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MozambiqueElectricity Tariffs Study

Report No. 181/96

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JOINT UNDP/WORLD BANKENERGY SECTOR MANAGEMENT ASSISTANCE PROGRAMME (ESMAP)

PURPOSE

The Joint UNDP/World Bank Energy Sector M\vanagement Assistance Programme(ESMAP) is a special global technical assistance program run by the World Bank'sIndustry and Energy Department. ESMAP provides advice to governments onsustainable energy development. Established with the support of UNDP and 15 bilateralofficial donors in 1983, it focuses on policy and institutional reforms designed to promoteincreased private investment in energy and supply and end-use energy efficiency; naturalgas development; and renewable, rural, and household energy.

GOVERNANCE AND OPERATIONS

ESMAP is governed by a Consultative Group (ESMAP CG), composed of representativesof the UNDP and World Bank, the governments and other institutions providingfinancial support, and the recipients of ESMAP's assistance. The ESMAP CG is chairedby the World Bank's Vice President, Finance and Private Sector Development, andadvised by a Technical Advisory Group (TAG) of independent energy experts thatreviews the Programme's strategic agenda, its work program, and other issues. ESMAPis staffed by a cadre of engineers, energy planners, and economists from the Industry andEnergy Department of the World Bank. The Director of this Department is also theManager of ESMAP, responsible for administer ing the Programme.

FUNDING

ESMAP is a cooperative effort supported by the World Bank, UNDP and other UnitedNations agencies, the European Community, Organization of American States (OAS),Latin American Energy Organization (OLADE), and public and private donors fromcountries including Australia, Belgium, Canada, Denmark, Germany, Finland, France,Iceland, Ireland, Italy, Japan, the Netherlands, New Zealand, Norway, Portugal, Sweden,Switzerland, the United Kingdom, and the United States.

FURTHER INFORMATION

An up-to-date listing of completed ESMAP projects is appended to this report. Forfurther information or copies of completed ESMAP reports, contact:

ESMAPc/o Industry and Energy Department

The World Bank

1818 H Street N.W.

Washington, D.C. 20433

U.S.A.

MOZAMBIQUE

Electricity Tariffs Study

June 1996

Power Development, Efficiency &Household Fuels DivisionIndustry and Energy DepartmentThe World Bank1818 H Street, N.W.Washington, D. C. 20433

This document has restricted distribution and may be used by recipients onlyin the performance of their official duties. Its contents may not otherwise bedisclosed without UNDP or World Bank authorization.

PREFACE

The present study is a continuation of efforts undertaken by the World Bank andESMAP to assist Mozambique in its attempts to define and implement appropriate policiesin the energy sector, which is of crucial importance for the welfare and development of thecountry. This study is cofinanced with funds from the Netherlands and Sweden.

The process of this study also contains an element of institutional developmentsince the team responsible for carrying it out promised to train staff of EDM's PlanningDepartment to continue this work in the future. As a first step, the team implemented astatistical software package in November 1995 and trained EDM staff in its use.Additionally, a qualified statistician from the Eduardo Mondlane University was hired toadvise EDM on applying the program and to provide backstopping services.

Michel Del Buono (Senior Economist, IENPD) and Witold Teplitz-Sembitzky(Energy Economist, Consultant) prepared this study following a mission to Mozambiqueduring May and June of 1995. Yuriko Sakairi (AFIEI), John Besant-Jones, Robin Bates(IENPD), Eric Daffem (IENOG), and Robert Bacon (Consultant, IENPD) providedcomments. Robin Bates also helped in preparing the final version. Jose Lopez contributedsome estimates of possible cost savings on EDM's investment program. Manuel Ruas ofthe Ministry of Mineral Resources and Energy provided informnation and critical thinking.EDM's Planning Department gave access to data and participated enthusiastically in allaspects of the preparatory work. Joao N. Baptista (Engineer, EDP) reviewed the entire textof this report prior to publication. Theresa Paiz edited the final version and prepared it forpublication. The green cover version of this study was presented to EDM's new Board inNovember 1995. In addition, a series of individual meetings with the General Manager,Board members and senior staff of EDM was held to discuss the main issues addressed bythe study. The authors are grateful for all these contributions but wish to stress that anyremaining errors are their responsibility alone.

ABBREVIATIONS

GDP gross domestic productGW gigawattGWh gigawatt hourHV high voltagekm kilometerkV kilovoltkVA kilovolt amperekW kilowattkWh kilowatt hourI literLRAIC long-run average incremental costsLV low voltageMT MeticalMV medium voltageMW megawattMWh megawatt hour

Acronyms

DNE Direccao Nacional de EnergiaEDM Electricidade de MozambiqueESMAP Energy Sector Management and Assistance ProgramHCB Hidroelectrica de Cahora BassaRSA Republic of South Africa

Currency Equivalents

US$ I = MT 6,054 (1994 average)= MT 8,000 (May 1995)= MT 11,093 (May 31, 1996)

US$ 1 = Rand 3.6 (May 1995)

TABLE OF CONTENTS

Executive Summary ................................................. i

1. Sector Characteristics and Performance .................................................. I

Physical Infrastructure ............................................ 1Gross Consumption ............................................ 2Sales and Losses ...... 3..................................... 3Financial Situation ...... 3...................................... 3

2. Present Tariffs and Cost of Supply . ................................................. 5

Tariffs ............................................ 5Supplies from HCB ............................................. 7Imports from Eskom ............................................. 7Prospects ............................................ 8

3. Demand Forecasts ................................................. 11

4. Investment and LRAIC ................................................. 15

Planned Investments ........................................... 15LRAIC .................................... 17

5. Proposals for a New Tariff Scheme ................................................. 21

ANNEXES

Annex A: Key Data .................................................. 31Annex B: EDM's Tariff System .................................................. 39Annex C: Minimizing the Costs of Electricity Imports from Eskom ................ ............. 46Annex D: Load Analysis Southern System .................. ............................... 51Annex E: Econometric Analysis of Electricity Demand ................................................ 56Annex F: Forecast of Electricity Consumption .......................... ....................... 66Annex G: Long-Run Average Incremental Costs of Power Supply ................. ............. 73Annex H: Basic Features of a Revised Tariff System .................................................. 88

TABLES

Table 3.1: Forecasts of Gross Electricity Consumption (Gwh) ................. ..................... 12Table 3.2: Forecasts of System Peak (Mw) ............................................................ 13Table 4.1: Summary of EDM's and Revised Investment Program (US$ Millions) ....... 18Table 4.2: LRAIC of Power Supply ...................... ...................................... 20Table 5.1: Comparison of Capacity and Energy Cost Estimates ............... ..................... 22Table 5.2: Notional Average Costs by Voltage Level and Scenario ............ .................. 23Table 5.3: Revised Tariff Regime ............................................................ 24Table 5.4: Illustrative Structure of Tariffs Based on EDM's Financial Projections ....... 25Table 5.5: Tariff Regime Based on Adjusted Average Costs of

Low-Growth Scenario ............................................................ 26

MAP

IBRD 27755: Mozambique Electric Power System Interconnected Network

EXECUTIVE SUMMARY

Introductn

1. A study was carried out by the World Bank in 1995, assisted by finance fromESMAP, to consider alternative structures of electricity tariffs in Mozambique. The presenttariff regime, which was implemented in 1992, does not reflect the economic costs ofmeeting additional demand. In particular, the current rates for energy (kWh) and capacity(kW) are, respectively, above and below the estimated long-run incremental costs of supply;they do not properly account for network losses; and they involve cross-subsidies. At thesame time, while the rates per unit of capacity are lower than the economic costs, the totalcapacity charges for which EDM charges significantly exceed the system peak. Thismeasurement and metering problem aggravates the distortions implicit in the current tariffsystem. A further difficulty with existing tariffs is that they fall short of the financialobjectives included in EDM's business plan, which involve a target of 9.5 UScentslkWh by1998.

2. A key objective of the study was to develop a methodology which EDM couldroutinely use to derive and keep current a tariff system that better reflects the long-runincremental costs of meeting demand. For that purpose, it reviews EDM's investmentprogram (as known in mid-1995) in the light of forecast electricity consumption and peakload. The forecasts are obtained by estimating a demand function and applying the modelto different scenarios about GDP growth and tariff increases. The two scenarios selected forinvestment planning are: (i) a relatively low GDP growth, combined with relatively hightariffs (which were basically in line with EDM's financial projections in mid-1995); and (ii)a higher (medium) GDP growth, in tandem with lower tariffs.

3. Following the review of EDM's planned investments, a revised sequence andvolume of investments are postulated for the purposes of deriving estimates of long-runincremental costs. While compatible with forecast demand, and less costly than thoseproposed by EDM in 1995, the revised sequences are to be viewed as illustrative only: theyare used to compute the long-run average incremental costs of meeting future demand underthe two scenarios.

4. Depending on the scenarios, the calculations result in total incremental costs thatrange from 6.0 to 9.1 UScents/kWh. The result is, by and large, consistent with the tariffassumptions underlying the respective demand forecasts. For generation --more accurately,imports or purchases of power, which replace generation at the margin-- incremental costsare about 2.8 UScents/kWh, under both scenarios. The remaining costs are attributable totransmission and distribution, which make up two-thirds of the planned investments.

ConclusiQns

5. If EDM were to introduce a new tariff structure, reflecting long-run averageincremental costs (LRAIC), the rates could be based upon two-part tariffs, involving acapacity fee per kW of coincident peak and an energy charge per kWh, at both the HV- andMV-level. At the LV-level, the schedules could distinguish between non-residential andresidential users, with some of the capacity costs subsumed under the energy charge for thelatter. This would provide a small subsidy to those users consuming less than the averageamount of electricity, at the expense of those consuming more. While representing a tariffdistortion (cross-subsidy), relative to the economic costs of supply, it would help toaccommodate EDM's commitment to serve less affluent customers at affordable rates. Byway of illustration, taking the medium-growth scenarios but ignoring financialrequirements, on average, the rates would translate into 4.9 UScents/kWh at the HV-Ievel,5.9 UScentslkWh at the MV-level, and 8.0 UScents/kWh at the LV-level. The systemaverage tariff would be in the vicinity of 7.0 UScents/kWh, compared with a LRAIC of 6UScents/kWh.

6. However, such a tariff structure would yield an average tarif below the target level,for financial purposes, of 9.5 UScents/kWh, which is now embodied in EDM's businessplan and also was proposed in the recently completed financial restructuring study ofEDM.' This is because the economic analysis does not take into account past investments,which are irreversible and thus sunk, although such investments are part of financial costs.Its focus is instead on future costs, and even here, there are differences between theinvestment program considered by EDM (at the end of 1995) and that used in this study toillustrate the methodology, which is lower (see Table 4.1, Chapter 4). Furthermore, theillustrative investment program used for the LRAIC analysis does not take into account theannual investment cap of US $20 million that has now been deemed necessary for EDM.

7. Aside from deriving a tariff structure based on long-run incremental costs, this studyconcludes that it would not be a high priority in Mozambique, under present conditions, toincorporate regional diferentials in the tariff structure, to account for variation inlocational cost. However, an important exception should be noted in the case of the isolatedsystems, which were not covered in the study. Neither do the load characteristics, atpresent, lend themselves to time-of-use pricing. Bulk supplies come from three sourcesonly (RSA, HCB, indigenous hydro) at fairly stable (contractually fixed) costs. Economicdispatch is not an issue, and given the load profile of EDM's current customers, there arefew opportunities for sophisticated load management.

8. Nevertheless, the illustrative tariff system could easily be refined (e.g. toward moreadvanced forns of peak-load pricing or location-specific rates) if analysis by EDM in thefuture should indicate that the situation has changed sufficiently to warrant it. Moreover,the new Electricity Law, which is currently under preparation, may eventually lead to

See "Financial Review of Electricidade de Mocambique (EDM)," June 23, 1995.

111

radical changes in the regulatory environment, sector structure, and ownershiparrangements, thus calling for more flexible rates and contractual terms. Even then, theillustrative tariff system might be a reasonable starting point for the design of a moreappropriate tariff policy.

9. While EDM might apply the illustrative tariff system to its different customerclasses, it would retain the right to negotiate special terms for large and strategicallyimportant customers, if merited by cost differences. Once (licensed) independent powerproducers enter the scene and are willing to sell electricity to the grid or wheel power tothird parties, EDM should be permitted to negotiate separate contracts, to cover specificcircumstances not included in the more general and illustrative analysis developed in thisstudy. EDM's benchmark for contractual negotiations would be its avoided costs at thepoint of injection and/or delivery.

10. A further conclusion of the study is that any alternative tariff structure, includingone reflecting LRAIC, must be implemented in combination with rejorms aimed atimprovements in customer metering, billing, and revenue collection. Technical assistanceto strengthen EDM's capabilities in these areas would be helpful. EDM also should besupported in its efforts to enhance sector planning and financial management.

11. Finally, the study emphasizes that tarif analysis must always be regarded as aprocess. The goal of the study was to put in place a methodology and also a capability toupdate the analysis, as the important underlying assumptions are changed, for example interms of system losses, planned investments, sales growth and financial prospects. Notably,EDM should review the results of this study and revise the analysis to reflect its latestbusiness plan. Especially, changes will be necessary to move the level of tariffs into linewith the financial restructuring program agreed upon by the Ministry of Finance and theMinistry of Energy and Mineral Resources. The financial objectives of EDM require anaverage tariff of 9.5 UScents/kWh, so that a pragmatic approach to reforning the tariffsystem needs to be found, in which the tariff level and structure would reflect financial andeconomic objectives, respectively. Some movement towards such a compromise could beinitiated by raising the capacity charges faster than the energy charge. EDM also shouldtake the opportunity to re-examine the efficiency of its operations, in light of its poorfinancial situation and the estimated difference between LRAIC and the tariff needed onfinancial grounds.

I

SECTOR CHARACTERISTICS AND PERFORMANCE

1.1 In the past, when Mozambique's power sector was exposed to the risks of civilunrest and sabotage, sector development was dictated by the need to keep the systemrunning, more or less without regard to costs, and was substantially dependent on theconcessional funds that donors provided. As a consequence, most of the investments thatwere not for replacement and repair, were based on expectations about the return of peaceand economic progress and implemented with high design and reliability standards.Moreover, with the advent of peace in 1992, EDM not only encountered the challenge ofhaving to graduate from an engineering task force to a commercially-oriented utility, butwas saddled with a number of acquired assets that are costly to repair and maintain, anddifficult to operate within a system, thus resulting in a huge financial burden reflectingbasically sunk costs.

Physical Infrastructure

1.2 EDM's transmission network consists of three independently operated systems (seeMozambique Map, IBRD 27755, on page 91). The northern grid is tied to a 220 kV linefrom Songo (Cahora Bassa) to Nampula (1,000 km), extending at 110 kV to Nacala (200km), designed as a double circuit between Songo and Caia. There is also an incomplete linefrom Matambo to Chibata which was planned to connect the northern grid with the centralsystem. A weak, temporary interconnection was to have been completed in late 1995.

1.3 The central system, which was repeatedly sabotaged during the war, comprisesabout 500 km of 110 kV lines and 113 km of 66 kV lines. It stretches from the Zimbabweborder to the coastal city of Beira. Of the two parallel lines between Mavuzi andNhamatanda, one has been reactivated recently. The double circuit connection betweenNhamatanda and Beira can only be operated as a single circuit system.

1.4 The southern system is composed of a 225 kV line, running from Maputo toKomatipoort (RSA), a 110 kV line coming from the RSA to Corumana and extending toMaputo, and a 110 kV line connecting Maputo with the towns of Chokwe and Xai-Xaithrough Macia

1.5 EDM's installed generating capacity amounts to 310 MW. About 206 MW arecurrently available, of which 85 MW are hydro and mainly in the central region. Thesouthern system accounts for 206 MW, while the central and northern systems are endowedwith 82 MW and 20 MW, respectively (see Table A. 11, Annex A for details). There arealso a number of isolated units, notably in Pemba, Angoche and Lichinga (North), and in

2

Inhambane (South). In addition to its own capacity, EDM has contractual access to 200MW of hydro power from the Cahora Bassa dam, currently at very low tariffs, and has thecapacity to import about 150 MW from South Africa. Hidroelectrica de Cahora Bassa(HCB) is a private Mozambican corporation that owns the Cahora Bassa dam, power plantand direct-current line to South Africa. HCB, in turn, is owned by the States of Portugal(82 percent) and Mozambique (18 percent).

Gross Consumption

1.6 Even though EDM's own available generating capacity would be sufficient to meetmost of the domestic load, about 78 percent of the power supplied in 1994 came from theRSA or was acquired from HCB, with the balance covered by indigenous hydro resourcesand a few thermal plants operated in isolated areas. For comparison, the share of grossconsumption2 supplied by imports and HCB-acquisitions was only 59 percent in 1991. Thesharp increase in imports (southem system) and HCB-supplies (northem system), whichcost less than the operation of EDM's thermal plant, becane feasible through improvementsin the reliability of the network brought about by the return of peace in 1992.

1.7 Between 1990 and 1994, aggregate gross consumption rose on average by 5 percenta year. Growth was fastest in the southern system with an average rate of 6 percent,compared to 3.5 percent in the central plus northern region (Table A.1, Annex A). As aconsequence, the share of gross consumption accounted for by the southem systemincreased from 61 percent in 1990 to 65 percent in the first quarter of 1995 (compared to23.3 percent in the central region and 11.7 percent in the northern region). While thepeaceful conditions prevailing since 1992 were conducive to faster demand growth in thenorthem (7.4 percent) than in the southern system (6.7 percent), consumption in the central

3region remained stagnant during the last two years.

1.8 Currently, the system peak is about 162 MW, compared to 144 MW in 1990. Thedaily peak tends to shift from about 7 p.m. during the wet season (April-October) to 12 a.m.in the dry season (see Annex F).There is a deep trough in demand, at night, year round.

1.9 Another change that can be attributed to the end of civil strife is a sharp increase inthe system's load factor. During the 1980s, the load factor, on average, was well below 0.6.Since 1992, however, the figure steadily improved to about 0.67 in early 1995, reflectingthe greater reliability of supply achieved by EDM.4

2 Gross consumption includes technical and nontechnical losses as well as station use.3 In 1994, a cyclone caused heavy damage to the network in the northern towns of Nampula and Nacala,

resulting in a temporary disruption of supply.4 Since there is no information available on the coincidence of subsystem peaks, estimates of

systemwide load factors include some margin of error. In February 1995, the load factor of the centralsystem was in the vicinity of 0.62, compared to 0.68 in the southern system.

