2 8.0 45.6 265.6(144.0) (2.0) (4.0) (150.0)

275 Kv Transmission Line 24.3 17.2 12.4 53.9(10.0) (10.0)

275 Kv Substations 24.7 0.7 4.5 29.9(18.0) (18.0)

275 Kv Cable Feeder 31.9 5.5 37.4(22.0) (22.0

Consulting Services 13.9 13.9

Total 273.7 37.1 21.9 68.0 400.7(194.0) (2.0) (4.0) (0.0) (200.0)

Note: Figures in parenthesis indicate financing from the Bank loan./a Refers to procurement through international and local shopping, direct procurement and consultant

services.lb Refers to duties and taxes, engineering and administrative overheads

Disbursemnts

4.17 The Bank loan would be disbursed against (a) 100% of the foreignexpenditures of directly imported equipment and materials; (b) 100% of thelocal expenditures (ex-factory) of locally manufactured items procured throughICB; (c) 70% of local expenditures for works related to procurement under ICB;and (d) 100% of expenditures for consulting services. TNB does not wish tofollow Statement of Expenditure procedures or avail of Special Accountfacility. This is acceptable as the number of contracts would be small andthe value of each contract relatively large. Annex 12 gives the disbursementschedule for the proposed Bank loan. This is generally in line with thestandard disbursement profile for Bank's power projects in Asia.

4.18 Retroactive financing would be permitted to the extent of US$5.0million equivalent, for payments made prior to the date of loan agreement, butafter December 1, 1991. The closing date of the loan would be December 31, 1997.

- 24 -

Environment

4.19 The Regulatory Framework. Government of Malaysia is lXilly committedto the protection of the environment and has adopted the eight principles ofsustainable development recommended by the World Commission. It is in theprocess of drafting a national policy document on sustainable development.The basis of the environmental legislation in Malaysia is the EnvironmentalQuality Act (1974). This act established the Environmental Quality Counciland created the Department of Environment (DOE) headed by the Director Generalof Environmental Quality. The Environmental Council is an advisory body whichadvises the Minister of the Environment, currently the Minister of Science,Technology and the Environment. The DOE is responsible for developingenvironmental policies, strategies and regulation, disseminating environmentalinformation and promoting international and regional cooperation inenvironmental matters. It is also responsible for environmental qualitymonitoring and publishes annually an environmental quality report. It has anadequate staff of 300 persons of which 80 are graduate professionals.Activities which potentially have significant environmental impacts areclassified as "prescribed activities" and the proponent of any such activityis required to furnish an Environmental Impact Assessment (EIA) to the DOE forapproval. DOE's approval is mandatory prior to the issue of a license (whichis normally issued by the state authority). Almost all significant expansionactivities of TNB come under the classification of "prescribed activities" andthus require preparation of an EIA and its clearance by the DOE. EIAs arereviewed by the EIA Technical Committee within the DOE and when necessary AdHoc Expert Committees are formed of local and overseas experts for review ofcomplex issues. The working of the environmental regulatory framework and inparticular the process of review and clearance of EIAs is satisfactory to theBank and would ensure that TNB's investment program is carried out in anenvironmentally acceptable manner.

4.20 Environmental Standards. Malaysia has in force atmospheric emissionstandards for: (a) intensity of smoke; (b) solid particles; (c) metals such aslead, arsenic, antimony and mercury, and their compounds; and (d) fluorine andinorganic fluorine compounds. There are no emission standards. in force forfuel burning equipment for the oxides of nitrogen and sulfur; howeverrecommended Malaysian guidelines in respect of N02 and S02 levels have beenpublished and are applied by the DOE in practice. The noise emissionstandards currently formulated relate to occupational exposure only and WHOstandards are used as guidelines for various other noise classifications.Ambient air and water quality requirements are expressed in the form ofguidelines which have still to be formalized. However, these guidelines arefairly stringent and are followed in the assessment of environmental impacts.

4.21 Environmental Assessment of TNB's Projects. TNB's power systemdevelopment plan over the 1991-1996 period includes the following generationprojects: (a) peaking gas turbine plant expansion at the existing ConnoughtBridge power station; (b) gas-fuelled combined-cycle power plant extensions atthe existing Pasir Gudang and Paka power stations; (c) gas/oil firedconventional steam thermal power plant expansion at the existing Port Klangpower station; and (d) the Pergau hydroelectric power station. EIA's of allthese power station projects are in an advanced stage of completion by

- 25 -

consultants engaged by TNB and would be cleared with the DOE before commencingconstruction. In the course of assisting in the preparation of the EIA forPaka power station extension which would be financed from the proposed Bankloan, the Bank has been following closely the preparation of EIA's for theother projects. This work is being handled with adequate professionalcompetence which would ensure that these projects would be constructed in anenvironmentally acceptable manner. The Pergau hydroelectric project (financedby the British Overseas Development Association) involves no resettlement.

4.22 Environmental Assessment for the Paka Power Station. The EIA forexpansion of Paka by 3x300 MW combined-cycls blocks has been reviewed indetail; its summary is presented in Annex L3. and the predicted environmentalimpacts are compared with DOE and IBRD guidelines in Table 1 of Annex 13. Thepredicted atmospheric ambient levels of NO2, SO2 and dust would be well withinthe DOE and the Bank guidelines, and the total emissions of these pollutantswould also be w3thin these guidelines. Effluent emissions from the powerstation would comply with the DOE's requirements. Oil, an importantcontaminant in the power plant effluent, would be removed by passing theeffluent through separators and a suitable treatment plant prior to discharge.The temperature of the cooling water at its hottest point would be within DOErequirement of 40°C, the maximum temperature rise within the plume would beless than 50C and the temperature rise would be less than 10C within adistance of 300 meters. The expansion would not pose any unacceptable impactson the beach or on the aquatic environment. The noise level in the vicinityof the gas turbine plant would exceed WHO guidelines, which is usual for suchplants. Engineering studies would be undertaken to reduce noise levels fromthe rotating machinery to the extent feasible, and, in addition, specialrequirements would be stipulated for the safety of workers including wearingof protective mufflers. The current TNB's staff housing colony within theplant boundary would be relocated to comply with noise specifications. TheEIA has been approved by the DOE which has stipulated a set of 20 conditions.TNB would be complying with these conditions. Socio-economic surveysundertaken during EIA preparation have shown that the majority of the localpopulation is generally in favor of the expansion of the Paka Power Station.The EIA and the mitigation measures proposed are satisfactory to the Bank.

4.23 Environmental Assessment of the KamRung Awah - Yong PengTransmission Line. Being a major 275 kV line, an Initial EnvironmentalExamination (IEE) was carried out by TNB. This showed that certain sectionsof the proposed line route would come close to the Tasek Bera wetland area.The Bank requested TNB to have an Environmental Impact Assessment (EIA) of theline route in the Tasek Bera area done by a NGO organization (Asia WetlandBureau (AWB)). This EIA has been completed by AWB, which has suggested analternative line route in this area. AWB's suggestion has be ccepted by TNBand the Bank is satisfied that the line would be constructed it. anenvironmentally acceptable manner.

- 26 -

V. FINANCE

Past and Current Financial Perfornance

5.1 In September 1990 the National Electricity Board (NEB) wasformally incorporated and renamed Tenaga Nasional Berhad (TNB) as a first steptowards its privatization. NEB was a well-managed and forward-lookingorganization. With the exception of minimal government contribution to itsrural electrification program, it has not received grants or subsidies. Inline with private enterprises, NEB has paid income taxes and dividends to thegovernment since 1986. NEB has had considerable autonomy in planning itsbudget and investments, mobilizing loans and meeting its expenses and debtservice. In preparation for its privatization (para. 1.12) TNB Board ofDirectors has been given more autonomy with corresponding accountability forresults to the regulatory authority vested in the DGES.

5.2 TNB's past andcurrent financial performances INCREASES IN GDP DEFLATOR AND CPI

have been fully satisfactory -

under any financial criteria(Table 5.1). This is a resultof: (a) a very stable 3,

macroeconomic environment, with Ereal increases between 1980-89 - ……I

of 62X (7.6% in 1990) in theoverall GDP and 83% (8.8% in1990) in the manufacturing GDP;(b) minimum inflation (Figure5.1), with a cumulativeincrease in consumer prices "

between 1985-89 of just 6.5%; , 1g 'G. iges 'W logo i. 2 le" 1X96 . g

(c) very large increases in D GM O0 COSUME P

electricity sales, averaging ___

11% p.a. during 1987-90 and Figure 5.113.2% between 1989-91; (d)adequate tariffs, that were not reduced after being raised in 1985, when oilprices peaked; (e) the progressive replacement of oil by indigenous economicnatural gas for power generation; and (f) efficiency gains, resulting from amoratorium on hiring and the implementation of several improvements in itssystem operation and control (particularly under previous Bank projects).

5.3 TNB's net income increased steadily from M$462 million to M$900million between 1986-89. As increases in fuel prices during the Gulf War werenot compensated by tariff increases, TNB's net income of M$478 million in 1990and M$400 million in 1991 were lower than in the past but still satisfactory.TNB's after tax financial rate of return on revalued assets has been

27 -

satisfactory (9% to 13%). Its return on equityl' has also been satisfactory,averaging about 10%, compared with an average inflation of 3.5% p.a.

Table 5.1 - Past Finanial Performance - (Billion M$)

1986 1987 1988 1989 1990

Electricity Sales Revenues 2.313 2.343 2.524 2.780 3.123Total Operating Revenues 2.420 2.469 2.662 2.922 3.279

Total Operating Expenses 1.729 1.620 1.68! 1.638 2.284

Taxes and Dividends 0.045 0.197 0.08' 0.134 0.265

Not Income 0.492 0.443 0.634 0.900 0.478

Cash Available From Operations 0.709 0.860 0.526 0.414 0.554

Total Investment 1.049 1.398 1.214 0.742 0.740

Borrowing 0.261 0.607 0.552 0.296 0.113

Rate Base 6.024 6.557 7.218 8.070 8.694

Total Assets 9.066 10.437 11.235 11.643 12.444

Total Lous-Term Debt (Net) 4.240 4.587 4.972 4.507 3.920

Total Equity 3.583 4.117 4.500 5.511 6.555

RATIOS AND COMPARATORSElectricity Sold - TWh 11.4 12.4 13.6 15.3 17.4Avexage Tariff - M$ cents/Kwh 20.3 18.8 18.S 18.2 18.0Rate of Return-Book Assets 11 14.71 13.2X 15.4X 17.71 10.7ZRate of Return-Revalued Assets 11.5Z 10.4Z 12.81 14.7Z 8.8Z

Self-Financing Ratio 21 NA 70.51 47.0X 46.11 42.61

Debt S3rvice Coverage 31 3.0 2.4 1.7 1.4 1.6

Debt /(Debt plus Equity) 41 54X 531 52Z 45X 371Working Ratio 5] 561 49S 50 37X 531Current Ratio 63 123X 1131 1081 1411 130XAccounts Receivable (days) 54 53 46 47 50

11 Operating Income less Taxes on historical Fixed Assets.23 Cash available for investment divided by the 3-year average Capital Expenditures.

31 Operating Cash Flow divided by Debt Servrice (Amortization plus Operational Interest)41 Long-term Debt divided by long-term Debt plus Total Equity.51 Operating Erpendituras excluding Depreciation divided by the Operating revenues.

61 Current Assets divided by Current Liabilities.

5.4 TNB's self-financingl/ performance has also been fullysatisfactory, averaging about 50%, well above the 30% covenanted under Loan2772-MA. Since there have been no tariff changes since 1986, other than thegranting of discounts to industrial and commercial consumers (para. 5.8), andgiven the large increase in industrial sales, which have the lowest averagetariff, there has been a gradual reduction of the total average tariff (Figure5.2). However, lower oil prices and increased efficiency more thancompensated for this decrease. In fact, the 34% increase in sales experienced

I/ Net income after interest and taxes divided by total equity and reserves.

A/ Cash available from operations divided by the average of the capital expend.tures in the previous,

current and following year.

- 28 -

between 1986 and 1989, which increased TNB's revenues by 20%, resulted in adecrease, even in nominal terms, in operatiornal expenses from M$1,729 millionto M$1,638 million. Other financial ratios similarly indicate a goodfinancial performance during the last five years: the working ratio averaged49X, the operating ratio about 66%, the debt service coverage remained above1.4 and the current ratio averaged 123%.

5.5 Investment levels between 1986-89 averaged M$1,030 million peryear, but averaged only M$740 million between 1989-90, due to delays ininvestment decisions for generating plants. Investments increased to M$2,400million in 1991 and is expected to stay at about M$4 billion (US$1.5 billion)between 1993-95. Long-term debt has been managed prudently, and the 1990 debtis some M$300 million below the 1986 level. This resulted in a substantialdecrease in the debt equity ratio, from 54% to 372 during this period, andnotwithstanding the large investment program it is expected to remain at about43% in future years.

Fixed Assets Accounting

5.6 The rate of returnon fixed assets reported by TNB TNB S POWER RATES

before 1986 was overestimated IN R0WNT 08ICES

because of delays in 026l_ ___l5

transferring assets into 0 24

operation. Under Loan 2727-MA, 022

a comprehensive inventory of 21

assets was completed with the 0_eaid of consultants, l__commissioned assets were g a la _ / _

incorporated into operation, O____

and procedures were set up to O __ f _

incorporate assets in operation 0- _ = - = - - =

as soon as completed. The ____ __ _ _ _. * 1

incorporation of assets intooperation will now be closely O K%ATRRAL 0 C9.AC..L a 4STlC V TOTAL

monitored by TNB, since it willallow it to claim the Figure 5.2corresponding depreciationexpenses and maintain an adequate return on total assets in operation. InMalaysia, the revaluation of fixed assets is not practiced, and because of thecountry's low inflation (Figure 5.1) the assets revaluation concept is notwell understood. Therefore, all audited reports and formal financialstatements are based on unrevalued assets. In order to satisfy ADB's 8% rateof return on revalued assets, TNB computes in memorandum form a revaluationbased on the GDP deflator. However, the GDP deflator is only available afterone or two years, and is often adjusted for previous years. Because of verylow inflation, the total cumulative revaluation (difference between revaluedand book values) is only about 15%; this is likely to chan6e under higherinflation rates. The appraisal financial projections are based on fixed assetsrevalued with the GDP deflator for previous years and with the forecast

- 29 -

consumer prices for future years (Annex 14). The assumptions for financialprojections are given in Annex 17.

Tariffs and Margita Cost

5.7 TNB's tariff structure is generally satisfactory and complies withthe criteria of simplicity, fairness and econom'c efficiency. The tariffincludes different rates by type of customers (industrial, commercial, mining,domestic and public lighting), as well as differences for low, medium and highvoltage connections. Demand charges and time-of-day prices are applicable forlarge commercial and industrial users, and initial charges for installedcapacity (for large users) or payment of part of the connection cost.However, to simplify the tariff administration, it will be desirable in thefuture to unify medium-voltage tariffs, regardless of the category ofconsumers.

5.8 A 1990 marginalcost analysis for each category TNB'S DIST-R IBUTION OF POWER REVENUESof consumers and voltage level,(for demand and energy charges)indicates that the averagetariff is very close to the 4 -

marginal cost, which is 35t -

satisfactory (Annex 15) and 30% -

that low and high voltage rates 25% -

are also close to marginal 20% -

pricing. However, industrial r

rates are low, due to discounts 10%

(averaging more than 20%).These discounts are intended to O Z . l. 3 1 1983 190

foster industrial growth, andwere adopted in 1986 after the 0 N^Ta*-L O C4*AEMCAL D OMESTC x OT99

drop in oil prices. The impact _of these discounts on reducing Figure 5.3the average industrial andcertain commercial rates (in current prices) is shown in Figure 5.2. Thisfigure shows substantial tariff increases between 1980-82, and fixed tariffsup to 1986, when discounts for industrial and to a lesser extent forcommercial consumers were introduced. The granting of discounts rather than atariff reduction was a temporary measure, and will facilitate the restorationof full tariffs.

5.9 As a result of the tariff structure and changes in demand, duringthe last decade the respective share of total TNB's revenues from industrialconsumers (which use 48% of the electricity) decreased from 43% to 38%, butincreased from 17% to 23% for domestic consumers, which use 19% of theelectricity (Figure 5.3). Similarly, the share of commercial revenuesincreased about 3% points to 37%, while mining revenues decreased 2% points to1.6% and together with other sales are now just 9% of total (Figure 5.3).

- 30 -

Table 5.2 Finmcing Plan

Total X ----- Kilion H$---------US$ Mill. M Mill. 1992 1993 1994 1995 1996

operating Cash Flow A$27 13032 67.3X 2001 2195 2486 2915 3435

LESS:Amortization 1317 3556 18.42 531 595 722 793 915Operational Interest 1092 2948 15.2X "9 423 596 691 979

Total Debt Service 2409 6503 33.6X 790 1018 1318 1484 1895

Wo:.&ng Capital Needs (4) 99 268 1.4Z -132 -62 -8 158 312Other Assets (-) Or Liab.Naeda -66 -179 -0.9X -31 -33 -36 -38 -41Taxes & Dividends Paid 634 1712 8.8X 246 223 388 428 426

CASH AVAILABLE FROM OPERATIONS 1751 4728 24.42 1128 1049 824 883 844

CaRit,l ExAendituresGeneration 4206 11356 58.6X 1593 2682 2418 2735 1927Transmission 911 2459 12.7X 360 562 639 549 350Distribution 955 2578 13.32 676 481 431 431 558Administration 196 529 2.7X 97 98 105 106 122Import Duties & Sale Taxes 472 1274 6.62 0 0 447 450 377Interest Capitalized 433 1169 6.02 122 203 226 343 275

Total Capital Ezpenditures 7172 19364 100.02 2848 4027 4266 4614 3609

NET TO BE FINANCED: 5421 14636 75.62 1720 2977 3441 3731 2766

Fineancd Dv:

Rural Elect. Contributions 41 l1o 0.62 49 45 16 0 0Equity Increase 1481 4000 20.72 100 1300 1300 1300 0

Ongoing Loans 107 289 1.52 231 40 18 0 0Proposed IBRD Loan 200 540 2.82 81 108 135 135 81Proposed ADB Loan 200 540 2.82 81 108 135 135 81Other Foreign Loans 2842 7674 39.62 870 1185 1796 2113 1710Other Local Loans 53 144 0.72 144 0 0 0 0Undefined Local Loans 852 2300 11.9X 70M 500 300 300 500

Total BorrowinA 4254 11487 59.32 2107 1941 2384 2683 2372

Total Financed 5777 15597 80.5X 2257 3286 3699 3983 2372

Cash Increase (+) Or Decrease 356 961 5.02 537 308 258 251 -394

Capital Expenditures Program

5.10 The proposed project represents just 6% of TNB's expected totalinvestments during 1992-96. As shown in Table 5.2, TNB's investments ofM$19,364 million ($7.2 billion) comprise: M$11,356 million (58.6%) forgeneration, M$2,459 (12.7%) million for transmission, M$2,578 million (13.3%)for distribution, and M$529 million (2.7%) for administration and other

- 31 -

capital expenditures. Import duties and taxes, which are expected to beexempted between 1992-93, add to M$1274 million (6.6%) during the remainingyears, while M$1,169 million (6.0%) is needed for interest duringconstruction. Import duties and taxes average 30% of the foreign component ozcapital expenditures, and a sales tax of 10% is charged on local materials andequipment. TNB has been exempted from these taxes, but after itsincorporation it was expected to start paying them from 1992. However, thecapital investments planned for 1992-96 are very large, averaging yearlyinvestments more than 2.3 times the average for 1989-91. Existing tariffscannot be modified to cope with such large and lumpy investments plussubstantial new taxes. Therefore, TNB has requested, and the government hasagreed in principle to grant a moratorium up to 1993 on these caj4tal taxesand, less importantly, on fuel taxes. This is reasonable for this criticalperiod. If this tax holiday is not confirmed, TNB will need larger tariffincreases or reductions in its investment. At negotiations TNB's capitalexpenditure program, and financial projections were revised based on thelatest data for FY91.

Overal Financing Plan

5.11 TNB's gross internal cash generation during 1992-96 (Table 5.2)would be about 67.3% of its capital expenditures, and its net internal cashgeneration (after debt service, working capital needs and the payment of taxesand dividends) would be 24.4% of its total capital expenditures, which issatisfactory. Borrowing of M$11.5 billion (59.3% of capital expenditures)includes ongoing loans (1.5%), IBRD and ADB loans (2.8% each), other foreignloans, mainly suppliers' credits (39.6%, about half of which is alreadyconfirmed), and local loar.s (12.6%, about 60% already confirmed). In additionrural electrification contributions and equity increases would finance 0.6%and 20.7% respectively. Equity increases include M$400 million to beaccounted as a grant in the United Kingdom (UK) financing package for Pergauhydro project (para. 2.4 (a)), and an estimated M$3,600 million from theproceeds of the further sale of shares between 1993-95. In case of delays insuch offerings, TNB would float bonds for a similar value. Under the proposedtariffs and capital expenditures, TNB would maintain adequate cash reserves tocope with financial contingencies.

