Document of

The World Bank I7jLE CQPYFOR OFFICIAL USE ONLY

Report No. 3171-SW

SWAZILAND

THIRD POWER PROJECT

STAFF APPRAISAL REPORT

May 7, 1981

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

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CURRENCY EQUIVALENTS

1 Emalangeni (E) = US$1.25US$1 = E 0.801 Emalangeni = 100 Emalangeni cents1 Rand (R) - US$1.25

1 Rand (R) = 1 Emalangeni

WEIGHTS AND MEASURES

1 liter = 1.057 quarts1 meter (m) = 3.28 feet1 kilometer (km) 2 = 0.621 miles1 square kilometer (km ) = 0.386 square miles1 kilovolt (kV) = 1,000 volts

1 kilowatt (kW) - 1,000 watts1 kilowatt hour (kWh) = 1,000 watt hours1 megawatt (MW) = 1,000 kilowatts1 megawatt hour (MWh) = 1,000 kilowatt hours1 megavolt ampere (MVA) 1,000 kilovolt ampere (kVA)1 gigawatt hour (GWh) = 1 million kilowatt hours1 kilo calorie (kcal) = 3.97 British thermal units (Btu)1 ton of coal equivalent (tce) = 7,000,000 kilocalories1 ton of oil equivalent (toe) = 10,500,000 kilocalories (Kcal)

ABBREVIATIONS AND ACRONYMS

AfDB African Development BankCDC Commonwealth Development Corporation (UK)EIB European Investment BankEPDC Electric Power Development Consultants (UK)ESCOM Electricity Supply Commission of Republic

of South AfricaKfW Kreditanstalt fur Weideraufbau (FRG)RSA Republic of South AfricaSEB Swaziland Electricity BoardSNPF Swaziland National Provident Fund

FISCAL YEAR (FY)April 1 - March 31

(Years shown in this report are SEB's fiscal years unlessotherwise indicated as calendar years).

This report is based on the findings of the appraisal missionconsisting of Messrs. I. Tuncay, E. Greenwood and G. Steinke,who visited Swaziland in July 1980.

SWAZILAND FOR OFFICIAL USE ONLY

STAFF APPRAISAL REPORT

THIRD POWER PROJECT

Table of Contents

Page No.

I. THE ENERGY AND POWER SECTOR ..... .............. 1Energy Resources ....................... 1Energy Demand and Supply .............................. 2Energy Pricing and Tariffs ............................ 3Power Sector .............................. 3Existing Facilities of the Swaziland Electricity Board 4Access to Service and Electrification of Rural Areas .. 5

II. THE BORROWER AND EXECUTING AGENCY ..... ........... 6Lending Arrangements and Previous Loans ............... 6Organization ........ ................. 6Management and Staffing ............................... 6Accounting and Auditing ............................... 7Billing and Collection ................................ 7Insurance ................................... 8Manpower Development and Localization ................. 8

III. DEVELOPMENT PROGRAM AND THE PROJECT ..................... 8Project Market ....... ................. 8Development Program ................................... 9Project Objectives ...... .............................. 10Project Description ................ .. ................. 10Cost Estimates ........................................ 11Project Financing ................... .................. 12Engineering, Consultants' Services andProject Implementation ............. .. ............... 14

Procurement ...................... ..................... 15Disbursement ..................... ..................... 15Project Monitoring and Evaluation ..... ................ 15Environment ........................................... 15

IV. FINANCIAL ASPECTS .................... .................... 17Past Financial Results . . 17Present Financial Position ............ .. ............... 18Tariffs ................................................ 18Financing Plan .. 19Revaluation of Assets . . 21Future Operations and Financial Position . . 21

V. ECONOMIC ANALYSIS .. 22Need for Additional Generating Capacity . . 22Alternative Expansion Programs, Least Cost Solutionand Optimization . . 22

Rate of Return . . 23Project Risks . . 23

VI. SUMMARY OF AGREEMENTS REACHED AND RECOMMENDATION ......... 23

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

LIST OF ANNEXES

ANNEX

1 Statistical Data on the Swaziland Electricity Board's Power System

2 Organizational Structure of the Swaziland Electricity Board

3 The Swaziland Electricity Board's Future Sales and Maximum Demand

4 Installed and Firm Capacity and Maximum Demand of the SwazilandElectricity Board's Interconnected System

5 Project Description

6 Project Cost Estimate

7 Project Implementation Program

8 Disbursement Schedule

9 Project Monitoring Guidelines

10 Income Statements, 1978-1990

11 Balance Sheets, 1978-1990

12 Cash Flow Projections, 1981-1990

13 Notes and Assumptions for Financial Projections

14 Economic Analysis

15 Selected Documents and Data Available in the Project File

MAP The Swaziland Electricity Board's Existing Power Systemand the Project (IBRD 15243)

I. THE ENERGY AND POWER SECTOR

Energy Resources

1.01 Swaziland is rich in energy resources, mainly in the form of coal asa depletable source and in the form of hydroelectric potential as a renewableresource. There are about 250 million tons of good quality coal (the energyequivalent of about 100 million tons of oil) in the western lowveld regions.All significant hydroelectric schemes are in the western plateaus, on the GreatUsutu River (Lusutfu) or its major tributaries, including the Little Usutu(Lusushwana), and on the Komati River. The total hydroelectric potential ofthe rivers is estimated at about 3,000 GWh per year (0.743 million toe/year).Although these are Swaziland's major rivers, they rise in the Eastern Transvaalin the Republic of South Africa (RSA).

1.02 RSA has tentative plans for large development schemes to use waterfrom these rivers, mainly for thermal power station cooling systems and forindustrial and domestic purposes. A series of RSA's White Papers on waterpolicy show that, by diversion, RSA could reduce Swaziland's total hydro-electric potential by nearly half to about 1700 GWh per year (0.421 milliontoe/year). However, it seems that RSA has so far consulted Swaziland on theuse of water resources of common interest.

1.03 Swaziland proposes to formulate its long-term water use policywhen the water resource study financed by AID and prepared by U.S. Army CorpsEngineers becomes available in 1981. The Lupohlo-Ezulwini HydroelectricScheme (the proposed third power project) will be located on the Little UsutuRiver, which has catchment areas in RSA that are too small for RSA's economicuse. Even though the Little Usutu River rises in South Africa, since themajor portion of the catchment is in Swaziland the project faces no signi-ficant risk in the event use of the upstream water by RSA becomes economic inthe future. Also, since the project is non-consumptive except for evaporationand the possibility of increased irrigation use through enhanced regulation,no impact is foreseen on the downstream riparian Mozambique. Thereforespecific undertakings in respect of international waters are not considerednecessary.

1.04 Although Swaziland has no known petroleum deposits or natural gas,firewood and bagasse provide other major energy resources. There are 200,000acres of indigenous forest in the north-western and central-western highveldareas. Three sugar factories produce about 280,000 tons/year of bagasse (about0.0506 million toe/year) as a by-product of refining sugarcane, and use muchof it as a fuel for steam and power production to meet power demands fromfactories and irrigation pumping. The production of power alcohol (ethanol)from molasses is being studied at one of the three sugar factories.

1.05 The Government's energy consultants (Fichtner, Ottogo:Ld andElectrowatt of Federal Republic of Germany (FRG)), are preparing an optimizedEnergy Master Plan to meet the future energy demand. The plan, expected to becompleted in 1981, will include the development of hydroelectric power, coal,bagasse and other energy resources. It will also review the possibility ofsubstituting other fuels for petroleum and also of refining oils in Swazilandfor domestic use. The Government expects this study to form the basis of itsenergy policy.

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Energy Demand and Supply

1.06 Total energy consumption of Swaziland in 1979 was about 366,400toe, or 0.672 toe per capita, among the highest in the Eastern Africa Region,as defined by the Bank. This is mainly attributable to the relatively highindustrial consumption compared to Swaziland's small population, which is550,000. Energy consumption 1/ per capita in other East African countriesis, for example: Kenya 0.024 toe, Madagascar 0.026 toe, Mauritius 0.305 toe,Sudan 0.027 toe. A general breakdown of Swaziland's consumption is as follows:

Energy Consumption of Swaziland (1979)

Price per toeQuantity (including transport Total

Energy Type (toe, thousands a/) excluding tax) (US$) (%)

Electricity b/ 109.4 162 29Coal c/ 71.8 40 22Coal Tar Products d/ 20.0 n.a. 5Petroleum e/ 91.0 258 (average) 24

Firewood f/ 37.1 n.a. 10Fire Bagasse f/ 29.7 n.a. 8Others g/ 7.4 n.a. 2

Total Energy Consumption 366.4 100

a/ Conversions to toe are made on the basis of the following rates:toe 1.0 = tce 1.5 (ton of coal equivalent); toe 1.0 = 4038 kWh (on thebasis of a 33% thermal efficiency).

b/ Electricity is generated from hydro and diesel stations and steam plants,using coal, firewood and bagasse. Electricity, 109.4 thousand toe,also includes 25.7 thousand toe (104 GWh) imported from RSA.

c/ 25,000 tons of imported coal (35 GWh) forms 8.7 thousand toe includedin the 109.4 thousand toe of electricity and is therefore excludedfrom the 71.8 thousand toe of coal.

d/ Fired by Usutu Wood Pulp Co. in their lignin burning plant.

e/ Made up of: 2 million liters of liquified petroleum gas; 1 millionliters of avgas and jet fuel; 3 million liters of luboil; 41 millionliters of motor spirit, and 44 million liters of diesel oil and kerosene(mainly for transportation, household cooking and lighting).

f/ Industrial use for steam production only. See bL above for the balance.

g/ Mainly wood, dung and charcoal consumption in rural areas.

1/ For comparative figures in power consumption, see para. 1.10.

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1.07 Swaziland has a hydroelectric potential of about 3,000 GWh per year,of which 140 GWh per year are being used. The proposed project will provide afurther 95 GWh per year.

1.08 Swaziland-s coal production is about 145,000 tons per annum, andfeasibility studies are underway for the development of two additional mines.The mines are expected to produce coal for export as well as replacing coalimports from RSA, which in 1980 were about 30,000 tons per annula. Swazilandhas no oil refinery. It imports all its oil and petroleum products throughRSA and Mozambique.

Energy Pricing and Tariffs

1.09 The Government of Swaziland regulates fuel prices, but the SwazilandElectricity Board (SEB) is empowered to set electricity tariffs. Prices ofimportant fuels used and of electricity in Swaziland are shown below:

Border Price peror Pithead Trans- Retail millionPrices portation Tax Price_ kcal

(Emalangeni)

Heavy fuel oil (ton) 119 20 12 151 14.3Diesel oil (ton) 153 20 4 177 16.9Kerosene (ton) 192 20 11 223 21.3Jet fuel (ton) 250 20 120 394 37.5Coal (local) (ton) 12.5 7 0.3 19.8 3.3Average price of electricity 30.5 35.4

(MWh)

Firewood, kerosene and electricity are the most commonly used sources ofenergy in Swaziland households. Electricity is used for lighting and waterheating, other fuels for cooking and also water heating. The effect ofdifferent pricing policies on energy consumption and the possible need tochange the tariff structure to a more cost effective basis will form partof the proposed tariff study (para. 4.06).

Power Sector

1.10 The total electricity energy consumption of the country in 1979was about 442 GWh, which corresponds to a per capita energy use of about 850kWh/yr, and is among the highest in the Eastern Africa Region. For example,electricity consumption per capita in other East African countries is asfollows: Kenya, 90 kWh; Madagascar, 43 kWh; Mauritius, 417 kWh; and Sudan,49 kWh. SEB generates about 26%, but supplies about 67% of the electricityconsumed in Swaziland (including RSA imports). Power is also generated byprivate companies to meet their own requirements, such as the operation ofsugar and wood pulp mills. Swaziland-s electricity generation and installedcapacity in 1978 and 1979 are given in Annex 1.

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1.11 Between 1975 and 1980, SEB's energy sales increased from 126 GWhto 276 GWh, which corresponds to an average increase of about 17% per annum.Increasing industrial loads have caused a very high rate of growth in SEB'ssales since it started operations in 1963. Between 1975 and 1980 the averageannual increase in SEB-s industrial sales was 17.6%. SEB has not made anyadditions to its generating capacity since 1973, but instead has met increaseddemand by importing from RSA. During 1980, 188 GWh were imported compared to117 GWh generated by SEB.