3

1.10 It is also worth noting in this connection that the load factor moved up in spite of thediminishing share of medium and high voltage consumption (see Table A.2, Annex A). Bycontrast, the number of residential users as well as their specific consumption has steadilyincreased during the last five years (except for 1992), and a similar trend is observable fornonresidential small-volume consumers (see Table A.10, Annex A).5 By early 1995,residential and nonresidential small-volume customers accounted for 53.0 percent of finalconsumption, followed by medium-voltage customers with a share of 39.1 percent, whilehigh-voltage consumption was down to 1.4 percent (see Table A.7, Annex A).

Sales and Losses

1.11 While the data on gross supply are fairly reliable, the records of electricity sales givea highly distorted picture of the level of final consumption and the losses involved in thetransmission and distribution of power. The sales figures published in EDM's annualreports are labeled "billed" energy ("energia facturada") and reflect what EDM thinks itdelivers to final consumers. A thorough investigation of EDM's accounts in 1994 shows,however, that there is a large gap between 'billed" energy and actual (recorded) sales: Outof a gross supply of 948 GWh, 727 GWh were considered to be delivered, but only 596GWh qualified as recorded sales. Hence, technical and nontechnical losses amounted to33.7 percent of gross consumption.

1.12 Armed with this insight, EDM's financial department has prepared a 1995 forecastthat more closely approximates the composition of losses facing the utility (see Table A.5,Annex A). According to this breakdown, technical losses account for 13.9 percent of grossconsumption, while 17.3 percent are made up by nontechnical losses (including publiclighting). Moreover, EDM expects to collect only 87 percent of the revenues accruing fromits forecast sales; this would result in overall losses of 40 percent.

1.13 About 40 percent of the nontechnical losses are assumed to be theft (e.g. tamperingwith meters), 36 percent are ascribed to substandard metering equipment and 18 percent tofalse meter reading. As a consequence, EDM gives top priority to a program aimed atreducing the nontechnical losses by two-thirds over the next three years.

Financial Situation

1.14 EDM's financial situation has worsened during the last three years. For instance,no cash was available to finance the construction of works; debt service in 1994 wascovered only 0.6 times; and the utility was unable to earn a positive rate of retum. Thefinancial difficulties can be explained mainly by six factors:

As is argued below, however, the level of sales reported in the past is subject to measurement errors.While this is not likely to affect the trends underlying the published data on electricity use byconsumer group, care should be taken in interpreting the absolute figures.

4

* overstaffing and expenditure on parts and services that is high in relation tothe quantity of electricity sold;

* the high level of losses, especially the non-technical ones (see above);* the high level of investment;* the cost of staffing and maintaining standby equipment;* an unacceptably persistent and high level of non-payment and late payment;* delays in tariff adjustment, so that EDM fails to maintain its earning power

when measured in hard currency.

1.15 EDM has begun to act on the first two problems and will obtain some measure ofsuccess. Regarding the third problem, EDM has taken steps to prune its investmentprogram. In fact, under EDM's new business plan (as of April 1996), the investmentprogram presented by EDM in mid-1995 has been adjusted downward. As to the cost ofmaintaining and staffing standby equipment, this is something that EDM has not yetaddressed, but will need to be incorporated into its business plan. Likewise, EDM hasincorporated provisions on the state non-payment problem into its proposed business plan.

Income Distribution

1.16 Higher tariffs and vigorous enforcement of timely payments by customers mayhave a serious impact on household budgets. However, it is difficult to predict thereaction of electricity users to tariff levels higher than experienced in the past. To gainsome insight into this process, ESMAP and the DNE carried out a brief survey, betweenJanuary and March 1996. A total of 912 randomly selected LV-customers wereinterviewed, of which 800 are households falling into the "domestic tariff' category. Thefinal results will be available in mid-1996.

1.17 The survey's preliminary findings indicate that electricity consumption levels andend uses vary significantly across the country and by income. Electricity consumptionand the number of electric appliances increase with income, and higher-incomehouseholds are more likely to live in Maputo, Beira and Chimoio than in the rest of thecountry. Moreover, those households with access to electricity are comparatively affluent.Seventy percent of the households covered by the survey live on income from civilservants and self-employed family members; 34% use electric cookers; 14% LPG-stoves; and 8% cook with both electricity and LPG. Overall, it is likely that only a smallproportion of the LV-electricity users interviewed would be severely affected by thetariff increases sought by EDM. However, the survey was not designed to answer thefurther important question as to whether or not higher tariffs would make electricity muchless affordable for those households that are not yet served by EDM, but wish to becomeelectrified.

2

PRESENT TARIFFS AND COST OF SUPPLY

Tariffs

2.1 With a few exceptions, the rate-setting approach underlying the currently prevailingtariff system follows the recommendations made in a tariff study submitted in 1991. Theproposals were implemented in January 1992 and the resulting tariffs have since beenadjusted for inflation, but their structure was not modified.

2.2 A detailed examination of EDM's tariff regime is provided in Annex B. Its majorshortcomings, from an economic standpoint, can be summarized as follows:

* The estimated average costs used as a benchmark for fixing the initial tarifflevels did not properly reflect the future costs of meeting (growing) demand.Adjustments in nominal tariffs which have since taken place failed to correctthis weakness.

* The tariffs overcharge for energy and undercharge for capacity, but they do notproperly account for network losses across different voltage levels.6

* The tariff system offers options that do not appear to promote economicefficiency.

* At each voltage level, the tariffs cause cross-subsidies from consumers with ahigh load factor to those with a lower load factor.

* The system subjects those low-voltage customers with a contracted capacity ofless than 19.8 kVA to discriminatory capacity charges which have no economicjustification, but complicate billing, especially where it is still done manually.

In addition, EDM's estimates of the capacity needs of its customers grossly exceed theircontributions to the system peak (for details, see Annex B). While this a problem ofmeasurement and metering rather than a problem of tariff design, it aggravates thedistortions caused by the current tariff regime.

6 This statement is subject to the caveat that the rated capacity charged for by EDM significantlyexceeds the system peak, i.e., the customers' responsibilities for the system peak are grosslyoverestimated (by a factor of more than two). As a consequence, EDM collects higher payments forcapacity than would be justified if the current rates were applied to correctly measured maximum loadscoincident with the system peak .

6

2.3 In particular, HV- and MV-customers, as well as LV-customers with a maximumdemand in excess of 19.8 kVA are given the choice among three two-part tariffs involving atrade-off between payments for energy and capacity.7 The schedule is designed to induceconsumers to select a lower energy rate associated with a higher capacity charge if thesavings from cheaper energy more than offset the additional capacity costs. The main effectof the optional tariffs is, however, that users with a low load factor are charged less thanestimated average cost while those with a high load factor are charged more. It may evenhappen that the total revenues generated by the scheme fall short of the estimated costs ofsupply.8 A further point is that the optional tariffs, while complicating the tariff selectionand billing process, have limited practical relevance because there are virtually no short-utilization users. At the HV-level, all customers fall into the long-utilization category,given that its choice gives a cost advantage at a rather low load factor; while about 97percent of the LV-customers with a contracted capacity exceeding 19.8 kVA, whichaccount for less than 6 percent of total electricity sales, opt for the medium-utilization tariff.

2.4 Similar arguments apply to the capacity charges for residential and small-volumenonresidential users. The schedule comprises nine different flat rates for capacity, which,on a per unit basis, increase with the level of maximum demand.9 There is, however, noconvincing reason why unit capacity costs should rise in direct proportion to the level ofload served. Five of the capacity charges are tailored to consumption profiles whichrepresent less than 10 percent of the customers affected by the tariff scheme. Electricitybills are prepared with carefully computed capacity and energy charges even for thesmallest consumers although EDM can neither control nor meter capacity utilization byindividual consumers.

2.5 Finally, it should be mentioned that while EDM theoretically is entitled to adjustnominal tariffs for inflation and exchange rate depreciation, its latitude to do so has beenlimited by the need to seek political approval. In the last three years, nominal tariffs wereusually frozen over a period of four to six months before EDM could catch up with thegeneral price increases, thus exposing the company to avoidable financial losses, andmaking subsequent tariff increases larger and more disruptive than necessary. To remedythis problem, EDM has submitted a new proposal that if approved by the Cabinet, wouldtrigger automatic quarterly adjustments in the level of tariffs based on predeterminedcorrection factors.

2.6 In conclusion, EDM's situation did not improve when it revised its tariffs in 1992.A new tariff structure and level should, therefore, now be considered, in order to meet

7 The schedule is composed of a short-utilization, medium-utilization, and long-utilization two-parttariff, whereby long-utilization users are those with a load factor of about 0.15 or more.

8 Note that "estimated average costs" are those computed in the tariff study of 1991 and do not reflecteconomic costs.

9 Since there are no load limiters installed, maximum demand charges are assigned in accordance withthe level of consumption, which might badly overestimate the coincident peak.

7

EDM's financial needs, while at the same time addressing more effectively the underlyingstructure of EDM's economic costs. Some possible approaches in moving toward tariffreform are presented in Chapter 5.

Supplies from HCB

2.7 EDM is entitled to call upon 200 MW from Cahora Bassa (HCB).10 Currently,about 33 MW are injected into the northern grid, while imports from Eskom (by way of abilateral contract between EDM and Eskom) substitute for the supplies that HCB is unableto deliver to the southern system while the line to Apollo (RSA) is out of service.

2.8 The rates EDM pays for HCB power supplied to the northern system were agreedupon in 1983 and, as they have remained fixed in nominal terms, have since been erodingthrough inflation. For example, at a load factor of 55 percent, EDM s northern systemobtains HCP power at 7.23 Rand/MWh. "

2.9 For the southern system, the rates negotiated in the early 1980s for HCB powerwheeled through the RSA are somewhat higher (via a tripartite agreement among HCB,EDM and Eskom which assigns all of Cahora Bassa's output to Eskom, except for a 200MW entitlement to EDM). Under the old terms, and assuming a load factor of 0.66, EDMwould pay about 10.6 Rand/MWh plus transmission fees. In 1989, however, Eskomindicated that it would be prepared to pay a higher price once it has access to HCB-power(for details, see Annex G). Since the tripartite agreement states that EDM must pay at leastthe same price as Eskom for HCB power, at these higher rates, EDM's bill would be about28 Rand/MWh (or UScents 0.8 per kWh as of May 1995) plus transmission fees.

Imports from Eskom

2.10 As a substitute for HCB power that EDM cannot now obtain, the southern systemimports from Eskom. The latest agreement between Eskom and EDM came into effect inJanuary 1995 and will be valid until July, 2000, or three years after the resumption ofsupply from HCB to Eskom (for details, see Annex C).

2.11 The rates are denominated in US$ and indexed with respect to US-producer prices.They currently amount to 0.5 UScents/kWh for firm energy, 3.24 UScents/kWh foremergency energy (i.e. in excess of contracted capacity), and US$8.44 per kW of contractedcapacity, charged on a monthly basis.

O Strictly speaking, EDM's share is 220 MW at the Cahora Bassa busbar or 190 MW at Komatipoort(RSA).EDM pays 4 Rand per MW times the duration (number of hours) of the respective month. With a loadfactor is 0.55, EDM therefore pays 7.23 Rand/MWh (= 4/0.55), which in May 1995 was equivalent to2 US$/MWh.

8

2.12 The way the rates are structured makes it profitable for EDM to contract lesscapacity than needed to serve expected maximum demand, and to cover the balance withemergency energy. EDM has quickly realized that there is a potential for cost savings andshould be commended for pursuing the correct strategy of reducing the amount ofcontracted capacity during the first four months of 1995. On average, it paid only UScents1.97 per kWh imported from Eskom, which is close to the theoretical minimum of 1.76UScents/kWh. i 2

Prospects

2.13 Since HCB is committed and determined to bring the line from Cahora Bassa to theRSA back into operation by March 1997, EDM can count on the availability of HCB-powerin the southern system from that time onwards. However, while it would be desirable forEDM's finances that supplies for the southern system become available at rates similar tothose currently charged by HCB, this is not certain. EDM should hope that suchadvantageous terms remain in force as long as possible, but the principle of conservatism infinancial analysis would strongly suggest that EDM plan for higher cost power, perhapssignificantly so and be prepared to enjoy a windfall if this did not happen.

2.14 The fact that EDM expects to have access to additional HCB-power (i.e., >200MW) when needed also is relevant in this connection. This is only feasible if Eskomreleases part of its claim on HCB supplies (as it has done in favor of Zimbabwe).13 Eskom'sopportunity costs of giving EDM a cut of its share, however, are the revenues it wouldforego by not exporting to Mozambique its own power or, equivalently, power acquiredfrom HCB. The current agreement between Eskom and EDM leaves Mozambique thechoice to continue importing power from the RSA beyond 2000.

2.15 While more expensive than current HCB sales to the northem system, powerobtained at 2 to 2.5 UScents/kWh is significantly less costly than operating EDM's thermalplant and is also an attractive alternative to investments in additional hydro or thermal (coalor gas-fired) facilities built to serve the domestic market.

2.16 In sum, HCB may attempt to renegotiate the terms of its agreement with Eskomand EDM once it is in a position to reliably supply the RSA and EDM's southem system.The resumption of large-scale supplies from Cahora Bassa will buttress the trend towards a

12 The theoretical minimum can only be achieved if EDM correctly predicts the southern system'smonthly load (duration) curve, which is unlikely (for more details, see Annex C).

13 It should be also kept in mind that Zimbabwe is a potential bidder for what is left of Eskom'sentitlement to HCB-power.

9

greater regionalization of power markets and, thus, the equalization of rates at which bulksupplies are traded. These forces may eventually increase the price of tradable powerbeyond the level at which EDM's northern system presently acquires it.

3

DEMAND FORECASTS

3.1 A number of electricity demand forecasts have been prepared in the last four yearsto lay the groundwork for EDM's investment planning and financial projections.14 Theforecasts were based on ad-hoc assumptions or extrapolated past trends into the future. Inretrospective, the forecasts tended to be inaccurate.

3.2 Under the circumstances prevailing in Mozambique, forecasting is a challengingexercise. Since past developments were hindered by the impacts of war and recordingerrors, and given that the recent period of negotiating and consolidating peaceful conditionshas a transitional character, there is little empirical evidence upon which long-termpredictions can be built. In light of these difficulties, the present study relies on a Bayesianapproach to modeling electricity demand using prior information from other developingcountries (see Annex F), and applies the coefficient estimates to different scenarios coveringthe period 1995-20 10.

3.3 The estimated demand function is of the partial adjustment type with real GPD,inflation-adjusted average tariffs, and gross electricity consumption (the dependent variable)lagged one year, as arguments. The short-run elasticity estimates obtained are 0.460 forGDP and -0.097 for price, while the long-run counterparts are 1.460 and -0.309 for GDPand price, respectively (for details, see Annex E). 1 These results are consistent with manyother studies that show power demand to be relatively inelastic in the short term butconsiderably more elastic, especially with respect to income, over the longer run.

3.4 In terms of scenarios, the cases of slow, medium, and high GDP-growth arecombined with a low and a high tariff policy. The high-tariff variant assumes that averagetariffs rise to 9.5 UScents/kWh by 1998, which is consistent with the recent financialanalysis carried out for EDM. Alternatively, a lower target level of 7.5 UScents/kWh isconsidered. In both cases, only modest tariff increases (in real terms) are expected for theperiod after 2000.

3.5 Regarding the prospects for GDP growth, the "low" case assunes that real GDPrises at an average rate of 3 percent a year. Medium growth translates into average annualgrowth rates of 4.7 percent for 1995-2000 and 4.2 percent for 2000-2010. High growth

14 Forecasts have been conducted by Norconsult, EDF, KfW, and, most recently, by EDM's financialdepartment.

'5 While the long-run GDP elasticity may appear to be on the higher end, in the context of the estimatedcoefficients, adjustment is slow so that the long-run tends to be remote into the future and its elasticityonly is approached asymptotically.

12

corresponds to 6.7 percent a year for 1995-2000 and 5.5 percent for 2000-2010 (for details,see Annex F).

3.6 The resulting forecasts are presented in Table 3.1 below.

Table 3.1: Forecasts of Gross Electricity Consumption(GWh)

Year Fla Flb F2a F2b F3a F3b1995 935.03 935.03 942.58 942.58 949.64 949.641996 962.38 968.80 984.21 990.77 1003.22 1009.921997 982.90 999.57 1021.89 1039.22 1057.80 1075.741998 1000.52 1035.64 1058.56 1095.71 1117.08 1156.291999 1028.89 1077.99 1109.06 1161.98 1198.81 1256.012000 1065.50 1125.64 1170.97 1237.07 1300.75 1374.182001 1108.77 1177.77 1243.01 1320.37 1414.76 1502.802002 1158.64 1235.36 1327.14 1415.02 1539.26 1641.182003 1211.49 1295.03 1417.64 1515.39 1675.08 1790.582004 1266.23 1355.62 1510.27 1616.89 1817.69 1946.012005 1323.02 1417.91 1605.85 1721.04 1965.94 2106.952006 1382.04 1482.24 1705.29 1828.92 2121.44 2275.242007 1442.25 1547.25 1807.76 1939.36 2283.85 2450.112008 1505.34 1615.24 1915.74 2055.60 2456.71 2636.062009 1566.54 1680.78 2023.50 2171.06 2639.00 2831.432010 1628.02 1746.93 2133.94 2289.79 2827.83 3034.36

ARGa:

1995-2010 4.0 4.5 5.9 6.4 7.9 8.41995-2000 2.6 3.8 4.2 5.4 6.4 7.6

Note: Fla = low GDP, high tariff; Flb = low GDP, low tariff; F2a = medium GDP, high tariff; F2b =medium GDP, low tariff; F3a = high GDP, high tariff; F3b = high GDP, low tariff.

a. Average annual rate of growth (percent); least squares estimates.

3.7 Depending on the scenario assumed, gross electricity consumption is predicted togrow at average annual rates ranging from 4.0 percent to 8.4 percent. For comparison, inthe last three years, consumption grew at about 5.5 percent. Beyond 2000, forecastconsumption tends to increase faster than in the period 1995-2000, mainly because thedampening effect of the tariff adjustments tapers off, while GDP continues to rise, thushaving a marked positive impact on demand in the longer term.

3.8 In addition to the long-term projections shown above, a short-term forecast ofmonthly gross electricity consumption has been conducted on the basis of time series

13

analysis (see Annex F). The cumulative estimates are 950 GWh for 1995 and 993 GWh for1996, compared to 899 Gwh in 1994. The long-termn predictions that come closest to thesefigures are those made under the medium-growth-cum-low-tariffs scenario.