Foreign Exchange Exposure

5.12 As of August 31, 1990 (the end of its fiscal year), TNB hadoutstanding loans for M$4,684 million of which M$639 are repayable within 12months. M$925 million of signed loans are still to be drawn. In the past,part of the foreign exchange loss was deferred, but starting in 1991, andfollowing the recommendation of the private auditors the total foreignexchange deferred account of M$1,349 million was transferred as prior yearadjustment against the Capital Development Reserve, and foreign exchangelosses would thereafter be charged as operational expenses. This will conformto international accounting standards for treatment of foreign exchangelosses.

- 32 -

5.13 The large majorityof TNB's loans (89%) are RATES OF RETURN

foreign loans. Yen-denominatedloans represent 58% of the I _ - - -

total loans (excluding the 14- . -

fraction in Yen in the Bank and 2- = X - - -

ADB currency pools). The s- -

percentages of total loans in =M I_other currencies are: 15.6X in __ _ 7 4 _,i,,a,European-currencies, 13% in US =t.dollars (including IBRD and ADB - Z_ _

loans) and 1.3% are loans in - -

other foreign currencies. - -

Unfavorable variations ia n i 9

exchange rates could have a ,86 ." ."o 192 194 loge 1990 2000

significant impact on TNB's a 0. onyPl ASSETS O CM 916ORC ASSETS 04 TOTAL WITY

finances and capitalization. I_ITNB has introduced a foreign Figure 5.4exchange risk managementprogram and has already taken several steps to reduce its foreign exchangeexposure to any single currency, and during the last two years Yen denominatedloans have been reduced from 67% to 58% of the total outstanding loans.

Future Finnces

5.14 In the future, TNBfinancial objectives should be AVERAGE TARIFF

to: (a) increase itsefficiency; (b) self-finance areasonable portion of Its 0substantial investment program; 0 2

(c) achieve an adequate return _

on its capital, supporting thesale of its shares and its 0 O2

future privatization; and (d) s 0.i …l

maintain adequate tariffs to 0 _lensure its financial viability, 009 _ -

while providing a stable base 002

for the country's econcmic ¶9 ¶999 1990 19*1 194 1999 X

development. As indicatedbefore, TNB finances have been a a.F4r eces ,".I ¶99

satisfactory, but as a resultof the oil prices during the Figure 5.5Gulf War, financial results for1991 were lower than usual: its revalued rate of return was about 7% and itsself-financing ratio was about 19%.

5.15 The expected large increases in electricity sales, a substantialreduction in the consumption of oil (starting in 1992) and the reduction ofoil prices, (which are projected to average about $20 per barrel for fiscalyears 1992-93) and the use of gas would facilitate maintaining a strong

- 33 -

financial condition for TNB. The government has been considering a regulatorytariff mechanism similar to the one followed in the UK for recently privatizedutilities. Under this system, part of the tariff will be adjusted for theimpact of fuel prices, but the remaining portion will be increased somewhatless than the increase in consumer prices, the difference being due toefficiency gains expected from the utility. This requires further analysis,particularly to set initial tariffs at a sufficient level to ensure anadequate demand for TNB shares (para. 3.6).

Table 5.3 - Future FinanCial Performance - (Bilon M$)

1988 1989 1990 1991 1992 1993 1994 1996 1998

Electricity Sales Revenues 2.524 2.780 3.123 3.515 3.928 4.474 5.093 6.608 8.970Total Operating Revenues 2.662 2.922 3.279 3.695 4.118 4,668 5,291 6.816 9.187Total Operating Expenses 1.685 1.638 2.284 2.831 2.933 3.208 3.665 4.702 6.042Taxes and Dividends 0.089 0.134 0.265 0.246 0.223 0.388 0.428 0.441 0.829Net Income 0.634 0,900 0,478 0.401 0.743 0.727 0.702 0.833 1.146

Cash Available From Operations 0.526 0.414 0.554 0.375 1.128 1.049 0.824 0.844 1.S92Total Investment 1.214 0.742 0,740 2.416 2.848 4.027 4.266 3.609 3.796Borrowing 0.552 0.296 0.113 1.747 2.107 1.941 2.384 2.372 2.952

Rats Base 7.218 8.070 8.694 9.365 11.117 13.284 15.449 24.673 32.707Total Assets 11,235 11.643 12.444 .4.313 17.355 21.625 26.132 33.995 42.333Total Long-Term Debt (Not) 4.972 4.507 3.920 5.350 6.974 8.205 9.811 13.042 16.181Total Equity 4.500 5.511 6.555 6.808 8.182 10.657 23.157 17.429 21.478

MONITORING INDICATORSElectrioity Sold - TWh 13.6 15.3 17.4 19.5 21.9 24.6 27.5 33.7 40.1Average Tariff - MS cents/Kwh 18.5 18.2 18.0 18.0 17.9 18.2 18.5 19.6 22.3Rate of Rketurn-Book Assets 1X 15.4X 17.7X 10.7X 8.3X 11.1 11.21 11.3X 9.61 9.9XRate of Return-Revalued Assets 12.8X 14.7X 8.81 7.0X 9.1S 9.2X 9.21 8.01 8.0Z

Self-Financing Ratio 21 47.02 46.11 42.61 18.8S 36.4X 28.3X 19.22 21.71 43.6XDebt Service Coverage 31 1.7 1.4 1.6 1.4 2.4 2.0 1.6 1.4 1.6Debt /(Debt tlus Equity) 41 521 451 371 441 46X 441 43S 431 431Working Ratio 5) 501 37Z 53Y 63S 572 541 542 52X 49XCurrent Ratio 6) 1081 1411 130X 1091 1361 1262 127X 1281 1471Accounts Receivable (dayr) 46 47 50 48 44 44 44 43 40

1l Operating Income less Taxes on historical Fixed Assets.2l Cash available for investment divided by the 3-year average Capital Expenditures.31 Operating Cash Flow divided by Debt Service (Amortization plus Operational Interest)4) Long-term Debt div1i.ed by long-term Debt plus Tntal Equity.51 Operating Expenditures excluding Depreciation divided by the Operating revenues.6l Current Assets divided by Current Liabilities.

5.16 The above financial objectives (para. 5.14) would be satisfied byan after-tax rate of return of 8% on revalued fixed assets in operation, whichis the basis for the financial projections presented in Annex 14. Agreementwas reached with GOH and TNB during negotiations that starting in fiscal year1992 TNB would achieve an -.fter-tax rate of return on its net revalued fixedassets in operation not lower than 8%. Assets would be revalued using the GDP

- 34 -

deflator (for previous years), and the forecasted increase in consumer pricesfor future years. This rate of return can be obtained under existing tariffsand by a gradual reduction (during the next four years) of the industrial andcommercial discounts (Figure 5.5). After TNB privatization, GOM inconsultation with the Bank may consider a somewhat lower rate of return topromote a higher reliance on private loans and equity financing, rather thanon internal uash generation.

5.17 Annex 14 providesTNB financial projections and % SELF-FINANCING PATIO

Annex 16 the monitoring I.

indicators between 1987 and e0_

1997. Under these projections 70 - ___ -

and assumptions TNB financial 6- - -. _

performance will be fully - -

satisfactory (key financial _ 40

indicators are summarized in -_Table 5.3). In particular, 30% _ - -/

its interest coverage would 9 \8exceed 1.8 times, its working 2_-

ratio will average about 55% . - - - _ -

and its operational ratio will c - - -

be about 70%. The self- 1989 1980 1990 9l o 9g, 1916 l 99s l 000

financing ratio (internal YA

contribution to investment) SFR_C;_, Al_ I _Ion>

would average about 24% between Figure 5.61992-96, but, given thedecrease in capital investments, would reach larger values, in excess of 40%thereafter (Figure 5.6). TNB's debt/equity ratio would stay relatively low,at about 43% indicating that higher loan financing is feasible. However, thismay be difficult given the large level of loans required and thc transitionperiod from a government corporation enjoying government-guarantee for itsloans, to a private corporation. Bank support, and loan guarantees which maymaterialize from potential Expanded Cofinancing Operation (ECO) are expectedto facilitate this transition, and introduce TNB to the international markets.Particularly important for private lenders would be TNB's debt servicerepasment capacity. Agreement was reached at negotiations that unless the Bankaccepts otherwise, TNB may incur additional debt only if its forecasted debtservice ratio exceeds 1.5 times its projected debt service requirements2'.The debt service ratio is expected to average 1.7 during the period 1992-96.

Finmncial Sensitivity Anldysis.

5.18 Sensitivity analysis shows that the main financial variables aresales, inflation, fuel prices and the foreign exchange rates. Both fuelprices and inflation (within limits) would be compensated by the revalued rate

V/ Based on a reasonable annual forecast of the debt service ratio during the term of the debt to be

incurred and calculated dividing its net revenues after all expenditures by the sum of the amortization and

operational interest.

- 35 -

of return covenant. Regarding the foreign exchange risk. TNB is achieving amore balanced debt, so that revaluation in some currencies could at least bepartially compensated for by devaluation of other currencies (par&. 5.13).For the financial kJrojectionq TNB's Base Case load for*cast has been used.However, the Low Load Forecast (para. 2.2) could well materialize. In such acase, TNB's financial performance would be somewhat weaker but still fullysatisfactory as shown in Annex 1'4, Table 4.

Monitoring and Evaluation

5.19 TNB has considerably improved its planning and managementinformation systems during the last few years. The project includes technicalassistance to improve TNB's financial management information systems and itsoverall financial management (para. 3.16) which would be critical for itsoperation as a private corporation. Given the large impact of electricitydemand and capital expenditures on its financial viability, TNB's forecastingsystems for load demand, and for its financial planning for capitalexpenditures, debt management and financial projections should be furtherimproved to more accurately forecast its finances. Agreemnt was reached atnegotiations that TNB will furnish to the Bank by December 31 and June 30 ofeach year updated reports for the previous two years and projections for thefollowing 8 years, for: (a) capital expenditures; (b) project cost; (C) debtservice; (d) financial projections (Annex 14); and (e) monitoring indicators(Annex 16).

VI. PROJECT JUSIIFICATION

Justification

6.1 The proposed development program is needed to meet the fastincrease in power demand over the next few years. It has been formulated usingleast-cost analysis, but taking into consideration GOM's policy ofdiversification of types of generation and fuel to enhance supply reliability(para. 1.10). The program supports use of domestic resources (natural gas andrenewable hydro energy) and would save foreign exchange by averting oil importand ensure long-term energy security for Malaysia. Timely and adequategeneration capacity additions would provide reliable power supply to supportthe country's rapid economic growth. Commensurate expansion of thetransmission and distribution systems would ensure system reliability andoptimize system losses, while investments in rural electrification wouldsupport government's social objectives of bringing electricity to all parts ofthe country.

Economiic Analysis

6.2 The project forms a part of TNB's overall investment plan. Toconfirm the economic viability of this plan, an Internal Economic Rate ofReturn (ERR) was calculated, on the basis of incremental cost and benefitstreams associated with the 1990-1999 time-slice of the overall investmentplan. Capital costs included the costs of generation, transmission anddistribution facilities installed during 1990-1999 (exclusive of taxes andduties). Incremental fuel consumptions were derived from the SYSGENproduction costing model which simulates system operation on a daily basis.Fuel prices were assumed as: (a) fuel oil price of US$110/ton (equivalent to acrude oil price of US$20/barrel) in 1992 escalated at 3% per annum in realterms; (b) coal price of US$50/ton in 1992 escalated at 1% per annum in realterms; and (c) cost of gas assumed at M$6/MMBTU (Wesu Coast) and M$5/MMBTU(East Coast) in 1990, with 60% of the price remaining constant in real termsand 40% linked to the price of fuel oil in subsequent years according to theformula suggested by the Bank in the Gas Utilization sector study (para. 1.1).Incremental operation/maintenance and overhead costs were assumed at 2% ofincremental capital costs. The benefits were evaluated in terms of revenuesrealized on the basis of an average tariff of Mcl8.5/kWh (remaining constantin real terms), and demand based on TNB's Base Case Load Forecast. The ERRfor the base case was 12%. This understates the economic rate of return dueto non consideration of consumer surplus. Considering only 30% of thebenefits due to consumer surplus (evaluated on the basis of Mc39/kWh forequivalent kerosene lighting for the domestic sector and Mc24/kWh for medium-sized diesel generation for the other sectors) the ERR was 16%. Even thoughTNB's generation expansion plan can be adapted relatively easily to changes inthe load forecast (due to substantial internal combustion turbine andcombined-cycle capacity in the plan) by modifying the timing of future units,the ERR was tested for a lower demand using the Low Case load forecast (para.

- 37 -

2.2). The ERR for this lower demand was 10%. A 10% increase in the capital

cost of the program reduces the ERR to 11%. Details of the ERR calculations

are in Annex 18.

Risks

6.3 TNB's power development plan is ambitious but achievable.Though TNB has demonstrated organization capability in :.he execution of largethermal, hydro and transmission/distribution projects, delays have occurred in

the past due to an excessively long decision-making and approval process onprocurement. There is thus some risk of delay in the implementation of the

proposed expansion program on this account and this could lead to the systemoperating at reduced levels of reliability. However, TNB's increased autonomy

is expected to improve its efficiency and effectiveness. Further, in order to

minimize delays in implementation TNB would be (a) making use of consultancy

assistance for all its generation expansion projects for design, engineeringand construction supervision; and (b) using turnkey supply and installationconcepts for generation and major transmission system projects (para. 4.10).As construction of the gas pipelines would be completed by 1992, there is nomajor risk foreseen due to the non-availability of gas on time for TNB's power

plants. Gas supply failure risks are minimal and would be mitigated by makingprovision for stocking distillate oil for use by internal combustion turbineand combined-cycle installations in an emergency. Conventional steam plants

introduced in the program would revert to heavy fuel oil.

- 38 -

VII. AGREEMENTS REACHED AND RECOMMENDATION

7.1 During negotiations, agreement was reached with Government and TNB thatstarting in fiscal year 1992 TNB would achieve an after-tax rate of return on itsnet revalued fixed assets in operation no; lower than 8% (para. 5.16);

7.2 During negotiations, agreement was reached with TNB on the following:

(a) TNB would furnish to the Bank by June 30 of each year its generation andtransmission development programs (para. 2.7);

(b) audit reports would be provided to the Bank within six months of thecompletion of its fiscal year (para. 3.17);

(c) TNB would maintain adequate insurance (para. ,.19);

(d) consultants under Terms of Reference acceptable to the Bank wouldcomplete by December 31, 1994 the following studies: (i) FinancialManagement Information System; (ii) Total Quality Management Program;and (iii) Demand-side Management and Electricity Conservation(para. 4.7);

(e) TNB would maintain and strengthen the Environmental Unit (para. 4.7 (a);

(f) unless the Bank otherwise agrees, TNB would incur additional debt onlyif its debt service ratio exceeds 1.5 times its projected debt servicerequirements (para. 5.17);

(g) TNB will furnish to the Bank by December 31 and June 30 of each yearupdated reports for the previous two years and projections for thefollowing 8 years, for: (a) capital expenditures; (b) project cost; (c)debt service; (d) financial projections; and (e) monitoring indicators(para. 5.19).

7.3 Subject to the above agreements, the proposed project would constitute asuitable basis for a Bank loan of US$200 million equivalent, for a period of 17years, including a grace period of 5 years, at the standard variable interestrate. The borrower will be the Tenaga Nasional Berhad with the guarantee ofMalaysia.

ANNEX I- 39 -

UALAYSIA

POWER SYSTEM DEVELOPMENT PROJECT

TNBaf ACtual Eleetricity Sles,. Genoration. Peek Demnd. Inst lled Capacity, and Number of Consumers

FVYO FY75 FYVO FY85 FY86 FY87 FYS8 FY89 FY90

Electricity Sales (Gwh. 2.171 3.981 7.265 10.811 11.421 12.438 13.637 15,253 17,394Domestic 268 474 1.148 2,224 2,481 2,674 2,876 3.021 3,350Coemmrcial 599 1,113 2.161 3.571 3,891 4.109 4,417 4.681 5.153Industriel 576 1,481 2,744 4.487 4,608 5,14U' 5,829 6,887 8,357Mining 23 103 294 427 329 344 357 402 387Public Lighting 0 40 65 102 112 115 121 134 146Sole$ to PREHP/EGAT YA 353 570 863 0 0 50 37 128 0

Grosa Generation (GWhl 24 4.5 8,466 12.73Q 13.512 14.645 26.216 18.127 20.6MHydro 928 789 1,126 3.004 3.639 3,671 4.586 5.043 3,275Oil 1,376 3.536 6,431 7,433 6.832 8,104 7.310 7.409 8.870Diesel 100 176 621 1.091 979 367 382 84 65Natural gae 0 0 0 1.097 2.062 2.503 3.866 3.592 5,312Bulk purchase 94 151 89 106 0 0 0 0 0Coal 0 0 0 0 0 0 72 1.999 3,146

Peak Demand (MW) 364 693 1.427 Z.148 2.267 2.441 2.720 3.033 3.447

Installed Capacity (Qy) 664 734 2.048 3.781 4.710 4.529 4.829 5.040 5.040

Hydro 265 265 613 1.147 1,250 1,250 1.250 1.245 1,245Oil 360 S40 1,210 1.570 2.090 1.930 1,930 1,930 1,930Diesel 39 49 124 205 190 169 169 85 85IC turbine / 0 0 100 260 280 280 280 280 280Combined cyele 0 0 0 600 900 900 900 900 900Coal 0 0 0 0 0 0 300 600 6oO

Number of Conaumer 450,967 704.377 1.258.477 2.124.676 2.Z89.374 2.424.132 2.576.814 2.735.930 2.903.27l

Domstic n.e. n.e. 1.062.679 1.832,406 1,983.252 2,.05,799 2.242,831 2,381.770 2,531,198Conmmrciel n.a. n.a. 191.059 284,165 297,137 308.496 322.812 341,354 357,694Industrial n.a. n.a. 2,830 4,274 4,778 5,158 5,745 6.659 7.482Mining n.e. n.a. 59 434 271 237 227 234 219Public Lighting n.e. n.o. 1850 3.397 3.936 4.443 5.199 5.913 6,678

Employee*

Number of employees 9,405 113,330 19.248 25.144 24,701 24,347 23,892 23.596 22,436Consumers/employee 49 62 65 84.5 92.7 99.6 107.9 116.9 129.4Sales per employee (MWh) 230.8 351.3 377.4 429.9 462.4 S10.9 570.8 646.4 775.3Employae*/Ml Installed 14.2 15.4 9.4 6.7 5.2 5.4 4.9 4.7 4.5

j_ Perak River Hydro Electric Project/Electricity Generating Authority of Thailand.

Ib Internal combustion turbine operated on medium fuel oil.

- 40 -

ANNEX 2

POWER SYTEiM DEVELOPMENT PROJECT

EFomc it ELctsrscity a by Conumer Cateaory (GWh) /a

PublicFY hcdugrW Commecal Residential Mining Ughting Total

1991 9,635 6B696 3,673 474 162 19,539

1992 10,9B6 6160 4,078 506 177 21,909

1993 1.600 6779 4,466 538 192 24,549

1994 14,441 7,456 4,865 569 208 27,508

1995 16644 g1N9 5,255 601 225 30,824

1996 U,:236 0954 5,610 629 233 33,660

1997 20,09 977 5.984 656 240 36,757

1998 22,160 10677 6,381 684 247 40,138

1999 2,400 11,669 6,799 711 253 43,831

2000 a2m6 12&732 7,241 7?,7 258 47,864

/a Referen o Scerio

- 41 - AN_EX 3

MALYSIA

POWER SYSTEM DEVELOPMENT PROJECT

Forecast of TNB's Electricitv Sales. Generationr Peak Demandand InstaUed Capac1tv

FY91 FY92 FY93 FY94 FY95 FY96 FY97 FY98 FY99 FYOO

Energy Sales (GWh) 19539 21909 24549 27508 30824 33660 36757 40138 43831 47864

Total Generation (GWh) 23162 25915 28986 32421 36264 39507 43041 46891 51086 55656

Load Factor (%) 66.5 66.4 66.4 66.4 66.5 66.5 66.5 66.5 66.5 66.5

Peak Load (MW) 3976 4455 4983 5574 6225 6782 7388 8049 8769 9554

Generation Shares (%0)

Oil 43.6 23.7 4.1 0.8 0.4 0.5 0.2 0.8 0.3 2.1Hydro 16.0 14.1 12.5 11.4 10.3 10.7 10.0 10.3 10.0 9.3

Natural gas 24.3 45.4 69.5 73.0 78.1 70.6 64.0 65.01 68.0 68.4

coal 16.1 16.8 13.9 14.8 112 18.2 25.8 23.8 21.7 20.2

Installed Cavac (MW) La .845 5696 6.445 7.422 7.812 9.322 9.622 1244 11.163 12063

Oil 1,780 820 600 600 600 510 510 510 390 390

Hydro 1,253 1,323 1,323 1,338 1,338 1,938 1,938 2,454 2,669 2,669

Natural gas 852 2,773 3,742 4,704 5,094 6,094 6,394 6,519 7,419 8,319

Coal 600 600 600 600 600 600 600 600 600 600

(MFO/Jistillate)/b 275 95 95 95 95 95 95 76 0 0

Diesel 85 85 85 85 85 85 85 85 85 85

/ Derated capacity.