Existing Facilities of the Swaziland Electricity Board

1.12 The SEB system (map IBRD 15243) comprises the Board's three hydro-electric stations, a diesel generating plant, and two 132-kV links, with acapacity of about 67 MW, for importation of power from RSA's ElectricitySupply Commission (ESCOM) and transmission and distribution facilities. SEB'stotal generating capacity is about 30 MW, of which 21 MW is hydro and 9 MWdiesel, as shown below:

SEB's Installed Capacity

Total TotalLocation of No. of Installed Capacity Maximum Available Date

Station Units Type MW Capacity MW Installed

Mbabane 2 Hydro 0.60 0.55 1955/54

Edwaleni 4 Hydro 10.00 9.60 1964/671 Hydro 5.00 5.00 19691 Diesel 0.50 0.50 19672 Diesel 9.00 9.00 1968/70

Magaduza 1 Hydro 6.50 5.60 1969

Total 31.60 30.25

1.13 Although almost all private power plants (para. 1.10) are connectedto SEB-s system, most operate independently except for seasonal start-upsduring maintenance periods. The bagasse (para. 1.04) is insufficient toproduce any surplus energy for sale to SEB. At present, the use of coal forpower production by private plants is not an economic alternative to supplyfrom SEB because of the small plant sizes involved.

1.14 At present, the 66-kV transmission network covers almost the entirecountry and is also connected to ESCOM's system by the 132-kV power links.SEB's distribution voltages are 11 kV, 6 kV and 400 volts. It is a well-designed and effective network. System frequency is 50 Hz.

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1.15 SEB's control center (for load dispatching and switching), which islocated in Mbabane near its headquarters, communicates with its power plantsand almost all major substations and ESCOM by radio and power-l:Lne carrier. 1/

It controls almost all important circuit breakers on the network by theradio/remote control system. Furthermore, SEB's power network has an effi-cient load control system, which reduces loads automatically during systemdisturbances. The control center uses diesel sets during peak hours tokeep ESCOM demand charges at the most economic level.

1.16 Statistical data on SEB's network are:

SEB's Transmission and Distribution System Statistics (1980)

High Voltage Overhead Lines Length (km)

132-kV 8766-kV 70211-kV and Lower 871

Substations Number Capacity (MVA)

132/66-kV 1 55

66/11-kV 19 100

66/6-kV and Lower 5 11

11/0.4-kV 975 76

1.17 SEB's existing transmission system has sufficient capacity tocarry the additional electricity to be generated by the project. However,SEB-s consultants have recommended minor additional transmission facilitieswhich would improve the reactive load flow control and will reduce systemlosses. These facilities are included in SEB's general system developmentand are not included in the project.

Access to Service and Electrification of Rural Areas

1.18 The Government has given high priority to industrial and urbanelectrification for many years. About 14% of the population, totalling about77,000, is supplied with electricity by SEB. This is one of the highestpercentages in the Eastern Africa Region.

1.19 Neither Government nor SEB has any special rural electrificationpolicy. To date, nearly all electricity supplies to the rural population,which is widely dispersed, have been to community services such as schools,

1/ Telephone system which works through the transmission lines.

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hospitals, churches, water supply systems, post offices, police stations andto workshops and community centers of rural development schemes. In allcases, SEB expects the capital cost of connections to be recovered in twoyears from revenues for the sale of electricity to the consumers. In caseswhere SEB estimates revenue to be inadequate, a bank guarantee of revenue isrequired before a project is started.

II. THE BORROWER AND EXECUTING AGENCY

Lending Arrangements and Previous Loans

2.01 The Swaziland Electricity Board (SEB) would be the borrower andexecuting agency. The proposed loan would be the third Bank loan to SEB.The first of these loans (338-SW) for US$4.2 million was made in 1963to help finance the foreign exchange costs of a 10-MW hydroelectric plant atEdwaleni. This was followed by a second loan (492-SW) for US$2.75 millionin 1967 to help finance a 6.5 MW hydroelectric plant at Magaduza, a 5-MWdiesel station at Ezulwini and expansion of Edwaleni hydroelectric plant by5 MW. Both projects included transmission and distribution extensions. Theprojects were completed within the time and cost estimated at appraisal, andSEB's administrative and technical performance was satisfactory.

Organization

2.02 SEB, a government-owned corporate body operating throughoutSwaziland, was established under the Electricity Act in 1963. SEB's mainfunctions are to generate, transmit, distribute and supply electricity and,except under the authority of a license by SEB, no other body is empoweredto carry out these functions.

2.03 The Board consists of a chairman and not less than three or morethan five other members appointed by the Minister of Works, Power and Com-munications. Subject to the general directions of the Minister, the Boardis given considerable autonomy under the Act to conduct its business alongcommercial lines. SEB's chairman is a leading businessman in Swaziland.The Board approves all matters involving financial, staffing and other policyissues. The Board also approves tariff changes. The General Manager (who isalso Chief Executive Officer) is given considerable freedom to carry outday-to-day operations within prescribed policies, and his recommendations onpolicy matters have an important influence on the Board decisions.

Management and Staffing

2.04 SEB's General Manager has occupied the position for several yearsand is an effective manager. He is supported by competent and experiencedpersons in the senior management positions, most of whom have been with SEB

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for many years. The covenant under Section 2.11 of Loan 492-SW requires theagreement of the Bank prior to making any new appointment to the position ofGeneral Manager. It was agreed during negotiations that this covenant wouldbe repeated for the proposed project. It was also agreed that Government wouldobtain the consent of the Bank before making any new appointment to theposition of Chairman of the Board.

2.05 SEB's staff totalled about 360 in 1980 and, apart from additionsto meet increasing work requirements, has remained stable. The staff includes8 professional engineers, including the Deputy General Manager. SEB's manage-ment performance has been good. Accounting, plant operation and maintenance,procurement and personnel activities have been carried out effectively.

2.06 SEB's organizational structure is given in Annex 2. The allocationof responsibilities among senior staff has developed on an ad hoc basis.Senior staff are individually involved in a number of activities such asplanning, construction, procurement and administration. This informal arrange-ment has worked well in the past. However, as the size of SEB's activitiesincreases, SEB in consultation with the Bank will review the continuing adequacyof its organization to meet current needs and will make changes if necessary.

Accounting and Auditing

2.07 SEB's financial management is of a good standard. Accountingrecords are well maintained, expenditures carefully planned, recorded andmonitored, and close attention given to planning future cash needs. TheGeneral Manager is a qualified accountant with many years of practicalexperience and the accounting staff, most of whom have substantial practicalexperience, are competent.

2.08 SEB's accounts are audited by a well-established, reputable firm ofexternal auditors. The audit covenant under Loan 492-SW, which requires SEBto have its financial statements audited by independent accountants acceptableto the Bank and to submit its audited financial statements to the Bank withinfour months after the close of SEB's fiscal year, has been met. It wasagreed at negotiations that a similar covenant would be included under theproposed loan.

Billing and Collection

2.09 SEB's accounting records are maintained manually with the exceptionof accounts receivable and billings. Billings for about 10,000 consumeraccounts are processed through a computer bureau which produces relatedstatistical information. The system works well and collection performance issatisfactory. Although Government departments meet their obligations, some

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are slow payers. Accounts receivable at March 31, 1980 were equal to about70 days sales, and it is expected that this level, which is reasonably satis-factory, can be maintained or even reduced in the future.

Insurance

2.10 SEB maintains a comprehensive insurance program with a privateinsurance company which is reviewed annually with the insurers and is satis-factory for third party coverage. The project would carry no unusual risks.

Manpower Development and Localization

2.11 SEB places much emphasis on manpower development, and it has beensuccessful in training Swazi nationals to occupy most of the professionaland technical positions which in the 1960s were staffed almost entirely byexpatriates. In 1980 only six out of 16 of SEB's senior management positions(including the top management group) are occupied by expatriates, and it isexpected that this number will be reduced by the further development ofqualified Swazi staff through training and experience.

2.12 SEB commenced its training efforts in the 1960s. It administersfellowship-training programs for professional and technical personnel atuniversities, colleges and technical institutions, and personnel have beentrained in the UK, USA and RSA. Many technicians participated in a specialtraining program for SEB personnel at the Swaziland College of Technology. Inaddition to other staff development efforts, SEB training officers and seniorstaff conduct introductory courses for new staff as well as a number of shortcourses for technical staff. Almost all professional SEB staff have benefitedfrom some of the above training opportunities.

2.13 In preparation for the operation of the project plant facilities,SEB will select some of its experienced personnel for training by the plantmanufacturers in operating and maintenance practices; this training willbe provided for in the contracts with the suppliers.

2.14 Since 1978 when a new training officer was appointed, SEB hasenlarged and improved its existing systematic manpower development program.The appraisal mission is satisfied that this program will continue to beadministered successfully and that adequate resources will be availablethrough SEB or bilateral assistance.

III. DEVELOPMENT PROGRAM AND THE PROJECT

Project Market

3.01 SEB sales more than tripled between 1970 and 1980, with an averagegrowth rate of about 13% per annum. Sales growth has been particularlyrapid since 1975, averaging 17% per annum due to rapid industrialization.

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Energy consumption by SEB consumer groups is as follows: domestic 17%,commercial 9%, irrigation 32%, and power and bulk (wholesale industrial,commercial and domestic) 42%. Industrial consumption, including irrigation,accounts for about 50% of SEB's total sales. Statistical data on SEB-s powersystem are given in Annex 1.

3.02 A comprehensive load forecast study covering the period 1980-1990was carried out in 1979 by SEB's main engineering consultants, Merz andMcLellan and Watermeyer, Legge, Piesold and Uhlmann (UK) in assc,ciation withCoopers & Lybrand Associates Limited (UK), and was included as aL part of theirdraft feasibility study for the project. It was based on historical growthtrends for domestic and small consumers and on projected individLual growth formajor consumers.

3.03 The load forecast study estimates average yearly growth from 1979to 1982 at 16%, followed by a decline to 6% from 1982 to 1990 (Annex 3). Theprojected higher load growth for initial years of the forecast is due torelatively large additions to existing industrial consumption because of newindustrial construction, and the expansion of existing large plants (such asa third sugar mill, the Swaziland Irrigation Scheme, and a new coal mine).Thereafter, growth in industrial usage is expected to taper off as there areno firm plans for other large industrial projects.

Development Program

3.04 Based on the load forecast study mentioned above, SEB"s consultantsrecommended a generation development program which includes (i) the proposedproject, the Lupohlo-Ezulwini Hydroelectric Scheme, to be commissioned in1984; and (ii) construction of a third power link between ESCOM and SEBsystems by 1985; and (iii) construction of an additional hydroelectric stationwith a capacity of 8 MW by 1986.

3.05 The possible additional hydroelectric station downstresam of theexisting Magaduza Hydroelectric Station was proposed to the Bank for financingas part of the proposed project and has been thoroughly investigated.Although the recommended installed capacity of this scheme is 8 MW, its firmcapacity would only be about 4 MW for most of the year. Its costs would beabout US$6,600 per installed kW, compared to US$3,000 for the proposed projectand it is not economical. SEB has, therefore, decided not to include it inits present development plans.

3.06 In 1985, SEB-s total firm capacity (including the proposed projectand the proposed third ESCOM link) will increase to about 110 MW, which willbe sufficient to meet the expected system maximum demand of about 90 MW withreasonable system reserves until 1990 (Annex 4). SEB will probably constructanother power link with ESCOM after 1991 to meet growing demand, and willstudy the feasibility of using indigenous resources, such as coal and hydro,for its future long-term power generation plans.

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3.07 The consultants have also carried out studies to evaluate thefuture performance of SEB's 132-kV and 66-kV systems and have recommendedreinforcement of the 66-kV systems in the north-east (including Simunye,Mhlume and the Big Bend areas). These reinforcements are included in SEB'stransmission construction program.

Project Objectives

3.08 The project objectives are: (a) the provision of additional powergenerating capacity to help meet the power demand up to 1990 (average produc-tion 94 GWh per year; firm production 54 GWh per year); (b) the developmentof an indigenous renewable energy resource; and (c) the reduction of depen-dency on RSA for power. The project will also help to improve SEB's pricingpolicies through a tariff study (para. 4.06).