3.9 Since the data base is too weak to estimate a (nonlinear) peak load function,maximum demand is assuned to be linear in electricity demand. Table 3.2 shows theforecast peaks conditional on forecast gross consumption, assuming that the system loadfactor remains in the vicinity of 0.66. 1 6

Table 3.2: Forecasts of System Peak(MW)

Year Fla Flb F2a F2b F3a F3b1995 161.7 161.7 163.0 163.0 164.3 164.31996 166.5 167.6 170.2 171.4 173.5 174.71997 170.0 172.9 176.7 179.7 183.0 186.11998 173.1 179.1 183.1 189.5 193.2 200.01999 178.0 186.5 191.8 201.0 207.3 217.22000 184.3 194.7 202.5 214.0 225.0 237.72001 191.8 203.7 215.0 228.4 244.7 259.92002 200.4 213.7 229.5 244.7 266.2 283.92003 209.5 224.0 245.2 262.1 289.7 309.72004 219.0 234.5 261.2 279.7 314.4 336.62005 228.8 245.2 277.8 297.7 340.0 364.42006 239.0 256.4 295.0 316.3 366.9 393.52007 249.5 267.6 312.7 335.4 395.0 423.82008 260.4 279.4 331.4 355.5 424.9 455.92009 271.0 290.7 350.0 375.5 456.4 489.72010 281.6 302.2 369.1 396.0 489.1 524.8

Note: F I a = low GDP, high tariff; FIb = low GDP, low tariff, F2a = medium GDP,high tariff; F2b = medium GDP, low tariff; F3a = high GDP, high tariff; F3b= high GDP, low tariff.

3.10 There is no obvious way to choose between the different demand scenarios.However, it is useful to regard, as a lower band, the scenario combining low growth withhigh tariffs, since its predictions are close to EDM's forecast of May 1995. On the otherhand, it can be argued that the scenarios based on high GDP-growth are over-optimisitic.The study therefore supposes that the scenario combining the medium growth with lowtariffs can be regarded as the upper band.

16 Even though a load factor of 0.66 looks rather high, it reflects the current situation. On the other hand,assuming that the load factor will decrease in the future implies that the forecast peaks would be evenhigher than is shown in Table 3.2.

14

3.11 In allocating gross electricity consumption between EDM's southern system and therest of the country, it is assumed that the share accounted for by the southern system is 65percent in 1995, declines to 62.5 percent by 2000, and remains at this level until 2010.Since the systems will be interconnected by then, this will not matter very much.

3.12 The forecasts as well as the underlying models should be refined and updated onceadditional information about the relevant variables becomes available.

4

INVESTMENT AND LRAIC

Planned Investments

4.1 As of late 1995, EDM was planning to launch an ambitious investment programover the next 15 years. About US$ 332 million would be needed to implement the projects(not including Alto Malema). Given that EDM can supply most of its generation needsfrom HCB or Eskom, most of the US$ 332 million investment program is earmarked torehabilitate and extend the transmission and distribution network.'7 More importantly,about two-thirds of the investments are scheduled for the period 1995-2000, and manyprojects appear to be overdesigned and expensive, judged by the design and engineeringstandards prevailing in similar countries.

4.2 Given these concerns, it was decided to use an alternative investment program, forillustrative purposes. The alternative does not imply the formal review of investmentrequired under credit 2033; and is not necessarily a recommended or least-cost program.However, it has been judged feasible in relation to the forecast demand, while reducing thelevel of average incremental costs (See Appendix C). Hence, it does provide a vehicle todemonstrate the methodology of tariff analysis based on LRAIC.

4.3 Specifically, the alternative investment program removes those projects that do notcontribute to serving domestic demand and/or improving the reliability of supply. As aresult, the only regional projects considered in the revised expansion plan (apart from theHVDC line to Apollo) are the 275 kV line connecting Zombodze (Swaziland) with Matola,which will increase the southern system's import capacity to 350 MW by 2000, and theproposed interconnection between Orange Grove (Zimbabwe) and Chibata, assuming thatthe works start in 2006 rather than in 2001. Regarding the interconnection between thenorthern and central system, it is assumed that the 220 kV line between Matambo andChibata/Xigadora will come on stream by 2001 (in addition to the temporary 110 kVinterconnection which may happen much sooner).

4.4 Existing thermal generation plant, which in some locations needs to be overhauled,is used as stand-by, unless it supplies isolated areas until they are connected to the grid.The firm hydro capacity available in the northern-central system is estimated at 50 MW for2500 hours a year. The Corumana hydro plant is rated at 12 MW for 2500 hours a year andwould now be operated to shave the peak load of the southern system, if it were operational.Finally, HCB-power can be wheeled to the southern system from early 1997 onwards. HCB

17 See EDM's "Highlights 1994/95," presented in Maputo during a donor conference in June 1995.

16

supplies, however, could be shifted between the three subsystems and EDM's hydrocapacity could be used to lower system costs depending on the type of tariff faced by EDMin the future.

4.5 A comparison of the above supply options with the two demand forecasts reveals(see Table G.1, G.2, G.3, and G.4, Annex G) that EDM would need additional sources ofsupply either in 2002 (medium demand growth) or in 2007 (low demand growth). EDMcould continue importing from Eskom (which would be feasible by extending the currentimport agreement), or from other parties (Southern Africa will by then be entirelyinterconnected), count on the possibility of increasing its share of HCB generation. orexpand its own generation capacity. It is most likely that one of the first three options willbe available (hopefully at a cost below 2 UScents/kWh) and, therefore, the fourth option istoo costly and is dismissed as a concrete possibility in this study. 18

4.6 Another problem that needs to be addressed is that the risk of line outages isrelatively high in the northern-central region. While the planned extensions to Pemba andLichinga will increase this risk, investments in rehabilitating and reinforcing the grid tend toreduce it. A project to rehabilitate and strengthen the Center-North Line is currently beingcarried out and may improve line reliability. While additional insurance against disruptionsin supply could be bought by investing in backup generation plant, the economics of thisoption depend on the probability of transmission failures and the value of lost load.)9

Unfortunately, the likelihood of future line outages is not known; nor do we know whatdifferent consumer groups are, or will be, willing to pay for greater reliability than thatprovided by the grid. A sizable group of consumers with a comparatively high value of lostload, however, is more likely to emerge under the medium-growth scenario than under slowgrowth. As a consequence, the alternative investment program assunes the construction ofa 25 MW gas turbine in Nacala in 2002, for the case of medium growth, but not for slowgrowth.2 0

4.7 In addition, the alternative investment program assumes lower investments intransmission and distribution facilities. In some cases, the EDM cost estimates are reviseddownwards to account for savings that can be achieved by lowering the design standards.In other cases, the planned investments are postponed or stretched over a longer period thanis assumed by EDM (for details, see Annex G). These changes notwithstanding, the revisedprogram considers all proposed/comunitted projects, except those aimed at power exports,

Is In particular, during the planning horizon there is no need for EDM to invest in a hydropower stationat Alto Malema. However, if private investors are reportedly interested in this plant, that would be adifferent matter as the plant would only be dispatched if it were economic to do so. Nor is there anymerit in considering a coal-fired plant near Moatize because its generation costs have been estimated at4-6 US cents per kWh.

19 For instance, if the probability of line outages were equal to 220 hours per year, it would be economicto provide those customers with a backup who are willing to pay a premium of US$ 0.80 per expectedkWh of lost load (see Annex G).

20 Some generation along or at the end of a long line also may be required for system stability.

17

and is consistent with forecast demand. Table 4.1 provides a comparison of EDM'sinvestment program and the altemative used by this study to illustrate the methodology ofthe tariff analysis.

4.8 It should be noted that only one project of the revised program is conditional ondemand, namely the gas turbine proposed for Nacala. For convenience, investments intransmission and distribution were not tailored to the different profiles of forecastdemand, by assuming that the medium-growth scenario is at least as likely as the low-growth scenario. With this assumption, the minimum-regret strategy would be to plan asthough the system will follow a medium-growth path, and adjust the program downwardsif demand happens to increase at a lower rate, or to bring forward investments whendemand grows faster than expected.

LRAIC

4.9 Table 4.2 shows the long-run average incremental costs (LRAIC) implied by theillustrative alternative investment program (for further details, see Appendix G). Note thatthe cost estimates do not account for non-technical losses. As expected. LRAIC variesinversely to the rate at which demand rises. Under the slow-growth-cum-high tariffsscenario, total average incremental costs amount to 9.13 UScents/kWh, which is roughlyconsistent with the tariff assumption underlying projected demand (9.5 UScents/kWh).With medium growth and lower tariffs (7.5 UScents/kWh), total average incremental costs

22are about 5.98 UScents/kWh .

4.10 At the generation end, the unit cost differential proves insignificant. This is becausethe slightly higher costs incurred under the medium growth forecast (Nacala gas turbine) aredistributed over larger volumes of consumption. With about 2.8 UScents/kWh, incrementalgeneration costs are fairly low, reflecting the fact that we expect EDM to have access to lowcost power from Eskom and/or HCB.

21 If private investors were to construct a hydro plant a Alto Malema, this could, possibly, obviate theneed for EDM to install the Nacala gas turbine.

22 The methodological problem in this connection is that we wish to arrive at a tariff that both covers thecosts of future service and is consistent with forecast demand. If, for instance, GDP growth is meagerand predicted tariff levels are high, demand will be relatively low, thus leading to high incrementalcosts. Alternatively, if we assume a somewhat more rapid growth of GDP, which will support morebuoyant power demand, and assume that tariffs are set at a lower level, then the incremental costs godown because projected sales revenues will be spread over a larger volume of demand. Moreover,should the incremental cost estimate significantly differ from the tariff assumptions underlying thedemand forecast, the predictions as well as the investment program need to be adjusted in an iterativeprocess until a reasonably consistent picture is obtained. In effect, tariffs based on LRAIC, whetherhigh or low, are implicit in the projections and are not a policy variable.

18

Table 4.1: Summary Comparison of EDM Investment Programand Illustrative Alternative(in millions of US dollars)

EDM A L TERNA TI V'E96-00 01-05 06-10 Total 96-00 0U-05 06-10 Total

T1 20.0 0.0 0.0 20.0 9.0 5.0 0.0 14.0T3 15.0 0.0 0.0 15.0 6.0 1.0 0.0 7.0T4 0.0 4.0 0.0 4.0 3.0 0.0 0.0 3.0T5 11.4 0.0 0.0 11.4 11.4 0.0 0.0 11.4T6 0.0 3.0 0.0 3.0 0.8 1.3 0.0 2.0T7 10.0 0.0 0.0 10.0 6.5 6.0 0.0 12.5T8 4.0 0.0 0.0 4.0 2.0 2.0 0.0 4.0T9 20.0 0.0 0.0 20.0 0.0 20.0 0.0 20.0TIO 25.0 0.0 0.0 25.0 20.0 0.0 0.0 20.0Tl l 0.0 19.0 0.0 19.0 0.0 20.0 0.0 20.0T12 0.0 4.0 0.0 4.0 0.0 0.0 4.0 4.0T13 0.0 4.0 0.0 4.0 0.0 0.0 4.0 4.0T14 10.0 0.0 0.0 10.0 0.0 0.0 0.0 0.0T15 0.0 6.0 0.0 6.0 0.0 0.0 6.0 6.0T16 0.0 15.0 0.0 15.0 0.0 0.0 7.5 7.5D)1 7.0 0.0 0.0 7.0 7.0 1.0 0.0 8.0D2 8.0 0.0 0.0 8.0 7.0 1.0 0.0 8.0D3 7.0 0.0 0.0 7.0 3.0 1.0 0.0 4.0D4 6.0 0.0 0.0 6.0 5.9 0.3 0.0 6.2D5 7.0 0.0 0.0 7.0 1.0 2.0 0.0 3.0D6 2.0 0.0 0.0 2.0 1.9 0.2 0.0 2.1D7 7.0 0.0 0.0 7.0 7.2 0.0 0.0 7.2D8 3.0 0.0 0.0 3.0 1.0 4.0 0.0 5.0D9 13.7 0.0 0.0 13.7 0.0 6.0 0.0 6.0DIO 9.2 0.0 0.0 9.2 4.5 1.5 0.0 6.0DlI 27.0 0.0 0.0 27.0 8.5 9.5 0.0 18.0D12 8.0 0.0 0.0 8.0 8.3 0.0 0.0 8.3D13 0.0 7.0 0.0 7.0 0.0 7.0 0.0 7.0D14 0.0 5.0 0.0 5.0 0.0 5.0 0.0 5.0DIS 0.0 2.0 0.0 2.0 0.0 2.0 0.0 2.0D16 0.0 4.0 0.0 4.0 0.0 4.0 0.0 4.0D17 0.0 7.0 0.0 7.0 0.0 7.0 0.0 7.0El 1.0 0.0 0.0 1.0 1.0 0.0 0.0 1.0E2 0.6 0.0 0.0 0.6 0.6 0.0 0.0 0.6GI 0.0 0.0 0.0 0.0 3.0 0.0 0.0 3.0G3 0.0 0.0 110.0 110.0 0.0 0.0 0.0 0.0G4 12.0 0.0 0.0 12.0 0.0 16.0 0.0 16.0G5 3.0 0.0 0.0 3.0 1.5 1.5 0.0 3.0Cl 2.0 0.0 0.0 2.0 2.1 0.0 0.0 2.1C2 3.0 0.0 0.0 3.0 1.5 1.5 0.0 3.0C3 3.0 0.0 0.0 3.0 3.0 0.0 0.0 3.0C4 1.0 0.0 0.0 1.0 0.0 0.0 0.0 0.0CS 5.9 0.0 0.0 5.9 4.6 1.3 0.0 5.9

Total 251.8 80.0 110.0 441.8 131.3 127.1 21.5 279.8

Source: EDM and mission estimates.

19

Note: G1 = thermal rehabilitationG3 = Alto Malema Hydro, 80 MWG4 = gas turbine NacalaG5 = Chicamba dam rehabilitationTI = 220 kV, rehab Songo-Nampula, split into Stage I and Stage 2T3 = 1 10 kV, replacement Nampula-NacalaT4 = 1 10 kV, rehab of 2nd line Mavuzi-NhamatandaT5 = 245 kV, Swaziland (Zombodze)-Mozambique (Matola)T6 = reactive power devices BeiraT7 = 1 10 kV + 220 kV, interconnection HCB-EDM (at Chibata)T8 = 110 kV, Alto Molocue-Gurue + substation GurueT9 = 1 10 kV, Nampula-Ancuabe-Montepues-PembaTI 0 = 110 kVM Xai-Xai-InhambaneTI 1 110 kV, Gurue-Cuamba-LichingaT12 = 110 kV. Corunmana-XimavaneT13 = 110 kV, Massingir-ChokweT14 = 220 kV. Mozambique (Matambo)-Malawi (Blantyre)T15 = 110 kV, Caia-Luabo-MarromeuT16 = 220kV to Zimbabwe (Chibata - Orange Grove)Dl = rehab and extension of Nampula distribution systemD2 = rehab and extension of Beira distribution systemD3 = rehab and extension of Quelimane distribution systemD4 = rehab and extension of Nacala distribution systemD5 = rehab and extension of Maputo distribution systemD6 = power supply to BuziD7 = rehab Xai-Xai, Mampula, Nacala substationsD8 = extension Maputo substations SE4, SE5, SE6D9 = primary and secondary distribution Gurue, Cuamba, LichingeD1 0 = rehab electrification Chimoio and ChokweDI I = rehab electrification southD 12 = Maputo substation extensionD 13 = overhaul of Matola distribution systemD14 = overhaul distribution system Xai-Xai and ChokweDl 5 = overhaul of Angoche distribution systemDl 6 = conversion from to diesel to electric pumping in LimpopoD17 = new substation MatolaD 18 = new substation in Tete and MatundoEl = urban household energyE2 = emergency program NacalaC I = rehab control system central regionC2 = remote control center MaputoC3 = Telecommunication Phase IIC4 = Cahora Bassa studyC5 = vehicles, equipment, EDM headquarters building

20

Table 4.2: LRAIC of Power SupplyLow Growth, Medium Growth,High Tariffs Low Tariffs

GenerationA. UScents/kWh 2.795 2.803

TransmissionUS$/kW/year 164.930 82.810

B. UScents/kWh 2.853 1.432A+B 5.648 4.235

DistribulionUS$/kW/year 150.680 75.660

C. UScents/kWh 2.606 1.308A+B+C 8.254 5.543

Total Transmission & DistributionUS$/kW/year 315.610 158.470UScentsAkWh (B+C) 5.459 2.740

Operation & Maintenance(UScents/kWh)

D. Transmission 0.202 0.101E. Distribution 0.307 0.154

A+B+C+D+E 8.763 5.798

F. Miscellaneous (UScents/kWh) 0.367 0.184

Total LRAIC (A+B+C+D+E+F) 9.130 5.982

Note: In prices of 1995.

a. Based on planned investment costs and expenditures for fuel, maintenance, etc. These are economic costsand exclude past (sunk) and purely financial costs. Estimated sales in kWh exclude non-technical losses.

Source: Mission estimates.

4.11 On the other hand, there is a sizable gap between the scenario-dependent averageincremental costs pertaining to transmission and distribution (5.97 vs. 3.0 UScents/kWh,including expenditures on O+M). This indicates how sensitive average costs are todemand. The high level of network-related average incremental costs, particularly in thecase of slow growth, sheds light on the risk of overinvesting in these facilities. This riskwould increase considerably if EDM were to embark on its more ambitious investmentprogram, as opposed to the alternative program considered for illustrative purposes in thisstudy.

5

ALTERNATIVE TARIFF STRUCTURES

5.1 In considering an alternative to EDM's tariff system, based on economic principles.consumers should be given price signals regarding the level and structure of economic coststhey impose on the system. However, it is never possible in practice to set tariffs solelywith reference to economic principles. As a practical matter, tariff making must also takeinto account financial requirements; equity between consumers; transparency; and ease ofimplementation.

5.2 A basic economic principle is that electricity tariffs should be forward-looking, i.e.,based on what it costs to meet future demand. The yardstick referred to in this study(economic costs) is long-run average incremental costs rather than marginal costs. Nojustification is seen for establishing a complex tariff system based on marginal costs, orequivalently, spot pricing with the present pattern of load in Mozambique and withhydropower and imports as the main sources of supply (see Annex H). At generation,average costs are not much different from marginal costs, given that the price structure forimports from the RSA or purchases from HCB is fixed in the medium-term. Additionally,the daily or seasonal changes in load are not significant enough to justify time-of-usepricing. From the point of view of giving consumers appropriate price signals, it should besufficient to focus on standard two-part tariffs, built on average incremental costs,differentiated by voltage-level. The tariffs could be composed of a capacity charge (per kWof coincident peak) and an energy charge (per kWh), differentiated by voltage level.