/b Interal combustion turbine.

- 42 - NNEX 4

Page I of 2

MALAYSIA

POWER SYSTEM DEVELOPMENT PROJECT

TNB's Installed Generating Capacitv and Energv Capability

AverageInstalLed Derated energy

Station Type capacity capacity capability(fuel) (MW) (MW) (GWh)

Thermal

Tuanku Jaafar Conv. Steam 600 555 3,403(Port Dickson) (gas/oil) (3 x 120)

(oiL) (4 x 60)

Perai Conv. Steam 450 415 2,545(oil) (3x30 + 3x120)

Sulten Iskander Conv. Steam 240 210 1,288(Pasir Gudang) (gas/oiL) (2x120)

Sultan Conv. Steam 1,200 1,200 7,358Salahuddin (gas/oil) (2 x 300)(Port Klang) (gas/oil/coal) (2 x 300)

Sultan Ismail Combined cycle 900 852 5,224(Paka) (gas) (3 x 300)

Connaught Internal Comb. 180 180 315Bridge Turbines (2 x 90)

(MFO)

Gelugor, Perai, Internal Comb. 100 95 166P. KLang, Turbines (5 x 20)P. Dickson, P. (Diesel oil)Gudang

Gelugor Conv. Steam 40 0 0(Oit) (4 x 10j

Diesel Sets 85 85 372

Total (thermal) 3.755 3.592 206

Nvdro

Sultan Mahmud Hydro 400 400 1,600(Kenyfr) (4 x 100)

Temenggor Hydro 348 348 684(4 x 87)

Sultan Azian Hydro 120 120 385Shah (Kenering) (3 X 40)

- 43 - ANNEX4Page 2 of 2

AverageInstalled Derated energy

Station Type capacity capacity capability(fuel) (MW) (MW) (CWh)

Sultan Azian Hydro 72 72 224Shah (Bersia) (3 x 24)

Sultan Yussuf Hydro 100 100 288(Jor) (4 x 25)

Sultan Idris 11 Hydro 150 150 433(Woh) (3 x 50)

Chenderoh Hydro 40 40 209(4 x 10)

Miscellaneous 23 23 75

Total (hydro) ¶1.53 L25W 3LI2

Total System Thermal & Hydro 5.L00 44 24571

Assumed anrual plant factors for computing energy capability:

Conventional steam and combined cycle: 70XinternaL combustion turbine: 20XDiesel: 50XHydro: Actual average

annuaL energy

- 44 -

ANNEX S

MLAYSIA

POIQER SYSTEM DEVELOMENT PROJECT

INB's Transmissfon and Distribution Facilities

FY70 FY75 FY80 FY85 FY86 FY87 FY88 FY89 FY90

Transmission Lines (ckm)275 kV 144 314 744 2,322 2,788 3,100 3,100 3,526 3,596132 kV 830 982 1,879 3,891 4,173 4,515 5,871 5,310 6,10766 kV 498 534 572 990 1,012 1,012 913 869 892

Substations (CaDacitv in MVA)

275 kV 0 860 1,940 4,680 5,940 6,310 6,310 7,030 7,510132 kV 112 1,512 2,885 4,963 6,235 7,120 7,560 8,988 9,88366 kV 452 610 702 1,331 1,377 1,409 1,194 1,296 1,28933/22 kV 414 894 1,508 2,883 3,045 3,138 3,149 3,276 3,37211 kV & betow 763 1,402 3,051 4,716 4,969 5,380 5,778 6,187 6,681

Distribution Lines Cckm)

33 kV 858 899 1,454 1,445 1,820 1,898 2,097 2,620 2,65622 kV 132 172 186 2,098 1,617 1,651 1,755 1,781 1,84511 kV 3,050 4,912 9,433 13,004 14,745 16,776 18,239 20,167 21,264Below 11 kV 360 301 440 817 814 802 597 985 -

- 45 -ANNEX 6

MALAYSIA

POWER SYSTEM DEVELOPMENT PROJECT

Assumitions for TNB s Least Cost Develoament Plan

A. Candidate Power Ptant Costs and Characteristics

Capital Heat Outage rate OB _Cost Constr. tDCPtant cost rate X Fixed Variable period Xtype US$/kW kcal/ Forced Sched. USS/kW USS/MWh years

kWh /month /ffionth month

Conv. steam gas/oil300 MW 749 2,331 8 7 0.77 0.59 4.0 18.53500 MW 702 2.420 11 9 0.63 0.53 4.5 21.12

Conv. steamJgas/oit/coal300 W 1,253 2,590 9 8 1.15 0.82 4.5 21.12500 MW 918 2,470 12 10 0.93 0.74 5.0 23.78

Combined-cycle300 MW 599 2,413 10 10 0.40 1.61 3.0 n.79

Int. comb. turbine100 MW 480 2,932 10.5 7 0.95 2.17 2.0 8.79

HydroPergau 1 393 5.0 23.78600 NWULu Jelai 824 5.0 23.78516 MW

All costs in 1991 US$USSi 1S2.7

B. Fuel Price Projections (in 1992 USS)

Price in 1992 Annual Real Escalation RatesFuel USS/ton USS/MMBTU (X)

Fuel oil 118.8 2.93 3.0

Coal 47.66 1.80 1.0

Natural gasEast Coast - 1.92West Coast - 2.31

/a Gas price = 6x(1 + inflation)x(O.6 + 0.4 x MFO price/MFO prIce (1990))in Ringgit/MMBTU on the West coastMFO = Medium fuel oil

C. Loss of Load Probability I day per year

- 46 -

POWER SYSTEM DEVELgPMENT PROJECI

TNBsI Generation Develooment Ptan - Prooosed-Plant Additions and Retirements

incremental Cumulat veFY Type of Capacity Energy Capacity Energy

Plant Location (MW) (GWh) (MW) (GWh)

1991 Existing System 4,845 24,571

1992 2xGT87 Paks 174 3052xGT87 Pasir Gudang 174 3053xGT129 Conn. Bridge 387 678Sg. Piah Sg. Piah 70 380Rehab. Program P. Gudang, Prai 20 123

P. Dickson2xGT9O conv. to gas Conn. Bridge 26 46 5,696 26,407

1993 1xGT129 Conn. Bridge 129 2262xGT1O3 conv.to CC Comn. Bridge 100 1,4792YGT125 Melaka 250 4382xGT125 Serdang 250 438Rehab. Program Prai, P. Gudang 20 123 6,445 29,110

P. Dickson

1994 1xCC265(-2xGT87) Paka 91 1,3201xCC265(-2xGT87) Pasir Gudang 91 1,320Chenderoh Rehab. Chenderoh 15 24xGT130 Paka 520 9112xGT130 Pasir Gudang 260 456 7,422 33,119

1995 1xCC300(-2xGT100) Paka 130 1.9361xCC390(-2xGT100) Pake 130 1,9361xCC300 P. Gudang 130 1,936 7,812 38,927

1996 2xG500 P. Klang 1,000 6,132Pergau Pergau 600 5153x30MW Pral -90 -552 9,322 45,022

1997 1xCC300 Not decided 300 1,840 9,622 46,862

1998 1xGT125 Not decided 125 219Jelai Ulu Jelai 516 53520MW GT retired Gelugor -19 -33 10,244 47,582

1999 Units 1,2 Retired Port Dickson -120 -73620MW GT Retired P. Klang, Prai -80 -133

P. GudangP. Dickson

3xCC300 Not decided 900 5,519Pelus Pelus 215 430 11,163 52,662

2000 3xCC300 Not decided 900 5,519 12,063 58,181

Notes:

1. GT a International combustion turbine plant; GT a 100 MW GTCC a Combined-cycle plent;G a Conventional steam plant;H = Hydro plant.

2. Capacity factors: GT 20X; CC and ST a 70X; H = actual.

47 -

ANNEX 8

MALAYSIA

POWER SYSTEM DEVELOPMENT PROJECT

TNB System Capacity Balance

FY System Demand I System Reserve[_________ -____________ -__,_-_- _,__ Capacity Margin A/

l FY | GWh | w Kw % G

1991 23162 3915 4845 81

1992 25915 4449 5696 151

1993 28986 4976 6445 171

1994 32421 5565 7442 231

1995 36264 6225 7812 16X

1996 39507 6782 9322 291

1997 43041 7388 9622 221

1998 46891 8049 10244 20Z

1999 51086 8769 11163 201

2000 55656 9554 12063 201

4a Reserve margin considering outage of two largest units in the system.

- 48

Annex 9 - Page 1 of 9

MALAYSIA

Power System Development Project

Consulting Studies: Terms of Reference

A) Financial Managument Information Systems

B) Total Quality Management

C) Demand Side Management and Electricity Conservatlon

A) Financial Management Information Systems

ObMectives

1. The principal objective is to seek consultancy services for enhancing the financial managementinformation system to provide more timely and effective financial reporting as required by a public limitedcompany. The consultant would therefore be required to design and implement an effective fmancialmanagement information system for the Tenaga Nasional Berhad which would:

(a) provide its managers with prompt and relevant fmancial and other information to assist them inp!anning, controlling and reporting the activities for which they are accountable;

(b) ensure tighter control over costs and budgets; and

(c) provide information which would satisfy statutory and licensing requirements.

Badsgroud

2. A public limited company Tenaga Nasional Berhad (TNB) was incorporated under the CompaniesAct 1965 on 12th July 1990. This Company which obtained the Certificate of Incorporation on 30th August hassince taken over all the assets, liabilities and obligati mns of the National Electricity Board as from 1st September1990. This is provided for under the Electricity Supply (Successor Company) Act 1990. Since becoming a publiclimited company, Tenaga Nasional Berhad has converted from quarterly to month:y reporting with projectionto the end of the financial year. Under condition 6 of the current license, TNB is required to submit with effectfrom financial year 1991/1992, separate management reports on major functional activities; namely, generation,transmission and customer services in addition to the normal published accounts. As the Company proceeds tothe next stage of privatization, i.e. flotation and divestment, it is now opportune to review and upgrade itsfinancial management information system into a more effective one. This Fmnancial Management InformationSystem (FMIS) must be flexible enough to support the Company in its missions and objectives.

Scop

3. The proposed FMIS must provide on-line costing, management and financial information for eachlevel of management to increase the degree of cost and budget control and hold managers accountable for the

- 49 -

Annex 9 - Page 2 of 9

costs which they incur. The proposed system should enable managers to take and report promptly on correctiveactions taken. In addition, the system should facilitate the provision of detailed costing information which wouldbe required for tariff analysis and for reporting under the licensing agreements. The proposed system shouldbe fully integrated with relevant sub-systems whether financial or statistical. Standard cost and variance reportingshould be incorporated, where appropriate. The consultancy services required would be rendered in two phases.Phase I is the review and planning phase to determine the system requirements including hardware and softwarerequirements and a proposed revised chart of accounts and an implementation plan. Phase 2 would involve theimplementation and conversion to the new system and would cover assistance in the installation and training inthe use of the system. The consultants appointed would work closely with the Company's senior accountants todevelop detailed formats and report contents for statutory, corporate and licensing requirements.

Maign Concenpts and Framework

4. The proposed system should incorporate the following design concepts:

(a) the use of budgetary control and responsibility accounting which would place emphasis onaccountability,

(b) systematic collection and summary of fnancial and physical information relating to functions andactivities of the Company;

(c) the e of user pays concept where appL3 able in the allocation of costs;

(d) the financial/management reports must contain performance indicators which would facilitateperformance appraisal of managers;

(e) more timely preparation of statutory, corporate and operating management cost reports andsummaries including those required under the licensing requirements;

(f) the accounting system and classification must be flexible enough to cater for financial reportingof separate (and legal) core business units, e.g. construction, supply operations (generation andtransmission), and customer services (distribution, supply and consumer services) and forconsolidation to cater for future business strategy, and

(g) the accounting system and classification must be flexible to enable horizontal and verticalexpansion or contraction and for consolidation to cater for the needs of the business plans.

5. The proposed system would also be an online system with online data entry for low volume inputsand security-controlled online access of the finacial data base. A broad conceptual overview of such a systemis shown in Appendis WA'.

Detailed Terms of RPeference

6. As stated earlier, the development of the FMIS is to be undertaken in two phases, namely:

(a) Phase 1, which involves the preparation of a conceptual system design and outline plan forimplementation; and

b) Phase 11, which involves the conversion, paralel running and live operation of the new system.

- 50 -

Annex 9 - Page 3 of 9

Phase I

7. This phase would include the following:

a) Establish the management's financial information requirements and assess the extent to which theexisting information system is meeting TNB's current and future needs;

b) Specify the conceptual design of the new financial management information system; and

c) As an immediate work plan, assess the various computerised systems and facilities that need tobe modified to ensure more timely financial reports to be produced. Timely reports would meanthat the reports must be produced by the following month. It is envisaged that there will be acomprehensive assessment of the required amendments to be made to existing computerisedsystems which would include the following:

Subsidiary Svstems

(i) Invoices and payments(ii) Payroll and labour distribution

(iii) Supply function(iv) Mechanical transport(v) Cash receipts summary

(vi) Income summary(vii) Journal vouchers

(viii) Final adjustments and allocations(ix) Consumers accounts (will be upgraded to a Customer

Information Billing System)(x) Ftnancial planning and analysis and long term

inancial projection.

Internediate SyStems

(i) Rechargeable works(ii) Capital works and expenditures tracking and

status reporting(iii) Loan management(iv) Treasury dealing(v) Taxation computations

Final Systems

i) General ledger incorporating revenue budgetspreparation

ii) Fixed assets and depreciation accountingii) Capital budgets.

Phase 11

8. Phase II implementation will involve two stages, namely:

Stahv I

(a) This will involve the detailed specification of the enhanced financial information sytem.

- 51 -

Annex 9 - Page 4 of 9

(b) In the case of the subsidiary and other systems which need to be changed or enhanced, preparethe system and procedural and change specifications;

(c) Implement the amendments/enhancements for exsting systems to provide faster financialreporting,

d) Prepare new revised chart of accounts; and

e) Prepare a detailed implementation plan.

(a) To develop detailed budgeting and control procedures;

(b) To develop detailed accounting procedures induding user manuals for the guidance of end users;

(c) To design and draft new or revised report formats and input forms for corporate, managementand license reporting,

(d) To design training programs, training materials and conducting of training courses for end users,trainers and Finance Division's staff;

(e) To prepare detailed software specifications and modifying, installing and testing the software forthe new system (responsibility lies with the consultant but with full involvement of Company'sInformation System and Fimance Division's staff);

(t) To provide guidance to users in the preparation of the first set of capital and operating budgets;

(g) To provide guidance to end users and Fmance Division's staff during the conversion from the oldsystem to the new system; and

(h) In conjunction with Information System staff to work out the increase in processing power, diskstorage, workstations and communication network requirements and assist in the implementationof the system.

Timeframe for deliverables

9. It is envisaged that Phase I is to be completed within six months and Phase n to be completedin thirty months. A detailed proposal outlining the approach and methodology, C.V. of consultants, etc. includinga detailed implementation plan must be providtd. A statement of deliverables must accompany the proposal.

- 52 -

Annex 9 - Page 5 of 9

B. Total Quality Management

Introduction

1. Ia the context of the World Bank financed Power System Development project, the Tenaga NasionalBerhad wishes to enhance its organizational performance, in terms of its overall organizational efficiency,productivity, and quality. The World Bank would finance the proposed consultancy study, and as such, it shallbe invited to review the consultant's reports and make comments.

Objectives

2. Taking into account the significant changes taking place in TNB as a result of the incorporation of theNational Electricity Board (NEB), and the changes that shall take place upon the subsequent privatization ofTNB in the near future, the services of the consultants are needed to assist the NB management intheoperationalization of its changed management efforts, and, in particular, in the implementation of the 'TotalQuality Management' program.

SCOpe of Work

3. The consultant shall undertake the following:

(a) Together with the TNB's Quality Project Group (hereafter referred to as the project group), reviewthe existing quality-related strategies, policies, programs, and documentations, and establish formalcorporate quality objectives and policies, appropriate to the current and envisaged corporation's businessenvironments;

(b) Together with the project group analyze existing organisational structures, systems, and managerialcapacity, and identify quality-related areas of concerns and prioritize them;

(c) Based on (a) and (b) above, and together with the project group, formulate the short and the long-term action plans for TNB management comments and approval. In this context the consultant shall berequired to develop appropriate measurement and control mechanisms and to train the understudyingproject group members on the methodology of action plan monitoring and review,

(d) Assist the Tenaga Nasional management to establish the Corporate Quality Management Secretariat,whose primary functions shall include the following.

(i) To understudy the consultants

(ii) To initiate and implement preparatory activities together with the consultants

(iii) To take over the consultants' functions after initial trial runs, to continue the implementationof the programs.

(e) Together with the project group, conduct briefings and seminars for top and senior level executivesin order to bring about awareness regarding thei- roles and their commitment to quality improvementand management efforts;

(f) Train and prepare the project group members and selected cadres to assume the role of qualityfacilitators and resource people;

- 53 -

Annex 9 - Page 6 of 9

(g) Together with the project group, establish and, where appropriate, enhance quality improvementteams at operational levels and provide them with appropriate training and guidance;

(h) Conduct review on the program two years after iwrlementation of the Total Quality ManagementProgram;

(i) TNB shall be furnished with the following:

(i) An inception report, to be prepared within eight weeks after mobilization, including theconsultant's perception of TNB's current and envisaged business environments, the existing quality-related strategies, policies and programs, and areas of concerns thereof. The inception reportmust include draft proposals of the short and the long-term quality improvement action plans forTNB;

(ii) First progress report, to be submitted within one month of the acceptance of the inception report,furnishing detailed recommendations on the action plans and appropriate measurements andcontrol mechanisms, as well as schedule of briefings and seminars for top and senior levelexecutives;

(iii) Second progress report, to be submitted within one year of the establishment of qualityimprovement task forces and quality improvement teams at operational levels, highlightingproblems and improvisations therefrom; and

(iv) A concluding report to be submitted within one month of the program review, commenting on thesuccess (or lack of it) of the total program, the factors that would lead to potential problems andthe follow-up actions required.

C. Demand Side Management and Electricity Conservation

Background

1. Tenaga Nasional Berhad (TNB) of Malaysia, a private power utility, has a license to generate,transmit and distribute electricity in Peninsular Malaysia. The current system is about 3,650 MW peak demand,20 TWh energy. It is envisaged that peak demand will reach around 5,500 MW in 1995. Faced with a rapidincrease in demand, TNB will embark on a large power development program. In addition to increasing supply,TNB would like to explore the possibilities for demand-side management (DSM) through load management andal.ed activities with the dual objectives of system load modulation and promoting efficient use of electricity.

2. Historically, TNB has treated the level of electricity demand, in terms of peak load and thedemand curve, as a fixed input and proceeded to plan and implement the least cost generation mix to meet thatload. Considering electricity demand as a partial-controllable variable, DSM introduces a new element into theplanning framework by allowing for a delilterate intervention by TNB in the market place to alter the load shapein order to achieve strategic objectives of peak clipping, valley filling, load shifting, strategic conservation,strategic load growth and flexible load shape. These desired objectives are consistent with the MalaysianGovernment's energy policy of promoting efficient use of energy. DSM schemes offer an opportunity for TNBto help reduce load growth in the short term, thereby postponing or even eliminating supply interruptions, andthis will help the country towards more efficient use of energy. Efficient electricity use will also help to mitigateadverse environmental and aesthetic impacts by burning less fuel and implementing fewer projects.

3. Electricity tariffs offered by TNB are based on long-run marginal cost (LRMC). TNB adopteda price-induced DSM scheme in 1985 when the peak and off-peak tariffs were introduced for medium and high

- 54 -

Annex 9 - Page 7 of 9

voltage ( >6.6kV) consumers. Shortly after its introduction, many eligible customers opted for the time of daytariff but now it attracts new customers only. There is therefore a need for renewed emphasis to seek innovativeways to condition and/or curtail the system load growth.

4. In order to design appropriate DSM schemes, it is essential to understand electricity consumptionpatterns among various types of consumers, based on detailed end-use analysis. The demand for electricity isclosely linked to ownership of electrical appliances or equipment. Identifying the major end-uses of electricityof various consumer categories is the first step to determine the targets for implementing DSM. The major end-uses according to consumer groups are:

1. Residential Customers

a. Air-conditioningb. Lightingc. Refrigeration

2. Commercial Customers

a. Air-conditioningb. Lightingc. Lifts/Escalators

3. Industrial/Mining Customers

a. Air-conditioningb. Lightingc. Motive Power (motors)

5. The contribution of these major end-uses to total sales by consuming sectors has been estimatedto be (total does not sum to 100%):-

AIR CONDITIONING LIGHTING ANOTHER ENDI _ _ _. _ _ ._ _._ _. _ _ _ _ _ _ _ _ _ _ _ _ U SE

RESIDENTIAL 9.0% 20.2% 46.8% (FRIDGES)

• COMMERCIAL 533% 19.9% 9.0% (LIFT/ESC)

* INDUSTRIAL 16.2% 5.9% 63.7% (MOTORS)

* MV and HV consumers only

Objectives and Scope of Work

6. The main objective of the consultancy services is to study the feasibility of implementing DSMschemes by TNB with a view to modulate TNB's system load profile and promote efficient use of electricity.Subsequently, the consultant should develop a series of action plans together with the implementation of at leasttwo pilot projects to asses their effectiveness.