Project Description

3.09 The project consists of the following elements:

(a) a rockfill dam at Lupohlo, about 40 m in height and400 m in length, to provide an 3effective reservoircapacity of about 20 million m on the Little Uluturiver, and an average river flow of about 3.5 m /sec;

(b) a tunnel and penstock system consisting of an unlinedlow-pressure power tunnel 4.4 km long, leading to asurge chamber and thence to a vertical shaft; a 600-mlong steel-lined tunnel and a surface penstock systemproviding a head of about 250 m between the Lupohlosite and the powerhouse at Ezulwini;

(c) a powerhouse with two 10-MW pelton turbine-generatorhydroelectric units at Ezulwini, with a short tailracechannel to the Mwutshini river, which joins the LittleUsutu river near Mbabane; a 66-kV switchyard adjacentto the power station; and

(d) consultants services for bid evaluation, constructionsupervision (para. 3.17), a tariff study (para. 4.06),health and ecological studies (para. 3.28); and a panelof experts to advise on civil works (para. 3.18).

3.10 The dam is to be constructed about 3 km downstream from the roadbridge which links Mbabane and Mhlambanyati. The site selection was based onan optimization study which considered the most favorable ground conditions,together with the required reservoir capacity. The transfer of water fromthe reservoir at Lupohlo to the power station will be made through an unlined,

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low-pressure tunnel system passing under Lupohlo mountain. The surge chamberwill be located at the junction of the low-pressure tunnel and the high-pressure system, which will consist of the shaft, steel-lined tunnel and thepenstock. The Ezulwini power station will be located about 5 km south ofMbabane along the main road to Manzini on the Mwutshini river at a point ofabout 1 km upstream of its confluence with the Mbabane river. A more detaileddescription of the project is given in Annex 5.

Cost Estimates

3.11 The estimated project cost, without interest during construction,is E 42.01 million (US$52.52 million), of which about 69% amounting toE 28.84 million (US$36.06 million) are foreign exchange costs. The localcosts include allowances for import duties and taxes. These total aboutE 0.50 million (US$0.63 million) or about 1% of the total financiing require-ment. The cost estimates (Annex 6) are summarized below:

Summary Project Cost Estimate(E 1.0 = US$1.25)

% inProject Components Local Foreign Total Local Foreign Total Total

-- E millio …------ -----US$ million----…

1. Civil Works 7.07 11.42 18.49 8.84 14.27 23.11 392. Mechanical & Electrical Works 1.74 7.50 9.24 2.17 9.38 11.55 193. Engineering Consultancy

Services and Administration 0.55 2.57 3.12 0.69 3.21 3.90 64. Studies 0.08 0.29 0.37 0.10 0.36 0.46 1

Sub-Total 9.44 21.78 31.22 11.80 27.22 39.02 65

Contingencies

5. Physical Contingency 1.06 3.10 4.16 1.32 3.88 5.20 96. Price Contingency 2.67 3.96 6.63 3.34 4.96 8.30 14

Total Contingencies 3.73 7.06 10.79 4.66 8.84 13.50 23

TOTAL PROJECT COST 13.17 28.84 42.01 16.46 36.06 52.52 88

7. Interest During Construction 1.27 4.11 5.38 1.59 5.14 6.73 12

TOTAL FINANCING REQUIREMENT 14.44 32.95 47.39 18.05 41.20 59.25 100

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3.12 The cost estimates are based on contractors offers for recentsimilar civil, mechanical and electrical works. The base costs are expressedin January 1, 1981 prices. SEB engaged two additional consultants, the firstto re-evaluate the geological investigations and design (Woodward Clyde, USA)and the second to re-evaluate estimated costs (Farrow Lane, RSA). During theappraisal mission, the project costs were revised to take into account theconsultants' recommendations. Physical contingencies for different projectcomponents, ranging from 8% to 16% for civil works and 7% to 10% for equipmentand 10% for engineering services, have been added. The cost estimates arebased on the price escalation shown in the following table:

Calendar Year 1981 1982 1983-85

Local (%) 12.5 11.0 10.0Foreign (%) 9.0 8.0 7.0

3.13 The risk of cost overruns has been minimized by obtaining bids forthe main civil works contracts prior to finalizing the cost estimates.

Project Financing

3.14 The proposed Bank loan of US$10 million equivalent would be usedto help finance the foreign exchange costs of the civil works and relatedengineering services, health and ecological studies and the services of apanel of experts to advise on civil works (para. 3.18). The Bank loan wouldcover about 23% of the estimated foreign exchange requirements and 16% of thetotal project financing requirements.

3.15 The following table shows the financing sources and the allocationto specific goods and services:

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Millions of Allocation of Finance toSources of Finance Emalangeni U.S. Dollars Specific Project Goods and Services 1/

External Finance

IBRD 8.0 10.0 Parts A, 2/ B, and E of Project CostEstimate

AfDB 6.5 8.2 Part C and resettlement costs in Part A

CDC 6.1 7.6 Not allocated to specific goodsand services

EIB 7.0 8.8 Parts A 2/ and B

KfW 6.5 8.1 Part D

Total External Finance 34.1 42.7

Local Finance

Swaziland National 5.0 6.2 )Provident Fund )

)Government 2.0 2.5 ) Not allocated to specific goods

) and services)

SEB-s Internal 6.3 7.8 )Cash Generation _ )

Total Local Finance 13.3 16.5

Estimated TotalFinancing Requirements 47.4 59.2

The European Investment Bank (EIB) funds of US$8.8 million equivalent wouldbe used to help finance the local costs of the dam, tunnel and powerhouse andrelated engineering services, the African Development Bank (AfDB) funds ofUS$8.2 million to help finance the foreign costs of generators, turbines,valves and crane, and resettlement costs, and Kreditanstalt fur lWeideraufbau(KfW) funds of US$8.1 million would finance the foreign and part of the localcosts of electrical and mechanical plant and engineering services for allelectrical and mechanical work. The Commonwealth Development Corporation(CDC) funds of US$7.6 million equivalent would be available to help meetproject financing requirements not met by other sources.

1/ Project parts are identified in Annex 6.

2/ Excluding resettlement costs.

- 14 -

3.16 External finance would cover about 72% of the project's financingrequirements (including total foreign exchange costs estimated at 69% of thoserequirements). US$6.2 million from the Swaziland National Provident Fund(SNPF), US$2.5 million from Government and the remainder from SEB's internalcash generation would complete the financing. In the case of AfDB and KfW,finance will be provided to Government and passed to SEB under onlendingarrangements. As a condition of the effectiveness of the Bank loan, allconditions of effectiveness of the AfDB, CDC, EIB, KfW and SNPF loans shouldbe met.

Engineering, Consultants Services and Project Implementation

3.17 SEB would be responsible for implementation, assisted by engineeringconsultants, who were also responsible for preparing the feasibility study(para. 3.02). SEB is to enter into a separate contract with these consultantsto cover the preparation of bid documents, the evaluation of bids and construc-tion supervision. The cost of the consultants' services is estimated atUS$4.2 million. The average man-month cost (including about 800 man-monthsof salary, international travel and subsistence) is estimated at US$6,600.Additional consultants' services for health and ecological studies are esti-mated to cost US$0.2 million. The estimated average man-month costs for theseservices is US$5,700. It was agreed during negotiations that SEB would employengineering consultants to supervise project construction whose qualifications,experience and terms and conditions of employment are satisfactory to the Bank.

3.18 SEB staff have some experience in the construction of transmissionand distribution facilities as well as hydroelectric projects. SEB will setup a constru'ction supervision unit consisting of a project manager, engineersand technicians. A panel of experts would be appointed to review the engineer-ing design and revisions to the detailed engineering design and to reviewprogress of construction from time to time. Among other things the panel willadvise on foundation treatment, extent of excavation, grouting and concretingprograms, composition of the fill, and support to the tunnel during itsexcavation. Assurances were obtained during negotiations that SEB wouldsubmit to the Bank a detailed dam inspection program including the nature,frequency and monitoring procedures for the inspection of hydroelectric worksand dams to ensure that the works will be inspected regularly in accordancewith sound engineering practice. The panel would consist of an engineeringgeologist and two civil engineers specializing in dam construction and under-ground excavation. The estimated total cost of the panel's services would beUS$0.42 million with an average man-month cost of US$12,700. These man-monthcosts reflect the high calibre of experts required for a panel of this nature.During negotiations it was agreed that SEB will appoint a panel of expertswhose qualifications, experience and terms and conditions of employment aresatisfactory to the Bank. SEB plans to appoint the panel by August 1, 1981.Terms of reference were agreed with SEB during negotiations.

3.19 Project design was completed in May 1980. Bid documents were issuedin January 1981 and bid closing was in April 1981. Construction is expectedto begin in October 1981, and to be completed by March 1984 (Annex 7).

- 15 -

Procurement

3.20 Contracts of US$100,000 equivalent or more for civil works financedfrom the proposed Bank and EIB loans would be awarded on the basis of inter-national competitive bidding (ICB) consistent with the guidelines for procure-ment under World Bank loans and IDA credits. Contracts for whiclh ICB is notrequired may be awarded in accordance with local procedures which have beenreviewed and are acceptable to the Bank. Total expenditures under suchprocedures would not exceed US$500,000. All major materials and equipmentwould be imported as there are no local manufacturers or contractWors in thesespecialized fields.

3.21 Contracts to be financed by other co-lenders will be awarded on thebasis of international competitive bidding, but AfDB procurement proceduresexclude RSA. Bid documents were issued in January 1981 for the major civilworks items and for mechanical equipment related to dam construction.

Disbursement

3.22 Bank funds would be disbursed against: (a) 26% of the total costsof civil works for construction of the dam, tunnel and power house and relatedengineering services and (b) 40% of the total costs of consultants' servicesfor health and ecological investigations relating to the project, and of apanel of experts to advise on civil works.

3.23 If any of the Bank funds remain undisbursed after project completion,they would be cancelled. The proposed closing date would be March 31, 1985,about one year after the expected project completion date. A disbursementschedule is given in Annex 8.

Project Monitoring and Evaluation

3.24 During negotiations the reports and records necessary to monitorprogress of the project and its evaluation on completion were agreed upon.Proposed guidelines for a project monitoring system are given in Annex 9. Itwas agreed during negotiations that, within one year of the project completion,SEB will submit a completion report to the Bank, based on an outline to beagreed with the Bank.

Environment

3.25 As part of the feasibility study SEB-s consultants con,ducted areview which showed that the impact of the project on the environment willbe insignificant as the reservoir would be relatively small. The surfacearea of the lake at maximum and minimum supply levels will be 1.8 km2

and 0.5 km2.

- 16 -

3.26 About 300 people in the reservoir area would be resettled andcrops and forests in the same area would be inundated. Environmental effectson the Mlilwane game park, which is close to the Lupohlo reservoir, would beminor. The following measures would be taken in relation to these environ-mental and social factors:

(a) resettlement of residents, land acquisition, and bush clearingin the reservoir area;

(b) a forestry survey to assess exploitable timber potentialand siltation in the reservoir area;

(c) an ecology survey covering present and future fish life andto identify measures to avoid any possible effects on healtharising from water diversion; 1/

3.27 SEB has assessed the timber potential at the reservoir site workingclosely with the Forestry and Agricultural Departments. SEB would be respon-sible for resettlement of the people in the reservoir area. Governmentpermission for land rights for the project and for resettlement plans has beenobtained and various options discussed with individual property owners and thelocal chiefs. Progress on this only awaits approval of the project. TheNational Trust Commission and Government would be responsible for the imple-mentation of (c) and (d) above. The National Trust Commission would alsoassess the fish potential and tourism value of the proposed lake. The con-sultants' report (para 3.02) recommended a coordination committee be estab-lished consisting of SEB and concerned government agencies. This would helpensure integrated develoDment, optimum reservoir utilization and appropriateconservation measures.

3.28 It was agreed during negotiations: (a) that by June 30, 1982SEB would complete a study of the human health and disease implications of theproject and, based on an exchange of views with the Bank, promptly take allnecessary measures to implement the appropriate recommendations of the study;and (b) that Government would carry out a study of the ecological implicationsof the project on the Lusushwana/Usutu River basin and promptly thereafterexchange views on the results thereof with SEB and the Bank.

1/ While Bilharzia is endemic in still waters in Swaziland it is felt thatthis can be controlled by periodically lowering the reservoirs- waterlevel to prevent the hatching of snail eggs. This method will beexamined in the health and ecological study.

- 17 -

IV. FINANCIAL ASPECTS

Past Financial Results

4.01 The results of SEB's FY1976-1980 financial performance are summar-ized below. Except for FY1980 SEB has more than met its principal financialobjective of achieving an annual 9% rate of return on the average net fixedassets at historical costs in operation under Loan 492-SW. As a consequenceof tariff increases (para. 4.03) the rate of return for FY1981 should beabout 13%. Between FY1976 and 1980 SEB financed about 65% of its investmentrequirements, which totalled E 9.2 million (US$12 million), froma internal cashgeneration.