5.3 Any simple form of peak-load pricing, however, could easily be introduced if thesituation subsequently changed. Given that there is a deep trough at night throughout theyear in the daily load schedule, a change to a specific and off-peak tariff could beimplemented as soon as some users emerge that would consume reasonably large amountsof electricity during those hours. The simple two-part tariff structure is a reasonablyappropriate benchmark for modifications that may be warranted once the new ElectricityLaw, which is currently under preparation, leads to far-reaching sector reforms, such asvertical and horizontal unbundling and competition. EDM could apply the two-part tariff toits general customers and enter into separate agreeements with large customers who wish todo so and qualify for such a treatment. Likewise, if independent power producers operatingunder the new sector legislation were willing to sell electricity to the grid subject to centraldispatch (which may be the responsibility of EDM or any other grid operator), specialcontracts not covered by the general tariff system could be easily designed. In both cases,the utility's standard for negotiations would be its avoided costs at the point of delivery orinjection.

22

5.4 With the important exception of the isolated systems, which were not included inthis study, no convincing case can be made for regional differentiation of tariffs underpresent conditions. Once the northem and central systems are interconnected and HCBpower is wheeled to the southem region via the RSA, the average costs of bulk suppliestend to become fairly uniform across the networks. There will be locational differences intransmission losses, notably along the line through the northem region, but little would begained from designing site-specific transmission charges. The true cost at any given pointalong the line should be known so that if investment in electricity-intensive activity wereconsidered, the decision on location could be made optimally to minimize costs to thesystem. Since about two-thirds of EDM's planned investments are assigned to the northemand central region, this provides a stronger argument in favor of regionally distinct tariffs.Making this point, however, is probably not worth the political quarrel that it could create.The case of isolated centers is more complex and should be analyzed separately as costs ofgeneration could vary widely.

5.5 An illustrative tariff structure based on LRAIC is discussed in Annex H. Table 5.1below compares the voltage-specific capacity charges and energy rates implied by EDM'spresent tariff regime with the estimates of LRAIC obtained under the low-growth andmedium-growth scenarios. The figures show that existing tariffs underestimate capacitycosts and that this bias increases in indirect proportion to the voltage level.23 They alsopoint to the financial inadequacy of present tariffs.

Table 5.1: Alternative Estimates of Capacity and Energy Cost

EDM (Updated)0 LRAIC (low growth) LRAIC (medium growth)

Voltage Capacity Energy Capacity Energy Capacity EnergyLevel (S/kW/month) ($/kWh) (S/kW/month) ($/kWh) (S/kW/month) ($/kWh)

HV 8.33 0.018 22.61 0.0188 15.32 0.0157

MV 7.73 0.020 27.78 0.0194 18.03 0.0162

LV 5.98 0.021 39.14 0.0242 24.08 0.0191

a. Inflation-adjusted estimate used in the tariff study submitted in 1991, as of May 1995. The EDM figures includesunk and financial costs. LRAIC excludes them. This comparison is illustrative only of the differences in tariffstructure.


5.6 Table 5.2 shows how the above two-part tariff based on LRAIC would translate into(notional) voltage-specific average tariffs, using very tentative assumptions about thecomposition of demand and typical load factors by voltage level. Table 5.2 suggests thatthe overall system average tariff would vary by about 3.5 UScents/kWh, depending on the

23 This conclusion continues to hold after the most recent tariff adjustments of October 1995.

23

demand scenario. LV-consumers would pay between I and 2 UScents more (per kWh) thanis charged on average. It should be noted that these tariffs are different from thosecalculated in the recent financial restructuring study of EDM because LRAIC does not takeinto account past or "sunk" costs and the underlying investment programn is more modestand slower than EDM's program presented in 1995. Taking account of these financial costswould require charging 2 - 2.5 UScentslkWh over and above the average structuralestimates of LRAIC, under the medium-growth scenario.

Table 5.2: Notional Average Costs by Voltage Level and Scenario(in US cents per kWh)

LEFa Low Growth Medium Growth

Generation/Pointof Injection 0.66 3.15 2.94

HV 0.65 6.65 4.79

MV 0.58 8.50 5.88

LV 0.54 12.35 8.02

System Average'b 10.43 6.95

Note: This table differs from Table 4.2 because miscellaneous investment costs have been lumped withgeneration costs.

a. Assumed average load factor.b. Demand is assumed to be composed of 8 percent HV, 38 percent MV, and 54 percent LV.


5.7 At the LV-level, it is not unusual in practical tariff setting to distinguish betweenresidential and non-residential consumers; and to provide a subsidized schedule for low-income residential users. The subsidy could be granted through a discount on the capacityfee, while charging a uniform rate for energy. The subsidy to small residential users couldbe financed through a slightly higher energy charge for all other LV users. Part of the low-voltage capacity costs could be rolled over onto the energy rate, to make the low voltagetariffs recognize further the social objectives, and thus to offer an additional subsidy to usersconsuming less than the average (see the example shown in Table 5.3).

5.8 Prior to these refinements, the level of tariffs needs to be fixed, which means takinga position on the likely growth of electricity consumption and on EDM's financialobjectives. The point that can be made in favor of the low-growth-scenario is that predictedgross consumption is close to EDM's most recent demand forecast; furthermore, both thetariff assumptions underlying this scenario and the revenue requirements it generates are inline with EDM's financial targets. We return to this point later. Altenatively, Table 5.3

24

shows an illustrative tariff structure that would be compatible with the medium-growthscenario.

Table 5.3: Illustrative Tariff Structure Based on LRAIC(Medium-Growth Scenario)

Fixed Charge Energy Charge(US$/kW/month) (UScents/kWh)

HV 15.30 1.57

MV 18.00 1.62

LVResidential 7.50 6.25Non-Residential 14.00 4.40

Social Tariff' 1.50 6.25

a. Applies to small-volume residential users with a maximum demand not exceeding I kW.

5.9 In Table 5.3, HV- and MV-rates have been set in accordance with LRAIC. but ratesat the LV-level have been adjusted in the following ways (see paragraph 5.7):

* there is a two-part schedule for residential users, which subsumes almost 70percent of the capacity costs under the energy charge;

. there is again a two-part schedule for non-residential users, but this timesubsuming about 42 percent of the capacity costs under the energy rate;

. a social tariff is introduced for small-volume residential users, i.e. with amaximum demand of I kW or less, subject to the installation of a load limiter(or an inexpensive meter, e.g. Chinese mechanical meters).

Recovering part of the capacity costs through energy charges departs from a basic principleof tariffs reflecting economic costs, because consumers using more than the average cross-subsidize those using less. However, such cross-subsidies would allow EDM to offer itsless affluent customers rates which might be regarded as more affordable. Nevertheless,cross-subsidies should be phased out as the standard of living rises.

5.10 For comparison, in May 1995 average tariffs were 6.35 UScents/kWh for "tarifasocial" customers, varied between 6.98 and 9.78 UScents/kWh for LV-users (from 1.1 to19.8 kVA), were 8.50 UScents/kWh for short-utilization MV-customers, were 4.68UScents/kWh for long-utilization MV-customers, and were 4.12 UScents/kWh for longutilization HV-customers.24 The tariff changes in Table 5.3 would make most customersneither better nor worse off, compared to what they paid in mid-1 995.

24 Figures apply to the southern system at 8000 MTIUS$. It also should be kept in mind that the tariffaverages include what customers were charged for rated capacity, which was more than twice as much

25

5.11 The implementation of any alternative to EDM's existing tariff system, includingthe illustrative structure in Table 5.3, would have to go hand in hand with improvements inEDM's billing and revenue collection performance. This would not only help cutnontechnical losses, but contribute to a fairer (more accurate) and more transparentapportioning of capacity costs across EDM's customers. EDM should be supported in itsefforts to catch up with inflation and currency depreciation, which has been eroding itsrevenues, notwithstanding its theoretical entitlement to compensating tariff adjustments.

5.12 Table 5.4 shows shows how the methodology developed in this study can also beapplied to cost estimates contained in EDM's financial projections for the period 1996-2000(for details, see Annex H). The computations are based on EDM's sales forecast, which isclose to the low-growth scenario presented in this study. It is assumed that depreciationcharges are proportional to the book value of existing assets; technical losses amount to11.4 percent of gross supply; the system load factor is 0.66; the cost of capital (includingprofits) is 10 percent a year; and EDM earns a 3.6 percent rate of return over the entireperiod under consideration. The latter assumption differs from EDM's projection(according to which the 3.6 percent rate of return will not be achieved before 1988) and isin large part responsible for the slightly lower average tariff of 9.3 UScents/kWh shownin Table 5.4 (compared with 9.5 UScents/kWh that EDM seeks to achieve by 1998).

Table 5.4: Illustrative Structure of Tariffs Based on EDM's Financial ProjectionsCapacity Energy Average Costs

(S/kW/month) (Uscents/kWh) LF UScents/kWhGeneration 7.500 3.96 0.66 5.585Transmission 5.500 0.22Losses (5%) 0.684 0.22Total HV 13.684 4.40 0.65 7.284

Primary Dist. 1.722 0.12Losses (2%) 0.314 0.092Total MV 15.720 4.612 0.58 8.325

Secondary Dist. 3.444 0.230Losses (4.4%) 0.882 0.223Total LV 20.046 5.065 0.54 10.150

System Average 9.227


as what they would have had to pay if their contribution to the system peak had been measuredaccurately.

26

5.13 The methodological difference between the example based on EDM's financialprojections (Table 5.4) and the figures presented in this study (Table 5.2) is that the latterare future-oriented, while the financial estimates reflect historic (revalued) costs. Thenumerical differences between the tariffs based on the medium-growth scenario and thetariffs shown in Table 5.4 can be explained mainly by the fact that in EDM's financialaccounts, the absolute and relative level of generation costs is higher than in the plannedfuture investments. The high absolute level of generation costs reflects large recentinvestments in generation plants (e.g. Maputo gas turbine, Corumana hydropower plant,etc.), which more than offset the assumed savings from low-cost HCB power.25 Therelative difference can be attributed to the fact that, in the investment program advancedin this study, there are almost no future investments in generation, while there are manyfuture investments to reinforce and expand the network (hence, higher T+D charges in theestimates associated with the medium growth scenario than in the example reflectingEDM's financial projections).

5.14 The voltage-specific average rates depicted in Table 5.4 come close to whatconsumers would have to pay if the tariff regime were based on the notional average costsassociated with the low-growth scenario (see Table 5.2) and if they are adjusteddownwards to yield an average tariff level (systemwide) of 9.5 USscents/kWh. Thisregime is shown in Table 5.5. Its structure, however, differs from that implied by EDM'sfinancial projections for reasons explained above.

Table 5.5: Tariff Regime Based on Adjusted Average Costsof Low-Growth ScenarioFixed Charge Energy Charge Average

(US$/kW/month) (UScents/kWh) (UScents/kWh)HV 19.20 1.95 6.00MV 23.70 2.14 7.74LV 33.85 2.66 11.25

LV.Residential 10.50 8.55Nonresidential 19.50 6.30Social 2.00 8.55

System Average 9.50

5.15 EDM has committed itself to a financial restructuring program, agreed upon bythe Ministry of Finance and the Ministry of Energy and Mineral Resources, which has asa target for 1998 an average tariff of 9.5 UScents/kWh. Hence, the illustrative tariff

25 EDM assumes that HCB power wheeled to the southern system will cost about 2.5 UScents/kWh.

27

structure in Table 5.3 would be incompatible with EDM'S business plan. Nevertheless, itwould be feasible to change the existing rate structure, in order to move it toward a tariffregime which better reflects the underlying structure of EDM's economic costs, whileraising the average tariff to 9.5 UScents/kWh. The tariff system in Table 5.5 would beone way to do so. Alternatively, the tariff system could be based on the structure in Table5.4. All these tariff structures and levels would satisfy EDM's need for financialresources to reach its cost-covering and profitability targets.

5.16 Finally, it should be stressed that the main concerm of this study is to demonstratethe methodology of computing long-run incremental costs and to illustrate how theresulting cost estimate can be converted into a tariff system. Also, EDM has beenprovided with the software needed to do these computations. In fact, EDM should re-estimate its system's long run incremental costs and check the consistency of the tariffsystem on a regular basis or as a built-in routine of system planning. At a minimum,updates are required whenever key parameters change. A case in point is EDM'sinvestment program. While this study refers to a streamlined version of EDM's programas of mid-1995, EDM itself has since made further downward adjustments in its businessplan and accepted the need for a cap on total annual investments (US$20 million). As aconsequence, long-run incremental costs need to be re-calculated on the basis of EDM'smost recent expansion and business plan. Likewise, during the last 12 months, EDM hasgathered additional infornation on sales and load growth. These data can be used toupdate and refine the demand forecast.

ANNEXES

31

Annex APage I of 8

KEY DATA

Table A.1: Gross Electricity Consumption (MWh), 1985-95Gross Cons. Gross Cons. Svstem

Year Generalion Imports Acquisition Gross Cons. South Central & North Peak

1985 264,400 229,000 51,900 545,300 - - 118

1986 216,300 304,700 38,100 559.100 - - -

1987 268,800 330,200 25,700 624,700 - - -

1988 263,100 340,700 40,500 644.300 452.500 191,800 -

1989 342.200 307,100 92,500 741.800 457,000 284.800 -

1990 322,200 321,800 94,200 738,200 455,100 283,100 144

1991 325,700 373,300 98,700 797.700 501,900 295.800 -

1992 273.800 436.200 95,000 805,000 505,600 299.600 150

1993 223,600 510,900 118,100 852,600 538.200 314,400 -

1994 200,000 559,000 140.000 899,000 574,584 324.416 -

1995a 170.936 607.291 169.657 947,874 615.291 332,593 11

- Not Available.

a. EDM forecast.b. Estimate based on furst quarter.

Source. EDM.

Table A.2: Billed Electricity By Tariff Category (MWh), 1988-94

Year General Residential Medium + High Voltage Total

1988 78,900 180,800 264,100 526,000

1989 90,100 203,000 284,500 591,100

1990 93,100 224,400 276,900 595,300

1991 126,000 257,700 311,000 694,700

1992 133,230 252,222 291,738 678,702

1993 133,207 285,439 265,626 692,617

1994 151,713 317,766 258,125 727,604

Source: EDM

32

Annex APage 2 of 8

Table A.3.a: Monthly Gross Electricity Consumption (MWh), 1989-95/989 1990 199/ 1992 1993 1994 1995

January 59122 54104 6467 62440 68618 73698 79200February 52264 55100 63283 70438 60937 71369 73157March 63446 62179 68593 69871 71431 78659 82636April 59757 50127 70606 66752 70295 72397May 63112 66035 74116 66042 72927 74889June 61719 62919 58104 67942 68692 71501July 66153 67132 76955 65156 72013 73359August 57700 67682 58627 66814 71239 76237September 61040 64294 65274 62975 71048 74910October 58995 68231 67624 67284 75009 75980November 58739 62004 64887 63544 74143 76270December 61357 57807 65622 67651 76227 78938

Source: EDM

Table A.3.b: Monthly Gross Electricity Consumption (MWh),Moving 12 Month Average, January 1990 - March 1995

1990 1991 1992 1993 1994 1995January 60283.7 61467.8 66530.2 66409.1 71048.2 74850.6February 59865.5 62348.4 66344.3 66923.9 71471.6 75309.1March 60101.8 63030.3 66940.5 66132.2 72340.9 75458.1April 59996.2 63564.8 67047.0 66262.2 72943.3May 59193.8 65271.4 66725.8 66557.4 73118.4June 59437.3 65944.8 66053.0 67131.2 73281.9July 59537.3 65543.6 66872.8 67193.7 73516.0August 59618.9 66362.2 65889.6 67765.1 73628.2September 60450.7 65607.6 66571.8 68133.8 74044.7October 60721.9 65689.2 66380.3 68806.6 74366.5November 61491.6 65638.7 66351.9 69450.3 74447.4December 61763.7 65878.9 66240.0 70333.6 74624.7

33

Annex APage 3 of 8

Table A.4: Annual Peak by Operational Area(MW)

,4rea 1985 1990 1992 1993 1994

Pemba 1.3 1.9 1.9 2.6

Lichinga 0.8 1.2 0.9 1.0

Cuamba - 0.4 0.4 0.5

Nacala 2.6 6.0 4.6 4.9

Nampula 4.2 5.5 6.0 6.3

Angoche 0.6 0.6 0.7 0.7

Gurue 0.1 - - -

Mocuba 0.6 0.7 0.6 0.8

Quelimane 2.9 3.5 - 4.4

Tete 4.1 4.7 4.3 3.0

Chimoio 15.6 17.0 17.8 18.0

Beira 12.6 14.9 15.4 15.6

Inhambane 0.9 1.3 1.3 1.4

Lionde 1.9 3.2 3.5 4.9

Xai-Xai 1.7 2.2 2.4 2.9

Maputo 66.2 86.0 92.0 90.5

- Not available.

Source: EDM.

34

Annex APage 4 of 8

Table A.5: EDM Sales Forecast 1995% of Gross

System (MWh) SupplyTherrnal Generation 40,135 n.a.

- Station Use 1.876 n.a.= Therm.Energy Sent Out 38,259 4.0

+ Imports 607,291 64.2+ Acquisitions 130,801 13.8+ Hydro 169,657 17.9Gross Supply 945,998 100.0

- Transmission Losses 78,197 8.3- Distribution Losses 48,046 5.1- Internal Consumption 4,952 0.5

Net Supply 814,803 86.1

- Non-technical Losses 149,187 15.8- Public Lighting 13,792 1.5= Sales 651,824 68.9

n.a. Not applicable.

Source: EDM.

35

Annex APage 5 of 8

Table A.6: Electricity Sales First Quarter 1995, (MWh)South Central North System

Therrn.Generation 2,057 620 5,907 8,584-Station Use 51 361 569 981= Thermal Energy 2.006 259 5,338 7.603

Sent Out+ Imports 150,399 150,393+ Acquisitions 35,037 35,037+ Hydro 42,161 42.161= Gross Supply 152,399 42,420 40,375 235,194

- Transm. Losses 5.724 2,758 7,719 16,201- Distrib.Losses 7,335 2,658 3,648 13.641- Intern.Consum. 846 321 504 1,671-Net Supply 138,494 36,683 28,504 203,681

- Non-techn.Losses 32,891 5,750 2,457 41.098* Public Lighting 1,890 626 756 3.272-Sales 103,713 30.307 25,291 159,311

Source: EDM.

Table A.7: EDM Sales Forecast By Consumer Group (MWh), 1995Year % Actual Ist %

Quarter

Domestic 243,034 37.3 61,360 38.4Geral 85,813 13.2 23,347 14.6Low Voltage 38,345 5.9 10,318 6.5

Short 922 0.1 139 0.1Medium 35,200 5.4 9,410 5.9Long 2,223 0.3 769 0.5

Medium Voltage 264,559 40.6 62,485 39.1Short 9,209 1.4 1,274 0.8Medium 118,051 18.1 30,333 19.0Long 137,299 21.1 30,878 19.3

High Voltage 20,089 3.1 2,272 1.4ShortMediumLong 20,089 3.1 2,272 1.4

Total 651,840 100.0 159,782 100.0

Neglibible.