- 55 -

Annex 9 - Page 8 of 9

7. The scope of work for the consultants will be as follows:-

(a) To review all related work in demand-side management carried out by TNB, assess if furtherstudies need to be carried out and develop a scope and timeframe for such studies;

(b) To identify and prioritise DSM schemes for implementation, and recommend at least two pilotprojects for implementation during the study period;

(c) To prepare a detailed implementation plan in line uith the dual objectives of system loadmodulation and promoting efficient use of electricity in Peninsular Malaysia. In preparing theplan, due consideration must be given to the institutional capabilities of TNB and the possibleinvolvement of Government agencies concerning fiscal incentives and appropriate assistance. Theoverall plan would be divided into a series of action plans;

(d) To conduct technical and economic evaluations for each of these DSM action plans including costbenefit analyses and probable customers response. In this regard, to provide cost estimates ofsuch schemes and their benefits to TNB and its target customers;

(e) To evaluate the technical and economic performance of at least two selected pilot DSM projects.The pilot projects will benefit TNB counterparts through hands-on experience for futureevaluations of other DSM schemes. (The pilot projects could be any DSM scheme successfullyimplemented by other utilities).

Conduct of the Study

8. The study will be conducted in two phases as follows:

Phase I (To be completed within two months).

This phase would comprise discussions with relevant TNB departments and other governmentagencies, and review of existing studies to be followed by an interim report. The report would present:

(a) a clear definition of DSM objectives;(b) a broad assessment of the technical and economic feasibility and scope for DSM;(c) the most appropriate (cost effective) methods of achieving the DSM objetives;(d) a broad estimate of the cost and benefits.(e) a recommendation to implement at least two pilot projects during the second phase.

The interim report should indicate if any further studies need to be carried out. It should bediscussed with TNB before embarking on the second phase of the work.

Phase 2 (to be completed within four months).

This phase would comprise further work necessary to formulate the detailed DSM implementationplan covering the scope of work outlined in paras 6 and 7 above and presentation of a draft final report.Concurrently, a technical and economic assessment of at least two pilot projects recommended in the firstphase would be carried out. The report would be discussed with TNB prior to finalization.

- 56 -

Annex 9 - Page 9 of 9

Consultant's Oualifications and E=erience

9. For the purpose of this study, it is expected that nine man-months of expert services are required.This should comprise one or two persons with wide experience in evaluating, designing and implementing DSM3chemes in utilities. The experts must be able to provide cost estimates of DSM schemes and to give advice onpotential pitfalls of implementing such schemes. The experts are expected to work closely with relevant TNBofficers who will carry out most of the detailed analysis with the experts' guidance. TNB would provide a highlevel of counterpart assistance during the course of this study.

10. The experts would also be required to consider innovative means to achieve the desired goalsthrough peak clipping, valley fillin load shifting, strategic conservation, strategic load growth and flexible loadshaping, etc. and to recommend state-of-the art technologies for hardware, communication links and softwareto accomplish load-management. The experts are also expected to recommend measures for integrating demand-side management planning with supply side least cost planning for generation expansion, and institutionalisingthis activity.

11. It is envisaged that at least one of the experts will work in Malaysia on a full-time basis. Oncompletion of the study, the experts together with local counterparts will present the report and findings madeon the pilot projects to TNB management.

12. Further assistance may be sought from the experts in the implementation of the recommendationsbut that would be covered by separate terms of reference.

ANNEX 10

MALYA

POWER SYSTEM DEVELOPMENT PROJECr

ThB's CAPITAL EXPENDITURES 1990-2000

TOTAL 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000

Hydro 5548 46 352 425 612 528 739 727 612 490 462 555

Thermal 14920 78 979 1167 2070 1890 1996 1200 1077 1441 1269 17S2

Transmission 5843 192 375 360 562 639 549 637 644 514 559 812

Distrnbmtion 6142 272 433 581 391 400 431 558 633 716 810 916

Rurd Eletrifation 453 91 146 95 90 31 0 0 0 0 0 0

Other 1239 56 85 97 98 105 106 122 130 138 146 15S

TOTALS

Foreign Component 17030 22211228 1700 2099 1957 1931 1552 1479 1549 1432 1881

Local Component j 17114 514 j 1141 1026 1724 1636 1890 1693 r 1617 1750 1814 j 2310

TOTAL WITHOUT I)C 134144 736 2369 2726 3824 3593 3821 3245 3096 3299 3246 14190

Interest During Constr. 239S 4 47 122 203 226 343 275 273 273 3191309

TOTAL WrTHIDC 136538 740 J 24161 2848 4027 3819 41641 3519 3369 3S73 356 4499

- 58 - ANNEX 11 - Page 1 of2

MALAYSIA

POWER SYSTEM DEVELOPMENT PROJECT

Propect Cost Estimates(USS millions)

Item Local Foreign Total

A. Paka Combined-Cycte Power StationPreliminary works 1.0 0.0 1.0Civil works 12.0 3.0 15.02 x 100 MW gas turbine generators 0.0 66.0 66.01 x 100 MW steam turbine generator and boilers 0.0 44.9 44.0Plant mechanical systems 0.0 21.0 21.0Plant electrical systems 0.5 9.4 9.9i%3chanical construction 12.5 2.5 15.0Electrical construction 5.5 1.0 6.5Construction supervision 4.0 1.0 5.0Consulting services 1.0 6.0 7.0Eng. and Admin. overheads 1.0 0.0 1.0Duties and taxes 37.0 0.0 37.0

Base Cost 74.5 153.9 228.4Physical contingencies 7.5 15.4 22.9Price contingencies 7.4 15.4 22.8

Subproject Cost 89.4 184.7 274.1

B. 275 kV transmission line (Kamwung Awah-Yong Peng)Right of way 5.9 0.0 5.9Conductors 12.7 0.0 12.7Towers 0.0 5.4 5.4Insulators and fittings 0.0 2.6 2.6Survey and wayleave clearing 1.3 0.0 1.3Foundations and tower 6.3 1.0 7.3Stringing and commissioning 1.0 0.4 1.4Eng. and Admin. overheads 0.9 0.0 0.9Duties and taxes 2.3 0.0 2.3

Base Cost 30.4 9.4 39.9

Physical contingencies 3.0 0.9 3.8Price contingencies 2.5 7.7 10.2

Suborolect Cost 35.9 18.0 53.9

C. 275 kV System for Kuala LumpurPudu Ulu Substation

2 x 240 MVA transformers and installation 0.2 1.0 1.211 x 275 kV GIS switchgear and installation 1.5 10.0 11.5Station auxiliaries 0.3 0.1 0.4Civil works of building 0.6 0.0 0.6

Subtotal 2 11.1 13.7

Jalan Galoway-Substation2 x 400 MVA transformers and installation 0.3 1.3 1.66 x 275 kV GIS switchgear and installation 0.9 5.5 6.4Station auxiliaries 0.3 0.1 0.4

Subtotal 6.9 8.4

-59 - ANNEX 11 -Page 2 of 2

g75 kV Cable Feeders2 x 4 km, 400 MVA oil-filled cables and installation 13.9 13.9 27.6Project cowponent cost 1.0m 31.9 49.9Eng. and Admin. overheads 1.0 0.0 1.0Duties and taxes 7.7 0.0 7.7

Pase Co8t 58.7 6. M:6

Physical contingencies 2.6 3.2 5.8Price contingencies 1.3 1.6 2.9

Suboroiect Cost 30.6 36 7 67.3

Total Base Cost (In 8/1991 Prices) 132.4 199.3 331.7Physical contingencies 13.2 19.9 33.1Price contingencies 11.2 24.7 35.9

Total Proiect Cost 156.8 243.9 _00 7Interest during construction 0.0 28.6 28.6

Total Ffnancing Required 156.8 272.5 429.3

- 60 -

ANNE% 12

MALAYStA

POWER SYSTEM DEVELOPMENT PROJECT

DISBURSEMENT SCHEDULE

Disbursement Disbursement ProfileBank FY Semester Annual Cumulative Project Standard La

(In Million US$) (Cumulative X)

1992 I 0.0 0.0 0 0II 6.0 6.0 3 3

1993 I 6.0 12.0 6 6II 8.0 20.0 10 10

1994 I 16.0 36.0 18 18II 24.0 60.0 30 30

1995 I 24.0 84.0 42 42II 24.0 108.0 54 54

1996 I 24.0 132.0 66 62II 24.0 156.C' 78 74

1997 I 24.0 180.0 90 82II 20.0 200.0 100 86

Ia Based on the standard profile for power projects in Asia issuedon April 25, 1990.

- 61 -

ANNEX 13 - Page 1 of 12

MALAYSIA

POWFVR SYSTEM DEVELOPMENT PROJECT

Sultan Ismail Power Station-Paka

Environmental Asessment - Summary

1. INTRODUCTION

1. The Sultan Ismail Power Station (SIPS) of the Tenaga Nasional Berhad(TNB), in the State of Terengganu on the east coast of Peninsular Malaysia, hasbeen in operation since 1984. TNB proposes to expand this station by installingthree additional combined-cycle blocks of 300 MW each. An environmental impactassessment (EIA) report entitled "Environmental Impact Assessment-LLN Proposed Gas

Turbine - Combined-Cycle Extension Project at Sultan Ismail Power Station, Paka"was prepared in accordance with the guidelines of the Department of Environment

(DOE) of Malaysia by the Institute of Advanced Studies, University of Malaya inAugust, 1990. The EIA report was submitted to the DOE for approval as required by

the Environmental Quality Act. Approval has been granted by the DOE on 31stDecember, 1990 subject to 20 conditions (see Annex 1). Appropriate actions have

been and are being taken by TNB to comply with these conditions. This report

presents a summary of the proposed development, the EIA report on theenvironmental impacts of the proposed expansion and recommended mitigationmeasures. Table 1 provides a comparison of the main predicted impacts with theDOE standards and the IBRD guidelines.

HI. PROPOSED DEVELOPMENT

Existing DeveloRment

2. The SIPS is located in the Paka-Kerteh Industrial Estate, an area of

about 6 km2, zoned for industrial development. The estate is bordered on the east

by the South China Sea and on the west by the Federal Highway Route 3. Furtherwest are the foothills of the Terengganu Highlands. The location of SIPS is shown

in Annex 2. Apart from the towns of Paka and Kerteh, there are some villageswhich are about 5 km from the power station. The closest residential area is the

TNB staff quarters.

3. The existing power plant comprises 3x300 Mw natural gas fired combined-cycle blocks. During open cycle operation, the flue gases are exhausted through35 m blast stacks of the gas turbines. During combined-cycle operation, fluegases are emitteA through Lhe 35m waste boiler stacks. Boiler water is taken fromthe Public Works Department's water supply system and treated on site before use.Waste from the water treatment plant is discharged to the sea afterneutralization. Boiler blow-down (which is clean water) is discharged to the seathrough the out-fall without any treatment. But, boiler cleaning wastes aretreated to comply with DOE's standards prior to disposal to the sea. Coolingwate. is drawn from the sea at about 600 m from the shore using a submergedintake. Heated water is discharged into the sea about 200 m from the shorethrough a submerged out-fall about 450 m south of the intake.

- 62 -

ANNEX 13 - Page 2 of 12

Table 1. Summay of Main Environmental Impacts

Impact Predicted DOE IBRD

N-itrog-en Oxide (N02

AmiblentAinual average (ug/cu m) < 10 - 1001-hour maximum (ug/cu m) 150 320

EmiSsLOXug/Joule 0.03 0.086g/cu m 0.14 1.7 -

Sulfur Dioxide (S02)

A=mbientAnnual average (ug/cu m) <1.0 10024-hour max. (ug/cu m) 90 105 500

EmissionEach stack (g/cu m) 0.41 L/ 3.5 -Total incremental (tonnes/day) 82 la - 500

Dust (Total suspended particles TSP)

AmbientAnnual average (ug/cu m) <1.0 90 10024-hour max. (ug/cu m) 100 260 500

Emission (ug/cuA m) 0.05 /a 0.4

Noise (dB (A))

Industrial AreaPower plant 85-100/c 90 (75)Lb 70Boundary fence 61 55 55

Residential Area <55 55 55

Cooling Water Temperature (o C)

Maximum allowable 39 40Maximum rise within plume 5Within 300 m 1

Chlorine in Cooling Water (mg/1) 0.05 1.0

g When using distillate (1X sulfur) instead of gas in an emergency.&b Figure in brackets refer to WHO standards./c Mitigation measures necessary (usual for gas turbine plants).ug/cu m - micrograms/cubic meter; mg/l - miligrams/liter.

- 63 -

ANNEX 13 - Page 3 of 12

To control fouling of the cooling water system, cooling water is chlorinated tomaintain a residual chlorine level at the condenser outlet of 0.2 to 0.3 mg/l. Asystem of perimeter drains diverts clean storm water runoff from the power stationto prevent contamination and minimize waste water requiring treatment. Thisdrainage system extends over the present and proposed power station site. Aseparate underground pipe system collects flows from station areas which may becontaminated with oil and other spillage which includes road drainage in oilloading/unloading areas, transformer compounds and oil tank farm. The collectedwaters are conveyed to an oil separator for treatment. Treated effluent isdischarged to the sea via the out-fall. Sludge from the treatment plant isremoved by tanker for further treatment off-site. Spillage from the fuel oil tankfarm and the transformer areas are pumped to a corrugated plate oil separator fortreatment. Agair. the treated effluent is discharged to the sea via the out-fall.The separated oil is pumped to a sump which is periodically emptied by contractorfor off-site disposal. A sewage treatment plant has been provided to handledomestic waste. The plant is capable of handling the existing power station wastefrom some 260 persons. The treated effluent from the sewage plant is dischargedto the sea via the cooling water out-fall. Sludge from the treatment plant isperiodically removed by tanker for off-site disposal. Natural gas burned at thepower station is supplied directly to the station by pipelines with appropriatesafety provisions. The gas has a very low sulfur content of 5.7 mg/cu m maximum.Distillate oil, which would be used in an emergency following failure of gassupply, would have a sulfur content of 1X maximum.

ProQosed Exoansion

4. To the north of the existing three 300 MW combined-cycle blocks, withinthe existing SIPS compound, TNB proposes to install three additional 300 MWcombined-cycle blocks. The first of these blocks, proposed to be financed by thuWorld Bank, will be commissioned by September 1994. The following provisions havebeen or are being made for the expansion:

(a) The Alte for the new units has already been levelled and prepared.Therefore, there will be no major earth-works required. Existing sealedaccess roads will be adequate for the proposed extension and no new roadswill be constructed other than the extension of the internal road system.

(b) The capacity of the existing perimeter drainage system will besufficient to service the proposed expansion.

(c) A new cooling water intake and out-fall system will be constructed tothe north of the existing system. An additional sewage treatment plant willbe installed to cater for the increased work-force. The contaminated waterfrom the new units will be collected and treated in the same manner as theexisting units with a new oil/water separator. The present boiler watertreatment plant will be expanded to cope with the additional requirements. Atreatment facility similar to the existing facility will be provieed to treatspillage and contaminated water. Wastes from boiler cleaning will becollected in a holding sump and treated to comply with DOE standards prior todischarge.

(d) The existing fuel oil storage capacity does not need to be increased andno additional spillage and contaminated water treatment plant is, therefore,required.

(e) During the construction phase, the estimated total construction work-force is about 1,500 persons. The contractors would be required to provide

- 64 -

ANNEX 13 - Page 4 of 12

their own sanitation and septic system for their workers, both at the workcamp and on site.

m. ENVRONMENTAL [MPACTS

ImRacts on the Natural Environment

5. The power station is located at an elevation of 6.5 m on marine sanddunes within a large expanse of the flat coastal plain formed between the riversSg Paka and Sg Kerteh. The coastal area comprises alluvium and marine sands overgranites to a depth of 25 to 35 m. The soil of the area has high permeability,low moisture holding capacity, low nutrient reserves and low nutrient retentioncapacity.

6. Annex 2 shows the distribution of vegetation in areas around the powerstation. Scrub grassland is found within the coastal strip about 1 km wide and 6km long centered around the power station. Further west is mixed mangrove swampsextending some 3 to 4 km inland and about 10 km north and 5 km south of the powerstation. Within the swamp areas are some rubber and coconut plantations and smallpadi fields. Further west towards the foothills of the Terengganu Highlands aremainly oil palm plantations with forested areas in the north towards Dungun. Thevegetation cati be classified into four types: (a) coconut/tembusu-lallang; (b)Melastoma, Gleichenia, Rhodomyrthus; (c)tembusu thicket; and (e) mangrove. Theproposed expansion site has already been prepared and is presently grassed. Theimplementation of the project is, therefore, not expected to affect the flora,fauna and the natural environment in the surrounding areas. Construction of thecooling water system would have a temporary impact on the beach. However, afterbackfilling and removal of debris, the beach would be restored to its originalcondition.

Impacts on the Water Quality

Existing Water Quality

7. Data collected from sampling during the EIA study on three separateoccasions at nine locations 40 m from the shore line and up to 300 m from thepower station cooling water out-fall showed that: (a) Tne free chlorine levelswere below the detection limit of the analytical method of 0.05 mg/l; (b)Temperatures of the seawater for areas outside power station cooling waterinfluence have mean values of about 28 to 300C with a range of 25.6 to 320C. Atabout 100 m from the power station cooling outfall, water temperatures were closeto the ambient of 30°C, rising to 350C near the centre of the cooling water plumeemerging from the submerged outfall; (c) Dissolved oxygen levels at locations nearthe outfall ranged between 6.2 to 7.0 mg/l with a mean of 6.4 mg/l. The meanvalue was considered to be typical of well-mixed sea water with no significantpollution; (d) BOD levels were found to be close to the limit of detection atsites near the outfall, ranging between 0.8 to 2.2 ppm with a median value of 1.0ppm; (e) Coliform measurements gave median values of 13 MPN/100 ml for presumptivecoliform and 7 MPN/100 ml for faecal coliform which indicate that sewage pollutionwas insignificant in the sea off the station site; (f) Salinity measured in thecoastal water off the Paka are was about 32 parts per thousand (ppt) with nosalinity gradient with depth. The measurements compared well with the reportedmean salinity in South China Sea of between 31.5 and 33.0 ppt; (g) Nitrate andtotal Kjedhal nitrogen levels ranged from about 0.1 and 1.6 mg/l respectively; (h)Phosphate levels ranged from below detection limit to 0.7 mg/l; and (h) Oil and

- 65 -

ANNEX 13 - Page 5 of 12

grease levels ranged from 1 to 4 mg/l. The above data showed that there was nosignificant pollution to the coastal waters from the SIPS.

ImRacts of the Power Plant Effluents

8. The proposed expansion can affect the water quality during theconstruction phase as well as the operation phase of the development. During theconstruction phase there are three main sources of pollutants: (a) storm-waterrunoff from disturbed areas; (b) water contaminated with oil and grease; and (c)sewage. As the site has already been prepared, there will be minimum disturbanceof ground surface. Storm-water runoff would have minimal sediment load and wouldbe collected by the existing perimeter drains and disposed off to the sea. Wastewater contaminated with oil and grease with concentration in excess of thedischarge limit set by DOE will be directed to the existing oil separator at SIPSfor treatment prior to discharge. Untreated sewage from work area would not beallowed to be discharged into natural waters. Contractors would be required toprovide their own sanitation and septic system at both the work camps and workareas. During the operation phase of the project, in addition to the above threesources, there are four other major sources: (a) cooling water discharges; (b)water treatment plant effluent; (c) waste from boiler cleanup; and (d) chlorinefrom the cooling water system. Storm-water runoff will be collected by theexisting perimeter drainage system and discharged into the sea. With thecontaminated water treated, contaminants and sediment loads of the storm-waterrunoff would be minimal and would have no significant impacts on the water qualityof the receiving water body. As part of the expansion, additional sewagetreatment plant, oil water separator and treatment sump for boiler cleaning wastewill be provided. Waste from water treatmenL plant will also be neutralized towithin DOE standards. Therefore, impacts from sewage, contaminated water, watertreatment plant waste and boiler cleaning waste during the operation phase of theproposed expansion will be kept to within acceptable levels.

Impact of the Cooling Water Discharge

9. The cooling water discharge temperature will be kept within the DOEstandard of 400C maximum. According to the thermal plume modelling study carriedout, surface water temperature in the immediate vicinity of the cooling watersubmerged outfall will be within about 4 to 5oC above the natural ambient watertemperature. Within about 300 m from the submerged outfall, the water surfacetemperature will be only about 1°C above the ambient. Therefore the effect ff thecooling water discharges on the sea water temperatures would be well withinlimits. As the control of fouling using chlorine will be carried out similar towhat is being done at the existing units, based on the data discussed above, theimpacts on the water quality and also the aquatic environment will be negligible(see paras. 10 and 11 below).