SUMMARIZED REVENUE AND EXPENDITURE ACCOUNTS

1976 1977 1978 1979 1980

Units sold (millions of kWh) 153 184 202 223 276Average price per kWh (E cents) 1.92 2.25 2.34 2.66 2.68

(US cents) 2.40 2.81 2.93 3.32 3.35

thousands of Emalangeni

Revenues 2,943 4,153 4,741 5,932 7,410

Operating Expenses

Purchases from ESCOM 1/ 441 768 1447 1790 3475Other 904 992 1207 1646 2003Depreciation 553 828 702 842 839

TOTAL 1,898 2,588 3,356 4,278 62317

Operating Income before Interest 1,045 1,565 1,385 1,654 1,093

Average Net Fixed Assets inoperation at historical cost 10,565 11,648 12,338 12,983 13,727

Rate of Return (%) based on- historical cost 9.9 13.4 11.2 12.7 8.0- estimated revaluation 2.0 2.6 2.4 2.7 1.0

1/ The quantity of electricity imported from ESCOM was 4.6 times greaterin 1980 than in 1976, while local production varied up to 26% dependingon water availability. ESCOM price increases during this period wereabout 70%.

- 18 -

Present Financial Position

4.02 SEB's audited balance sheet at March 31, 1980, which is summarizedbelow, indicates a good financial position with a current ratio of 1.8 anda debt/equity ratio of 40:60.

ASSETS ------ thousands of-------Emalangeni US$

Fixed Assets at Cost 20,606 25,757Less Accumulated Depreciation 6,464 8,080

Net fixed assets 14,142 17,677Work in Progress 433 542

14,575 18,219

Current Assets 2,135 2,669Less: Current Liabilities 1,159 976 1,448 1,221

Total Assets 15,551 19,440

EQUITY

Retained Earnings 9,225 11,532

LOANS 6,326 7,908

Total Equity and Loans 15,551 19,440

Tariffs

4.03 One of SEB's principal financial objectives has been to earn anannual rate of return on average net fixed assets in operation at historicalcost of at least the minimum 9% level required under Loan 492-SW. To achievethis objective, tariffs were increased from January 1, 1980 and this raisedaverage revenues per kilowatt hour sold by about 13%. In 1978 and 1979tariffs had been increased by 10% and 13%. These were the only tariff in-creases over the last ten years, a period when consumer prices increased byat least 120%.

4.04 It was agreed during negotiations that SEB would contribute not lessthan E 20 million (US$25 million) from internal cash generation towards itscapital spending, including the proposed project, during the 1981-1985 projectdisbursement period. This would be close to SEB's capital requirements, notprovided by loans, based on present capital spending estimates. It was alsoagreed during negotiations that SEB would annually review the adequacy of itstariffs for meeting the E 20 million (US$25 million) cash generation objectiveon the basis of forecasts prepared in a manner satisfactory to the Bank.As a first step towards meeting this objective SEB made a 15% tariff increaseon February 1, 1981 and plans to follow this with further tariff increases of12% on January 1, 1982 and January 1, 1983, after which two 6% annual tariffincreases are estimated to be required during the project disbursement period.

- 19 -

4.05 Notwithstanding the above it was agreed at negotiations that, toensure that SEB earns a reasonable rate of return on capital employed, itwould earn a minimum annual rate of return on net revalued net fixed assets ofnot less than 7% in FY1982 and not less than 8% in FY1983 and thereafter. Thefollowing table indicates the estimated annual nominal tariff levels andincreases that would be required if adjustments were made annually to meet theminimum 8% rate of return requirement from FY1986 to FY1990.

1986 1987 1988 1989 1990

Average tariff per kwh (E cents) 5.26 5.62 5.98 6.38 7.01(US cents) 6.57 7.02 7.47 7.97 8.76

Annual nominal tariff increase (%) 13 7 6 7 10

The above rate of return covenant would replace Section 2.07 of Loan 492-SWunder which SEB is to set its revenues at a level sufficient to cover operatingexpenses, interest, repayments on long term indebtedness or depreciation(whichever is greater) and reasonable allocations to reserve, and wouldreplace the Supplementary Agreement requiring SEB to earn an annual 9% rateof return on average net fixed assets at historical cost.

4.06 Although some minor changes have been made in SEB-s tariff struc-ture over the last few years, a systematic review of the econom:ic and socialaspects of SEB's tariffs should now be made. It is expected that changes willbe required which will bring the tariff more into line with long run marginalsupply costs to different types of consumers and take into account time-of-dayconsumption. During negotiations it was agreed that SEB will employ consultantson terms and conditions acceptable to the Bank to complete a tariff study byJune 30, 1982 and that, after consultation with the Bank, SEB will promptlyimplement such tariff changes as are considered necessary.

Financing Plan

4.07 SEB's estimated financial requirements and financing sourcesduring the FY1981-1985 project disbursements period are:

- 20 -

FINANCING PLAN FY1981-1985

Us$Emalangeni Equivalent %

---------- (millions)---------

REQUIREMENTS

Capital ExpendituresProposed Project 42.01 52.51 69Interest During Construction 5.38 6.72 9

Total Project Financing Requirements 47.39 59.23 78Other 13.44 16.78 22

Total Requirements 60.83 76.01 100

Sources

Internal Cash Generation 31.31 39.13 51Less: Debt Service and

Working Capital Needs 11.20 14.00 18

Net Internal Cash Generation 20.11 25.13 33

Project Finance:BorrowingsAfBD 6.54 8.17 11CDC 6.07 7.58 10EIB 7.00 8.75 12IBRD 8.00 10.00 13KfW 6.52 8.15 11Swaziland National Provident Fund 5.00 6.25 8Government 2.00 2.50 3Cash increases (0.41) (0.52) (1)

Total Sources 60.83 76.01 100

4.08 In the financing plan it has been assumed that the Bank loan ofE 8.00 million (US$10 million) would be available to SEB over 20 years, in-cluding a 3-year grace period, at a 9.6% interest rate. Other borrowingswould be available to SEB on the terms shown below.

- 21 -

Terms of Co-Lender Finance

Source Term Grace InterestYears Period Rate

ExternalAfDB 1/ 20 5 8CDC 15 3 9.5EIB 15 3 8KfW I/ 30 3 8

InternalSNPF 20 10 10

Government 24 4 8

1/ Finance would be provided to Government and passed to SEB underon-lending agreements.

Revaluation of Assets

4.09 SEB s consultants have revalued its fixed assets to reflect currentvalues by using the wholesale machinery and transport index published inRSA, which they recommended as most appropriate for SEB's purposes. This isacceptable and at negotiations it was agreed that, for the purpose of the rateof return covenant (para 4.04), fixed assets will be valued at March 31, 1980at a replacement cost of E 44.22 million less accumulated depreciation ofE 14.78 million. It was also agreed at negotiations that fixed assets wouldbe annually revalued using the same index or such other method als is accept-able to Government and the Bank.

Future Operations and Financial Position

4.10 Projected income, balance sheet and cash flow statements forFY1981 to FY1990 together with notes on assumptions, are shown iLn Annexes10 to 13. The statements indicate that SEB's financial performance would besatisfactory. Between FY1981 and FY1990, electricity sales are forecast toincrease at an average annual rate of 6% from 305 million kilowatt hours inFY1981 to 526 million kilowatt hours in FY1990. Revenues would increase byabout 4 times during this period, while expenses (including depreciation)would increase by 3 times. The increase in expenses assumes that inflationwould about double during this period. SEB would be able to contribute anincreasing proportion of its revenues towards capital spending. SEB isexpected to be well able to meet its current obligations throughout the1981-85 project disbursement period and has regular access to bank overdraftfacilities should they be required. Present facilities are for E 1 million.

- 22 -

4.11 Section 2.06 of Loan 492-SW included a provision limiting SEB-sborrowings without the Bank's agreement to outstanding amounts which did notexceed the equivalent of Rand 400,000. SEBEs financial management has beenof a high standard, and such strict conditions relating to future indebtednessare no longer necessary. The foregoing covenant should be rescinded. Insteadit was agreed at negotiations that SEB will not incur future long-term debtwithout the Bank's consent, unless net income before interest and depreciationis at least 1.5 times future debt service, including proposed new borrowings.

V. ECONOMIC ANALYSIS

Need for Additional Generating Capacity

5.01 In a report on SEB's generating capacity 1/, the consultants clearlydemonstrated that SEB should increase its capacity by 1984 to meet demandgrowth (para. 3.03). Taking into account variations in SEB's generatingcapacity because of seasonal water flow changes, SEB's firm supply capacity(including existing ESCOM links) would be about 73 MW in 1984 compared to theestimated maximum system demand of 86 MW.

Alternative Expansion Programs, Least-Cost Solution and Optimization

5.02 In considering SEB's generation requirements up to the year 2000,the consultants investigated a number of alternative optimization programscombining various power generation and fuel sources using diesel, coal, oiland hydroelectricity taking into account various plant and reservoir sizes.Given the highly seasonal system load characteristic and that the ESCOMtariff is largely a capacity-charge tariff, SEB's main consultants (Merz andMcLellan) and also independent consultants (EPDC) employed by the Governmentcarried out comprehensive optimization studies to determine the most economicunit size and total power plant capacity. Their studies showed that, usingindigenous resources, the least-cost solution for meeting SEB's long-termpower requirements would be the proposed project.

5.03 The consultants also considered importing more power from RSA(ESCOM) as an alternative to local generation. The equalizing discount ratebetween proceeding with the project and the ESCOM alternative is 9%, whichrepresents the approximate opportunity cost of capital in Swaziland. Thisestimate does not take into account the possibilities of real increases inSouth African coal prices which would cause ESCOM to increase its electricitytariffs and would further justify the proposed project. The equalizing dis-count rate will increase to 10% if ESCOM increases its tariff in real terms

1/ "Report on Future Electrical Generation Policy", (Merz and McLellan inassociation with Watermeyer, Legge, Piesold & Uhlmann, and Coopers &Lybrand Associates Ltd.) 1978.

- 23 -

by about 2% per year during the next five years. This is well below thereal increases which were about 8% per year over the last 4 years. Moreover,Swaziland would benefit from the development of indigenous renewable resourcesas well as from reduced dependence on RSA. Therefore, the project is ade-quately justified. A description and economic analysis of the alternativedevelopment program is given in Annex 14.

Rate of Return

5.04 The return on the project, which is taken to be the discount rateat which the present value of all capital and operating costs (excludinginterest during construction and taxes) equals the present value of allrevenues and benefits (using the current average tariff level of E3.46 centsper kWh) associated with the project over its lifetime, is 12%. The rate ofreturn would drop to about 11%, if costs were 10% higher than estimated or ifexpected revenues were 10% lower. If both these events occurred the rate ofreturn would be 9%. The present value calculations are given in Annex 14.

Project Risks

5.05 No major risks to the project are foreseen. However, since thelong-term availability of water for the operation of the hydroelectric plantis essential to the project, it was agreed during negotiations that thecovenant under section 5.08 of Loan 492-SW would be extended to providethat, except as the Bank and the Borrower shall otherwise agree, Governmentwill not permit any abstraction of water from the Little Usutu River or itstributaries that would reduce the potential generating output of the EzulwiniHydroelectric Station, and will permit SEB to divert water from the LittleUsutu River in such amounts as may be necessary for the operation of theproposed project.

VI. SUMMARY OF AGREEMENTS REACHED AND RECOMMENDATION

6.01 During negotiations, agreement was reached that SEB:

(a) would obtain Bank approval before making an appointmentto the position of General Manager (para. 2.04);

(b) would continue to have its financial statements audited byindependent auditors acceptable to the Bank and would submitits audited financial statements to the Bank within fourmonths after the close of its fiscal year (para. 2.08);

(c) would employ engineering consultants to supervise projectconstruction (para. 3.17);

(d) would ensure that the project construction works, includingthe dam, be inspected regularly in accordance with soundengineering practices and would inform the Bank about thenature, frequency and monitoring procedures for theirinspection (para. 3.18);

- 24 -

(e) would appoint a panel of experts (para. 3.18);

(f) would submit a report to the Bank on the project withinone year of project completion (para. 3.24);

(g) would complete, by June 30, 1982, health and ecologicalstudies satisfactory to the Bank and would promptly impleme)such recommendations as are considered necessary (para. 3.2,8);

(h) would contribute E 20 million (US$25 million) towards itsFY1981 to FY1985 capital spending from internal cash genera-tion and would annually review the adequacy of its tariffs formeeting this objective (para 4.04);

(i) would maintain its tariffs at a level sufficient to earnan annual rate of return on average net revalued fixedassets of not less than 7% in FY1982, and 8% thereafter(para. 4.05);

(j) would employ consultants to complete a tariff study byJune 30, 1982 and would promptly implement such tariffchanges as are considered necessary (para. 4.06);

(k) would revalue its fixed assets annually on the basis ofan index acceptable to the Bank, and, for the purpose ofthe rate of return covenant, the gross value of fixedassets at March 31, 1980 shall be E44.22 million lessaccumulated depreciation E14.78 million (para. 4.09);

(1) would not incur long-term debt without the Bank's consent,unless future debt service is covered at least 1.5 timesby internal cash generation (para. 4.11).