Source: EDM.

36

Annex APage 6 of 8

Table A.8: Index of Real GDP and Electricity Tariffs, 1988-94Year GDP CPI A T RA T1988 77.89 11.00 23.75 215.901989 81.59 15.95 36.55 229.101990 83.11 22.33 63.90 286.101991 84.91 29.81 90.05 302.001992 81.31 43.12 177.20 410.901993 94.88 61.50 235.30 382.601994 100.00 100.00 347.00 347.00

Note: GDP = index of real GDP (1994=100); CPI = consumer price index(1994=100); AT = average tariff revenues (MT/kWh); RAT = inflation-adjusted average tariff revenues.

Source: EDM and Departamento Nacional de Estatistica.

Table A.9: Quarterly Data on Gross Electricity Consumption and Tariff Revenues(1/1992-1/1995)

Quarter GC IIO CPI AT RAT1/92 202749 100.0 100.0 132 132.02/92 200736 106.8 112.1 140 124.93/92 194945 113.3 111.4 145 130.24/92 198479 106.8 126.2 209 165.61/93 200986 81.0 145.0 216 149.02/93 211914 78.5 154.3 199 129.03/93 214300 88.3 160.7 233 145.04/93 225379 88.2 179.8 261 145.21/94 223726 57.8 224.2 315 140.52/94 218787 64.5 243.7 320 131.33/94 224506 89.6 272.4 355 130.34/94 231183 84.3 303.7 351 115.61/95 234993 46.2 344.5 460 133.5

Note: GC = gross electricity consumption (MWh)110 = index of industrial outputCPI = consumer price indexAT = average tariff revenues (MT/kWh)RAT = real average tariff revenues

Source: EDM and Departamento Nacional de Estatistica.

37

Annex APage 7 of 8

Table A.10: Key Data on Consumer GroupsNumber of Connections Specific Consumption'

Medium andYear General Residential High Voltage General Residential

1990 17,560 97,620 822 5,131 2,079

1990 17,997 100,028 882 5,183 2,223

1991 19,615 107,206 882 6,574 2.404

1992 19,656 111,891 865 6,676 2,254

1993 20,509 115,070 746 6,495 2,481

1994 20,464 118,957 934 7,413 2,671

Note: Classified by tariff.

a. kWh per connection.

Source: EDM.

38

Annex APage8 of8

Table A.11: Available Generating CapacityInstalled Cap. Available Cap.

Station Type (MW) (MW) RetirementNorthPemba Diesel 6.4 5.5 > 2010Lichinga Diesel 1.3 0.6 2010Nacala Diesel 21.5 3.7 > 2010Quelimane Diesel 7.1 6.0 > 2010Nampula Diesel 6.4 1.4a > 2010Mocuba Diesel 0.8 0.7 2005Angoche Diesel 1.6 1.0 > 2010Lichinga Hydro 0.7 0.6 > 2010Cuamba Hydro 1.1 1.0 > 2010

CentralMavuzi Hydro 52.0 36.0 > 2010Chicamba Hydro 38.4 34.0b > 2010Beira Gas (Jet) 12.0 12.0 > 2010

SouthInhambane Diesel 3.9 1.6 1.15MW by 1998,

0.45MW > 2010

Lionde Diesel 4.0 2.7 2000Xai-Xai Diesel 2.7 1.7 1998Maputo Coal 57.5 20.0 2000

Gas 78.5 64.0 41MW by 2005,23MW > 2010

Corumana Hydro 14.5 14.0c > 2010

a. Upon completion of rehabilitation works, about 5.5 MW will be available by 1998.b. When Chicamba and Mavuzi are run simultaneously, the joint firm capacity is assumed to be 50 MW at

3400 hours a year (170 Gwh/year).c. The firm capacity is assumed to be 12 MW at 2500 hours a year (30 GWh/year).


39

Annex BPage I of 7

EDM's TARIFF SYSTEM

1. The structure of the current tariff system. which was introduced in January 1992,appears to be complex.26 Tariffs are uniform across the country, but differ by voltage level(kV), maximum demand (kVA or the kW-equivalent), and customer class. At each voltagelevel, customers with a contracted capacity of more than 19.8 kVA are offered threeoptional two-part tariffs. Medium- and high-voltage users are entitled to choose betweenbilling periods lasting from 7 a.m. to 9 p.m. (system peak) and from 9 p.m. to 7 a.m. (offpeak). There is a special low-tension schedule composed of increasing block charges forcontracted capacity up to 19.8 kVA, with a uniform energy rate for residential and non-residential users. Small-volume consumers (! 30 kWh/month) are offered a social tariff("tarifa social") with a 75 percent discount on the capacity charge.

2. As per the new law enacted in 1991, EDM is permitted to adjust the level of averagetariffs for inflation (CPI) and exchange rate depreciation (ED). Indexation of nominaltariffs (T) is defined on a monthly basis by the following formula:

AT =03ACPI + 7AEDT CPI ED

3. In practice, however, EDM's leeway to raise tariffs has been limited by the need toseek political approval. During the last three years, nominal tariffs were regularly frozenbetween four to six months before EDM was allowed to catch up with inflation. As aconsequence, changes in real tariffs showed a marked cyclical pattern with no drift. That is,by early 1995 inflation-adjusted tariffs were at the same level that had prevailed in early1992 (see Table A.9, Annex A).27

Voltage levels are defined as:Low Voltage (LV): LV S 1 kV;Medium Voltage (MV): I kV < MV < 45 kV;High Voltage (HV): HV > 45 kV.

26 Decreto do Conselho de Ministros No. 32/91. The structure of the tariff system is based on a studyprepared in 1991. At the outset, the nominal rates charged by EDM were exactly those proposed bythe study.

27 The nominal tariffs referred to in this section were valid until July 1995. The latest increase, whichwas on August 1, 1995, is not reflected in the numerical examples presented below.

40

Annex BPage 2 of 7

4. Low voltage users with a maximum demand up to 39.6 kVA are charged forcontracted capacity. Customers with a maximum load in excess of 39.6 kVA are subject toa monthly capacity charge. The capacity (in kW) billed is determined as K = CC - 0.8[CC-ML], where CC denotes the contracted capacity and ML is the recorded maximum loadwith a duration of at least 15 minutes.

5. As is shown in Table B. 1, low-, medium-, and high-voltage consumers are given theoption to choose among different two-part tariffs. The idea underlying the schedule is thatconsumers supplied at a given voltage level differ in terms of demand (i.e., in terms of therate at which contracted capacity is utilized). Its effect is that consumers have an incentiveto opt for a longer-utilization tariff if their load factor is such that the gains from a lowerenergy charge more than offset the higher costs of capacity (compared to a shorter-utilization tariff, and vice versa).28 In other words, consumers are offered the opportunity toself-select a two-part tariff that minimizes costs relative to their expected load profile.Another feature of the scheme is that for a given customer class (defined in terms ofcontracted capacity utilization) the rates for energy increase as the voltage level decreases.Capacity charges, however, are insensitive to the voltage level. That is, higher downstreamcosts (network losses, etc.) are reflected by energy charges only.

6. The rationale for properly designed self-selecting two-part tariffs is that withdifferent consumer classes the resulting choices tend to increase welfare, at least as long asthe tariff system on the whole involves deadweight losses.29 EDM's two-part tariffs,however, aggravate rather than reduce distortions. This is because the capacity fees arefixed at essentially arbitrary levels, while the rates for energy are adjusted so as to recovernotional total costs. Consumer class-specific total costs are inferred from system averagecapacity and energy costs, subject to a predetermiined utilization rate.30

28 As a result, consumers with a higher load factor will enjoy a lower average tariff (provided they selectthe appropriate tariff option).

29 Note that deadweight losses occur if prices depart from marginal costs.

30 To illustrate the point, consider the two-part tariff that applies to short-utilization-high-voltageconsumers: EDM's capacity and energy costs are estimated 66,631 MT/kW and 142 MT/kWh, whichis an update of the 1991 tariff study. (19,770 MT/kW and 42.2 MT/kWh). Under the assumption thatthe monthly utilization rate is 150 hours, total costs amount to 87,931 MT (= 66,631 + 150*142).Setting the capacity charge at 30,331 MT/kW (9,000 MT/kW according to the 1991tariff study)implies that the energy charge should be set at 384 MT/kWh in order to recover total costs (30,331 +150*384 = 87,931).

41

Annex BPage 3 of 7

Table B.1: Optional Tariffs by Voltage Level

Short Utilization Medium Utilization Long Utilization

High VoltageMT/kW/month 30,331 36,941 43,700MT/kWh 384 259 199Optimal utilization regiona

(hours/month) X < 52.88 52.88 < X < 112.65 X > 112.65Design utilization rateb

(hours/month) 150 250 400

Medium Voltage 30,331 36,941MT/kW/month 43,700MT/kWh 408 279 206Optimal utilization regiona X •51.24 51.24<X<92.59 X>92.59

(hours/month)Design utilization rateb


Low VoltagecMT/kW/month 30,331 36,941 43,700MT/kWh 429 299 224Optimal utilization region'

(hours/month) X < 50.85 50.85 < X < 90.12 X 2 90.12Design utilization rateb


Note: As of May 1, 1995.

a. The optimal utilization region is implied by the rate structure and, thus, changes when nominal tariffadjustments alter the rate structure. In the past, though, these changes were marginal.

b. Assumed utilization rate when the tariff system was designed.c. With a contracted capacity of more than 19.8 kVA.


7. The outcome of the ad hoc assumptions underlying EDM's tariff system is thatcompared with estimated average costs (see Table B.2) customers are overcharged forenergy and undercharged for capacity.31 As a consequence, at each voltage level customerswould pay less than estimated average costs if their actual utilization rate (load factor) fell

3' Strictly speaking, the latter statement only holds true if the customers' rated capacity by and largereflects their contribution to the system peak. which is not the case. As will be discussed below, thecapacity charged for systemwide significantly exceeds the system peak. In what follows, though, it isassumed that the capacity charge would be levied per kW of coincident peak.

42

Annex BPage 4 of 7

short of the maximum design utilization rate.32 To put this impact into perspective, considerthe forecast sales for 1995 (see Table A.7, Annex A) and let us assume that the updatedaverage cost estimates of the 1991 study are correct and that the consumers' choice of tariffswill be optimal relative to their utilization rates. Under the latter assumption, forecast short-and medium-utilization demand should be far below the maximum tariff design level. Inaddition, some of the high-voltage-long-utilization consumption may not reach this level.33Therefore, at least 94.2 percent of the low voltage supply (>19.8 kVA) and 48.1 percent ofthe medium voltage supply would be billed below average cost, and it also is possible thatsome of the long-utilization customers would pay less than is required to cover the cost ofsupplying them with electricity. It is even conceivable that the net revenues from customerswhose utilization rate exceeds the maximum design level, would not cover the lossesgenerated by the shorter-utilization customers.

Table B.2: Notional Average Costs of Electricity Supply, May 1995

Capacity (MT/kW/month) Energy (MT/kWh)

High Voltage 66,631 142

Medium Voltage 61,831 156

Low Voltage (>19.8 kVA) 47,851 168

Low Voltage (<19.8 kVA) 33,644 168

Note: Updated 1991 estimates, not to be confused with actual average costs.


8. It also should be noted that the utilization rates at which customers have anincentive to switch to a longer-utilization tariff correspond to very low load factors,particularly in the case of the short-utilization tariff. So it does not come as a surprise thatthere are no short- and medium-utilization customers at the high voltage level, and that

32 For instance, the two-part tariff charged to high voltage customers does not recoup estimated averagecosts if the actual utilization rate is less than 400 hours a month.

33 Note that all high-voltage consumption is of the long-utilization type. Nonetheless, some of the high-voltage users who consume more than the minimum amount justifying the choice of the long-utilization tariff ( 12.7 hours) may have a utilization rate that falls short of the maximum tariff designlevel (400 hours). Of course, the same argument applies to low- and medium-voltage customersfalling into the long-utilization category.

43

Annex BPage 5 of 7

short-utilization consumnption at the low- and medium-voltage level accounts for only 3percent of total demand affected by optional tariffs.

9. Small low-voltage consumers (•19.8 kVA) are faced with two energy rates. As ofMay 1995, households pay 337 MT/kWh (tarifa domestica), while non-residentialcustomers are charged 541 MT/kWh (tarifa geral). These rates are determined in the sameway as the optional tariffs offered to larger users. In the case of residential users, theestimated capacity costs amount to 33,644 MT/kW, while energy costs are 168 MT/kWh.34

Based on a standard utilization rate of 100 hours, the monthly capacity chargecorresponding to 337 MT/kWh is about 16,744 MT/kW or MT 13,395/kVA.

10. According to the tariff study of 1991, the capacity payments of small low-voltageconsumers should be linear in the amount of contracted capacity. Customers who consume30 kWh/month or less, however, should be eligible for a 75 percent discount on the capacitycharge rated at 1. I kVA. The study also recommended the installation of load limiters sothat contracted capacity becomes a binding constraint. EDM implemented the proposedsocial capacity fee, yet decided to introduce discriminatory capacity charges for low-voltageconsumers subsumed under the "domestic" and "general" tariff. Moreover, since loadlimiters have not been installed to date, EDM estimates maximum demand by using theconsumption level as a proxy.

11. As is shown in Table B.3, the unit capacity charge rises under the domestic andgeneral tariff from 13,395 MT/kVA for a rated capacity of 1.1 kVA (corresponding to aconsumption level of 165 kWh/month) to 28,147 MT/kVA for a maximum load of 19.8kVA (or 2,970 kWh/month). Clearly, this kind of nonlinearity is hard to justify on the basisof costs. In fact, there is no reason why unit capacity costs should increase with the level ofload served. So the discriminatory capacity fees seem to be a means of generatingadditional revenues.3 5 Even in this context, though, block rates would only make sense ifthe price elasticity of demand for an additional (block of) kWh declines as consumptionincreases, which is unlikely. (By the same token, quantity discounts would be warranted ifthe price elasticity rises with the level of consumption). Increasing block rates are anunnecessary complication. To avoid losses, EDM could simply base the rates for capacityand energy on estimated average costs.

34 These are updates of the 1991 estimates.35 Note that if EDM had followed the 1991 proposal of charging a uniform capacity fee (13,395

MT/kVA/month), the revenues generated by customers with a monthly utilization rate of less than 100hours would not cover the estimated costs of serving these customers. So the increasing block ratesmay have been designed to make up for these losses.

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Annex BPage 6 of 7

Table B.3: Low Voltage Capacity PaymentsImplied % Share of

Monthlv Flat Rate for Capacitv ConsumersAlax Load Consumption Capacity Charge affected by

(k VA) (kWh) (MT/month) ('MT/k- A) the schemeTarifa Social 1.1 0 - 30 3,737 3,397 3.1

TarifaGeral and 1.1 31 - 165 14,735 13,395 44.3Tarifa Domestica 2.2 166 - 330 29,612 13,460 28.6

3.3 331 - 495 56,206 17,032 13.16.6 496 - 990 127,219 19,276 7.99.9 991 - 1,485 212,606 21,475 1.7

13.2 1,486 - 1,980 312,800 23,697 0.616.5 1,981 - 2,475 427,369 25,901 0.219.8 2,476 - 2,970 557,319 28,147 0.5

Note: As of May 1, 1995. The rates for energy are 337 MT/kWh (domestic and social tariff) and 541MT/kWh (general tariff).

Source: EDM.

12. Another point worth noting is that while capacity charges should be levied per kWof coincident peak, in practice it may be difficult (and costly) to exactly measure eachcustomer's contribution to the system peak, especially in the case of small users. As aresult, the rated capacity charged for will often be based on a rough estimate of thecustomers' peak responsibility. This would pose no serious problems if the margins oferror were reasonable. EDM, however, tends to overrate its customers' contribution to thesystem peak in a systematic and highly biased manner. Sales statistics for the southernregion as of May 1995 show that the total capacity charged for adds up to 252 MW, whilethe southern peak was only 1 10 MW. All customers are affected, but the bias is strongest atthe LV-level and lowest for long-utilization-MV-customers and HV-users. Clearly,overestimating the rate base for capacity charges makes up for some of the revenues EDMforgoes by keeping the charge per-kW of coincident peak too low (compared to the costs ofproviding the capacity). A more equitable and transparent way of recovering EDM'scapacity costs would be to increase the capacity charges, while adjusting the customers' ratebase downwards, so that the payments for capacity more closely reflect the peakresponsibilities. Better estimates of the individual load profiles can be obtained throughcustomer surveys that improve the data base underlying the categorization of small users, orthrough more accurate metering in the case of large users.

13. In sum, EDM's tariff regime has serious flaws. The structure of (system) costs usedas a reference for computing tariffs at different voltage levels has a downward bias withrespect to capacity and an upward bias with respect to energy. These built-in distortions areaggravated by the fact that EDM is offering optional two-part tariffs that provideeconomically meaningless choices. The main effect of this schedule is that it complicates

45

Annex BPage 7 of 7

tariff selection and billing. Moreover, it establishes voltage-dependent threshold utilizationrates (consumption levels) at which average tariff revenues match estimated average costs,such that consumers with a shorter (longer) utilization rate pay less (more) than it costs toserve them. Another distortionary feature of the current tariff system is that small low-voltage consumers are subjected to discriminatory capacity charges that have no economicjustification. It also should be mentioned that the cost estimates used to design the systemare questionable. Finally, the rated capacity customers are charged for significantly exceedsthe customers' contribution to the system peak. While this bias, which is a measurementand metering problem rather than a problem of tariff design, helps increase EDM'srevenues beyond the level that would result if current capacity charges were applied to amore accurately estimated rate base, it also implies an additional distortion at the expense ofefficiency and equity.

46

Annex CPage I of 5

MINIMIZING THE COSTS OF ELECTRICITY IMPORTS FROM ESKOM

1. According to the most recent power supply agreement between Eskom and EDMsigned in March 1995, electricity imports from South Africa (which are used to supply thesouthern system) are subject to the following rates:36

Contracted Capacity: 8.44 US$/kW/monthFirm Energy: 0.5078 UScents/kWhEmergency Energy: 3.2439 UScents/kWh (3.194 UScents/kWh until April 1995)

2. The above rates are valid until December 31, 1995. On January I of each new yearthe charges are automatically adjusted in direct proportion to the annual rate of change inthe US producer price index recorded during the previous year. The agreement will be inforce until July 31, 2000, or three years after the resumption of supply from Cahora Bassato Eskom, whichever is earlier.

3. EDM's capacity requests (expected maximum demand) must be forwarded on amonthly basis not later than three working days before expiry of the previous contract.Contracts have a minimum duration of one calendar month. Capacity payments depend oncontracted maximum demand rather than on the actual load profile. Instantaneous (hourly)load below or equal to the contracted capacity level is served at the firm energy rate. Theemergency energy rate applies to (hourly) loads served in excess of the contractedcapacity.'