Existing Aguatic Environment

10. With respect to the impacts of the cooling water, the variousparameters which were assessed include the diversity and abur.dance of planktons,benthos, aquatic plant and fisheries. The data collected during the EIA studyshowed that: (a) the diversity of phytoplankton (53 species) was similar to di'-acollected prior to the construction and operation the existing SIPS; (b) theabundance of zooplankton in the open water 1 km off SIPS was approximately 400 to2000 per m3 which fell within the range reported prior to SIPS; (c) the benthosdata showed that there arc some 17 species of Polychaete, 10 species of Crustacea,about 7 species of Mollusca, and a whole range of Nematoda, Nemertea, Gastrotrichaand others. The benthos counts ranged from 300 to 5,355 per m2. Enrichment of

- 66 -ANNEX 13 - Page 6 of 12

some sy cies was noted and attributed to the slight ir':rease in temperature andnutrient levels near SIPS outfall; (d) the area is moderately productive withregard to turtles (the main species are Dermochelys coriacea, Chelonia mydas,Lepidochelys olivacea and Eremochelys imbricata); (e) there are scattered coralheads. The main species are the wire type coral including Potherion whi.h arebelieved to occur at the 30-40 m contour depth, while 6-8 km off the coast ofKerteh four morphological types of Gorgonia, one Dendrophllia and some unknowncoral have been reported. The coral diversity off the coast off the Paka-Kerteharea is considered to be low compared to those off the coast in NorthernTerengganu and the total of 50 genera and 170 species occurring either in the formof coral reefs or scattered coral heads off the East Coast of Peninsular Malaysia,which concentrated at a group of islands in northern Terengganu and Johore; and(f) the fish density off the Paka-Kerteh area was estimated at 3-8 tonnes per sq.nautical mile as compared w,th 10-12 tonnes per sq. nautical mile for Terengganuand 3-17 tonnes per sq nautical mile for the East Coast of Malaysia as a whole.Much of the fishing grounds off the Paka-Kerteh area appeared to be un-trawlabledue to the presence of isolated rocks at a depth of between 20 to 40 m.

Impact on the Aquatic Environment

11. In general, the impacts of most of the discharges on the aquaticenvironment can be expected to be acceptable as the various effluent standardswould be met. The various data discussed in para. 9 above give an indication ofthe impacts of the exiting SIPS on the aquatic environment. Based on these dataand the thermal plume modelling study, it is concluded that:

(a) the impacts on zooplankton and phytoplankton diversity would benegligible;

(b) there would be some degree of enrichment of benthic fauna in terms ofquantity and diversity near the submerged outfall;

(c) the impacts on the offshore coral heads would be negligible as they aregenerally absent from areas within the zone likely to be influenced bythe cooling water plume;

(d) the impacts on turtles would be negligible because turtle has beenreported to bask in areas with temperature exceeding ambient temperatureby 100C and the sphere of influence of the thermal plume up to 1°C isrestricted to within 300 m of the outfall;

(e) the impacts on fisheries is expected to be minimal;

(f) given that the levels of free chlorine in the sea water at the outfallwere found to be below 0.05 mg/l and that benthos including adultgastropod and bivalves were found near the outfall, the impacts of theexpansion due to the chlorine in the cooling water discharges will beinsignificant; and

(g) trapping of aquatic animals into the cooling water system is notexpected to result in significant change in their population andtherefore the impacts would be insignificant.

- 67 -

ANNEX 13 - Page 7 of 12

Impacts on the Atmospheric Environment

Potential Air Pollution Sources

12. There are three hydrocarbon sources in the Paka-Kerteh area about 3 to 4km from SIPS: the gas processing plant, the crude oil terminal and the oilrefinery. There are six saw mills close to SIPS. They are the major sources ofparticulates in the area. The sawmills dispose of sawdust by open burning whichresults in substantial particulates and odor emissions. Natural salt spray fromthe nearby ocean is also a source of particulates. Air pollutants emitted by theSIPS and the proposed expansion will be mainly NOX, as the natural gas fuel hasnegligible sulfur content.

Existing Air Quality

13. TNB has an ambient air quality monitoring system around SIPS monitoringambient S02 at three locations and dust deposition rates at two of these sites.SO2 is measured using the lead candle method. Dust deposition is measured usingdust gauges. These gauges also collect rainfall. The acidity of the collectedrain water was also measured. As part of the EIA study, the following monitoringof the ambient air was done on several occasions: (a) 24 hourly total suspendedparticulates (TSP) levels using high volume air samplers; (b) 6 hourly ambient SO2levels by the West-Gaeke Method; and (c) 6 hourly ambient NO2 levels by the Greiss-Saltzman Method. Based on TNB's 1989 data, the ambient SO2 levels in the Paka arearanged from 2 to 8 pg/m3 as compared to the DOE's proposed air quality guidelinesof 105 pg/m3 for 24-hourly average ambient air SO2 level. Six hourly measurementsby West Gaeke Method ranged from 2.8 to 9.6 pg/m3. The SO2 levels are similar tothose measured in the Kuala Lumpur City, Kajang and the town of Kapar of 6.8-7.8pg/M3. The ambient air NO2 6 hourly measurements ranged from 2.3 to 12.5 pg/M3 ascompared to the ambient air 24 hourly.NO2 guideline of 260 pg/M3 and the levelsmeasured in Kuala Lumpur City of 27.1 pg/m3 and at Kajang of 11.2 pg/m3. The dustdeposition rates measured in 1989 ranged from 0.12 to 4.28 tonne/km2/month ascompared to the recommended secondary air quality guideline for dust depositionrate of 4.0 tonne/km2/month. The higher dust deposition rates were considered tobe influenced by road work or burning off near the monitoring sites. TSP valuesobtained as part of the EIA study ranged from 35 to 46 pg/m3 as compared to theproposed ambient air TSP guideline of 260 pg/m3. The pH levels of rain watercollected in the dust deposition gauges during 1989 ranged 6.26 to 7.2. Twosamples with values of 8.74 and 9.72 were measured during June, 1989. Both thesesamples were considered to be affected by ash fall-out collected. The source ofthe ashes was thought to have originated from the open burning of sawdust. TheMalaysian Meteorological Service monitored rain water acidity throughout thePeninsular Malaysia since 1976 with the monitoring network expanded in 1984. Thevolume weighted average pH values measure' it the various coastal locations on theeast coast of Peninsular Malaysia ranged from about 5.3 to 5.7 in Kota Bharu, 5.3to 5.5 at Kuala Terengganu to the Nortn of Paka and 5.3 to 5.1 at Kuantan to thesouth of Paka. Based on these data it is considered that the region around Pakais not affected by acid rain.

Potential ImRacts

14. During the construction phase, the expected impacts on the atmosphericenvironment will be related to dust emissions. Given that minimal site work isinvolved, with the judicial use of water tanker to spray access roads with waterto control dust emissions the impacts during the construction phase will benegligible. During the operation phase, the impacts of the proposed development

- 68 -

ANNEX 13 - Page 8 of 12

will be related to the changes in the ambient air quality due to the NOX and S02

emissions. Dust emissions from the proposed units will not be significant and

would have no significant impacts on the atmospheric environment.

Modelling - Dispersive CaRability of the Atmosphere

15. In modelling the dispersive capability of the atmosphere, the following

parameters were taken into consideration: (a) the characteristics of the climate

(temperature, humidity and rainfall); and (b) seasonal and prevalent wind speeds.

Limited atmospheric soundings were carried out during the EIA study period at Paka

and the data indicated that soundings at Kota Bharu in the north which is also

coastal in characteristics should provide good representation of tha situation at

Paka. The soundings from Kota Bharu showed that surface inversions are usually

formed during the predawn period and persist till morning. On average there are

about 14 days per month during which inversions occur which are usually eroded by

surface heating by 1100 hours. The mixing height being the depth of theatmospheric layer within which good mixing is achieved usually reaches up to 2000

m at midday. Six low level atmospheric soundings were carried out at Paka. Theresults showed that the atmospheric stability at Paka does not behave differently

from those monitored at Kota Bharu. Ground based radiative inversion of up to 350

m in depth was measured. The maximum mixing height recorded during the field

study was about 1700 m. Pilot balloon flights were also made to examine the

vertical wind structure close to the SIPS. The results showed the presence of

shallow land breeze in the morning. The depth of the land breeze is about 1 km.

The above climatic information was used in the plume modelling exercise to predict

the behaviour of the chimney emissions and the resulting ground level

concentrations of the various pollutants.

Ground Level Concentrations of NOX and 50

16. The ground level ambient concentrations of NOX and S02 were predictedfor a chimney height of 35 m. NOX emission from each gas turbine was assumed to

be at the specified maximum level of 100 ppm (0.14 gm/cu m). S02 emissions were

predicted for emission levels of: (a) natural gas firing - 5.7 mgm/cu m (for

annual average values); and (b) distillate firing - 0.41 gm/cu m (for 24 hour

maximum values). Model predictions indicated that the maximum hourly average

ground level concentration of NOX will be about 150 pg/cu m which is well below

the DOE standard of 320 ug/cu m. The annual average NOX value was predicted to be

below 10 ug/cu m, well below the IBRD guideline of 100 ug/cu m. The 24 hour S02

concentration was predicted to be 90 ug/cu m, which is within the DOE standard of

105 ug/cu m. The annual average concentration of S02 was negligible.

Impact of Noise

Acoustic Environment

17. Apart from the SIPS, two noise sources are clearly identifiable around

the power station. They are: (a) the traffic on the highway running along the

western boundary of the SIPS; and (b) saw mills to the west of the highway.

Natural noise sources such as wind and wave noise also contribute to the generalambient noise levels in the area. Three sets of measurements were made near the

highway to assess the traffic noise levels. It was found that the LS5 level wasabout 51 dB(A). Measurements taken at area remote from the highway and the SIPS

indicated that the background noise level in the region was about 40 dB(A).Measurements were also taken in several areas in and around the SIPS. In the

noisiest areas close to the power equipment, the noise levels ranged from 85 to

100 dB (A). Inside the control building, the noise level was 45 dB(A). The noiselevels tapered to about 40 dB(A) at distances of about 750 m from the existing

- 69 -

ANNEX 13 - Page 9 of 12

SIPS. For the proposed expansion, TNB's specifications require that all the unitscomply with all of the following noise emission limits:

(a) < 85 dB(A) measured at 1 m;

(b) < 55 dB(A) measured at 120 m; and

(c) < 55 dB(A) measured at the station boundary.

Predicted Noise Impact and Mitigation Measures

18. The EIA report concluded that it was difficult to quantify the noiselevels during the construction phase to provide an accurate measure of the likelyannoyance and no prediction of the likely noise levels was made. Predictions forthe operational phase indicated the following: (a) noise levels inside the plantwould have magnitudes similar to those measured in the existing installation (85-100 dB(A)). These levels are higher than those permitted by WHO standards; (b)the TNB staff housing just north of the SIPS boundary will be subjected to a noiselevel of up to 61 dB(A); and (c) noise levels at other residential areas will beless than 55 dB(A). In plart areas which are subject to high noise levels,workers will be required to wear protective mufflers, as done at present. Inaddition, the station would be required to establish and maintain an audiometrictesting program and a training program for employees. As TNB staff living in thehousing estate (referred in (b) above) would be moved from the area, no mitigationmeasures would be necessary.

Visual Impact

19. The impacts of the proposed expansion on the visual amenity of theregion were assessed by way of survey to define the public sensitivity and byanalyzing the dominant elements of the existing landscape. The public sensitivityanalysis revealed that the local community sees the SIPS as a sign of progress.Given that the proposed expansion will be fully contained within the existingboundary, and that the landscape in the area is monotonous, the impact of theproposed expansion was not considered to be significant. Visual perceptionanalysis suggested that the landscape in the Paka/Kerteh area can be rated asmonotonous but with natural colors and form contributed by the nearby sea. It wasconsidered that as the proposed expansion is contained within the existing sitethere should not be any significant incremental impacts from the proposeddevelopment. However, large leafy trees would be planted around the site withsome flowering plant to give colors to the area.

Safety and Environmental Hazards

20. SIPS has adopted the various safety rules and regulations governing theoperation and control of power plants. These rules and regulations cover theelectrical as well as the mechanical aspects and fire safety. A sophisticatedsystem of fire prevention and control which includes a network of fire and smokedetectors, early warning device and fire fighting equipment are in place at SIPS.The same safety procedures and equipment will apply to the proposed expansion.Provisions will also be made to control oil and gas leaks. As no new distillatetanks will be installed as part of the proposed expansion, the existing provisionwould suffice. Provisionc to control gas leaks similar to the existing systemwill be installed on the new units. The various measures to control gas and oilleaks are adequate.

- 70 -

ANNEX 13 - Page 10 of 12

Socio-economic Aspects

21. The total population of the Paka Mukim (district) was estimated to bebetween 10,000 and the number of households to be about 1,750. The town of Pakawas estimated to have a population of about 6,500, Kerteh, 4,000 and Kemasik2,500. Based on a survey carried out in 1980, about 34% of the population wereengaged in agricultural activities and 18% in fishing, with the remainder in theservice sector. A study in 1984 and the survey carried out as part of the EIAstudy indicated that after 1980 and at present only about 5% of the population arestill engaged in agriculture and 13% in fishing. About 27% are employed inprivate industries, 23% in the service sector and 19% in the public sector. Asample survey carried out as part of the EIA study during 1990 showed thatemployment struciure reported in 1984 has not changed and the manufacturing sectorhas remained the dominant employment sector. The Gross Domestic Product (GDP) percapita income of the State of Terengganu was $ 5,752 for the year 1990. For thosein the industrial areas around SIPS, the per capita GDP was expected to be higher.However, the survey showed that a large proportion of the population in thePaka/Kerteh area is still earning below $ 500 per year, suggesting the slow impactof the development on the local population. It is difficult to isolate and assessthe impacts of SIPS on the local population from the impacts of other industriesin Paka/Kerteh area. As part of the EIA study, surveys and interviews wereconducted to assess the likely impacts of the proposed expansion. The study foundthat a large majority of the local population were not opposed to SIPS (96% infavor and 2% against). The positive attitude was thought to be the result of thegeneral awareness of the local community of the benefits of the developmentespecially employment opportunity. Much improved availability and reliability ofelectricity supply were also considered as beneficial by the local population.Spin-off effect of availability of electricity supply in inducing other industriesto come into the area was also seen as a positive attribute of TNB's development.The consequential influx of migrants into the area is expected to give a boost tolocal business and trading activities. Opposition to the development was thoughtto be either from individuals who were politically motivated or the poor whoselivelihood has remained unchanged in spite of the various developmental projectsin the region.

Conclusion

22. Based on the assessment summarized in the various sections above, it wasconcluded that the proposed expansion of SIPS can be carried out in anenvironmentally acceptable manner with insignificant or negligible residualimpacts.

- 71 -ANNEX 13 - Attachment 1

Page 1 of 2

DOE Conditionis on Approval of Paka

EIA, Dated December 31, 1990

1. Emergency Response Plan (on site and off site) should be provided forthe operation of such facilities as liquid gas and distillate fuel piping systemas well as chlorine generation and injection plant in overcoming any accident oremergency. The plan should identify procedures to evacuate adjacent residents(when situation demands). Prior consultation with such authorities as, FireDepartment, Police Department, Local Government Authority and neighboringresidents before preparation of the plan. The plan should be submitted to HeadOffice of the Department of Environment, Department of Environment (NortheastRegion) and authorities which are involved, and it should be updated from time totime according to requirement.

2. Emissions of gas and other matters should be controlled to comply withStd C of Clear Air Regulations.

3. Fuel Burning Eauipment

Construction and Installation of fuel burning facilities - Require priorwritten approval from DG of DOE.

4. Scheduled waste management according to Scheduled Waste Regulation 1989.

5. Prohibition of use of PCB.

6. Sewage and Industrial Effluent

Construction and Installation of treatment system required priorapproval of Director General of Environmental Quality.

Discharge shall comply with Std B of Sewage and Industrial EffluentsRegulations, 1979.

7. Control Noise emission to within 65 dBA level at boundary fence.

8. Toilet facilities should be provided at workers camps according toHealth Ministry specifications.

9. Site Access road should be paved prior to commencement of constructionwork. It should be maintained and kept clean at all times.

10. Land clearance should be confined to construction areas only. Any landwhich is left exposed should be grown with grass of suitable plants.

11. Sedimentation pond and drainage system for collection of surface run-offshould be provided prior to land clearing and leveling work.

12. Water-spraying facilities should be provided and wheels of vehicles andmachinery use for construction work should be cleaned before they are allowed tomove on to highways to minimize dust problems.

- 72 -ANNEX 13 - Attachment 1

Page 2 of 2

13. Construction waste and garbage should be disposed off at disposal siteapproved by the Local Government Authority.

14. Open burning of construction waste and garbage is strictly prohibited.

15. Green belt should be provided around the boundary of Power Station forat least 5 m wide with landscaping through the planting of shrubs as hedges.

16. Should submit to Department of Environment before commencement of earthwork:-

(A) Names of (i) Earth-work Contract(ii) Resident Engineer

(B) 2 copies of construction and earth work contract document

17. Air Quality Monitoring on following parameters throughout the life ofstation:-

(i) Nox(ii) SOx(iii) Particulates

Monitoring stations and frequency are required to be confirmed with the DOEbefore commencement of monitoring program.

The monitoring program should be submitted to DOE before construction workbegins.

18. Stack sampling program should be planned for the monitoring compliancewith Standard C of Clean Air Regulation, 1978.

19. Sea water quality monitoring should be carried out throughout the lifeof the station.

Monitoring stations, sea water quality parameters and monitoring frequencyshould be decided with the DOE before commencement of the monitoring program.

20. Officer responsible for the management of environmental matters shouldbe in the complement of the TNB Organization Structure.

- 73 -ANNEX 14 - Page 1 of 4

MALAYSIA

POWER SYSTEM DEVELOPMENT PROJECT

TNWs FINACIAL PROJECrIONS

TABLE 1 INCOME STATEMENT 11Million M$

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 19P9

Electricity Sold (041) 12438 13638 15253 17394 19539 21909 24574 27540 30824 33660 36757 40139S Total Energy Losses 15.2X 15.7X 15.9S 15.8X 15.6S 15.51 15.3Z 15.22 15.01 14.82 14.6S 14.4SElectricity Generation (Owh) 14671 16175 18140 20663 23162 25915 29015 32458 36264 39507 43041 46891

Average Tariff - MO cents/Kwh 18.84 18.51 18.22 17.95 17.99 17.93 18.20 18.49 18.79 19.63 21.28 22.35

Electricity Sales Revenues 2343.2 2524.3 2779.6 3122.6 3515.0 3928.1 4473.5 5092.7 5792.7 6607.8 7822.9 89L,.dConsumer Contrib. Recog. as Income 118.4 132.3 137.0 151.5 173.1 183.0 186.5 190.1 194.1 200.0 209.0 208.0Other Operational Revenues 7.2 5.6 5.4 4.5 7.0 7.2 7.5 7.8 8.1 8.5 8.8 9.2

________ ----------------------------------------------------------------------------------------

O1lth1nKAL SiVENUES 2468.8 2662.2 2922.0 3278.6 3695.1 4118.3 4667.5 5290.6 5994.9 6816.3 8040.7 9187.0

Fuel Cost (Base-Load) 650.3 676.3 717.2 967.3 1445.3 1398.5 1622.2 1854.1 2013.5 2230.9 2496.7 2860.0Electricity Purchased 0.2 0.3 1.0 2.1 3.7 2.9 2.9 2.9 2.9 2.9 2.9 2.9Salaries And Wages 100.8 101.9 110.7 120.6 123.0 127.9 134.2 140.8 149.0 159.5 170.8 182.8Generation Materials & Maint. 49.4 55.8 71.6 144.8 150.0 177.5 210.6 249.8 295.8 341.6 394.5 455.5Transmission Materials & Maint. 15.3 16.2 23.0 30.5 34.0 39.8 46.8 55.0 64.6 73.8 84.5 96.6Distribution Materials & Maint. 102.7 104.1 120.7 141.2 142.0 162.1 185.1 211.2 240.7 267.4 297.2 330.2Consumer Services 14.5 14.4 15.6 19.9 23.0 26.4 30.5 35.1 40.4 45.4 50.9 57.1Billing And Collection 8.7 9.0 9.4 10.9 12.5 14.3 16.5 18.9 21.8 24.4 27.3 30.6Training And Welfare 25.1 24.0 26.5 26.0 29.3 33.7 38.8 44.7 51.5 57.8 64.8 72.8Administration 29.8 31.9 36.2 39.3 44.9 51.7 59.6 68.6 79.0 88.6 99.5 111.6General Expenses 63.2 63.7 64.5 110.6 113.7 122.1 139.5 159.1 181.4 201.5 223.9 248.9Unrealized Forex Loas 195.5 245.5 -120.0 124.2 195.3 180.0 30.0 36.0 44.0 52.0 62.0 75.0(Over)/Underprovision Last Year -35.0 -15.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

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

Operating Exp. Excl. Depreciation 1220.4 1327.8 1076.4 1737.2 2316.7 2336.8 2516.7 2876.4 3184.4 3545.8 3975.0 4524.1Revalued Depreciation 400.0 357.1 561.1 547.2 514.2 595.8 691.2 788.8 949.3 1156.7 1345.5 1518.2