6.02 During negotiations it was agreed that Government:

(a) would obtain the consent of the Bank before making new appoint-ments to the position of Chairman of SEB (para. 2.04);

(b) carry out a study of the ecological implicationsof the project (para. 3.28); and

(c) would not permit water abstractions that would reduce thepotential generating output of the project (para. 5.05).

6.03 As a condition of effectiveness of the Bank loan, all conditionsof effectiveness of the AfDB, CDC, EIB, KfW and SNPF loans should be met(para. 3.16).

6.04 With the above agreements the project would be suitable for a Bankloan of US$10 million equivalent, available to the Swaziland ElectricityBoard over 20 years, including a 3-year grace period.

_25 ANNEX I

Page 1 of 2

SWAZILANDTHIRD POWER PROJECT

Statistical Data on SEB's Power System

Year Ending March 31 1975 1976 1977 1978 1979 1980

Installed Generating Capacity (MW)

Diesel 9.5 9.5 9.5 9.5 9.5 9.5Hydro 20.5 20.5 20.5 20.5 20.5 20.5Capacity of ESCOM Links 36.0 36.0 36.0 36.0 67.0 67.0

Total Capacity 66.0 66.0 66.0 66.0 97.0 97.0

System Maximum Demand (MW) 28.5 33.2 42.0 43.2 53.1 57.2

Power Production (GWh)

Diesel Production .5 2.1 1.6 1.3 4.7 2.9Hydro Production 121.7 126.4 144.8 120.6 139.7 114.4

Total SEB Production 122.2 122.5 146.4 121.9 144.4 117.3Purchased from ESCOM 18.3 40.6 58.9 102.1 104.1 187.9

Total generated and purchased 140.5 163.1 205.3 224.0 248.5 305.2

Sales (GWh)

Domestic 21.6 26.2 30.1 34.0 41.0 47.0Commercial 13.8 15.9 16.7 19.3 22.0 24.2Irrigation 24.4 31.2 45.9 53.6 61.7 88.4Power and Bulk 66.4 80.0 91.2 94.7 98.2 116.2

Total sales 126.3 153.3 183.9 201.6 222.8 275.7

System Losses (GWh) 14.2 9.8 21.4 22.4 25.7 29.5(%) (11.2) (6.3) (11.6) (11.1) (11.5) (9.6)

Average Tariff E cents/KWh 1.98 1.92 2.26 2.35 2.66 2.69US cents/KWh 2.61 2.53 2.98 3.10 3.51 3.55

Number of Customers 4999 6184 6907 7572 8373 9471

_ 26 - ANNEX IPage 2 of 2

Power Generation and Capacity of Swaziland

AverageType of Type of Energy Production Installed PurchasesGeneration Fuel Used 1978 1/ 1979 1/ Capacity from SEB

Producers Facility GWh GWh kW kWH

Havelock Mine (asbestos) steam units coal 32.5 34.7 8,000 8

Swaziland Plantations (sawmill) hydro units 1.2 1.0 660 1

Peak Timbers (sawmill) steam units woodwaste 3.4 2.8 1,500 3

Ingonini Estates (citrus grower) 2/ hydro/diesel sets 0.7 0.7 190/240

Mhlume Sugar Co. (sugar mill) steam units bagasse 12.0 15.0 6,500 3/ 3

Simunye Sugar Mill (Third Sugar Mill) steam units bagasse 5/ 5/ 5/ 60

Ubombo Ranches (sugar mill) steam units bagasse 34.7 32.5 11,000 21

Usutu Pulp Co. (wood pulp) steam units wood bark 61.5 58.3 13,000 24lignin 4/

Other diesel, hydro 1.0 1.0 200Total Private Generation/purchase 147.0 146.0 41,050/41,100

SEB Generation 141.0 115.0 30,000

Importation from RSA 6/ 85.0 181.0 67,000

Total 373.0 442.0 138,050/138,100

1/ Calendar Year.2/ Not connected to SEB system.3/ Excludes 2000 kW steam units under repair.4/ Also burn some coal tar residues for stabilizing purposes.5/ Started generating in May 1980 at 3,500 kW capacity; planned to produce 25-30 GWh per annum by 1985.6/ Two 132-kV power links between RSA and Swaziland.

- 27 -

SWAZI LANDTHIRD POWER PROJECT ANNEX 2

SWAZILAND ELECTRICITY BOARDORGANIZATIONAL STRUCTURE

Board

General Manager

|Deputy GeneralManage r |

G ton ng neer e Eng neer Secretary

Deputy ChiefEngineer _

Power Stations ccountingSuperintendents epartment

Transportation Personnel

Department Central Services Four Area epartmentEngineer Managers

R even ue _Syster Contr o epartment

CenterSubstation

Constructionand Maintenance

Department Comme rcial Eepa tmentDepartment

Protection andTests

Department Surveyors

Meters andRelay Room Purchasing

Department

HousingMaintenanceDepartment

StockControlle r

Wotrld Bank - 21967

- 28- ANNEX 3

SWAZILANDTHIRD POWER PROJECT

SEB'S FUTURE SALES AND MAXIMUM DEMAND

Year Ending March 31 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990

Sales (Gwh)

Domestic Consumers 57 65 73 .81 89 97 105 112 119 125Commercial and Small Industry 1/ 28 31 34 37 40 43 45 48 51 53

Irrigation Consumers

Estates and Large Consumers 84 107 109 111 111 111 111 111 111 111Small Consumers 23 26 28 31 33 36 38 40 42 44Total Irrigation 107 133 137 142 144 147 149 151 153 155

Power and Bulk Supply

Large Industrial Consumers 59 64 73 79 77 80 83 84 86 86Hotels - - - 2 6 6 6 6 6 6Small Consumers 54 59 64 69 74 80 85 91 96 101Total Power and Bulk 113 123 137 146 157 166 174 181 188 193

Total Sales 305 352 381 406 430 453 473 492 511 526

System Losses 34 39 42 45 48 50 53 55 57 58

Total Net Output 339 391 423 451 478 503 526 547 568 584

System Annual Load Factor (M) 57 58 59 60 60 60 60 60 60 60

System Maximum Demand (MW) 68 77 82 86 91 96 101 105 109 112Demand Growth Rate (t) 15 13 6 5 6 5 5 4 4 3

Includes street lighting

- 29 -SWAZI LAND

THIRD POWER PROJECTINSTALLED AND FIRM CAPACITY ANNEX 4

AND MAXIMUM DEMAND OFSEB'S INTERCONNECTED SYSTEM

MW

160

150 -

PROPOSED ESCOM LINK (31

140 - SYSTEM

RESERVES

130 - ~~~~~~~~~~~~~~~~~~~~~~~~AND SCHEDULEDFIRM SYSTEM OUTAGESa/

CAPACITY

120 /r - r-' r-i ,

110_ I I I I I I I_INSTALLED SYSTEM CAPACITY r -- .. L. J , _

100 _

SYSTEM RESERVES90 _ _-CAPACITY OF ESCOM LINKS (1 & 2 S AND SCHEDULED

OUTAGES!/

go" i r r- r- r- r r7{

70 -

/ ~~~~~~~~~MAXIMUM DEMANDLUPOHLO-EZULWINI HYDROELECTRIC SCHEME4t \ / \NJ 9

~ ~~~~~~~~~~~~~~~~~~~(THF PRC)JECT)

20 - INSTALLED CAPACITY

,t . I I I I I I I I I197811 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988

Actual Estimated

1j Fiscal Year (ending 31st of March) World Bank - 21966

2/ Largest hydro and largest thermal unit

2! One ESCOM link

- 30 -

ANNEX 5Page 1 of 3

SWAZILAND

SWAZILAND ELECTRICITY BOARD

THIRD POWER PROJECT

Project Description

Project Area

1. The project area is shown on the map (IBRD 15243). A summarizedproject description is given in Chapter III. A fuller description of majorcomponents is given below, with a summary of important hydrogeologicalfeatures.

Hydrology

2. Hydrology and reservoir operation studies are based on the 47-yearrecord of simulated monthly hydrological data developed by the HydrologicalResearch Unit (HRU) of the University of Witwatersrand of RSA. Extensivetopographical and geological studies have been carried out by SEB's consul-tants. The location, type and principal dimension of all the major projectcomponents were based on various optimization studies. Principal fieldinvestigations and drilling for detailed construction methods and scheduleshave been finalized.

3. Average monthly outputs of the project are as follows:

Jan Feb Mar Apr May June July Aug Sept Oct Nov Dec

Power (MW) 20 20 20 20 20 20 20 10 1/ 10 1/ 20 20 20Energy (GWh) 10.97 11.03 11.10 8.94 7.37 6.11 5.78 5.25 5.01 5.95 6.80 9.01

Total Production: 93.32 GWh per annum (54 Gwh per annum with 95%reliability)

1/ One of the two 10-MW units will be out of service for the programmedyearly maintenance.

Dam

4. The embankment will be of the rockfill type, utilizing fine materialto form an impervious core. The rock excavated from the spillway channelswill be used for the embankment. The foundation of the dam, including acolluvial fan at the left bank, will be stripped to expose the unweathered,fairly homogeneous granite bedrock.

- 31 -.ANNEX 5Page 2 of 3

5. A spillway (without gates) situated at the left bank of the LittleUsutu River incorporating a side weir, chute and flip bucket will be partlyconcrete-lined and mash reinforced throughout, and will be consiructed tocarry the peak discharge of the catastrophic flood flow (2850 m per second).

6. Compensation water will pass through an encased, steel pipelinesituated on the left bank at an elevation just below the lowest drawdownlevel of the reservoir. The flow will be regulated at the downstream endby an outlet valve which will discharge into a dissipater situated at thetoe train of the embankment.

7. The temporary diversion conduit located below the embaLnkment willbe closed by a concrete plug constructed at, and keyed into, the upstream endof this conduit. The plug will be built in dry conditions by working behinda stoplog located at the entrance to the conduit. Permanent outflow facili-ties will be incorporated in the plug and the temporary diversion conduitto provide a means of drawing down the reservoir during either an emergencyor inspection maintenance of the upstream face of the dam. A pipeline3of1.2 m in diameter would reduce the top water level of the 20 million mreservoir by about 5 m during the course of one week.

Reservoir

8. The reservoir created by the dam will stretch 4.8 km upstream endwill ayerage about 400 m in width. The lake surface area will be 1.8 km and0.5 km at the maximum supply level (1016 m) and the minimum supRly level(997 m). The effective reservoir capacity is aout 20 million in . However,the capacity could be increased to 40 million m , if this should prove to bejustified in the future, as the dam design permits the height of the dam to beraised.

Intake Structure and Low Pressure Tunnel

9. The intake to the hydraulic system will be located at a largegranite outcrop situated on the left bank of the reservoir about 800 mupstream from the dam. The intake gate will be raised and lowered by adouble acting hydraulic system with an emergency closure device.

10. The low pressure tunnel will extend from the intake structurefor a distance of 4,400 m passing through Lupohlo mountain to the surgechamber situated above the Ezulwini valley. The depth of rock cover overthe tunnel will exceed 100 m for some 80 percent of the length and this, inconjunction with the excellent overall geology, makes the construction of anunlined tunnel practicable. The tunnel design is of horse-shoe cross-sectionwith a diameter equivalent to 3 m.

- 32 -ANNEX 5Page 3 of 3

Surge Chamber

11. The surge chamber, situated just inside the boundary of the Mlilwanegame park, will be set into the hillside overlooking the Ezulwini Valley. Thechamber will be lined with reinforced concrete and will be about 35 m high.