36 In addition, EDM has the option to choose the tariff schedule delineated in the former agreement ofMay 1984 (amended on May 7, 1993). Since the beginning of this year, however, EDM has opted forthe terms of the new agreement.

37 Whenever the 275 kV line from Komatipoort to Maputo is out of service, EDM is entitled to a rebateamounting to the hourly equivalent of the monthly payments for contracted capacity times the numberof hours the line is not operated. For instance, if the contracted monthly capacity is 85,000 kW at 8.44US$/kW and the line does not operate for 4 hours, the rebate is about US$ 3,985 (=8.44*85,000*4/720). On the other hand, if the 110 kV line from Komatipoort is used in lieu of the 275kV line, the capacity payment is equal to the maximum load served during the operation of the 110 kVline, times the number of hours of the disruption, times the hourly equivalent of the monthly capacitycharge. Thus, in the event that power has to be wheeled through the 110 kV line and the actual peakload falls short of the contracted maximum demand, EDM pays less than under normal conditions ofsupply.

47

Annex CPage 2 of 5

4. Clearly, at the margin, electricity from South Africa is less expensive than thermalpower generated with EDM plant.38 Therefore, it would not be economic to substitutethermal power for emergency energy from Eskom. On the other hand, it can be assumedthat the marginal costs of hydro power from Corumana are below the rates Eskom chargesfor firm and emergency energy. As a consequence, EDM's strategy should be to operatethe Corumana hydro plant and serve all the load not covered by hydro power withimports.3 9 The following analysis assumes that the loads (including maximum demand)served by imports are adjusted for the share of indigenous hydro power.

5. Under the new tariff agreement, EDM has an incentive to contract less capacity thanwould be needed to meet expected maximum demand. The optimal amount of capacitycontracted from Eskom is reached when the expected savings from an additional kW ofsubscribed capacity (i.e., the extra costs of emergency energy that EDM needs to importwhen the actual load exceeds contracted maximum demand) would be just offset by thecapacity charge.

6. The above condition can be easily derived by using the following notation:

D == capacity charge ($/kW/month),cl = firm energy rate (cents/kWh),C2 = emergency energy rate (cents/kWh),F(g) = normalized load duration function,g(F) = inverse normalized load duration function, i.e. g=F-1,H = duration of month (hours),F = predicted load (MW),;L = actual load (MW), which is stochastic,p = index of peak load,K = contracted capacity (kW),g1 = g(F) for F=K.

38 Fuel costs are about 12.0 UScents/kWh for a gas turbine run with jet julep fuel, 7.2 UScents/kWh for adiesel plant, and 3.8 UScents/kWh for coal-thermal generation, which in either case exceeds the costof emergency energy.

39 In particular, the water should be stored in the off-peak period and dispatched in the peak period,which is exactly what EDM intends to do: Corumana is scheduled to operate between 8 a.m. and 10p.m. on weekdays and between 7 p.m. and 9 p.m. during the weekend. In addition, the plant issupposed to be run between II a.m. and 12 a.m. on Saturday and between 8 a.m. and 9 a.m. onSunday. Currently, though, Corumana is not operational due to technical difficulties.

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Annex CPage 3 of 5

7. The load duration curve is normalized by setting the period's length equal to unity(i.e., H=l). Since future loads are stochastic, the inverse g(F), which assumes valuesbetween zero and one, can be interpreted as the (cumulative) distribution function of L. Inthis connection, the probability that the actual load L exceeds the predicted load F is

g(h) = P(L > F) .

8. For a given load curve, the choice of K determines the expected amount of firmenergy imports El:

(I) E, = HK g(F)dF.

9. By the same token, electricity demand that EDM expects to meet throughemergency energy imports, E2, is

(2) E2 = H Jf' g(F)dF.

Total expected costs of electricity imports amount to

(3)C= OK+ciE,+c2 E2 .

The necessary condition for a cost minimum is

= P + g, [c, - c2]H = 0,

which can be rewritten as

(4) [C2 - g;

10. Note that the right-hand-side of (4) can be interpreted as P{L>K}. Hence, condition(4) states that capacity should be contracted to the point where the probability that thecontracted capacity falls short of the actual peak is equal to the ratio of the hourly capacitycharge to the premium paid for emergency energy.40 Under the currently prevailing rates,the critical ratio is about 0.42 (=313/744). The corresponding optimal level of contractedcapacity, however, depends on the monthly load duration curve F(g) which is uncertain.

40 Clearly, the sufficient condition for a minimum is that Og/aK>O.41 In February the ratio will be about 0.46.

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Annex CPage 4 of 5

11. It follows that EDM's key problem is to forecast F(g1). Histograms of hourly loadswould be helpful in this connection. Unfortunately, the available data are incomplete.EDM has records of chronological loads for selected weeks, but there are no series ofhourly loads for an entire month.

12. Nevertheless, the available evidence suggests that the capacity contracted by EDMfrom January to April 1995 tended to exceed the level that was justified on economic

42grounds. Yet EDM has been on the right track in reducing the level of purchased capacityas is shown in Table C. I below.43

Table C.1: Electricity Imports Southern System, 1995

January February March 4pril

Firm Energy 49,823 45,807 51,829 47,501

Emergency Energy 393 1,207 1,173 522

Total Energy 50,216 47,014 53,002 48,023

Contracted Capacity 87 83 83 82

Peak 99.6 102.7 98.5 97.3

Average Costs (UScents/kWh) 1.98 2.06 1.88 1.98

NVote: In MWh (Energy) and MW (capacity, peak).

Source: EDM.

13. Based on hourly load figures for the first seven days of March 1995, we haveapproximated the load duration curve of March 95 through a 5th-degree polynomial.Normalization was done by setting both the peak load and the maximum number of hoursequal to unity. The resulting load duration curve is referred to as f(x) rather than F(g). Theestimate is

f(x) = 0.978 - 0.976853x + 4.40412x2 - 12.387x3 + 13.4813x4 - 5.01158x5 .

42 This is an ex-post statement that neglects the impact that EDM's desire to take or to avoid risks has onthe decision to buy capacity.

43 In order to approximate the optimal amount of contracted capacity, EDM has used an iterativeapproach based on daily load data. The graphical solution presented by EDM's planning department isconsistent with condition (3) above, stating that in a cost minimum the cost of contraction and using aMW for one hour must be equal to the cost of purchasing a MWh at the emergency energy rate.

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Annex CPage 5 of 5

14. Integrating the above function over the interval [0,1] and multiplying the integral byH = 743 hours and Lp =98.5 MW gives

L p H J,f(x)dx 52,830MW/,

which is close to the actual imports of 53,002 MWh (see Table C.l). Since gjH ; 313hours, the optimal capacity would have been 77 MW, compared to 83 MW contracted byEDM. The corresponding total costs (in US$) of electricity imports from Eskom work outto C(77)=994,600 and C(83)=1,001,83 1. Thus, if EDM had contracted 77 MW rather than83 MW, it would have saved about US$ 7,231. Again, this calculation is possible with thebenefit of hindsight.

15. It also can be assumed that the potential for cost savings was even larger in January1995 when EDM contracted 87 MW while the (southern) peak turned out to be 99.6 MW.44Our estimates lead to the conclusion that EDM's decision to reduce the level of contractedcapacity down to 82 MW in April 1995 was a directionally correct policy.

44 This conclusion rests on the assumption that in January the shape of the load duration curve wassimilar to that of March. In fact, weekly time series of hourly loads for the period March-June suggestthat the normalized load duration curves lie close together in the neighborhood of g, (see Annex D).We have therefore used an average normnalized load duration f(x) to calculate the potential savings inJanuary and February. The results indicate that if EDM had correctly predicted the monthly peaks itwould have contracted 77 MW in January and 76 MW in February (on the basis of the averagenormalized load duration function) and, as a result, saved US$ 26,000 in January and US$ 7,100 inFebruary.

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Annex DPage 1 of 5

LoAD ANALYSIS SOUTHERN SYSTEM

Southern System

1. Daily load curves of the southern system show marked seasonal changes. BetweenApril and October the daily peak is around 7 p.m. The morning peak occurs at noon and issignificantly below its evening counterpart. Typically, the load drops between 9 a.m. and12 a.m. (on weekdays) and in the afternoon (see Plot D. 1).

2. By contrast, from November to March (rainy season) the daily peak tends to be at12 a.m. on a workday and at 7 p.m. on weekends. The load does not fall before noon, butpicks up at 3 p.m. (on weekdays) and at 7 p.m. Occasionally, the evening peak may proveas high as the morning peak (see Plot D.2).

3. Based on weekly data provided by EDM, we have approximated normalizedmonthly load duration curves using a 5-th degree polynomial.45 The estimates presented inTable D. I suggest that the curves have a fairly similar shape, particularly for the periodApril-June (see Plot D.3). The average load factor is about 0.68. During the first half of1995 the highest load was recorded on February 9 at noon (102.7 MW).

Table D.l: Coefficients of Normalized Load Duration Curves, March- June 1995Month Peak (MW) Constant x X2 X3 X4 X5

March 96.0 0.9962 -0.94758 4.08436 -11.7165 12.9537 -4.87317

April 97.4 0.9888 -1.75006 9.3187 -24.5924 26.9083 -10.5178

May 93.5 1.0 -1.60139 6.45321 -12.9041 10.1341 - 2.61081

June 92.3 0.9998 -1.62171 7.61268 -17.5073 16.0175 - 5.05001

Sample 94.8 0.99646 -1.479 6.87174 -16.7261 16.5885 - 5.80825Average

Note: 5th degree polynomial; estimates based on weekly time series of hourly loads.


The normalized load curve is obtained by setting the peak load and the length of the period underconsideration equal to unity.

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Annex DPage 2 of 5

Plot D.1: Hourly Load Curve Southern System (MW), May 15-21 1995

. . ., . . I . . . I . .

6 0

0 so 5 7 10 125 150

53

Annex DPage 3 of 5

Plot D.2: Hourly Load Curve Southern System, March 1-7 1995

90

. ~ .. .E . . . . E .

0 Ig

0 25 50 15 100 125 150

54

Annex DPage 4 of 5

Plot D.3: Normalized Monthly Load Duration Curves Southern System,March-June 1995

0.70.8

00.

0 0.2 0.4 8.6 0.8

55

Annex DPage 5 of 5

Central and Northern System

4. Unfortunately, there are no data available from the northem system. EDM,however, provided data on hourly loads of the central system for selected days in 1994 and1995. The figures suggest that the central region load follows a pattern similar to thatobserved in the southem system: On weekdays, there is a seasonal shift in the daily peakfrom 12 a.m. (wet season) to 7 p.m. (dry season). The hourly load declines after noon,rebounds at 4 p.m. and reaches the evening peak at 7 p.m. During the weekend and onholidays the daily peak occurs at 7 p.m.

5. According to rough estimates, in February 1995 the load factor of the central systemwas in the vicinity of 0.62, compared to 0.68 in the southern system. EDM records suggestthat the load factor of the northem system is higher than in the central region, but below thatof the southem system.

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Annex EPage I of 10

ECONOMETRIC ANALYSIS OF ELECTRICITY DEMAND

1. This annex presents and evaluates parameter estimates that can be used to forecastelectricity demand. The estimates are obtained from causal and non-causal regressionmodels and incorporate data provided by EDM and Departamento Nacional de Estatistica aswell as extraneous (a priori) information. The software used consists of built-in routines

46and programmed functions based on Mathematica 2.2.

Abbreviations

2. The following abbreviations will be used:

CI = scaled condition indexes47

DF = Dickey-Fuller testdf = degrees of freedomDW = Durbin-Watson statisticserr = residualsF = F statisticGLS = generalized least squaresIV = instrumental variablesLog = natural logarithmN = number of observations

OLS = ordinary least squaresR2 = coefficient of determinationRBar2 = adjusted R2Reg = OLS-regressionSER = standard error of regression (=sigma)t = t-statistic

46 Mathematica Version 2.2, Wolfram Research, Inc., Champaign, Illinois, 1993.

47 Condition indexes, which are defined as the vector of the inverse eigenvalues of the data matrix timesthe maximum eigenvalue, indicate the presence and number of near dependencies among the datamatrix. Moderate dependencies are associated with indexes of 30-100; they are strong for indexesexceeding 100. The indexes are scaled in that the columns of the data matrix are standardized to haveequal (unit) length. Note also that if the data matrix contains log transforms, the logs need to be e-scaled before scaling for equal (unit) length is done. For details, see D.A.Belsley, ConditioningDiagnostics, New York, 1991.

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Annex EPage 2 of 10

CAUSAL MODELS

3. Causal models specify and estimate the linkage between dependent and independentvariables. In the present context, the focus is on electricity consumption as a function ofGDP and average tariffs.

Functional Form

4. The general form of the multiple linear regression model used in this annex is

(M)y, = ,, + D IXt I +.. + P X,.k-l + £,, t = 1,2,..., n.

5. There are n observations for the dependent variable y and the k-I independentvariables xi. The error terms are denoted by Ft. The constant (intercept) P. and the (slope)coefficients ,B; need to be estimated. Estimates are denoted by b. Classical statisticalanalysis assumes that the true, albeit unknown, values of the coefficients are fixed. From aBayesian viewpoint, however, the coefficients are treated as random variables.

6. Equation (1) can be written in matrix form as

(J')y = X13 + s,

where X is the n*k data matrix, with the first column consisting of elements set equal tounity, while P is k-dimensional.

7. The log-linear version of (') is

(2) Log[y] = Log/X] + s.

Equation (2) has the advantage that its coefficients can be interpreted as elasticities, i.e., , =

(ay/lx 1 )/(y/xi).

8. The basic equation estimated below accounts for a lagged dependent variable andhas the forn

(3) Log[y,] = Log[pj + P, Log[x,,]+.. .+ P,., Log[x,k,]/+ a Log[y, , + £,, t = 1,2.

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Annex EPage 3 of 10

9. Equation (3) is commonly referred to as the partial adjustment model anddistinguishes between short-run elasticities, Pi = (eyItxi)/(y/x,), and long-run elasticities,i/(l-cc), with cC<1.48

OLS and IV

10. The available time series used to estimate Equation (3) cover the period 1988-1994.Since EDM's records of past electricity sales are flawed, annual gross consumption, whichhas been measured with greater accuracy, serves as a proxy for electricity demand.49 Annualaverage tariffs are computed as the ratio of billings to net supply (including non-technicallosses). Figures on real GDP are obtained by using the consumer price index as deflator.

11. The variables and data under consideration are:

C = constant (= intercept)y = Log of gross electricity consumption (MWh)y(-I) = one year lag of yY = Log of real GDP (1994=100)P = Log of real average tariffs (MT/kWh)Y(- 1) = one year lag of YX = {C, Y, P, y(-1)}, n*k-matrixXl = {C,Y,P,Y(-1)},n*k-matrix

X = 1 4.3553 5.3748 13.3451 4.4018 5.4343 13.3761 4.4202 5.6565 13.5171 4.4416 5.7106 13.5121 4.3983 6.0182 13.5891 4.5526 5.9469 13.5991 4.6052 5.8493 13.656

48 Let y be the equilibrium level of y relative to X, which is defined for t=t,,= ... =t,., Adjustment of y, toits equilibrium level y is incomplete. The time path of Yt starting from the initial value y0 is

Y= Y (Yo / Y )

49 Gross electricity consumption includes technical and non-technical network losses and station use inthermal generation.

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Annex EPage 4 of 10

12. Estimating Equation (3) by OLS gives:

Reg[y, X];Dependent variable is y;R2= 0.903749; RBar2= 0.807498; SER = 0.0479503;N = 7; df= 3; dw = 2.85687 with 0 missing observations.

coef st. err. t

C 8.460 7.100 1.192Y 0.676 0.446 1.517P 0.188 0.267 0.704y(-l) 0.076 0.744 0.102err(-1) -1.246 0.530 -2.353

13. Variance-decomposition proportions:

CI. 97 37 11.9 1.0C 0.204 0.747 0.049 0.000Y 0.725 0.270 0.005 0.000P 0.839 0.062 0.099 0.000y(-l) 0.994 0.006 0.000 0.000

14. Given the small and spurious data base, it does not come as a surprise that the OLS-estimates look flimsy. The coefficients are insignificant, and that pertaining to price has the"wrong" sign. The low significance levels together with the strong dependencies among thedata at scaled condition indexes of 97 and 37 suggest the presence of collinearity affectingall coefficients. Serial correlation, however, seems not to be a problem. Note also thatthe estimates are subject to a small-sample bias due to the presence of a lagged dependentvariable.

50 As a rule of thumb, the variates involved in the dependencies among the columns of the data matrixare those with variance-decomposition proportions in excess of 0.5. Note also that the scaledconditions indexes are derived from e-scaled data since the data are in log form.

5l Note that with a lagged dependent variable the dw-statistic is biased towards the null of no serialcorrelation. A better test is to regress the residuals on the explanatory variables and the (one period)lag of the residuals and check on the significance of the coefficient associated with err(-I): If thelagged residuals are insignificant, the null of no (first-order) serial correlation can be accepted.

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Annex EPage 5 of 10

15. Moreover, it is likely that the exvlanatory variables have been measured with errors,thus leading to inconsistent estimates. Consistent estimates can be obtained by the IV-method. Using Y(-l) as an instrument fory(-l), the results are:

IV[y, X, XI];Dependent variable is y;R2 = 0.873814; RBar2 = 0.747629; SER = 0.0551756;N = 7; df= 3; dw = 3.31176 with 0 missing observations;Instruments= {C, Y, P, Y(-l)}.

coef st. err. t

C 1.526 10.256 0.149Y 0.321 0.603 0.533P -0.057 0.377 -0.151y(-l)y 0.809 1.078 0.750err(-l) -0.932 0.514 -1.814

16. Variance-decomposition proportions:

CI: 112.0 5.6 1.8 1.0C 0.990 0.007 0.003 0.000Y 0.997 0.003 0.001 0.000P 0.982 0.018 0.000 0.000y(-l) 1.000 0.000 0.000 0.000

17. Based on the IV-estimates, the elasticity with respect to price has a correct sign.Collinearity, however, continues to be a problem, and the coefficients lack significance.

Mixed Estimation

18. To correct for collinearity and to improve the small sample properties of theestimate, we can resort to extraneous information about the coefficients. The informationconsidered are coefficient estimates from Mauritius. The estimates are given by the vectorc, while the corresponding diagonal elements of the variance-covariance matrix are denotedbyS:

52 While unbiasedness is a finite-sample property (i.e., does not depend on the sample size), consistencymeans, simply speaking, asymptotic unbiasedness.