______________________ --------------------------------------------------------------------------

TOTAL OPERATING EXPENSES 1620.4 1684.9 1637.5 2284.4 2831.0 2932.6 3207.9 3665.2 4133.7 4702.5 5320.4 6042.3

OPERATING INCOME 848.3 977.3 1284.5 994.2 864.1 1185.7 1459.6 1625.4 1861.2 2113.8 2720.3 3144.7Sundry Revenues Received 39.9 46.7 45.7 62.0 77.0 39.3 78.1 101.0 120.4 139.3 113.2 165.8

INCOME BEFORE INTEREST 888.2 1024.0 1330.2 1056.2 941.1 1225.0 1537.8 1726.4 1981.6 2253.1 2833.5 3310.5Interest Charged to Operation 248.0 300.5 295.8 312.8 294.3 259.1 422.6 596.0 690.7 979.4 1162.5 1335.7Amortization Deferred Charges 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

PROFIT BEFORE TAX AND DIVIDENDS 640.3 723.6 1034.4 743.4 646.8 965.9 1115.2 1130.4 1290.9 1273.8 1671.0 1974.8Provision For Taxation 164.4 54.2 99.0 230.0 211.1 170.4 244.0 205.7 125.3 140.0 395.1 528.1PROFIT AFTER TAXES 475.9 669.4 935.4 513.4 435.7 795.6 871.2 924.6 1'65.6 1133.8 1275.9 1446.7Provision for Dividends 32.5 35.2 35.2 35.2 35.2 52.6 143.8 222.8 300.8 300.8 300.8 300.8Net Income 443.4 634.2 900.2 478.2 400.5 743.0 727.4 701.9 864.8 833.1 975.2 1145.9

RATIOS AND INDICATORS ------------ RATIOS AND INDICATORS --------------------Increase in Power Salos 8.9S 9.6X 11.8X 14.01 12.31 12.12 12.21 12.1S 11.92 9.21 9.2Z 9.21X Increase Average Tariff -7.01 -1.71 -1.51 -1.5S 0.21 -0.31 1.51 1.61 1.61 4.5S 8.41 5.02

Peninsular Population - Million 13.7 14.0 14.3 14.7 15.0 15.4 15.7 16.1 16.5 16.9 17.3 17.7t Electrification Ratio 73.12 75.91 78.4S 81.32 83.11 85.01 86.61 88.3S 90.01 90.8Z 91.62 92.4ZConnections-Million (End-Year) 2.42 2.58 2.74 2.90 3.05 3.20 3.35 3.51 3.68 3.82 3.96 4.10Power Sold/Total Pop. Kwh/peraon 909 976 1065 1186 1301 1425 1560 1708 1867 1993 2127 2270

Increase Cash Oper. Revenues 2.01 7.82 9.81 12.22 12.71 11.55 13.31 13.31 13.32 13.71 18.02X14.32Working Ratio (Dir.Expen/Revenues) 49.41 49.91 36.82 53.02 62.71 56.7X 53.91 54.42 53.1 52.01 49.42 49.21Operating Ratio (Oper.Exp/Rovenues 65.61 63.31 56.01 69.71 76.6K 71.21 68.72 69.32 69.02 69.01 66.22 65.82Not Profit on Equity 11.61 14.92 17.01 7.82 6.42 9.71 8.22 7.02 7.32 6.51 6.61 6.72

After Tax ROR on Hi6torical Assets 13.21 15.42 17.72 10.72 8.31 11.12 11.21 11.3S 10.9Z 9.62 9.72 9.92Average Asset's Rate Base 6557 7218 8070 8694 9365 11117 13284 15449 19443 24673 29065 32707After Tax ROR on Revalued Assets 10.4S 12.81 14.71 8.82 7.0 X 9.12 9.21 9.22 8.91 8.0S 8.02 8,02

1 Due to rounding, the last digit in totals may appear different than the sum of columns.

- 74 -

ANNEX 14 - Page 2 of 4

TABLE 2 - SOURCES AND APPLICATIONS OF FUNDS

Million MS

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999

s6URSEH OF FUNDS:Income Before IntCrest Clarges 888.2 1024.0 1330.2 1056.2 941.1 1225.0 1537.8 1726.4 1981,6 2253.1 2833.5 3310.5+ Depreciation 400.0 357.1 561.1 547.2 514.2 595.8 691.2 788.8 949.3 1156,7 1345.5 1518,2+ Unrealized Forex Loss 195.5 245.5 -120.0 124.2 195.3 180.0 30.0 36.0 44.0 52.0 62.0 75.0+ Net Disposal of Fixed Assets 4.5 1.8 16.6 41.3 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0• Consumer Contrib. Other than RE 92.9 93.6 80.0 93.7 192.9 178.5 117.3 120.1 129.0 168.0 190.0 215.0- Consumer Contrib.Recog.as Income 118.4 132.3 137.0 151.5 173.1 183.0 186.5 190.1 194.1 200.0 209.0 208.0

-- --------------------------------- _-----------------------------------------------------------

OPEBATINO CASB FLOW 1462.7 1589.C 1730.7 1711.0 1675.5 2001.4 2194.8 2486.3 2914.8 3434.8 4226.9 4915.7

LESS:Incr.Working Capital Excl.Cash (+) -93.1 161.7 182.4 96.2 112.3 -132.5 -62.0 -8.0 158.1 312.1 231.6 195.8Incr. Othor Asseta/LiLbilities -25.3 -25.2 -24.3 -27.6 -36 3 -30.5 -32.9 -35.6 -38.4 -41.5 -44.8 -48.4Tax and Dividends Paid 94.1 148.5 102.4 145.7 300.4 246,3 223.0 387.8 428.5 426.0 440.7 695.9

CASH AVAIL. bEFORE D2BT SERVICE 1487.0 1304.9 1470.2 1496.7 1299.1 1918.0 2066.8 2142.1 2366.6 2738.1 3599.5 4072.4

Amortization 379.2 478.8 760.3 630.1 629.4 530.9 595.0 721.6 792.9 915.2 1001.3 1144.7Operational Interest 248.0 300.5 295.8 312.8 294.3 259.1 422.6 596.0 690.7 979.4 1162.5 1335.7

TOTAL DEBT SERYICE 627.1 779.3 1056.0 942.9 923.7 790.0 1017.6 1317.6 1483.6 1894.6 2163.8 2480.4

CASH AVAILABLE FRC4 OPERATIONS 859.9 525.6 414.2 553.8 375.4 1128.1 1049.2 824.4 883.0 843.5 1435.7 1592.0

CAPITAL INHVSTIFNT

Hydro Generation 76.6 40.5 33.0 46.0 351.7 425.4 611.6 528.2 739.1 727.4 612.0 489.9Thermal Generation 721.2 483.8 109.9 77.7 978.7 1167.4 2070.5 1890.1 1996.3 1199.7 1077.1 1441.5Transmission 257.6 290.8 286.9 192.4 374.8 359.5 562.3 638.5 548.7 350.0 350.0 350.0Distribution 169.2 230.5 132.0 272,2 432.9 581.0 391.1 400.4 430.5 558.4 633.0 715.9Rural Electrification 78.5 62.2 81.4 91.2 145.6 95.0 90.0 31.0 0.0 0.0 0.0 0.0Administration & Others 46.1 45.2 51.5 56.3 85.2 97.2 98.1 104.6 106.5 122.2 130.1 137.9Import Duties & Sale Taxes 0.0 0.0 0.0 0.0 0.0 0.0 0.0 446.9 450.3 377.1 364.3 387.3Interest Capitalized 48.4 61.3 47.4 4.4 47.4 122.4 202.9 226.0 343.1 274.6 272.9 273.3

_____________________________________________________-------------------------------------------

TOTAL CAPITAL EXPEDITURE 1397.5 1214.3 741.9 740.1 2416.3 2848.0 4026.5 4265.6 4614.5 3609.3 3439.2 3795.7

BALADCZ TO BE FINANCED 537.6 688.7 327.7 186.2 2040.9 1719.9 2977.3 3441.2 3731.5 2765.7 2003.5 2203.7

SOURNCES OF FINANCE:

Rural Elect. Contributions 114.2 54.4 112.9 101.6 145.7 49.3 45.0 15.5 0.0 0.0 0.0 0.0Equity 11.9 0.0 0.0 0.0 0.0 100.0 1300.0 1300.0 1300.0 0.0 0.0 0.0

LCAN FINACIBI:

Ongoing Loans 606.8 552.3 296.0 113.1 622.8 230.9 39.6 18.2 0.0 0.0 0.0 0.0Proposed IBRD Loan 0.0 81.0 108.0 135.0 135.0 81.0 0.0 0.0Proposed ADB Loan 0.0 81.0 108.0 135.0 135.0 81.0 0.0 0.0Other Foreign Under Consider. 107.6 595,5 600.7 745.5 751.7 622.9 81.0 0.0Undefined Foreign Loans 0.0 274.9 584.4 1050.1 1361.2 1087.2 2153.2 2351.5Proposed Local Loans 816.6 144.1 0.0 0.0 0.0 0.0 0.0 0.0Undefined Local Loans 200.0 700.0 500.0 300.0 300.0 500.0 500.0 600.0

TOTAL BORRONWNG 606.8 552.3 296.0 113.1 1747.1 2107.4 1940.8 2383.8 2682.8 2372.1 2734.2 2951.5

IOTAL FINANCING 733.0 606.7 408.9 214.7 1892.7 2256.7 3285.8 3699.3 3982.8 2372.1 2734.2 2951.5

CASH INCREASE (DECREASE) 195.3 -82.0 81.1 28.5 -148.2 536.8 308.5 258.1 251.3 -393.6 730.7 747.8

2 Capital Expend. On Net Assets 20.82 15.71 8.8S 8.32 24.71 22.9X 28.5S 25.4Z 20.92 13.2S 11.12 11.02 Loan Financing of Capital Expend 432 451 402 152 722 742 482 561 582 f66 802 782Debt Service Ratio 2.4 1.7 1.4 1.6 1.4 2.4 2.0 1.6 1.6 1.4 1.7 1.6Self-Financing Ratio (3 Year Avg.) 70X 472 462 432 192 362 282 19S 212 222 402 442

- 75 -

ANNEX 14 - Page 3 of 4

TABLE 3 - BALANCE SHEFT

Million MSFiscal Year Ends Auguat 31

…------------------ _----------- _- __- _-- ___----_-------_--------_---__-_____--__ ----- _-____----- -------- ___--_----_--------------

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999…------------------------------------------------------------------__--------__-_-_------------ ---.------- _-----_------_____-- --

Fixed Assets in Operation 11377 12753 14093 15173 16877 20361 22840 26462 32870 39422 44670 50217

Les: Accumulated Depreciation 3255 3620 4181 4633 5307 6052 6915 7901 9078 10497 12147 14020

Less: Consumer Contributions (Not) 1398 1421 1483 1579 1800 1845 l821 1766 1701 1669 1650 1657…_______________________________________________________________________________________________

MET FID ASSETS 6724 7713 8428 8960 9770 12464 14104 16794 22091 27256 30873 34541

CEK IN PROGRESS 2045 1929 1359 1372 2606 2462 4605 5919 4904 2933 2291 1865

Cash 145 186 198 137 102 108 124 142 157 175 196 222

Short-Term Deposita/(Loans) 396 186 327 421 19 5.9 841 1082 1318 907 1616 2337

Accounts Receivable 356 337 377 447 486 494 560 635 719 806 904 1012

Other Account Receivable 385 447 479 550 619 638 691 749 812 881 954 1035

Inventories 257 298 335 390 540 512 597 697 811 922 1048 1191

Fuel Inventories 86 95 94 122 126 84 56 69 61 72 73 84

Other Current Assets 30 40 40 40 40 40 40 40 40 40 40 40

TOTAL CURRENT ASS1TS 1655 1589 1851 2107 1931 2425 2910 3414 3919 3801 4831 5922

Deferred Charges 0 0 0 0 0 0 0 0 0 0 0 0

Investments In Stock & Industries 13 5 5 5 5 5 5 5 5 5 5 5

TOTAL ASSETS 10437 11235 11643 12444 14313 17355 21625 26132 30919 33995 38000 42333

Trade Creditors 306 242 205 243 302 302 348 398 440 489 548 623

Capital Expend. & Retention Fee 73 126 83 60 70 136 306 485 513 400 380 423

Other & Short Term Loans 295 248 254 366 448 470 493 518 544 571 600 630

Tax Payable 164 70 126 245 273 232 305 267 187 201 457 590

Dividend Payable 59 94 70 70 35 53 144 223 301 301 301 301-------------------------------------------------------- __---__---------------------------------

Total Account Payable 898 781 739 985 1127 1193 1597 1890 1984 1963 2285 2566

Current Matur.Long-Term Debt 566 690 570 639 646 595 722 793 915 1001 1145 1454------------ _------------------------------------------__---------------------------------------

TOTAL CURRENT LIASILITIES 1464 1470 1308 1625 1773 1788 2318 2683 2899 2964 3429 4020

CONSUMER DEPOSITS 268 293 317 345 381 412 445 480 519 560 605 653

'OtAL LONG-TER DEBT (Net) 4587 4972 4507 3920 5350 6974 8205 9811 11610 13042 14677 16181

Gross Debt 5153 5661 5076 4559 5996 7569 8927 10604 12525 14043 15822 17635

Minus: Current Maturities 566 690 570 639 646 595 722 793 915 1001 1145 1454

TOTAL LIAWILITrES 6319 6735 6132 5890 7505 9174 10968 12975 15028 16566 18712 20855

Capital 903 903 903 903 903 1052 2397 3713 5013 5013 5013 5013

Retained Earnings 3843 4535 5287 5765 6165 6908 7636 8338 9202 10036 11011 12157

Revaluation Surplus -629 -938 -678 -113 -260 221 624 1107 1676 2381 3265 4309------------------------------------- _-_--------------------------------------------------------

TOTAL EQUlT 4117 4500 5511 6555 6808 8182 10657 13157 l38'1 17429 19288 21478

TOTAL EQUIY AND LIABILJITES 10437 11235 11643 12444 14313 17355 21625 26132 30919 33995 38000 42333

Current Ratio 113S 108S 141X 130S 1092 136X 1262 1271 1352 1282 1411 1472

Debt Equity Ratio 53S 522 452 37S 442 462 442 432 422 432 43S 432

I Days Accounts Receivable (Net) 53 46 47 so 48 44 44 44 44 43 41 40

- 76 -ANMEX 14 - F-;go 4 of 4

TABLE 4 - Financial Sensitivity to the Low Load Scenario

Million MS

,_.___.-_----_--_---_--___----_-__-__-------_----_-------_--------__---------__-----------------------------------

1988 1989 1990 1991 1992 1993 1994 1996 1998 2000-.------------------------------------- __--_------__-_-_____-------__--------__-----------------------------------

Electricity Sales Revenues 2.524 2.780 3.123 3.515 3.907 4.450 5.066 6.690 9.138 10,946Total Operating Revenues 2.662 2.922 3.279 3.695 4.098 4.644 5.264 6.898 9.355 11.210Total Operating Expenses 1.685 1.638 2.284 2.739 2.930 3.215 3.695 4.789 6.212 7.385Taxes and Dividends 0.089 0.134 0.265 0.246 0.216 0.376 0.408 0.436 0.827 1.020Not Income 0,634 0.900 0,478 0.492 0.732 0.707 0.665 0.824 1.142 1.499

Cash Available From Operations 0.526 0.414 0.554 0.467 1.115 1.038 0.796 0.888 1.618 1.578Total Investment 1.214 0.742 0.740 2.416 2.848 4.027 4.266 3.609 3.796 4.507Borrowing 0.552 0.296 0.113 1.747 2.107 1.941 2.384 2.372 2.952 3.334

Rate Dase 7.218 8.070 8.694 9.365 11.117 13.284 15.449 24.673 32.707 38.828Total Assets 11.235 11.643 12.444 14.313 17.337 21.583 26.047 33.850 42.192 51.047Total Long-Term Debt (Net) 4.972 4.507 3.920 5.350 6.974 8.205 9.811 13.042 16.181 19.154Total Equity 4.500 5.511 6.555 6.808 8.170 10.625 13.089 17.277 21.316 26.495

MONITORING INDICATORSElectricity Sold - TWh 13.6 15.3 17.4 19.7 21.9 24.1 26.5 31.6 37.0 43.3Average Tariff - M$ cents/Kwh 18.5 18.2 18.0 17.9 17.8 18.5 19.1 21.2 24.7 25.3Rate of Return-Book Assets 11 15.4S 17.7X 10.7X 9.5X 10.9S 11.01 11.11 9.61 9.91 10.42Rate of Return-Revalued Assets 12.81 14.7X 8.8S 8.01 9.0S 9.01 9.01 8.01 8.01 8.0Z

Self-Financing Ratio 21 47.01 46.11 42.6Z 23.31 36.01 27.9Z 18.51 22.81 44.31 38.41Debt Service Coverage 31 1.7 1.4 1.6 1.5 2.4 2.0 1.6 1.5 1.7 1.5Debt /(Debt plus Equity) 41 521 451 371 441 461 441 431 431 43Z 421Working Ratio 51 501 371 531 601 571 54Z 551 531 501 492Current Ratio 61 1082 141S 1301 1091 1351 1241 1251 123S 143Z 1681Accounts Receivable (days) 46 47 50 48 44 44 44 42 39 41

11 Operating Income less Taxes on historical Fixed Assets.21 Cash available for investment divided by the 3-year average Capital Expenditures.31 Operating Cash Flow divided by Debt Service (Amortization plus Operational Interest)41 Long-term Debt divided by long-term Debt plus Total Equity.51 Operating Expenditures excluding Depreciation divided by the Operating revenues.61 Current Assets divided by Current Liabilities.

- 77 -ANNEX 15

MALAYSIA

POWER SYSTEM DEVELOPMENT PROJECT

TENAGA NASIONAL BERHAD

Tariff Structure and Marinal Cost

Category 11 Concept Rates Average Marginal %Rate Comments| ____-,_ .___PRate/Kwh Cost/Kwh /Cost

A DOMESTIC First 100 Kwh M$0.20Next 900 Kwh M$0.23 M$0.212 M$0.185 115%Additlonal Kwh M$0.28

B COMMERCIAL-LV Per Kwh M$0.24 M$0.240 M$0.240 100% 10% discount to hotels

C1 COMMERCIAL-MV Per Kw max.demand M$12.0 M$0.224 M$0.241 93% 10% discount to hotels.Per Kwh M$0.18

C2 COMMERCIAL-MV Per Kw max.demand 10% discount to hotelsPeak Pricing during peak period. M$19.0

Por Kwh during peak M$0.18 M$0.193 M$0.180 107%Per Kwh off-peak M$0.08

D INDUeTRIAL-LV Per Kwh M$0.21 M$0.168 M$0.225 93% 10% discount. 20% totextile industries

El INDUSTRIAL-MV Per Kwh max. demand 10% discount. 20% toper month M$12.0 M$0.165 M$0.237 70% textile industries

.__________ Per Kwh M$0.16 _

-2 INDUSTRIAL MV Per Kw max. demand 10% discount. 20% toPeak Pricing during peak period M$17.0 M$0.139 MS0.152 91% textile industries

Per Kwh during peak M$0.16Per Kwh off-peak M$0.08

E3 INDUSTRIAL-HV Per Kw max. demand 10% discount. 2C% toPeak Pricing durlng peak period. M$15.0 M$0.117 M$0.159 74% textile industries

Per Kwh during peak M$0.15Per Kwh off-peak M$0.07

F MINING-LV Per Kwh M$0.19 M$0.143 M$0.275 52% 10% discount

Fl MINING-MV Per Kw ma-. demandper month M$12.0 M$0.157 M$0.282 56% 10% discountPer Kwh M$0.16

F2 MINING-HV Per Kw max. demandduring peak period M$17.0 M$0.120 M$0.149 81% 10% discountPer Kwh dui,nq peak M$0.16

.____________ .Per Kwh off-pea, M$0.08 .. __

G PUBLIC & Per Kwh M$0.18 M$0.180 M$0.196 92%UGHTING

1] LVu Low Voltage; MV= Medium Voltage; HV- High Voltage.Source: TNBs Study In 1990.