High Pressure System

12. The high pressure system will consist of three sections: the firstsection, located immediately below the surge chamber, will be a concrete-linedvertical shaft; the second section, a 650 m long steel-lined tunnel; and thethird section, downstream from the steel-lined tunnel, will be a free-standingpenstock incorporating expansion joints where appropriate; it will be locatedat ground level and supported on reinforced concrete piers; a single guard-valve will be located at the portal. The penstock will fork near the powerstation and the final length leading to the turbine inlet valves will belocated below the surface.

Power Station and the Switchyard

13. The station will be sited high enough to ensure tat, even undercatastrophic flood conditions on the Mwutshini river (600 m per second), thetailrace flow will be unaffected. The station will accommodate the two 10-MWpelton hydroelectric generating sets on a single floor. The superstructurewill consist of a series of portal frame constructed in reinforced concretewith infill panels to the sidewalls built of face brickwork and steel cladding.Crane-beams and rails will be supported by the portal frames. The roof willconsist of a structural steel lattice supporting steel roof sheeting.

14. The 66-kV switchyard will be located next to the power station andabove the catastrophic flood level of the Mwutshini river. An access road tothe power station and the switchyard will be built from the Mbabane to Manziniroad.

15. The average production of the project will be 94 Gwh per year,together with the diesel sets, and firm production will be about 54 Gwh peryear. The project is not designed for peaking. The load factor will be about53% average and 30% firm.

- 33 -

ANXEX 6

Page 1 cif 2

SWAZILAND

SWAZILAND ELECTRICITY BOARD

THIRD POWER PROJECT

Project Cost Estimate

---- E Million----- ----US$ Million----Project Items Local Foreign Total Local Foreign Total

Part A

1. Dam 3.36 5.75 9.11 4.20 7.19 11.392. Resettlement and Road

Relocation 1.35 0.80 2.15 1.69 1.00 2.693. Engineering Services and

Administration 0.24 1.13 1.37 0.30 1.41 1.71Subtotal 4.95 7.68 12.63 6.19 9.60 15.79

Contingencies

4. Physical Contingency 0.52 1.19 1.71 0.66 1.50 2.165. Price Contingency 1.38 1.61 2.99 1.72 2.01 3.73

Total Contingencies 1.90 2.80 4.70 2.38 3.51 5.89

Total Part A 6.85 10.49 17.34 8.57 13.11 21.68

Part B

1. Tunnel and Powerhouse 2.36 4.87 7.23 2.95 6.09 9.042. Engineering Services and

Administration 0.19 0.98 1.17 0.24 1.22 1.46Subtotal 2.55 5.85 8.40 3.19 7.31 10.50

Contingencies

3. Physical Contingency 0.33 0.74 1.07 Ot41 0192 1.334. Price Contingency 0.75 1.06 1.81 0.94 1.33 2.27

Total Contingencies 1.08 1.80 2.88 1.35 2.25 3.60

Total Part B 3.63 7.65 11.28 4.54 9.56 14.10

Part C

1. Generators 0.06 1.83 1.89 0.07 2.29 2.362. Turbine and Valves 0.04 1.47 1.51 0.05 1,84 1.893. Crane 0.01 0.95 0.96 0.01 1.19 1.20

Subtotal 0.11 4.25 4.36 0.13 5.32 5.45

Contingencies

4. Physical Contingency 0.01 0.41 0.42 0.01 0.51 0.525. Price Contingency 0.03 0.83 0.86 0.04 1.04 1.08

Total Contingencies 0.04 1.24 1.28 0.05 1.55 1.60

Total Part C 0.15 5.49 5.64 0.13 6.87 7.05

- 34 -ANNEX 6Page 2 of 2

SWAZILAND

SWAZILAND ELECTRICITY BOARD

THIRD POWER PROJECT

Project Cost Estimate

-----E Million--- - US$ Million----Project Items Local Foreign Total Local Foreign Total

Part D

1. Gates and Penstocks 0.90 1.85 2.75 1.12 2.31 3.432. Transformers 0.02 0.24 0.44 0.02 0.30 0.323. Station Auxiliaries 0.01 0.32 0.33 0.01 0.40 0.414. Station Cabling & Lighting 0.13 0.18 0.31 0.17 0.23 0.405. 66-kV 9witchgear 0.07 0.65 0.72 0.09 0.81 0.906. Engineering Services 0.12 0.46 0.58 0.15 0.57 0.72

Subtotal 1.25 3.70 4.95 1.56 4.62 6.18

Contingencies

7. Physical Contingency 0.14 0.38 0.52 0.18 0.48 0.668. Price Contingency 0.40 0.80 1.20 0.50 1.00 1.50

Total Contingencies 0.54 1.18 1.72 0.68 1.48 2.16

Total Part D 1.79 4.88 6.67 2.24 6.10 8.34

Part E

1. Studies and Panel of Experts'Consulting Services o.08 0.29 0.37 0.10 0.36 0.46

Contingencies

2. Physical Contingency 0.01 0.02 0.03 0.01 0.03 0.043. Price Contingency 0.01 0.02 0.03 0.01 0.03 0.04

Total Contingencies 0.02 0.04 0.06 0.02 0.o6 0.08

Total Part E 0.10 0.33 0.43 0.12 0.42 0.54

Part F

1. Custom Duties and Taxes 0.50 - 0.50 0.62 - 0.622. Contingencies 0.15 - 0.15 0.19 - 0.19

Total Part F 0.65 - 0.65 0.81 - 0.81

TOTAL PROJECT COST 13.17 28.84 42.01 16.46 36.06 52.52

Part G

1. Interest during Construction(IDC) on the Bank Loan - 1.24 1.24 - 1.55 1.55

2. IDC on the other Co-lenders' 1.27 2.87 4.14 -1.59 3.59 5.18Loans _ -___ -

Total Part G 1,27 4.11 5.38 1549 5.J14 6.73

TOTAL FINANCING REQUIREFMENT .14.44 32.95 47 39 18.05 41.2n 59.25

- 35 -

SWAZI LAND A 7SWAZILAND ELECTRICITY BOARD

THIRD POWER PROJECTIMPLEMENTATION PROGRAM

Calendar Years 1980 1981 1982 1983 1984

Quarters 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

CIVILWORKS ENGINEERING

1. Supplementary S,te Investigatrons

2. Bid Preparation and Issue

3. Bidding Period

4. Bid Evaluation

5. Contract Awards 0

CONSTRUCTION OF THE DAM

6 Poundation

7. Culvnert

8. Coffer Dam bill

9. Spiilway Excavation _ _ _ _

10. Spdllway Concreting _ _ _ _ _

11. Side Flanks

12. Central Plug

13. Roadway and Grassing

CONSTRUCTION OF HYDRAULICSYSTEM AND POWER STATION

14. Intake _ _ _ -

15. Tunnel - - - - - - - -

16. Surge Chamber and Shaft

17. Steelellned Tunnel - _ _ _ _

18. Down Stream Portal

19. Penstock

20. Power Station- - - - -

MECHANICAL AND ELECTRICAL PLANT

21. Contract Awards 0

22. Manufacturing U _ _ _ *

23. Delivery and Erection _ _ _ _

24. Commissioning irnst Unit 0 Second Unit

World Bank - 21965

- 36 - ANNEX 8

SWAZILANDSWAZILAND ELECTRICITY BOARD

THIRD POWER PROJECT

Disbursement Schedule(Thousands of US Dollars)

Cumulative UndisbursedIBRD Fiscal Year Quarterly Disbursements at end

and Quarter Disbursements at end of Quarter of Quarter

1981/1982September 30, 1981 1,000 1,000 9,000December 31, 1981 500 1,500 8,500March 31, 1982 600 2,100 7,900June 30, 1982 700 2,800 7,200

1982/1983September 30, 1981 900 3,700 6,300December 31, 1981 1,100 4,800 5,200March 31, 1982 1,200 6,000 4,000June 30, 1982 1,000 7,000 3,000

1983/1984September 30, 1983 800 7,800 2,200December 31, 1983 600 8,400 1,600March 31, 1984 500 8,900 1,100June 30, 1984 400 9,300 700

1984/1985September 30, 1984 400 9,700 300December 31, 1984 200 9,900 100March 31, 1985 100 10,000

- 37 -

ANNEX 9Page 1 of 2

SWAZILAND

SWAZILAND ELECTRICITY BOARD

THIRD POWER PROJECT

Project Monitoring Guidelines

1. There are a number of areas described in the various chapters whichare key elements in the efficient operation of the utility and the successof the project. The main areas for establishing a monitoring system aredescribed below. (See also paras. 3.24 and 6.01(f)).

2. The principal implementation steps to be compared monthly withplanned targets are as follows:

Description Target Dates

Civil Works

Preparation of Bid Documents November 1980Invitation to Bid January 15, 1981Bid Evaluation June 15, 1981Contract Award August 1, 1981Dam Impoundment begins October 31, 1983Water available for generation January 1, 1984

Electrical Mechanical Works

Award of contracts September 1, 1981Erection February 1, 1984Availability for service (First Unit) January 1, 1984

(Second Unit) March 1, 1984

Studies

Completion of the Tariff Study June 30, 1982Completion of the Reorganization Study June 30, 1982Completion of the Ecological Study June 30, 1982

3. Records will be maintained comparing the targets against actualresults in:

(a) hydro production (in kWh)(b) diesel production (in kWh)(c) purchase from ESCOM (in kWh)(d) power consumption (by classification)

-38 -

ANNEX 9Page 2 of 2

(e) consumption of power plants (in kWh)(f) system losses (in kWh)(g) number of interruptions and their durations(h) major equipment failures(i) average tariff level (in £ per kWh)(j) number of staff (by classification)(k) rate of return on average revalued net fixed assets(1) debt service coverage(m) operating ratio(n) no. of days' sales outstanding(o) debt/equity ratio(p) revisions to project cost estimates and related financing.

- 39 -

SWAZILANDANNEX 10

SWAZILAND) ELECTRICITY BOARD)

INCOME STATEMENT PROJECTIONS(thousands ofEalne)

----- Actual ----- ------------------------ ProjecteeL------------------Year Ended March 31 1970 1979 1960 198t 1982 1983 1984 1985 1986 1987 1988 19Y89 1 990

SALES IN GWN 202.0 223.0 276,0 305,0 352. 0 381.0 406.0 430.0 453.0 473. 0 492.0 5[.-L 0 526. 0

REYENUE/KWI4 GOLD

AVERAGE REVENUE! 0,023 0.027 0,02? 0.031 0,036 0.040 0.044 0.04? 0.053 0. 056 0,060 0. 064 0,0o/0MY31R SOLD .

OPERATING REVENUE 4741 5932 7410 9383 12548 15230 17883 20045 23828 2660? 29456 32648 36878

OPER,11ING EXPE NSE-S

SALARIES 763 960 1200 3398 1730 199? 2305 2662 3046 34,84 3986 4560 52I/FUEL 44 184 175 29 40 54 69 8? 110 134 161 192 227P:URCHASEDI ENERGY 1447 1790 3475 4609- 5640 6530 6798 5722 6773 8005 9105 10350 12345OTHER 400 502 628 685 739 791 910 984 1053 1127 1206 1290 138.LDIEPRECIAI1ON 702 842 839 1897 2152 2411 2693 3960 5341 5901 6532 7251 8061

TOTAL 3356 4278 6317 8618 10301 11783 12775 13415 16323 18651 20Y90 2.3643 27231

OPERATfNG INCOME 1385 1654 1093 765 2247 3447 5108 6630 7505 7956 8466 9005 964?