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Annex EPage 6 of 10

c = {2.838, 0.431, -0.098, 0.669};R = { {l1,0,0,0}, {0,1,0,0}, {0,0,1,0}, {0,0,0.1 }};S = DiagonalMatrix [0.108775, 0.00625779, 0.00150073, 0.00296514];

19. Using the vector c as a stochastic restriction, Mixed Estimation gives the followingGLS-results:

Mixed Estimation[y, X, c, R, S];Dependent variable is y;N = I1; df= 7; dw = 1.67584 with 0 missing observations.

coef st. err. tC 2.855 0.302 9.441Y 0.442 0.071 6.242P -0.083 0.035 -2.383yO(-) 0.682 0.032 21.600

Bayesian Estimation

20. Since Mixed Estimation is a special case of Bayesian statistics, we can harness theprior infonnation from Mauritius to conduct a full-fledged Bayesian analysis.

21. To this end it is assumed that the ,-coefficients and the residual variance c2 arestochastic with a joint normal gamnma distribution. Based on the information fromMauritius, the prior distributions have the means

priorb = {2.838, 0.431, -0.098, 0.669}; priorsigma = 0.0248961.53

22. In addition, given the variance matrix priorsigma*A'1 associated with theobservations from Mauritius, the implied confidence in the estimates is reflected by

A 0.0056982 0.030873 -0.76786 -0.427370.030873 0.099047 0.45046 -0.14769

-0.767860 0.45046 0.41301 -0.578330.042737 -0.14769 -0.57833 0.20903

53 It would be desirable to have prior information from a country that is more similar to Mozambique.Unfortunately, this kind of data is not available, however, Mauritius is clearly a more appropriatecomparator country than, say, Denmark.

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23. Combining the above inforrnation with the data from Mozambique yields thefollowing posterior estimates:

bo = 2.81619, b, = 0.459614, b, = -0.0972486, b3 = c = 0.685094;postsigma = 0.0286687. 5

24. Hence, the exponent of the intercept is equal to 16.731 and the elasticities have thefollowing values:

Bayesian Elasticity Estimates

Variable Short-Run Long-Run

GDP 0.460 1.460

Price -0.097 -0.309

25. Based on the posterior distributions of the coefficients, we can calculate prioritydensity regions for a given probability content. The table presented below tells, forinstance, that there is a 95 percent probability that the short-run GDP-elasticity lies in theBayesian interval (0.367, 0.553).

Highest Priority Density Regions

Probability Content: 0.80 0.95

bi (0.400, 0.519) (0.367, 0.5530)

b2 (-0.098,-0.096) (-0.099,-0.095)

b3 (0.660, 0.710) (0.0646, 0.724)

54 Note that estimating the coefficients without (consistent) prior informnation about the intercept does notchange the results.

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TIME SERIES ANALYSIS

26. Time series analysis is an example of non-causal modeling. It tries to delineate thebehavior of a variable on the basis of its stochastic properties observed in the past. In thissection, univariate time series analysis is applied to data on monthly gross electricityconsumption for the period January 1989 - March 1995 (see Annex A, Table A.3.a).

27. The vector of 75 observations is denoted by MC = {MCI, ... , MC75}. One wouldexpect that the stochastic process underlying the variable is a random walk with a trend, atleast in the medium-to-longer term. The upward trend shown by the available data,however, is not particularly significant (RBar2;0.63).55 Therefore, we base the test forstationarity on the assumption that the sample MC is generated by a random walk withalmost no drift, i.e.

y, = 0 + .y,, + g,, withk z O.

28. Testing the null that a = I (unit root test) gives a DF-statistic of 74*(0.097-1)=-66.822, while the critical 5 percent value is about -13.5. Hence, the hypothesis that MC isnonstationary can be rejected. Likewise, the F-statistic for the null that a = I and k = 0 is8.1596, compared to a critical 5 percent value of about 4.75 (according to the DF-distribution).

29. Given that the series follows a stationary stochastic process, the remaining problemis to find a model that captures the dynamics underlying the data. The dynamics can bedescribed by the frequency spectrum shown below.56 The plot suggests that the lowfrequency components are by far the most important determinants of the sample variance(j=2, j=3, and j=8). As a consequence, we simply assume that the data fit an autoregressiveprocess given by

(4)y, = (Cy, 2 +a2y 3 +a3y,- 8 + t = 1,2,...

30. Estimating equation (4) by OLS gives

Reg[MC, {lag[MC,21, lag[MC,3], lag[MC,81}];Dependent variable is MC;R2 = 0.641494; RBar2 = 0.63029; SER = 4037.1; N = 67; df= 64;

5S Another unusual feature of the data is the absence of annual seasonality.

56 The spectrum has been derived from the Fourier transform of the data.

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coef st. err. t

MC(-2) 0.50806 0.093 5.468MC(-3) 0.28555 0.098 2.923MC(-8) 0.21942 0.094 2.322

31. The above coefficient estimates will be used to conduct a short-term forecast ofmonthly gross electricity consumption (see plot E. 1).57

57 Note that the sum of the estimated coefficient values is slightly greater than unity. So there is a smalldrift or, equivalently, almost no drift (as was assumed at the outset). In the future, however, the drift islikely to become more important. Regardless, the short-term forecasting model should be refined andupdated once additional data become available.

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Plot E.l: Frequency Spectrum of Monthly Gross Electricity Consumption

.0000

50000

30000

201000

I0000i

0 5 10 15 20 25 30 35

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FORECAST OF ELECTRICITY CONSUMPTION

Short-Term Forecast

1. Based on the autoregressive model estimated in Annex E, Equation (4), monthlygross consumption has been forecast for the period April 1995-December 1996. The resultsare shown in Table F. 1 below.

Table F.1: Forecast Monthly Gross Electricity Consumption (MWh)

Year 1995 1996

January 79200 81531

February 73157 81279

March 82636 81539

April 76504 82156

May 79304 82189

June 79129 82413

July 78865 83130

August 80160 82867

September 80034 83650

October 79290 83665

November 81676 84045

December 79916 84412

Total Annual 949871 992876

Note: Actual consumption for the first quarter of 1995.

2. According to the predictions of monthly consumption, annual gross consumptioncan be expected to reach 950,000 MWh in 1995 and 993,000 MWh in 1996. EDM'sprediction for 1995 is 948,000 MWh. It also should be mentioned that the lead time of the1996 forecasts exceed the length of the largest lag considered in the model (8 months).Therefore, the projections made for 1996 tend to be less accurate than the figures predictedfor 1995.

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Long-Term Forecast

3. A major difficulty with long-tern forecasts based on causal models described inAnnex E is that even when the parameters of the model were known with certainty (whichthey are not), forecasting is conditional on predictions of the future behavior of theexplanatory (independent) variables. Moreover, since the explanatory variables are subjectto policy interventions, structural changes and other factors not incorporated in the model,forecasting rests on assumptions about the policy environment and its impact on thecoefficients of the model.

4. The Bayesian coefficient estimates that will be used to forecast gross electricityconsumption on the basis of Equation (3), Annex E, are:

Log of intercept: 2.811619Short-run GDP elasticity: 0.4596Short-mn price elasticity: -0.0973Coefficient pertaining to the lagged dependent variable: 0.6851.

5. The corresponding long-run elasticities are 1.460 for GDP and -0.309 for price. Thelarge differential between long-run and short-run elasticities is attributable to the low speedof adjustment (i.e., the comparatively high value of the coefficient associated with thelagged dependent variable). For instance, suppose that current electricity consumption is 10percent below the equilibrium level. Given GDP and price, then our estimate of theadjustment coefficient implies that it will take 6.2 years to come as close as 1 percent to theequilibrium level. If the estimate were 0.60 (rather than 0.6851), the same result would beachieved after 4.6 years.58 So in the context of our estimates, the "long-mnm" is,asymptotically speaking, far into the future.

6. Since the future development of the explanatory variables (average tariff revenues inconstant prices of 1994; index of real GDP, with 1994 = 100) as well as the policyenvironment are uncertain, we consider two tariff scenarios and three GDP scenarios. Theforecast horizon covers the period 1995-20 10.

7. The first tariff scenario assumes that average tariffs rise from 347 MT/kWh in 1994to 575 MT/kWh in 1998 (in constant prices of 1994). Based on the average annual rate ofexchange that prevailed in 1994 (6054 MT/US$), this is equivalent to increasing the tariffsfrom 5.7 UScentslkWh in 1994 to 9.5 UScents/kWh in 1998. The latter figure reflects thetariff target level that EDM thinks is necessary for its financial viability. On the other hand,

58 The results can be obtained by solving the formnula describing the time path of the dependent variablefor the index of time (see Annex Es footnote referring to Equation (3)).

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we also consider a lower target level 7.5 UScents/kWh (454 MT/kWh). Under both tariffscenarios, only modest increases (in real terms) are expected for the period after 1998.

8. Regarding the prospects for GDP-growth, we consider three scenarios ranging from"low growth" to "high growth." Alternatively, the scenarios may be classified in terms ofthe economic progress made by Mozambique during the transition from peace to economicrecovery. The least optimistic scenario can be squeezed into the assumption that real GDPon average rises at 3 percent a year. Medium growth translates into average annual growthrates of 4.7 percent for 1995-2000, 4.2 percent for 2000-2010, and 4.5 percent for 1995-2010. The implied growth rates of the most optimistic GDP-scenario are 6.7 percent for1995-2000, 5.5 percent for 2000-2010, and 5.9 percent for 1995-2010.59

9. The different assumptions concerming tariffs and GDP-growth are summarized inTable F.2.

Table F.2: Summary of Long-Term ScenariosTariff GDP

Year High Low Low Medium High1995 412 412 102.00 103.80 105.501996 454 424 104.55 108.47 111.831997 515 454 107.69 113.35 118.761998 575 454 111.03 118.45 126.481999 575 454 114.91 124.38 135.972000 575 454 118.93 130.59 146.172001 580 459 123.33 137.39 155.672002 580 459 127.90 144.94 165.012003 580 459 131.99 151.75 174.912004 585 464 136.21 158.13 184.532005 585 464 140.30 164.45 193.762006 585 464 144.51 171.03 203.442007 590 469 148.84 177.87 213.622008 590 469 153.31 184.99 224.302009 595 474 157.14 191.46 235.512010 596 474 161.07 198.16 246.11

Note: Tariff: MT/kWh in constant prices of 1994; GDP: index of GDP (1994 = 100); theaverage annual rate of exchange used for 1994 is 6054 MT/US$.

59 Growth rates are least squares estimates.

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10. Combining the different tariff assumptions and GDP projections, we obtain sixelectricity consumption scenarios, running the gamut from "low growth cum high tariffs" to"high growth cum low tariffs." The resulting forecasts are shown in Table F.3. Since thepredictions cover a fairly broad region of possible developments, no consideration is givento confidence intervals.

Table F.3: Forecasts of Gross Electricity Consumption (GWh)Year Fla Flb F2a F2b F3a F3b1995 935.03 935.03 942.58 942.58 949.64 949.641996 962.38 968.80 984.21 990.77 1003.22 1009.921997 982.90 999.57 1021.89 1039.22 1057.80 1075.741998 1000.52 1035.64 1058.56 1095.71 1117.08 1156.291999 1028.89 1077.99 1109.06 1161.98 1198.81 1256.012000 1065.50 1125.64 1170.97 1237.07 1300.75 1374.182001 1108.77 1177.77 1243.01 1320.37 1414.76 1502.802002 1158.64 1235.36 1327.14 1415.02 1539.26 1641.182003 1211.49 1295.03 1417.64 1515.39 1675.08 1790.582004 1266.23 1355.62 1510.27 1616.89 1817.69 1946.012005 1323.02 1417.91 1605.85 1721.04 1965.94 2106.952006 1382.04 1482.24 1705.29 1828.92 2121.44 2275.242007 1442.25 1547.25 1807.76 1939.36 2283.85 2450.112008 1505.34 1615.24 1915.74 2055.60 2456.71 2636.062009 1566.54 1680.78 2023.50 2171.06 2639.00 2831.432010 1628.02 1746.93 2133.94 2289.79 2827.83 3034.36

ARGa:

1995-2010 4.0 4.5 5.9 6.4 7.9 8.41995-2000 2.6 3.8 4.2 5.4 6.4 7.6

Note: Fla = low GDP, high tariff; Flb low GDP, low tariff; F2a = medium GDP, high tariff; F2b =

medium GDP, low tariff; F3a = high GDP, high tariff; F3b = high GDP, low tariff.

a. Average annual rate of growth (%); least squares estimates.

11. Clearly, the assumptions about GDP-growth have the strongest impact on predictedelectricity consumption. Switching from a lower- to a higher-growth-scenario accelerateselectricity consumption by about 2 percentage points. By contrast, the impact that thechoice between the two tariff scenarios has on predicted consumption growth (for a giventime path of GDP) is equivalent to 0.5 percentage points.

12. Depending on the scenario, the average annual rates of growth of gross consumptionvary between 4.0 percent (low GDP, high tariffs) and 8.4 percent (high growth, low tariffs).For comparison, during the last three years gross consumption grew at about 5.5 percent.The forecasts are similar in that beyond the year 2000 electricity demand rises markedly

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faster than during the period 1995 - 2000, mainly because the assumed increases in priceare highest during the initial three years. Another reason for the more rapid growth in lateryears is the delayed adjustment to changes in price and, more importantly, GDP.

13. It also is worth noting that the long-term predictions made under the 'medium-growth-cum-low-tariffs" scenario for 1995 and 1996 are closest to the short-termconsumption estimates based on time-series analysis.

14. A comparison between the above scenario forecasts and previous predictions carriedout by Norconsult (1993) and EDM (1995) shows the following (see Table F.4):

15. If adjusted for technical losses, the Norconsult forecasts for 2010 lie between our"low-growth-cum-high-tariffs" and "high-growth-cum-high-tariffs" predictions. Bycontrast, for the year 2000, Norconsult's medium- and high-case figures are significantlyabove those of the highest forecast (high growth, low tariffs) generated from our scenarios.Thus, the growth rates implied by the Norconsult predictions for the period 2000-2010 areconsistently less optimistic than those of our forecasts. A possible explanation of thisdiscrepancy is that our forecasts are based on a model in which the elasticities of demandwith respect to GDP and price are high in the long-run and low in the short-run, whileNorconsult may have used an entirely different model.

16. The demand forecast that EDM's financial department prepared in May 1995 coversthe period 1995-2005 and is part of a study on cash-flow problems besetting the utility. Thepredictions, which reflect ad-hoc assumptions, are in close vicinity of our "low-growth-cum-high-tariffs" scenario.

Table F.4: Previous Demand Forecasts (Norconsult and EDM)

1995 2000 2005 2010

NorconsultLow - 1,320 - 1,626

Medium - 1,769 - 2,419High - 1,851 - 2,708

EDM 904 1,108 1,318 -

- Not available.

Note: Gross electricity conswnption (GWh); original estimates refer to sales andhave been adjusted for technical losses.

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17. No attempt has been made in this study to model and estimate a peak load functionwhich could be used to predict maximum demand conditional on gross electricityconsumption and other variables deemed relevant. Instead, system peak or, equivalently,the system load factor is assumed to be linear in gross consumption. Resorting to thissimplification, however, poses the problem of determining a standard (or representative)load factor for the lead time of the forecast. Adding to this difficulty is that there is noinformation on the coincidence of the peaks recorded in the three subsystems ofMozambique's power sector. In the near future, however, the subsystems will beinterconnected either directly between the northern and central region, or indirectly, viaSouth Africa, between the northern and southern region. As a consequence, systemwideplanning will gain importance.

18. According to rough estimates, the combined system load factor rose from 0.53 in1985 to 0.58 in 1990 and reached 0.67 in 1994. The sharp increase in the last four yearsmainly reflects improvement in the reliability of supply, notably after the peace accord of1992, which more than offset the adverse impact that the decline in industrial demand andthe momentum of residential consumption and other small-volume use of electricity mayhave had on the load factor. Assuming that peaceful conditions persist and that economicrecovery will take the lead in determining the changes in the system's load profile, weexpect the load factor to remain in the neighborhood of 0.66. The resulting annual peakscorresponding to the scenario-dependent projections of gross electricity consumption arepresented in Table F.5.

19. There are no clear criteria for selecting among the different scenarios underlying thelong-term forecasts presented above. Therefore, the focus will be on a forecast intervalwithin which we expect electricity consumption to develop (disregarding the possibility of along-lasting stagnation or significant temporary decline). The lower band is clearly theforecast based on the "low-growth-cum-high-tariffs" scenario. For the higher band, weconsider the "medium-growth-cum-low-tariffs" scenario as the best choice.

20. Regarding the distribution of gross electricity consumption between the southernregion and the rest of the country, we assume that the share accounted for by the southernsystem increases from 64 percent in 1994 to 65 percent in 1995, thereafter graduallydeclines to 62.5 percent by 2000 and remains at this level until 2010. Furthermore, allsystems will be directly or indirectly interconnected by 1997.

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Table F.5: Forecasts of System Peak (MW)Year Fla Flb F2a F2b F3a F3b1995 61.7 161.7 163.0 163.0 164.3 164.31996 166.5 167.6 170.2 171.4 173.5 174.71997 170.0 172.9 176.7 179.7 183.0 186.11998 173.1 179.1 183.1 189.5 193.2 200.01999 178.0 186.5 191.8 201.0 207.3 217.22000 184.3 194.7 202.5 214.0 225.0 237.72001 191.8 203.7 215.0 228.4 244.7 259.92002 200.4 213.7 229.5 244.7 266.2 283.92003 209.5 224.0 245.2 262.1 289.7 309.72004 219.0 234.5 261.2 279.7 314.4 336.62005 228.8 245.2 277.8 297.7 340.0 364.42006 239.0 256.4 295.0 316.3 366.9 393.52007 249.5 267.6 312.7 335.4 395.0 423.82008 260.4 279.4 331.4 355.5 424.9 455.92009 271.0 290.7 350.0 375.5 456.4 489.72010 281.6 302.2 369.1 396.0 489.1 524.8

Note: Fla low GDP, high tariff; Flb = low GDP, low tariff; F2a = medium GDP, high tariff; F2b =

medium GDP, low tariff; F3a = high GDP, high tariff; F3b = high GDP, low tariff.

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LONG-RUN AVERAGE INCREMENTAL COSTS OF POWER SUPPLY

1. In computing the long-run average incremental costs (LRAIC) of power supplied tothe domestic market, we make a number of assumptions explained below.

Power from HCB and Import Opportunities

2. A key assumption is that Hydroelectrica de Cahora Bassa (HCB) starts supplyingEskom in March 1997. Henceforth, the southern system may retrieve up to 190 MW(=200/1.05) from the Komatipoort busbar. Given the share of northern-central demandcovered by HCP-power, Lb, the balance available for the southern system is L, = (200-Lb)/1 .05.