- 78 -

ANNEX 16

MALAYSIA

POWER SYSTEM DEVELOPMENT PROJECT

TNB's MONITORING INDICATORS

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999

CIEVEMENT F GALS:

S Electrification Ratio 73.1Z 75.91 78.45 81.32 83.12 85.05 86.65 88.31 90.05 90.85 91.6S 92.42Connections-Million (End-Year) 2.424 2.577 2.736 2.903 3.046 3.197 3.351 3.514 3.684 3.818 3.956 4.099Additional Connections-Million 0.135 0.153 0.159 0.167 0.143 0.150 0.155 0.162 0.170 0.133 0,138 0.143

Total Power Sold - Gwh 32,438 13,638 15,253 17, 94 19,539 21,909 24,574 27,540 30,824 33,660 36,757 40,139Power Sold Kwh/Person 909 976 1,065 1,186 1,301 1,425 1,560 1,708 :,867 1,993 2,127 2,270Power Generated - Gwh 14,671 16,175 18,140 20,663 23,162 25,915 29,015 32,458 36,264 39,507 43,041 46,891

MAJAEA3M/EFFICIEW'Y;

# Days Accounts Receivable 53 46 47 50 48 44 44 44 44 43 41 401 Receivables on Billing 14.42 12.75 12.92 13.62 13.22 12.0X 12.05 12.02 12.02 11.86 11.2X 11.0O

# of Employees 24,347 23,892 23,596 23,350 23,117 22,885 22,656 22,543 22,498 22,723 22,950 23,180Connections per Employee 99.6 107.9 115.9 124.3 131.8 139.7 147.9 155.9 163.8 168.0 172.4 176.8Sales per Employee (Mwh) 511 571 646 745 845 957 1085 1222 1370 1481 1602 1732X Total Energy Losses 15.22 15.72 15.92 15.82 15.62 15.5X 15.32 15.21 15.02 14.82 14.6X 14.4Z

FINANCIAL RATIOS:

Average Tariff - MS cents/Kwh 0.19 0.185 0.182 0.180 0.180 0.179 0.182 0.185 0.188 0.196 0.213 0.223Working Ratio 11 49.42 49.91 36.82 53.02 62.72 56.72 53.92 54.4X 53.11 52.02 49.4X 49.2SOperating Ratio 21 65.62 63.3X 56.02 69.72 76.62 71.22 68.72 69.31 69.0X 69.0S 66 25 65 8e

Nominal Rate of Return (Aft.Tax) 13.22 15.42 17.7S 10.72 8.3S 11.12 11.22 11.32 10.9Y 9.62 9.7X 9.92Revalued Rate of Return (Aft.Tax) 10.42 12.85 14.72 8.82 7.02 9.11 9.22 9.22 8.92 8.02 8.02 8.0XReturn on Capital Employed 5l 15.62 16.12 18.82 11.32 9.52 11.82 10.52 8.62 8.12 7.32 8.72 9.22Net Profit on Equity 11.62 14.92 17.02 7.82 6.42 9.7t 8.2S 7.02 7.3S 6.52 6.62 6.7X

Self-Financing Ratio 61 70.52 47.02 46.12 42.62 18.82 36.42 28.3X 19.21 21.22 21.72 39.72 43.62Debt Service Coverage 71 2.- 1.7 1.4 1.6 1.4 2.4 2.0 1.6 1.6 1.4 1.7 1.6Interest Coverage 8l 3,0 2.8 3.9 3.3 2.8 3.2 2.5 2.1 1.9 1.8 2.0 2.1Debt/Equity Ratio 91 52.72 52.5Z 45.02 37.42 44.02 46.02 43.52 42.72 42.2! 42.82 43.21 43.02

IN CRSTANT 1991 PRICES:

Averago Tariff - MS cents/Kwh 0.22 0.208 0.197 0.186 0.180 0.173 0.169 0.165 0.161 0.162 0.169 0.170Roal Tariff Increase (Decrease) -10.12 -5.52 -5.32 -5.32 -3.42 -3.92 -2.41 -2.3 -2.31 0,4X 4.22 1.02

CRITICAL FIIWICIAL INDICATICS BETWME 1991-1997.

VARIABLE OR INDICATOR MINIMKUi AVERAGE MAXIMUM VARIABLE OR INDICATOR MINIMUM AVERAGE MAXIMUM

Cash 101.6 143.3 195.6 Debt Service Ratio 1.4 1.7 2.4Average Tariff - MS cents/Kwh 0.16 0.17 0.18 Days Accounts Receivable 41 44 48Working ratio 49.42 54.62 62.72 Total Debt/Equity Ratio 42.22 43.52 46.02Rate of Return (Revalued) 7.02 8.52 9.22

1) Operational Expensos excluding Depreciation / Operational revenues2) Operating expenses including Deepreciation / Operational Revanuos3) Oparating Income less Taxes on Net Average Historical Fixed Assets in Operation4) Operatin, Income lese Taxes on Net Average Revalued Fixed Assets in Operation5l Profit before Interest and Taxes / Total Equity6) Cash Available from Operations / 3-ye-r Average Capital Expenditures71 Operating Cash Flow divided by Debt Service (Amortization elus Operational Inter-St)8l Profit Befoce Interest and Taxes / Interest Expenses9] Long-Term Debt / (Long-Term Debt Plus Total Equity)

- 79 -

Annex 17 - Page 1 of 4

MALAYSIA

Power System Development Project

ASSUMPTIONS FOR FINANCIAL PROJECTIONS

1. Inflation. For the next few years, it is estimated that the annual (January-December) increase inconsumer prices will be about 4% p.a. (which is slightly above the average during the last five years), and foreignprice increases would average 3.9% p.a. The exchange rate of M$2.70 per US dollar is assumed constant. Theexchange rate between different currencies and the dollar is based on mission assumptions which are detailedin the Debt Tables in the Project File.

Financial Computer Models

2. The planning and financial projections for TNB are based on financial projection models preparedduring the appraisal which inchlude the following main four programs: Capital Expenditures program (CAPEX),Loan Analysis (DEBT), load and demand forecast (DEMAND) and integrated financial projections(TNBFINAN). These programs produce more than 100 pages of financial tables, which are included in theProject File. Only the main summary tables are included in this report. To facilitate future project evaluationand supervision, diskettes with the respective programs are also included in the Project File. These programshave also been provided to TNB for their financial planning.

Load Forecast

3. TNB's load forecast is based on a comprehensive analysis of the latest load trends and includessever?l correlations relating gerneral and manufacturing GDP in Peninsular Malaysia with increases in powersales, income and price elasticity, the analysis of sales by type of consumers, population and per capita electricityuse, etc. This analysis is presented in the "Ramalan Beban 1990/91" publication, available in the Project File, andused to forecast the overatl sales up to the year 2010, and its distribution by consumer categories (industrial,commercial, mining, etc.). These projections were updated during negotiatians.

4. Based on recent large increases in power sales (10%, 12% and 14% in 1988, 1989 and 1990) TNBforecast a high growth in demand, averaging 12.1% p.a. between 1991-95, and 9.2% p.a. between 1995-00 withpower sales increasing 2.7 times to 47.9 GWh by the year 2000. These growth rates are similar to the expectedincreases in manufacturing GDP and about 1.4 times the increases in the total GDP. However, TNB's medium-term load forecast may be affected by factors such as recessien in its major trade partners notably the USA andcompetition from gas. Under these conditions, the industrial demand, which TNIB expects to increase from 48%to 56% of total sales (by 2000), may not materialize. Therefore, a lower forecast was also used during theappraisal based on growth rates of 1n.5% p.a. over 1991-95 and 8.2% p.a. between 1995-00. This load forecastis called the Low Load Forecast and was used for financial sensitivity analysis (Annex 14, Table 4).In both casesthe least-cost investment program was used, but if a lower demand start to materialize TN3 will have sufficientflexibility to reduce future capital expenditures.

Income Statement

5. Energy Losses and In Plant Use. The total energy losses and the energy use by the generatingplants average 15.8%, of which plant use is about 45%. Based on TNB on-going investments in capacitors andimproved power factor these losses, will be reduced gradually to 15% by 1995 and 14% by 2000. 1 ower losses

- 80 -

Annex 17 - Page 2 of 4

are desirable but may be difficult to achieve in the short run because the need to upgrade many transmissionand distribution lines. These losses represent potential revenues of about M$35 million per each 1% reduction.

6. Tariff Revenues. The power revenues are based on existing tariffs, and the impact of eliminatinggradually between 1993-95 the existing discounts (about 20%) for large industrial and commercial users. Tariffsincreases in line with inflation will be able to satisfy the financial objectives thereafter. However, higher tariffswill be needed if existing tax exemptions are not extended for the next two years, as reouested by TNB andagreed in principle by Government. Details of the average tariffs and revenues from each type of consumer(industrial, commercial, domestic, mining and lighting) are presented in the Financial Projections, Table 9,Project File.

7. Other Revenues. TNB receives cc sumer contributions (for connection services) of about M$100to M$200 million per year, which are charged to new customers, and represent either the connection cost, orrinimum sales to cover such cost. These consumer contributions are excluded from the rate base, and 1/15 oftheir net balance is recognized as operational revenue and debited to the cumulative consumer contributionaccount. This account also includes some minor charges for maintenance or electrical works performed by TNB.

Opeational Expenses

8. Fuel. The main operational cost is fuel, which represents about 62% of the cash operationalexpenses. The fuel quantity and cost is estimated by a SYSGEN optimization of the generating plants. The perunit price of fuel is about 10% higher for the high load forecast, because of use of plants at lower efficiency. Oilprices have been high (because of the Gulf War). It is expected that the average price for TNB fiscal year 1991would be about $20 per barrel. The price of oil is expected to be about $20 per barrel in 1992-93 and increasethereafter about 3% p.a in real terms. A major advantage for TNB is that its oil generation is being phased out,reducing from 16% of its total generation at present, to less than 10% by 1995 and about 6% by year 2000. Themain fuel cost, 77% of total, even in 1991 is gas. Starting in 1992, and following the Bank proposals for gaspricing, it is assumed that the price of gas, which was initially contracted at M$5/MBTU and M$6/MBTU (eastand west coast), will be indexed 60% with consumer prices and 40% with oil prices. Details of fuel expenditures(oil, gas and coal) are presented in Table 7 of the financial projections available in Project File.

9. Personnel. TNB has been reducing its staff during the last few years and has decAded not toappoint new staff during the next three years, which because of retirements and natural attrition will continueto decline about 1% p.a. This will further increase TNB's efficiency in preparation for its privatizati on. However,planned large increases in new capacity wil require additional but small staff increases startins in 1994. Tofacilitate privatization, when TNB was incorporated in September 1990, staff was given tenure fcr 5 years, andstaff salaries were increased 9%. Due to increasing GDP per capita, future salary increases are assumed toincrease about 2% over inflation. Details of the personnel expenses, including the breakdown by ma,jor categories(generation, transmission, distribution, consumer services, billing, training and administration) are sLown in Table7, financial projections (Project File).

10. Other Expenses. Other expenses (generation, transmission, distribution, consumer services, bilingand collection, training, administration and general services) are projected based on the unit cost per unitgenerated and expected economies of scale for some services (billing, administration). These costs represent lessthan 20% of the operational revenues. Detailed projections are included in the FinanciAl Projections, Table 8,Project File.

11. Depreciation. TNB's average depreciation rate varies with the composition of the assets enteringinto operation, and is forecast to average about 3.6% p.a. However, TNB's financial model is not using therevalued depreciation, which is practically the same as the nominal depreciation, and distorts the resulting rate

- 81 -

Annex 17 - Page 3 of 4

of return. The financial projections in the appraisal include fully revalued assets and depreciation starting in 1991(to avoid changing all previously reported financial statements).

12. Income Taxes. TNB pays income taxes as any other private corporaticn. Taxes are based on thedifference between all revenues, and all operational expenditures (excluding depreciation) but including theoperational interest. Instead of depreciation there are two deductions for capital expenditures. The initialdeduction is equivalent to 18% of the value of the assets entering into operaition. Thereafter, until fully allocated,there is an annual deduction of 4.5% of the value of the remaining deductible assets (fixed assets entering intooperation less amounts already deducted). This results in quite uneven taxable income, because of the largeimpact cf the 18% deduction when large assets enter into operation.

13. Dividends. Until now TNB dividends policy has been simple, to pay about 4% of its capital. Thisis expected to increase to 6% by 1992.

14. Other Taxes. Although TNB has been exempted from custom duties, local taxes on capitalexpenditures, and recently-established taxes on fuel (5% CIF on coal and M$17 per ton of oil), it was expectedto start paying them in 1992. However, TNB's required capital expansion is huge and would result in an increaseof almost 3 times in the annual capital expenditures. It is impossible for tariffs to be adjusted to finance suchhuge changes. TNB has therefore requested the continuation of the tax exemption on capital and fuelexpenditures for two additional years (1992 and 1993). This is reasonable and would assure that the hugefinancial requirements for the investment would be met and would not create delays on the proposedprivatization.

Plow of Funds

15. Investment Program. TNB's investment program includes many subprojects, ranging from verylarge generation plants to transmission and distribution expansions for each city in Peninsular Malaysia. TNB'soriginal investment program was reviewed during loan negotiations and is considered realistic. In order to analyzethese investments, a computer program was prepared that provides details by major categories (hydro, thermaltransmission, distribution, rural electrification, administration and others), see Annex 10. The investment priorityis the expansion of generation, representing about 21% of the total capital expenditures during this period. Theinvestment program is flexible and can be adjusted for higher or lower demands.

16. Rural Electrification Contributions. Rural consumers are scattered and are expensive to serve. Toensure that such less-profitable investments are made, the Government provides grants specifically targeted forthese works, which amount to about 40% of their cost.

17. Eguity Increase.. The Pergau dam and hydro generation will be financed I.y British ODA loans.The bilateral agreement covering this project includes a loan of M$1,000 million (in pounds at 9.6%) and M$400million to be considered as grants, and which would be paid pari-passu with the loan disbursements. 25% ofTNB's shares are expected to Le sold in the Kuala Lumpur stock exchange in 1992. After this initial offeringT,SB is expected to issue additional shares for about M$3.6 billion, which are assumed sold between 19%3-95 andprovide equity financing for its investments. In case such offering is TNB would be able to issue 5-year bondsfor an equivalent value.

18. Dervice. TNB debt is largely foreign (90%) and is represented in multilateral loans (IBRD,ADB), bilateral loans and suppliers credits represented in ten different countries. The largest share of the foreigndebt is in Yen, which represents almost 60% cf the loans balance in 1990. TNB has been concerned about thclarge impact that a revaluation of a single curren(y may have on its finances, and is targeting the achievementof a more balanced distribution of loans between major currencies (Yen, US Dollar and Euro-currencies). Thedebt service analysis for about 300 foreign and local loans is included in the DEBT tables (included in the ProjectFile). The analysis is complicated, becadse some of the initial bilateral or multilateral loans are not paid directly

- 82 -

Annex 17 - Page 4 of 4

by TNB, but are paid by the: government and reimbursed by TNB. This is beneficiaz to TNB, because at timesthe government billing is delayed for one year or even more, but is paid, without interest, at the original billingamount in Ringgit. The government is expected to transfer the obligation for direct payments of all loans to TNBby 1992.

19. Pinancial Plan. The overall financing plan (Table 3.2) includes the proposed Bank loan ofUS$200 million on standard conditions, and a US$200 million loan from ADB for other components. This loanis expected to be concluded later in 1991. A large amount of additional foreign loans (mainly suppliers credit)adding to US$2.8 billion will be needed to finance the investment program to 1996. A substantial amount of theseloans are in advance status of discussions.

Balance Statement

20. Fixed Assets and Revaluation. The government accounting gwtsiiines allow the revaluation ofbuildings and commercial properties to reflect their current value. Therefofe a partial revaluation is included inthe accounting. In order to better evaluate the return on the invested capital, fixed assets are revalued with theGDP deflator, which is adequate. This is in agreement with the AreB covenant of a 8% rate of return onrevalued assets. However, the GDP deflator is available only one to two years after the end of the fiscal year.For fnancial projections the increases in the GDP and consumer prices are expected to be similar. Thisrevaluation is ex-books, and is not fully understood by the Board and management, since inflation in Malaysiahas been traditionally very low (about 3% p.a.). In preparation for its privatization it is expected that with thesupport of consultants TNB will made an inventory and valuation of all its physical assets by mid-1992. Detailsof the revaluation of assets, depreciation and corAsumer's contributions are presented in Table 9, FiancialProjections in the Project File.

21. Accounts Receivable. Accounts receivable increased from M$377 million to M$486 milliot between1989 and 1991 (almost 2 months of billing), mainly because of the impact of delayed payments by governmentinstitutions. As a new corporation, TNB has given particular emphasis to a faster collection, and accountsreceivable are expected to be reduced gradually to about 40 days by 1998. The amount considered uncollectibleis very small an is netted out from the account.

22. Inventories for operation, which include transmission and distribution materials (cables, towers,transformers, etc) and spare parts for generating plants are assumed at about 150% of the annual cost ofmaterials and maintenance (some of these items have long procurement times and may remain in storage forlong periods).

23. Fuel Inventories. Include coal and oil, and are estimated at about 30% of the annual expendituresin oil and coal.

24. Trade Creditors. Estimated at about 13% of the operating expenditures (excluding depreciationand debt revaluation losses).

25. Provisigps for Taxes and Dividends. Taxes and dividends accrued in one year are assumed paidin the following year.

26. Consumer Dos§pits. These are deposits by each new consumer to ensure the payment of their bills.Although they are returned if one connection is closed, this is unusual and is more than compensated by theincrease resulting from new connections. Therefore, it is very stable and is considered a long-term rather thancurrent liability.

- 83 -

ANNEX 18MALAYSIA

POWER SYSlEM DEVELOPMENT PROJECT

Economaic Evaluation of TNB Development Plan

(All costs in 1991 M$ Mfllion)

Fiscal Capital Fuel Energy Incremental Values Incr. NetYear Cost Cost Sales Revenue Benefit

TWh Sales Fuel O&M Total at MS0.186TWh Cost Cost CInor per Kwh

. .. _ _ . - = =

1990 800 800 -800

1991 2372 1305 19.54 2372 -2372

1992 3273 1303 21.91 2.37 -2 3271 -3271

1993 3643 1517 24.55 5.01 212 202 4057 932 -3125

1994 3262 1702 27.51 7.97 397 267 3926 1482 -2444

1995 3301 1854 30.82 11.29 549 333 4183 2099 -2084

1996 2643 1968 33.66 14.12 663 386 3692 2627 -1065

1997 2252 2107 36.76 17.22 802 431 3485 3203 -282

1998 1608 2355 40.14 20.60 1050 463 3121 3831 710

1999 1376 2581 43.83 24.29 1276 491 3143 4518 1376

2000 0 2887 47.86 28.33 1582 491 2073 5268 3196

2001 0 3152 52.26 32.72 1847 491 2338 6086 3749to 2018

2019 0 3152 52.26 32.72 1847 491 2338 6086 3749

2020 -3064 3152 52.26 32.72 1847 491 -726 6086 6812

Base Case (Base Case Load Forecast) 12%

Lower Demand (Low Case Load Forecast) 10%f

Capital Costs increased by 10% o11%

- 84 -

Annex 19 - Page of 6

MALAYSIA

Power System Development Project

Review of Regulatory Arrangements

Background

1. Under the Electricity Supply Act of 1990 the Director General of Electricity should grant a license

for the supply power to TNB. The following comments apply to the draft license proposed by the consultants-1

and to the draft license received from the Director General on January 11, 1991.

2. The license is to be issued to TNB by the Director General of Electricity Supply under Section

9 of the Electricity Supply Act 1990 with the approval of the Minister of Energy, Telecommunications and Posts.It has been drafted by U.K Power Management (UKPM) on behalf of Peninsular Power, a team of consultantscomprising local and overseas consulting firms led by financial advisers Morgan Grenfeli Co. Limited. The draftlicensing arrangements have been prepared principally by Price Waterhouse and Ernst & Young/Ernst andWhinney.

3. On September 1, 1990 TNB was incorporated under the Electricity Supply (Successor Company)Act 1990 which received Royal Assent on August 22, 1990. This changed its itatus from being a statutory bxard

to a wholly owned government public company subject to the Companies Act. At the same time, the ElectricitySupply Act (No. 447) 1990 authorized the Minister to appoint a Director General of Electricity Supply to issue

licenses with the approval of the Minister to operators of electricity supply installations. For the time being, TNB

will be the sole supplier of electricity in Peninsular Malaysia. It is proposed that TNB's license be for 21 years.A temporary license has been issued for 6 months, up to February, 1991. TNB will seek stock exchange listing

and shares will be issued to investors atid the public at a future date.

Comments on Consultants' Proposals

4. The initial licensing arr.' ig.nments being proposed are based on the privatization experience of UK

and USA consultants. They reflect substantially wnany of the features recently established in the UK for

regulation of public utilities, and to establish a price control mechanism to limit the profits of electricity supply

entities and to set standards and performance measures to eiqur4 supply quality and efficiency is achieved by

the licensee. inowever, the proposed arrangements could lead to a fairly rigid regulatory regime and have the

potential for adversarial and costly regulation. The effectiveness of the licensing arrangements will depend to

a very great degree on the spirit of cooperation between TNB and the Director Gerneral of E!ectricity Supply.The free exchange of information on TNB's costs and performance will be necessary for effective regulation.

TNB's ability to do so will be constrained until it can develop information systems capable of providing timely

reports and data needed for regulation. The present accounting system will need to be restructured to provide

on line computerized fmancial information and reports on each main activity (i.e. for each power plant,

transmission line/substation and distribution center). This study will be financedI under the project. The

development of adequate information and reporting systems will take some time. This implies that the regulator

will have to accept in many circumstances that from the outset TNB will not be able to fully meet the

information requirements for regulation.

1/ Peninsular Power in their report to the Government of Malaysia on the Privatization of TUB -

June 30, 1990.