NET INCOME BEF INT 1385 1654 1093 765 2247 3447 5108 6630 7505 7956 8466 9005 964?TNT CHARGED' OP 442 403 413 471 372 315 262 3036 3652 3447 3223 3007 2788

NET' INCOME. 943 1251 680 294 1875 3132 4846 3594 3853 4509 5243 5998 6859

AVERAGE RATE BASE 31031 34003 3,6715 39553 65962 93526 991L01 105272 112300 120055RATE OF REEURNI (7.) ON REVALUED ASSETS 2.5 6.6 9.4 12.9 10.1 8.0 8.0 8.0 8.0 8.0

OPERATING RATIO 92 82 77 71 67 69 ) 71 72 74

April 23, 1981

-40 -

SWAZIll ANNf 11

SWAZILAI EIZCTZICLTY BOA=D

BAlANC SEEEl EtOJZCONS

(thousauds of flulaTngeni)

---- Actual ------- -------------------------------------- Projected -------------------------------------- __-_-_

As at March 31 1978 1979 1980 1981 1982 1983 1994 1985 1986 1987 1988 1989 1990

ASSETS

PLANT IN OF'ERATION 17501 18981 44220 50633 56984 63573 71063 126931 140116 154924 171669 190886 212148LESS: DEPRECIATION 4846 5669 14782 18009 21602 25525 30005 36065 43931 52907 63142 74513 88ll1

1/ …………… - -- - - - - - - - - - - - - - _- - - - - -

NET PLANT 12655 13312 29438 32624 35382 38048 41058 90866 96185 102017 10527 116073 124037

WORK IN F'ROGRESS 0 0 433 360 6673 23723 44571 0 0 0 0 0 0

CtJRRENT ASSETS-CASH AND BANKS

TEMPORARY SURP 527 348 113 0 65 194 242 521 2772 5063 8046 11119 15037

-ACCOUNTS REC 779 1118 1693 1877 2510 3046 3577 4009 4766 5321 5891 6530 7376-INVENTORIES 233 242 329 380 427 477 533 952 1051 1162 1288 1432 1591

TOTAL 1539 1708 2135 2257 3002 3717 4352 5482 8589 11546 15225 19081 24004

IOTAL 14194 15020 32006 35241 45057 65488 899t81 96348 104774 113563 123752 135154 148041

LIABILITIES

EQUITY-RETAINED EARNINGS 7294 8545 9225 9519 11394 14526 19372 22966 26819 31328 36571 42569 49428

-REVALUATION RESER 0 0 15296 17946 20556 23033 25696 28570 34930 41663 48805 56402 64527

TOTAL 7294 8545 24521 27465 31950 37559 45068 51536 61749 72991 85376 98971 113955

LONG TERM DEBT 6472 5864 6326 5566 11669 26277 43121 43074 40988 382-14 35733 33184 30595

CUR'NT LIABILITIES-ACCOUNTS PAYABLE 192 370 887 1008 1222 1406 1512 1418 1673 1913 2169 2459 23/6

ACCRUED INTEREST 110 100 106 0 0 0 0 0 0 0 0 0 0

CUSTOMERS DEF'OSIT 126 141 166 189 216 246 280 320 364 415 474 540 615-OVERDRAFTS 0 0 0 1013 0 0 0 0 0 0 0 0 0

TOTAL 428 611 1159 2210 1438 1652 1792 1738 2037 2328 2643 2999 3491

TOTAL 14194 15020 32006 35241 45057 65488 89981 96348 104774 113563 123752 135154 148041

DEBT/DEBT I EQUITY 47 41 21 17 27 41 49 46 40 34 30 25 21

DEBT/EQUITY 0.9 0.7 0.3 0.2 0.4 0.7 1.0 0.8 0.7 0.5 0.4 0.3 0.3CURRENT RATIO 3.6 2.8 1.8 1.0 2.1 2.2 2.4 3.2 4.2 5.0 5.8 6.4 6.9

RECEIVABLES/REV X 16 19 23 20 20 20 20 20 20 20 20 20 20

RECEIVABLES-DAYS 59 68 82 72 72 72 72 72 72 72 72 72 72At historical cost up to 1979, atd revalued basis thereafter

April 23, 1981

- 41 -

SWAZILAND ANNEX 12

SWAZILAND ELECTRICISEY BORD

CASH FLOW PROJECTIONS(thousands of Emalangeni)

§ngary,

1981-

Year ended March 31 1981 1982 1983 1984 1985 1985 1986 1987 1988 1989 199(

SOURCE AND USESOF FUNDS

INTERNAL SOURCES--NET INCOME BEF IN 765 2247 3447 5108 6630 18197 7505 7956 8466 900S 9647-DEPRECIATION 1897 2152 2411 2693 3960 13113 5341 5901 6532 12'1l S061

TOTAL 2662 4399 5858 7801 10590 31310 12846 138'.7 14990 16256 17/08

OPERATIONAL RE-QUIREMENTS

-WORKING CAPITAL 197 439 372 447 905 230 557 375 381 427 513-DEBT SERVICE 1231 1107 116° 976 4355 8838 5738 6191 5734 5556 'J377

TOTAL 1428 1546 1541 1423 5260 11198 6295 6566 6115 5983 5890

NET AVAILABLEFROM OPERATIONS 1234 2853 4317 6378 5330 20112 6551 7291 88S3 10273 11818

CONSTRUCTIONREQUIREMENTS

-ONGOING WORKS 2000 2300 2600 3040 3500 13440 4300 5000 5900 7200 7900-PROPOSED PROECT 368 5890 155g85 18 52 2119 42010 0 0 0 0 0I1ITEREST DUR. CONSTRUCTION ------ 42----------204 --- 5384…-- --

TOTAL 2360 8613 19650 23888 6323 60834 4300 5000 5900 7200 7900

BALANCE TO FINANCE 1126 5760 15333 17510 993 40722 -2251 -2291 -2983 -3073 -3918

FINANCED BY:IBRD 0 1754 3443 2635 168 8000 0 0 0 0 0CDC 0 541 2383 2785- 361 6070 0 0 0 0 0APB 0 441 609 5100 390 6540 0 0 0 0 0KFW 0 590 2313 3385 232 6520 0 0 0 0 0EIB 0 1012 3214 2653 121 7000 0 0 0 0 0PROV. FUND 0 2500 1500 1000 0 5000 0 0 0 0 0GOVT LOAN 0 0 2000 0 0 2000 0 0 0 0 0

TOTAL 0 6838 15462 17558 1272 41130 0 0 0 0 0

SURPLUS(DEFICIT)OF CASH -1126 1078 129 48 279 408 2251 2291 2983 3073 3918ACCUMULATED -1013 65 194 242 521 521 2772 5063 8046 11119 15037

DEBT SERVICE COVERAGE 2.2 2.9 2.2 2.1 2.1 2.2 2.2 2.2 2.6 2.9 3.3

April 23, 1981

- 42 -ANNEX 13Page 1 of 3

SWAZILAND

SWAZILAND ELECTRICITY BOARD

THIRD POWER PROJECT

Notes and Assumptions for Financial Projections

1. In preparing the financial projections SEB's FY1980 actual financialstatements have been used as a base.

Revenues

2. Average revenues per kWh for 1981 are based on SEB's estimatesof E 3.10 cents per kWh which will be produced from tariff increases effectedJanuary 1, 1980 and February 1, 1981.

Operating Costs

Fuel

3. Expenditures for fuel (which are small) are based on engineeringestimates of diesel plant utilization for peaking. Costs are assumed toincrease by 9% per annum.

ESCOM Purchases

4. The quantity of electricity supplied is based on engineering esti-mates. Inflation is assumed at 8% for 1982 and 7% for 1983-1990.

Employment Costs

5. These are assumed to increase by 4% per annum in line with pastexperience and in addition local inflation rates have been assumed as follows:1981 - 12%, 1982-1984 - 11%, 1985 onwards 10%. Provision has also been madefor additional staffing.

Other

6. Inflation is assumed at 9% for 1981, 8% for 1982 and 7% for 1983onwards with real increases assumed on capacity additions.

Depreciation

7. An average rate of 4% has been used.

- 43 -

ANNEX 13Page 2 of 3

BALANCE SHEETS AND CASH FLOW PROJECTIONS

Fixed Assets

8. Fixed assets and related accumulated depreciation at March 31, 1980are based on a revaluation by SEB's consultants. To maintain these assetsat current values they have been revalued annually, using estimated inflationrates of 9% for 1981, 8% for 1982 and 7% thereafter.

9. Accounts Receivable

Based on experience, it has been assumed that 20% of annual revenueswould be outstanding.

Inventory

10. This consists of repair parts, poles, transformers, conductors,insulators. These are estimated at 0.75% of gross fixed assets.

Creditors

11. These are estimated at 15% of cash operating expenses.

Consumer Deposits

12. These are estimated to increase at 14% per annum.

13. IBRD and co-lender finance is to be made available to SEBon the following terms:

- 44 -

ANNEX 13Page 3 of 3

TERMS OF IBRD AND CO-LENDER FINANCE

Years of InterestTerm Grace Rate Principal Amount(year) (%) Emalangeni

(millions)

IBRD 20 3 9.6 8.00 2/

Co-lenders

AfDB 1/ 20 5 8 6.54 2/CDC 15 3 9.5 6.07 21KfW 1/ 30 3 8 6.52 2/EIB 15 3 8 7.00 3/

Government 24 4 8 2.00 2/

Swaziland 20 10 10 5.00 4/National Pro-vident Fund

1/ Funds to be made available by SEB by Government under on-lending agree-ments.

2/ Equal annual principal repayments.

3/ Level combined payments of principal and interest.

4/ Equal annual principal repayments after 10 years.

- 45 -

ANNEX 14

Page lof 7

SWAZILAND

SWAZILAND ELECTRICITY BOARD

THIRD POWER PROJECT

Economic Analysis

Alternative Expansion Proposals and Least Cost Solution

1. Selection of the next step in expanding SEB's generatiLng capacityinvolves the economic analysis of different possible development strategieswhich would satisfy the increasing demand in the interconnected power systemover the planning period (1981-2030). The cost streams of these differentstrategies have been compared, and the development program which includesthe project as the next stage is the least cost solution among all possiblelocal alternatives.

2. SEB's consultants also reviewed the possibility of importing more

power from RSA through additional 132-kV power links between the ESCOM andSEB systems. This review included the following alternatives: expandedsupplies from ESCOM; and hydroelectric development at Lupohlo-Ezulwini,followed by additional supplies from ESCOM. In addition the consultantsconsidered variants of options based on the various levels of system reservestandards (lower reserve and higher reserve).

3. Local development possibilities are hydro, coal (steam), diesel andgas turbine. The first comprehensive survey of the hydroelectric potentialin Swaziland was carried out under a UNDP program in the late 1960s. About21 potential sites for hydroelectric development were identified, includingthe project. The UNDP report 1/ concluded that the most suitable site forhydroelectric development is the project site. SEB's consultants, who alsoreviewed all 21 sites, drew the same conclusion. The possibilities of usinga coal-fired thermal power plant were also studied: (a) 30-MW steam turbineunits, (b) 15-MW steam turbine units; (c) mixed development with hydroelectricgeneration either followed by 15-MW thermal units or following 15-MW thermalunits or (d) followed by increased supply from ESCOM. Furthermore, theconsultants also considered options under which Swaziland would be eithercompletely self-sufficient in electricity supply, by terminating the existingagreement with ESCOM and installing 30-MW thermal units, or normally self-sufficient, by retaining the ESCOM supply for standby purposes.

1/ "Usutu, Mbuluzi, Komati and Lomati River Basins", prepared by Engineeringand Power Development Consultants (EPDC) of U.K.

- 46 -

ANNEX 14Page 2 of 7

Method of Comparison

4. The alternative plans have been extended over the useful life ofthe projects (about 45 years) and also to reach a point of insignificancefor the present worth factor. The discounted cash flow method was used forthe comparison and for calculating the equalizing discount rates of thealternatives. The total costs of the programs includes capital costs, andoperations and maintenance costs but exclude interest during construction.

5. In arriving at the net expenditures used in comparing alternatives,the benefits to Swaziland from the South African Customs Union (SACU) agree-ment and from the irrigation potential arising from the regulation of waterflows during the dry seasons have been deducted. SEB's consultants havecalculated that the project will increase the firm water flow of the riverby 1.7 m /sec and have estimated that this will have a minimum annual valueof E340,000 based on the present water tariffs to downstream users. Thecustoms revenue benefit to Swaziland from SACU would be increased by theapplication of the revenue sharing formula to the goods imported for theproject. It is estimated that SEB will pay about E430,000 for goods importedinto the RSA customs area, and this has been included in the project costestimates. The SACU net benefits which are about 20% of the value of allgoods imported from RSA into Swaziland, including power, are included in theeconomic analysis. The average incremental cost of power produced by theproject is estimated at about US4J.

Diesel Engine and Gas Turbine Plant Alternatives

6. Two 4.5-MW diesel sets are in service at the Edwaleni power stationand further diesel engine and gas turbine driven generating plant can becommissioned in Swaziland as part of the electricity supply system. Atpresent, SEB operates these diesel sets for peak lopping to reduce ESCOMbills. Simulation studies carried out by the SEB consultants have shownthat the existing diesel capacity will be adequate to meet daily system peaksup to about 1990. The studies have also shown that the diesel station willbe more expensive than the steam plant alternative for capacity factors above30%. A gas turbine plant (which combines low capital costs with high fuelcosts and low efficiency) is even more unfavorable due to the higher capacityfactors (estimated at about 45%) and the existence of the above diesel setsfor peak lopping and emergency use.

7. The most probable supply options are therefore, hydro, steam plantand importing more power from ESCOM. Discounted economic costs of the alter-native development plans taking into account these options are given below:

- 47 -

ANNEX 14Page 3of 7

---Thermal-- ---------The Project----------Followed Following Self

30-MW 15-MW by 15-MW 15-MW Followed Sufficiency

ESCOM Units Units Units Units by ESCOM 30-MW Units

DiscountedEconomicCosts (at 9%) 92.5 121.3 118.5 110.5 116.0 92.5 154.2(E million)

8. Equalizing discount rates between the alternatives of ESCOM and thehydro followed by ESCOM (the project alternative) is estimated at about 9%,and of all other alternatives are negative. Cash flow for the two least costalternatives (a) ESCOM and (b) the project, followed by additional ESCOMimports are given on pages 7 and 8 of this annex.

9. The sensitivity of the discounted economic costs to changes in themajor variables (capital costs, local coal costs and ESCOM tariff charges)were tested as follows:

Capital Costs

10. Although it is unlikely that the mission's capital cost estimatesfor the project would be exceeded, the effects of variation in project costsusing a 9% discount rate have been considered. The ESCOM alternative wouldbe 4% cheaper than the project, if the project costs increased by 15%, and3% more expensive if the project costs decreased by 15%. Equalizing discount

rates for 15% higher and lower project capital costs are estimated at 6% and12% respectively.

Fuel Costs

11. It is assumed that the proposed coal-fired plant will burn localcoal with the following characteristics: moisture 7.0%, ash content 22.7%,volatile matter 10.0%, gross calorific value 5830 kal/kg and that the priceof the coal (without taxes will be E12.5 per ton (US$16.5 per ton). The rateof coal consumption of thermal units is estimated at 0.68 kg/kWh. Economiccosts of the petroleum fuels are considered as follows (excluding tax butincluding transportation): heavy fuel oil E91 per ton (US$120 per ton) diesel

oil E 115 per ton (US$152 per ton) and jet fuel E151 per ton (US$199 per ton).A plus or minus 50% variation in local coal cost does not affect the priorityof the alternatives.

ESCOM Tariff Charges

12. The charges made by ESCOM under its bulk supply agreement with SEBhave three components:

- 48 -

ANNEX 14Page 4 of 7

(i) a monthly extension charge of about E33.000 (US$43,560)covering ESCOM's capital cost of additional transmissionsequipment which ESCOM has to provide to make supply of theagreed capacity available, and to cover the associated costsof operation and maintenance. The charge is equivalent to1.3% of the capital cost per month, i.e. 15.6% per year. Themonthly extension charge is subject to a discount of R 1.0 perkVA of maximum demand charged under (i) following:

(ii) a monthly demand charge of R 5.175 per kVA (US$6.831 per kVA)of maximum power demand supplied i.e. an effective powercharge of R 4.175 per kVA (US$5.51 per kVA) when the R 1.0(US$1.32 per kVA) per kVA discount on the extension chargeis deducted from the power charge. However, the totaldiscount cannot exceed R 33,000 (US$43,560).

(iii) a unit charge of R 0.00855 per kWh of energy supplied byESCOM 1/. Using a 9% discount rate, the ESCOM alterna-tive would be 4% cheaper than the project if ESCOM tariffsdecreased by 15%, and 3% more expensive if the ESCOMtariffs increased by 15%. Equalizing discount rates for15% higher and lower tariff charges are estimated at 10%and 7% respectively.

Rate of Return

13. The return on investment for the project is defined as the dis-count rate at which the present worth of the estimated capital and operatingcosts of the development over its life equals the present worth of revenuesattributable to it.

14. Costs are assumed to consist of the estimated expenditures forconstructing and operating the project and for the related transmissionand distribution network extensions.

15. Benefits attributable to the project are custom union revenues(para. 5 above) and revenues from the energy sales and water benefits. Basedon electricity production from average annual river flows, project revenuesfrom electricity sales would commence in 1984 with 47 GWh (average wateryear), rising to 91 GWh in 1985 and remaining constant thereafter. Pro-duction from the project facilities would immediately replace electricityimported from ESCOM.

16. The project cost and benefit streams are shown at the end of thisannex. This rate of return is estimated at 12%. Shadow pricing of foreignexchange is not necessary because the shadow rate is 1.0.

1/ The formula for the ESCOM tariff charges is: (R33,000-Rl.O per kVAmaximum demand + (R5.75 per kVA maximum demand + 0.954 per kWh) x 0.90.

ANNEX 14- 49 - Page 5 of 7

SWAZILANDSWAZILAND ELECTRICITY BOARD

THIRD POWER PROJECT

Cash Flow for Power Development Program with the Project(E. Million)

Capital 1/ BenefitsExpenditurei ESCOM Operation Custom Total

ESCOM Tariff 2/ and Total Union Water Total NetThe Project links Charges Maintenance Expenditures Revenues Benefits Benefits Expenditures

1981 0.50 4.68 5.18 5.1882 2.90 5.30 8.20 1.01 1.01 7.1983 3.22 0.10 5.74 9.06 1.47 .1.47 7.5984 11.60 1.00 5.58 0.45 18.63 1.62 0.34 :1.96 16.9485 10.15 1.80 4.86 0.45 17.26 2.94 0.34 3.28 13.9886 1.25 1.10 5.25 0.45 8.05 2.74 0.34 3.08 4.9787 5.69 0.45 6.14 1.45 0.34 1.79 4.3588 6.38 0.50 6.88 1.14 0.34 1.48 5.4089 6.94 0.50 7.44 1.27 0.34 1.61 5.83

1990 0.10 7.26 0.50 7.76 1.39 0.34 1.73 6.0391 1.00 7.52 0.50 9.02 1.64 0.34 1.98 7.0492 1.80 7.90 0.50 10.20 1.70 0.34 2.04 8.1693 1.10 8.23 0.55 9.88 1.94 0.34 2.28 7.6094 8.56 0.55 9.11 1.87 0.34 2.21 6.9095 8.90 0.55 9.45 1.73 0.34 2.07 7.3896 9.25 0.55 9.80 2.20 0.34 2.54 7.2697 9.56 0.60 10.16 2.21 0.34 2.55 7.6198 10.37 0.60 10.97 2.33 0.34 2.67 8.30

1999 10.94 0.60 11.54 2.07 0.34 2.41 9.132000-2030 11.07 0.60 11.67 2.19 0.34 2.53 9.14

Equalizing Discount Rate is about 9%.

1/ The capacity of system reserves are as follows: One largest and one second largest hydro unit plus onelargest thermal unit.

2/ On the basis of current ESCOM tariffs.

- 50 - ANNEX 14Page 6 of 7

SWAZILANDSWAZILAND ELECTRICITY BOARD

THIRD POWER PROJECT

Cash Flow for Power Development with ESCOM Links(E Million)

Capital ESCOM Operation CustomExpenditures Tariff and Union Totalof ESCOM linksl/ Chargesl' Maintenance Revenues Expenditures

1981 4.68 0.0 4.6882 0.10 0.10 5.30 0.93 4.5783 1.00 1.00 5.74 1.10 6.6484 1,80 1.80 6.30 0.30 1.55 8.6585 1.10 1.10 7.16 0.30 1.67 7.9986 7.56 0.30 1.73 6.1387 7,94 0.30 1.58 6.6688 8.30 0.30 1.67 6.9389 0.10 8,66 0.33 1.90 7.19

1990 1.00 8.98 0.33 1.73 8.5891 1.80 9.31 0.33 1.99 9.4592 1.10 10.02 0.33 2.22 9.2393 10.55 0.33 2.22 8.6694 0.10 10.88 0.37 2.11 9.1695 1.00 11.56 0.37 2.19 10.2696 1.80 11.57 0.37 2.67 11.0797 1.10 11.92 0.37 2.60 10.7998 12.30 0.37 2.46 10.5899 12.67 0.41 2.46 10.62

2000-2030 13.06 0.42 2.53 10.95

1/ Capacity of one ESCOM link is considered as system reserves.

2/ On the basis of current ESCOM tariffs.

ANNEX 14- 51 - Page 7 of 7

SWAZILANDSWAZILAND ELECTRICITY BOARD

Cash Flow for Internal Rate of Return(E Million)

Capital ExpendituresTransmission Operation

and and Total Benefits S,ales TotalThe Project Distribution Maintenance Expenditures 1/ 2/ Revenues

1981 0.50 0.5082 2.90 2.90 0.07 0.0783 3.16 3.16 0.41 0.4184 11.60 0.10 0.29 11.99 0.78 :1.60 2.3885 10.15 0.40 0.47 11.02 1.97 3.15 5.1286 1.25 0.60 0.50 2.35 1.94 3.15 5.0987 1.00 0.50 1.50 1.70 3.15 4.8588 0.45 0.50 0.95 0.40 3.15 3.5589 0.50 0.50 0.34 3.15 3.4990 0.55 0.55 0.34 3.15 3.4991 0.55 0.55 0.34 3.15 3.4992 0.55 0.55 0.34 3.15 3.4993 0.55 0.55 0.34 3.15 3.4994 0.55 0.55 0.34 3.15 3.4995 0.60 0.60 0.34 3.15 3.4996 0.60 0.60 0.34 3.15 3.4997 0.60 0.60 0.34 3.15 3.49

1998-2030 0.65 0.65 0.34 3.15 3.49

Rate of Return is 12%

1/ Benefits include custom union reventes and also water benefits estimated

at E 340,000/year.

2/ Revenues are based on the present average tariff of E~ 3.46 per kWh.

- 52 -

ANNEX 15Page 1 of 2

SWAZILAND

SWAZILAND ELECTRICITY BOARD

THIRD POWER PROJECT

Selected Documents and Data Available in the Project File

General Reports and Documents Related to the Sector

1) "Interim Report on Current Exploratory Programme of the Swazi Nation'sCoal Area to the Ministry of Overseas Development", London, June 1970(Powell Duffryn Technical Services Limited);

2) "Usutu, Mbuluzi, Komati and Lomati River Basins", 1970 (Engineeringand Power Development Consultants);

3) "Technical Feasibility of Supplying Power Station Coal from theSwaziland Collieres Ltd., Concession Area", London, June 1971 (PowellDuffryn Technical Services Limited);

4) "Report on Thermal Power Station", April 1971 (Watermeyer, Legge,Pieshold and Uhlmann, Merz and McLellan, Cooper Brothers and Co.);

5) "Kingdom of Swaziland Thermal Power Plant Project Report andRecommendations", October 1973 (Northcutt Ely and Neil Adams);

6) "Kingdom of Swaziland Thermal Power Plant Project", January 1974(Northcutt Ely and Neil Adams);

7) "Swaziland Electricity Board, Report on Future Electricity GenerationPolicy", December 1978 (Merz and McLellan, Watermeyer, Legge, Piesholdand Uhlmann, and Coopers and Lybrand Associates Limited).

General Reports and Studies Relating to the Project

1) "Swaziland Electricity Board, Pre-Investment Report on Hydro-ElectricProjects", May 1980 (Merz and McLellan, Watermeyer, Legge, Piesholdand Uhlmann, and Coopers and Lybrand Associates Limited).

2) "Swaziland Electricity Board Lupohlo-Ezulwini and Lower Hydro-ElectricProjects, Civil Engineering Quantities and Unit Rates", April 1980(Watermeyer, Legge, Pieshold and Uhlmann);

3) "Government of Swaziland, Review and Analysis of Water ResourcesPlanning and Development in Swaziland", October 1979 (U.S. Army Corpsof Engineers);

- 53 -

ANNEX 15Page 2 of 2

4) "Reconnaissance Irrigation Study of Lusushawana River, Swaziland,Technical and Economic Feasibility' 1980 (Engineering and PowerDevelopment Consultants);

5) "Swaziland Electricity Board, Cost Estimates and Lower I{ydro-ElectricScheme Projects", 1980 (Farrow Lane);

6) "Swaziland Electricity Board, Recommendations on Geology and Designof Lupohlo-Ezulwini and Lower Hydro-electric Schemes", L980 (Woodward-Clyde Consultants, S. T. Thorfinnson and E. B. Waggoner).

Selected Working Papers

- Computer printouts and discounted cashflow studies.

- Project cost estimates.

- Financial and accounting statements.

IBRD 15243SEPT'-MBER 198G

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