- 85 -

Annex 19 - Page 2 of 6

5. The initial regulatory arrangements do not make provision for competition by other suppliers (i.e.private generators). The legislation does not yet permit private generators to sell power to TNB, or containmechanisms for establishing the prict which TNB would pay for electricity supplied by private generators.Therefore private generation is unlikely to come up at least for some time. This is inconsistent with one of theGovernment's objectives of privatization i.e. to create competition. Opportunities should then be given beafforded to private generators as soon as possible after privatization of TNB to create competition, attractadditional private investment and afford Government the opportunity to reduce the degree of regulation asTNB's monopoly position reduces. The technical requirements for transferring power from private generatorsto TND would have to be prepared. It may also need to consider relaxing some of the licensing conditions i.e.reduce the degree of regulation.

6. The regulatory mechanisms to be established appear to limit too much the autonomy of TNB. Forthe proposed regulatory arrangements to work effectively, Government will need to minimize its involvement inTNB relying on the regulatory arrangements and the Director General's functions to replace the role previouslyundertaken by various ministries. The regulator should then provide a high degree of autonomy to TNB's boardand management allowing them to take filli responsibility for operations and holding them accountable formeeting performance standards. The regulator should also be independent from Government as far as possibleonce the Minister has approved the regulations.

7. Initially, it should be anticipated that the Director General will have some difficulties developingstaffting capabilities to undertake regulation. The main source of experienced technical staff for regulation wouldbe TNB. The ability of the regulator to attract and retain skilled staff may be constrained by better salaries andconditions provided by TNB. This problem could be minimized by seconding staff from TNB (although thiscarries with it the risk of regulatory capture). Such cooperation would help both TNB and the regulator todevelop better understanding of the regulatory processes.

8. Government and Regulator will need to be flexi' le in applying the regulations. This would simplifythe procedures, and avoid delays and costs. Some modifications may be necessary once experience has beengained with regulation. It would be helpful to regulators to examine in practice how other industries such as gasand telecom are regulated in other countries. The Government could consider other features of regulation beingfollowed in other countries, particularly in South Korea, New Zealand and Chile. In Chile regulatoryarrangements minimize Government regulatory involvement, encourage private investment in power systems andderegulation of prices; in New Zealand increased efficiency is pursuit through agreement with Government oncorporate performance targets; or as in Korea the same objectives are been reached by the evaluation of publicenterprise parformance. After competition is estabfished, TNB ceases to be in a monopoly position and thegovernment could move towards deregulation of the industry. TNB's monitoring would then be performed bythe shareholders, consumers and capital markets, which would impose financial discipline required to maintainand attract financing on the best available terms.

Regulationi Studies

9. Further studies are needed prior to the issue of a permanent license to TNB to specify operatingstandards, levels of performance and codes of practice. These studies are proposed to be carried out in twophases:

Phase I - Engineering and Management AuditPhase 11 - Regulatory Framework

10. Phase I would require 2 months to review TNB's organization and management, system operation,maintenance and planning procedures, engineering practices and procedures, management information systems,system dispatch procedures and treasury and tax management systems. However, TNB needs more time to

adjust to corporatization and complete the current staff reorganization before these studies are commenced. Thiswould require that the temporary license period be extended at least to September 1, 1991.

- 86 -

Annex 19 - Page 3 of 6

11. Phase II is scheduled to commence after completion of Phase I, but could started in conjunctionwith Phase I. This would enable the studies to be completed more speedily. Phase II work is proposed tofinalize TNB's lcense, train TNB and the regulator's staff, undertake financial analysis and tariff setting includingprice formula and also study performance standards, targets, operating codes of practice and develop reportingprocedures. TNB should appoint an Advisor to assist in the preparation of its submissions to the regulator. Theconsultant should not be associated with consultant appointed for the above studies.

Regulatory Reports

12. Under the Companies code TNB has to meet reporting requirements to its shareholders. Thesewould include preparation of annual reports on its activities and provision of its audited financial statements.It is common to report on financial and technical performance against corporate targets set through a corporateplanning process.

13. In addition TNB has obligations to report to its board of directors and provide it and themanagement with relevant information for management decisions. It also has external reporting requirementswhich it must meet for international lenders which include periodic reports on project construction, loandisbursement, projects costs and actions taken to meet undertakings in loan arrangements. It is important tolimit reports to regulators as far as possible to information that is normally produced by the company for itsboard and management and to external requirements under the companies code and external lending agencies.In any case TNB will need to modify its information systems (especially the Financial Management InformationSystem) to produce timely and relevant information for regulation. It needs to work closely with the regulatorand consultants to establish the precise form and detail of reporting. With respect to performance measures, theBank has published a report by consultants Ernst and Whinney which contains recommendations on electricpower utility performance measures. These should to some degree be able to be developed not only for reportsto management but used selectively by regulatory bodies for monitoring performance.

CONDITIONS OF THE LICENSE

14. Separate Accounts for each Activity. These provisions will require TNB to change some of itsaccounting and budgetary practices. A new accounting and recording system (i.e. an on-line computerizedfinancial management information system) would be needed to enable TNB to provide reliable and promptfinancial information on each activity and to measure performance. This would take some time to establish evenif an existing general ledger package were to be used (an existing software package would be sirmpler and cheaperthan developing an in-house program)

15. Financial Statements. The preparation of separate balance sheets for each activity should not berequired unless it is proposed to operate generation, transmission and distribution as separate business units.If they are to be prepared separately, there should be clear procedures for preparation of consolidated accountsfor TNB as a whole.The consolidated statements should include a statement of sources and application of funds (currently this is partof TNB's financial statements).

16. Audit. TNB's financial accounts for 1991 will be certified by auditors (i.e. public accountants)appointed by the board of directors. This would mean that the Auditc.. General would no longer be responsiblefor certi5ication of TNB's financial accounts. The audited financial statements should be the consolidatedaccounts of TNB i.e. revenue account, balance sheet and sources and applications of funds. The consolidatedfinancial statements should include separate accounts for other activities in which TNB may engage in eg.manufacturing. The audited financial statements should identify any deviations from national accounting standardsand should include a statement by the auditors that the TNB is in compliance with financial obligations agreedwith international lending agencies.

- 87 -

Annex 19 - Page 4 of 6

17. The licensee must submit within 3 months of the end of each year under paragraph 5 (Condition2) a statement from auditors that fuel costs, revenues and quantities and values are in accordance withaccounting records. However, this period may be too short since under Condition 2, the licensee is required tosubmit audited financial statements NOT later than 6 months after the end of the financial year. Therefore,should be the same for both audited statements.

18. In practice, it would be important for the regulator and the licensee to co- operate in provision ofinformation to ensure (as the draft license proposes) submission only of information "reasonably required".There is a risk that TNB could have difficulty paying full attention to operation of its power plant and facilitiesif the information requests of the regulator become onerous.

Electrcilty Prices

19. Under the new legislation any increase in tariff. is to be approved by MOE. The initial consultant'srecommendation was to limit price increases by linking increases in non-fuel costs to a Consumer Price Indexand allowing increases in fuel costs to be passed on to consumers. This will require a very careful selection ofthe proposed index. Both the fuel and non-fuel components provide for savings through increased efficiency tobe shared by TNB and consumers. This is rather complex to establish and -quires comprehensive financial andengineering models and a management audit to establish realistic efficiency factors. Moreover, the present tariffmay not adequately satisfy criteria of adequate returns to investors, or satisfy minimum financial performancetargets i.e. rate of return or cash generation and debt service cover (as required by international lenders). Aformula based on consumer prices may not be able to achieve these targets. For example, a major local currencydevaluation could increase TNB's foreign exchange losses and debt service to levels which could not be coveredby in the short-term by the Consumer Price Index.

20. The above proposal does not indicate how the tariff structure would be determined i.e. the pricesto be charged to each consumer category. It is noted that special tariff agreements are permitted with industrialconsumers but all tariffs should be regulated. There is no mention of using marginal costs to determinerespective costs for each consumer category so as to identify the extent of cross subsidies. However, there isprovision to phase out discounts and it is proposed by the consultants that tariffs be increased uniformlyaccording to the distribution of sales by category (i.e. a "tariff basket") based on previous years sales. There willbe a need to permit adjustment to the tariff basket when the regulator wishes to change the structure of tariffs.

21. It such tariff approach were to be implemented, it is necessary to allow time for testing theproposed pricing mechanisms to ensure that they will work as intended and be clearly understood by regulators,the utility, investors and consumer groups or their representatives. Because the formula is complex, it may bedifficult to administer and will not be easily understood by consumers or investors. Therefore it would beprudent to consider a simpler mechanism such as annual review of tariffs by the regulator (for example toachieve minimum rates of return) based on submissions by TNB and subject to comments by consumer groups.Moreover the ability of TNB to achieve cost savings will be limited initially because of recent increases in salarycosts and constraints on reduction of existing staff levels ove; the next 5 years. It will also have to provide fordividends and pay higher rates on property, sales and fuel taxes.

22. Since the Minister has the ultimate authority to approve all increases in tariffs, there exists thepossibility that increases could be delayed or modified where they may be inopportune on political grounds. Thisdegree of control may be an obstacle for the privatization of the corporation. If the Minister were to limit hispower to intervene when approving tariff adjustments only to extraordinary circumstances (eg. financial crisis),this should not affect investor confidence in normal circurmstances. Some clarification of this aspect would beuseful in the proposed prospectus.

23. Setting the initial pricing level will be difricult especially if an increase is needed since theGovernment has already signalled that any increase would be unacceptable at the time of privatization. If theproposed public flotation is to succeed, TNB's projected profits and dividends must be sufficient to attract private

- 88 -

Annex 19 - Page 5 of 6

investors. Increases in tariffs would have to be implemented before privatization, and the timetable forprivatization should be set only when an appropriate level of profits can be predicted based on the pricingformula.

24. The consultant has recommended that the rate of return for determining the tariff level shouldbe based on profits before interest and tax as a percentage of capital employed i.e. as a return on shareholdersfunds and borrowing. This he suggests would avoid probems associated with the rate of return based onrevalued assets since it would avoid revaluation of assets. However, this should enable TNB to self-finance areasonable share its capital expenditures.

25. In a tariff adjusted for consumer prices a cfrrection factor will have to be established to enabledifferences between the forecast demand and actual results to be adjusted in the following year. Since theregulator has power to Umit corrections carried forward this may adversely affect the company's financialperformance. The consultant recommends that the operation of the pricing formula be reviewed every 4 yearsto look at financial performance, investment requirements, efficiency and profitability. The review would startafter 3 years be based on comments/submission from the licensee. It would be useful to allow a special reviewat the discretion of the regulator, and also to obtain the views of consumers through submission be afforded inaddition to submissions from the licensee. The Government should also make provision to review the role ofregulation to ensure that it is fulfilling its intended purpose and that there has been no abuse of regulatorypower.

26. The regulator should also be empowered to modify the pricing formula under the license if it isfound that changes to it are needed to enable its more effective use or if in the opinion of the regulator thatsome modifications are needed to encourage increased competition by private generators. Some deregulationwould be necessary to attract competition.

27. Other Charges. These charges include Connection, use of system, top-up and stand-by charges.It is not clear to whom the above charges would apply i.e. existing consumers or new private generators. Thiscondition seem to enable other private generators to sell power to TNB, allowing competition with TNB if theTNB paid them a price which allowed the private generators a reasonable return on investment.

Other Condidons

28. Obligation on Economic Purchasin. Purchasing ard procurement of fuel, supplies and equipmentshould be the responsibility of the licensee and not subject to approval of the regulator. The procurementfunction is complex and requires a significant level of technical and contractual skills which would be very difficultfor a regulator to develop. In addition, the potential for delay in obtaining the regulator's approval for contractscould be costly and could interfere with scheduled construction and plant operation and maintenance.

29. Rural Electrification. The costs of rural electrification projects should be directly financed byGovernment where they involve extension of the grid to consumers that are unable to meet the full costs ofsupply. TNB should complete the rural electrification as planned by the government, which is largely to becompleted by 1992.

30. Generation Security Standard. Further consideration of the acceptable level of loss of loadprobability may be needed to establish the acceptability of the standard proposed of 1 day per year. The criteriaadopted should take account of the acceptable number of plant outages based on analysis of consumer needsand availability of stand-by capacity at consumers' premises. There needs to be clarification of the term"planning margin or margins' (possibly it refers to the planned level of reserve plant).

31. Transmission System Design Standard This condition seeks the development of a code of practicefor setting standards for operation and maintenance of the transmission system. It requires the licensee tosubmit proposals within one month of issue of the license. If the TNB were to be able to comply with this

- 89 -

Annex 19 - Page 6 of 6

condition, considerable work would needed to be done before the license is issued. This, we understand isplanned to be undertaken by consultants over the next 6 months. It is noted that the licensee is required underthis condition to report on performance during the previous financial year. The licensee will need to establishinformation and reporting systems to meet this requirement.

32. RevocatiQn of the License. It is inconceivable that the Minister would revoke TNB's licensee givenTNB's present role as the sole supplier of electricity in the Malaysian Peninsular. It is suggested that thisprovision be only applicable to licensees other than TNB.

Revised License

33. A revised license was provided to TNB by the Director General of Electricity Supply on January8, 1991. The following comments apply.

34. Priciny. The pricing formula proposed by the consultants have been replaced by a new provisionwhich restricts the license to tariffs existing on September 1, 1990. This is an interim arrangement until a finalpricing formula is agreed. The restriction in price to customers would not be appropriate if significant increasesin fuel prices should occur. For that reason consideration s%hould be given to a reintroduce as soon as possiblean automatic fuel adjustment formula to ensure that any sudden increase in fuel prices beyond TNB's controlcan be passed on promptly to consumers.

35. ReRogting on Dangerous Premises. This condition could impose a high administrative burden onTNB depending on the form and frequency that reports are required. Annual statistical reports to the regulatorwould be more appropriate than reporting on each occurrence.

36. Insulation Test on Domestic Installation. The appropriateness of the technical aspects of thiscondition should be agreed between the Director General and TNB.

37. Licensee and Renistration Fees. This revised provision specifies the procedures for determiningthe amount of the license fees. Calculation of these fees will impose some administrative burden on TNB sincefees are payable on each generation station and substation. Fees are payable from April 1, 1990. It is unusualto seek collection of fees retroactively i.e. before any license is issued. Presumably, the fee schedule has beendrawn to meet the estimated costs of regulation incurred by the Director General.

38. Managenment Audit. Terms of Reference for such audit would need to be established by theDirector General.

39. Review of Terms and Conditions. This condition replaces Schedule 2 of the Consultants' proposalswhich provided for revocation of a license issued by the Director General. The provision for review of the licenseconditions is more suitable than in the original draft. Such review would take account of the management auditproposed in Condition 21.

- 90 -

ANNEX 20

MALAYSIA

POWER SYSIEM DEVELOPMENT PROJECT

Documents on Project File

1. Environmental Impact Assessment. LLN Proposed Gas Turbine - Combined Cycle. Expansion Projectat Sultan Ismail Power Station, Paka. Institut Pengajian Tinggi. University of Malaya. August 1990.

2. Ramalan Beban 1990-91 (Load Forecast) Lembaga Letrik Negara. Jabatan Perancang Pembangunan.Laboran pp(G) 1/90/4. Ogos 1990.

3. TNB Project Brief for the transmission projects (underground cables for Pudu Ulu Substation, KampongAwah-Yong Peng 275 transmission lines and LLN/EGAT Stage II interconnection.

4. Act 448 Electricity Supply (Successor Company) Act 1990 and Act 447 Electricity Supply Act 1990. Lawsof Malaysia. Approved on August 22, L990.

5. NEB's Power System Development Review. World Bank Mission November 27 - December 8, 1989.

6. Establishment of Galloway 275/153 Substation. Lembaga Letrik Negara. Jabatan PerancangPembangunan. September 1989.

7. Environmental quality Act, 1974 (Act 127) & Subsidiary Legislation. September 25, 1989. InternationalLaw Book Services, Kuala Lumpur.

8. Transmission Expansion Phase I. Project Brief. Dcvelopment Planning Department. Tenaga Nasional.January 1989.

9. Tariff. Lembaga Letrik Negara. Tanah Melayu. Effective September 1985.

10. Appraisal Mission Working Papers: (a) Demand Projects; (b) Capital Expenditures; and (c) FmancialProjections (paper and computer diskette).

MALAYSIAPOWER SYSTEM DEVELOPMENT PROJECT

TENAGA NASIONAL BERHADOrganization Chart

1 B1OARD OF| DIRECTORS

MIANAGING i IDIRECTOR Audit

Managing ~~~Business Supply Customfer a,,foet iac oprt aDirectors Developnent rations Services i i Sebirsi C esporateOlvislon %evision0,r1 Division Dvso

Sec;etary Devo,mn Generation Generation Financal Information Persor.tnP Snn Operation Projects Accounting Services Manageme writ

New Business | j Performance Technica | Transmission ct LManageme rkdrttd |strial@improvemntor Workshops Projects AconigManagementReain

Research &System Materials L fauyActcua elnDevelopment Operation |nStores ManaProJects M| erst Serces

Transmrission Marketing Taxaton |Setices Psue

Rural ProcurementProte Electritication_ Budget & 'ontract Train

Mini Hydro Slie

PLC & Funids General EducationConurtunication | Regins |iwestments Administratin TraiingNetwork

1 Ptikk Afalss |

ErAV

- 92 -

Page I of 2

CHART 2

300 MW COMBINED CYCLE PLANT AT PAKAIMPLEMENTATION SCHEDULE

1991 1992 1993 1994DESCRIPTION

APF4ANT CONSULTANT

PREPARE SPEC:ICATION4S

CIV WORKS

Bidding & A.ard

Construction $

BALANCE OF PLANT

Bidding & Award

Construction

MAD PLANT

Bidding & Award OF-I rT-2 ST/CC

Construction m . I

GT = Ga TurbineST - Stm TurbineCC - Combind Cycle

- 93 -

Page 2 of 2

CHART 2

A - 275 KV KAMPUNG AWAWHYONXG PENG TRANSMISSION LINEB - JALAN GALLOWAY/PUDU ULU SYSTEM

1991 1992 1993 1994

DESCREM~ON 2 14 1 I 4_ _

A - KAMPUNG AWAHIYONG PEN- tTRANSMISSION LINE

Environmental Assessment ................

Way Leaves

Bidding & Award . ... .

Construction

B - JALAN GALLOWAY/PUDU ULU SYSTEM

SUBSTATIONS

TRANSFORMERS & SWITCHOEAR

Bidding & Award

Civil Works

Equipment Installation

275 KV CABLFq

Way Leaves & Permits

Bidding & Award

Instalation

IBRD 23464

1So 1 TOt PENINSULAR mAtAYSIA

POWER SYSTEM DEVELOPMENT PROJECTT H A I L A N D TENAGA NASIONA BERHAD POWER GRIDr> PT _ TRANSMISSION LINES

- -~~~~~OWM 225 kV

Al} ¶hY _ _ 32kV

J tk1. KelrU P( WgR STATIONS

/ N~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~1ydro

oh < > > tSUBSTATIONS

XAlor Sqla A ) { r , Lunxtang _ STATE BOUNDARIES d°

-O£ChentPak A, / - INTEhINATIONAL BOUNDARIES

ourun>4 Jmlen 20 40 T0

~~~~~~~~~~~~~~~~~~~~~~~~0 28 48 05 809\iji qItS EOSooli Potonl 'V.E4.'10

'1 ,f "'" < ) ) Kusla K<t \ t(ltr)UEfE*Sk --------

(iv4Vc;\/uz GaI80oaX 4(0.10 Totogglg U(.Ja Te nu

Pv.t B r J> A A \ /m 9 EasentirOII J < ffs ~~~~~~~ T A t/ ) XKualda 09 g

_rINQ /unting J GvaMumno \ ENGGANU

Pemk Caddo K-K 0 ' Uln <

Sobar.JoyESY St A /'.Jo

g l KKalLS.018 J Ad, Ieatt 30

7I.ootoshot 800p,OlO~0d81t POrt K*WI - oogITO IU

4° 0 Tdok Anson KNP45mt

Groop. The denominolioos ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~K A ko0od o~~~d IIte boood0000 oltoto,to.1a00 ~ ~ ~ 5 lb 0A8 do i,0 jop7 R otv, h hP

K.alra S l$-go,

S.ba0f%;J vi^SkJ\tS £ A Porit S

2 ' .1~~~~~~~~~~~mktR. 0

Po KgF b.. Nir6SuJp s B .5rM1

3°~~ ~ ~~ VImptSbep- eTNAM 30iKl9~l Mu&t VSb9JY 0¢t Kl Shb

(a, co,, nV rrcolftbetie kti OConniughtweif j IN JON N S G I' R/ R

Ortdssgl.weuoifT ewlrdiNnk tKSK-rgn1jf9w-!-5 Ku&s7

iro.w. The dno-m=nfov. /\ SnWP

V5;7 h<WMp ioe 'jo'miy. ahon1 ebt Rnu

d ,,-the INOIOETuanku AeLIfAr O 531 13

CAMBODLA~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~~~~~DCMBR19

NvITe P < ~~VIET NAMd2 uv .e K v n

7- BtRUNEI P,k Nuea

,> taDtesa ~~~~~~~~I N D O E Si A SNGPR,Ky SINGJLPORE K__l.°t3 0

$;lle«trArts WDO11£51 ttsvv*#7A4 ~~~~~~DECEMBDE 1991