3. Currently, the monthly payments for HCB-power injected into the northern systemare:

F1 =0.8*L*h*P if E<0.8*L*h, orF2 = F1 + (E - 0.8*L*h)P/3 if E>0.8*L*h,

whereL = maximum demand (MW),h = length of month (hours),P = 5 Rand/MW,E = metered energy supply (MWh).

4. The above formulas are part of an agreement that HCB and EDM signed in May1983. F, can be interpreted as a capacity charge. F2 includes a penalty for energy suppliedin excess of the level determined by a load factor of 0.8.

5. The old agreement calls for slightly different terrms in the event that HCB wheelspower to the southem system through Komatipoort, which has not been the case since theearly 1 980s. Here, the formula for the payments by EDM to HCB reads

F3 1 .05(L*h*P, + (E - L*h)P,/3).

6. F3 is composed of a capacity fee and a surcharge (discount) for energy that exceeds(falls short of) the ceiling given by the contracted capacity. The factor 1.05 accounts fortransmission losses. Under the old contract, Ps was fixed at 7.5 Rand/MW.60 In 1989,Eskom agreed to pay HCB 20 Rand/MW if and when the link to Apollo is put back into

60 The contract was assumed to remain valid for 30-35 years, i.e. until 2010-2015.

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service. Therefore, the 20 Rand/MW could, ceteris paribus, become a benchmark forpossible, future renegotiations between HCB, Eskom and EDM. In addition, EDM wouldbe required to pay to Eskom a standby charge of 500 Rand/MW plus a monthlytransmission fee of Rand 30,000 (according to the old contract). Also, should HCB wheelpower to the southern system, these supplies would substitute for the current imports fromEskom, at least as long as the power recalled from HCB is sufficient to meet growingdemand in Mozambique's south.

7. In any case, the above formulas and the resulting rates may change especially whenHCB restarts the transmission of power from Cahora Bassa to Eskom and EDM's southerncustomers. EDM at present pays 0.4 UScents/kWh under the 1983 contract, and Eskomwould pay about 1.5 UScents/kWh if the 20 Rand/MW agreement of 1989 were to apply.

8. Another uncertainty is whether and on what conditions EDM will be permitted toincrease its share of HCB-power, assuming that Eskom would give up some of its claims.In this connection it is worth mentioning that even though the current import agreementbetween EDM and Eskom would expire in March 2000 (3 years after the resumption ofsupply from HCB), there is the option to keep the import agreement in force beyond theyear 2000 (Article 9). Therefore, if Eskom were to release HCB-capacity to EDM, EDMmight have to pay about the rates charged under the current import agreement (which isabout 2 UScentslkWh on average), depending on the availability of capacity in Eskom'ssystem, or whatever rate Eskom agrees to pay HCB.

9. Apart from the rehabilitation of the 533 kV line from Cahora Bassa to Apollo, anew 275 kV line between Zombodze (Swaziland) and Matola is to be completed by the year2000. With this additional transmission capacity of 150 MW, the southern system would bein a position to meet up to 350 MW through imports (including power from HCB).

10. Regarding the connection between the northern and central system, EDM expects tocomplete and operate a temporary 1 1O kV line (10 MW capacity) by 1996, thus facilitatingthe supply of HCB-power to the central region. We also assume that the 220 kV linebetween Matambo and Chibata/Xigadora will be ready by the year 2001 (for details, seeTable G.5 below).

Power Supply from Existing Generating Facilities

11. The firm hydro capacity in the central and northern system is assumed to be 50 MWat 3500 hours a year (175 GWh/year). The Corumana plant is rated at 12 MW for 2500hours a year (30 Gwh/year), while Cahora Bassa has a capability equivalent to 6750 hours ayear. The availability of existing therrnal generating capacity is assumed to follow the pathoutlined in Table A. 11, Annex A. The resulting scope for power generation and power

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imports (including acquisitions from HCB and subject to transmission line constraintsmentioned above) is summarized in Table G. I below.

Table G.1: Potential for Power Imports and Power Generation from Existing Plant(MW), 1995-2010

Southern System Central - Northern System

Year Hydro Thermal Imports Total Hydro Thermal Importsa Total

1995 12 90 200 302 50 30 200 280

1996 12 90 200 302 50 30 200 280

1997 12 90 200 302 50 30 200 280

1998 12 87 200 299 50 35 200 284

1999 12 87 200 299 50 35 200 284

2000 12 67 350 429 50 35 200 284

2001 12 67 350 429 50 35 200 284

2002 12 67 350 429 50 35 200 284

2003 12 67 350 429 50 35 200 284

2004 12 67 350 429 50 35 200 284

2005 12 26 350 388 50 34 200 283

2006 12 26 350 388 50 34 200 283

2007 12 26 350 388 50 34 200 283

2008 12 26 350 388 50 34 200 283

2009 12 26 350 388 50 34 200 283

2010 12 26 350 388 50 34 200 283

a. Not including the 400 kV line to Zimbabwe (for HCB-exports) which is likely to be operational by1998.


Future Demand

12. Table G.2 presents a regional breakdown of the forecasts of gross electricityconsumption pertaining to the low-GDP-cum-high-tariffs scenario and the medium-GDP-cum-low-tariffs scenario, respectively. The corresponding predictions of peak load areshown in Table G.3 (for details, see Annex F).

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Table G.2: Forecasts of Gross Electricity Consumption by Region(GWh)Fla F2b

Year SS CN ST SS CN ST1995 607.8 327.2 935.0 612.7 329.9 942.61996 620.7 341.7 962.4 639.1 351.7 990.81997 629.0 353.9 982.9 665.1 374.1 1039.21998 635.3 365.2 1000.5 695.8 399.9 1095.71999 648.2 380.7 1028.9 732.1 429.9 1162.02000 665.9 399.6 1065.5 773.2 463.9 1237.12001 693.0 415.8 1108.8 825.2 495.2 1320.42002 724.1 434.5 1158.6 884.4 530.6 1415.02003 757.2 454.3 1211.5 947.1 568.3 1515.42004 791.3 474.9 1266.2 1010.6 606.3 1616.92005 826.9 496.1 1323.0 1075.6 645.4 1721.02006 863.8 518.2 1382.0 1143.1 685.8 1828.92007 901.4 540.9 1442.3 1212.1 727.3 1939.42008 940.8 564.5 1505.3 1284.7 770.9 2055.62009 979.1 587.4 1566.5 1356.9 814.2 2171.12010 1017.5 610.5 1628.0 1431.1 858.7 2289.8

Note: Fla = low GDP, high tariff; F2b = medium GDP, low tariff; SS = southem system; CN = central andnorthern system; ST = system total.

Table G.3: Forecasts of Peak Load by Region (MIW)Fla F2b

Year SS NC ST SS NC ST1995 105.1 56.6 161.7 106.0 57.0 163.01996 107.4 59.1 166.5 110.5 60.9 171.41997 108.8 61.2 170.0 115.0 64.7 179.71998 109.9 63.2 173.1 120.3 69.2 189.51999 112.1 65.9 178.0 126.6 74.4 201.02000 115.2 69.1 184.3 133.7 80.3 214.02001 119.9 71.9 191.8 142.7 85.7 228.42002 125.3 75.1 200.4 153.0 91.7 244.72003 131.0 78.5 209.5 163.8 98.29 262.12004 136.9 82.1 219.0 174.8 104.9 279.72005 143.0 85.8 228.8 186.0 111.6 297.72006 149.4 89.6 239.0 197.7 118.6 316.32007 155.9 93.6 249.5 209.6 125.8 335.42008 162.7 97.7 260.4 222.2 133.3 355.52009 169.3 101.7 271.0 234.7 140.8 375.52010 176.0 105.6 281.6 247.5 148.5 396.0

Note: Fla = low GDP, high tariff; F2b = medium GDP, low tariff; SS = southern system; CN = central andnorthern system; ST = system total.

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Investments in Power Generation

13. A comparison of the demand forecasts with EDM's supply options reveals thatunder the current agreement power from HCB, together with EDM's existing generatingcapacity, are sufficient to meet demand both in the northern/central region and in thesouthern system until 2006 (low growth, high tariffs) or 2001 (medium growth, low tariffs),assuming that the thermal plants are nornally kept on standby (see Table G.4). Therefore,whatever the scenario, EDM must seek additional sources of supply. It could import fromEskom, hope to increase its HCB-share or expand its own generating capacity. Thefollowing analysis assumes that either of the first two options will be available, and that theacquired costs of power (imported, HCB supplied) would be lower than those of additionalgenerating plants.

Table G.4: Projected Supply Deficits

Low-Growth-cum-High-TariWffs Medium-Growth-cum-Low-Tariffs

Year Capacity (MW) Energy (GWh) Capacity (MW) Energy (GWh)

2002 0 0 10 58

2003 0 0 25 145

2004 0 0 43 250

2005 0 0 65 327

2006 0 0 80 420

2007 10 58 100 530

2008 25 145 124 648

2009 35 203 144 755

2010 45 260 164 875

14. Another problem is that the risk of line outages is comparatively high in the north-eastern region, which is supplied from Cahora Bassa over a distance of more than 1000 km.The planned grid extensions to Pemba and Lichinga also will increase this risk. While theoption of reinforcing the grid through the construction of parallel lines can be dismissed asprohibitively expensive, it may be reasonable to hedge against the risk of transmissionfailures through the provision of backup generating facilities in the main load centers. Infact, EDM, following the advice of NORCONSULT, plans to install a 25 MW gas turbine

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in Nacala as an additional backup. Whether such a project is economic, however, dependson the probability of transmission failures on the one hand, and the customers' willingnessto pay for improvements in the reliability of supply on the other.6'

15. Unfortunately, we do not know what premium the different customer groups of thenorthern region are prepared to pay for uninterrupted power. Nor do we have estimates ofthe probability of line outages at different locations. It can be assumed that the reliability ofthe line will improve, which will increase the premium that customers would have to payfor further reducing the risk of transmission failures. A sizable group of consumers with anexceptionally high value of lost load is more likely to emerge under the medium-growth-cum-low-tariffs scenario than under the low-growth-cum-high-tariffs scenario. Therefore,we include the proposed stand-by gas turbine (25 MW) or any other generation plant ofsimilar size and cost in the northern region, but only in the investment program associatedwith the medium growth demand forecast.

61 Suppose that line outages are exponentially distributed with parameter l/P, where P is the expectedduration of outages per unit of time. Moreover, let the long-run willingness to pay for a reliabilitylevel I-P be W(P). Then it is economic to provide a backup generating plant if

FW(P) 2 + c

hP(I -Q)where

F = fixed costs of the backup (US$/kW/year)

c = operating costs of the backup (US$/kWh)

h = annual load factor (hours per year)

Q = outage rate of the backup (per unit of time).

For instance, based on a gas turbine with specific investment costs of 650 US$/kW (10% interest,lifetime of 25 years, fixed O+M of 13 US$/year), we have F = 85 US$/kW, c = 0.12 US$/kWh. Let Q= 0.15 and h = 0.66. Then for a backup to be economic, the willingness to pay must be at least 0.29US$/kWh for P = 0. 1, 0.47 US$/kWh for P = 0.05, and 0.81 US$/kWh for P = 0.025.

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16. Under both scenarios, we also account for planned investments in thermal plantoverhauls and the rehabilitation of the Chicamba dam. No other generation investmentneeds to be contemplated by EDM to meet forecast demand. A project such as AltoMalema, which is being promoted by EDM, could only make sense if it were financed bythe private sector and, therefore, is excluded from the streamlined investment program ofEDM as shown in Table G.5 below.

Table G.5: Investment Plan Generation (millions of 1995 US dollars)

96 97 98 99 00 01 02 03 04 Total

GI 1.0 1.0 1.0 0.0 0.0 0.0 0.0 0.0 0.0 3.0

G4a 0.0 0.0 0.0 0.0 0.0 0.0 16.0 0.0 0.0 16.0

G5 0.0 0.0 0.0 1.5 1.5 0.0 0.0 0.0 0.0 3.0

Note: G I = thermal rehabilitationG3 = Alto Malema Hydro, 80 MWG4 = gas turbine NacalaG5 = Chicamba dam rehabilitation

a. Only under the medium-growth-cum-low-tariffs scenario.


Investments in Transmission Facilities

17. For calculating the LRAIC of domestic power supply, we have revised EDM'stentative investment program as follows:

18. The overhaul of the 220 kV line from Songo to Nampula (TI) is spread over aperiod of 9 years. EDM's cost estimate of US$ 20 million has been adjusted downwards toUS$ 14 million. Likewise, the costs of overhauling the line from Nampula to Nacala (T3)has been reestimated at US$ 7 million. An additional US$ 2 million has been allocated tothe HCB-EDM interconnection projects (T7). The rehabilitation of the second Mavuzi-Nhamatanda line (T4) starts in 1996 rather than in 2001. First measures to improve voltagecontrol in Beira (T6) are scheduled for 1996. The planned grid extension to Cuambo andLichinga is postponed, starting in 2001. Similarly, the lines to Montepuez and Pemba (T9)are installed between 2001 and 2004 rather than in the period 1996-1998. The extension

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projects T12, T13 and T15 are commissioned not before 2006. Even though the timing ofthe planned investments in the Xai-Xai-Inhambane line (T1O) is questionable on economicgrounds, it is assumed that the required funds are committed and the project will beimplemented on EDM's schedule (1996-1998).

19. The planned interconnection between Swaziland and Mozambique (T5) isconsidered to be essential for the future supply of the southern system. A less convincingcase can be made for the proposed interconnection between Orange Grove (Zimbabwe) andChibata (T6). We assune, however, that the line will contribute to the reliability of supplyin Mozambique, with the works starting in 2006. On the other hand, typical export projectssuch as the 400 kV line from Songo to Harare (Zimbabwe) and the planned 220 kV line toBlantyre (Malawi) are not included in the investment program used for computing LRAIC.

20. A list of all transmission projects under consideration is presented below. Table G.6shows the sequence of investments deemed relevant for LRAIC.

TI = 220 kV, rehab Songo-Nampula, split into Stage I and Stage 2T3 = 110 kV, replacement Nampula-NacalaT4 = 110 kV, rehab of 2nd line Mavuzi-NhamatandaT5 = 245 kV, Swaziland (Zombodze)-Mozambique (Matola)T6 = reactive power devices BeiraT7 = 110 kV + 220 kV, interconnection HCB-EDM (at Chibata)T8 = 110 kV, Alto Molocue-Gurue + substation GurueT9 = 110 kV, Nampula-Ancuabe-Montepues-PembaT1O = 110 kV, Xai-Xai-InhambaneTI 1 = 110 kV, Gurue-Cuamba-LichingaT12 = 110 kV, Corumana-XimavaneT13 = 110 kV, Massingir-ChokweT14 = 220 kV, Mozambique (Matambo)-Malawi (Blantyre)T1 5 = 110 kV, Caia-Luabo-MarromeuT16 = 220kV, Chibata-Orange Grove(Zimbabwe)

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Table G.6: Investment Plan Transmission System (millions of 1995 US dollars)Year 96 97 98 99 00 01 02 03 04 TotalTI 2.0 1.0 1.0 2.5 2.5 2.0 1.0 1.0 1.0 14.0T3 3.0 1.0 1.0 1.0 1.0 0.0 0.0 0.0 0.0 7.0T7 0.5 0.0 3.0 3.0 3.0 3.0 0.0 0.0 0.0 12.5T9 0.0 0.0 0.0 0.0 0.0 8.0 5.2 5.2 1.6 20.0TIO 6.0 5.0 5.0 4.0 0.0 0.0 0.0 0.0 0.0 20.0T8 0.0 0.0 0.0 2.0 2.0 0.0 0.0 0.0 0.0 4.0T4 1.0 1.0 1.0 0.0 0.0 0.0 0.0 0.0 0.0 3.0T6 0.0 0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.25 2.0Tll 0.0 0.0 0.0 0.0 0.0 8.0 5.2 5.2 1.6 20.0T5a 2.2 3.5 4.6 1.1 0.0 0.0 0.0 0.0 0.0 11.4T16a 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 7.5T12 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4.0T13 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4.0T1S 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 6.0

a. EDM's share.


Investments in Distribution Facilities

21. The investments that EDM plans to allocate to primary and secondary distributionhave been revised as follows:

22. Rehabilitation of the Nampula and Beira distribution systems (Dl, D2) is broughtforward, starting in 1996. The estimated costs for Quelimane (D3) have been trimmed toUS$ 4 million. Overhauling the Maputo distribution network (D5) starts in 1999 atreestimated costs of US$ 3 million. The Maputo substation extensions (D8) are postponedby three years, with the costs adjusted upwards to US$ 5 million. The investments in thedistribution systems of Gurue, Cuamba and Lichinge (D9) are deferred, stretching from1999 to 2005. Rehabilitation of electrification schemes in the Chimoio and Chokwe areas(DID) is commissioned earlier (1996), with the costs cut to US$ 6 million. Likewise,rehabilitation of southern electrification schemes (Dl11) starts in 1996, while costs are cut toUS$ 18 million and spread over nine years.

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23. Table G.7 gives an overview of the investment program referring to the distributionprojects listed below.

Table G.7: Investment Plan Distribution (millions of 1995 US dollars)96 97 98 99 00 01 02 03 04 05 Total

DI 2.0 3.0 1.0 1.0 1.0 0.0 0.0 0.0 0.0 0.0 8.0D2 0.0 3.0 2.0 2.0 1.0 0.0 0.0 0.0 0.0 0.0 8.0D3 1.0 0.5 0.5 1.0 1.0 0.0 0.0 0.0 0.0 0.0 4.0D4 1.3 1.6 1.5 1.5 0.3 0.0 0.0 0.0 0.0 0.0 6.2D5 0.0 0.0 0.0 1.0 0.5 0.5 0.5 0.5 0.0 0.0 3.0D6 0.0 0.0 1.1 0.8 0.2 0.0 0.0 0.0 0.0 0.0 2.1D7 5.2 1.4 0.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 7.2D8 0.0 0.0 0.0 1.0 1.0 1.0 0.5 0.5 0.5 0.5 5.0D9 0.0 0.0 0.0 0.0 0.0 0.0 2.0 2.0 2.0 0.0 6.0DIO 1.0 1.0 1.0 1.5 1.5 0.0 0.0 0.0 0.0 0.0 6.0DII 2.0 2.0 2.0 2.5 2.5 2.0 2.0 1.0 1.0 1.0 18.0D12 1.6 2.5 3.4 0.8 0.0 0.0 0.0 0.0 0.0 0.0 8.3D13 0.0 0.0 0.0 0.0 0.0 2.0 2.0 1.0 1.0 1.0 7.0D14 0.0 0.0 0.0 0.0 0.0 1.5 1.5 1.0 0.5 0.5 5.0D15 0.0 0.0 0.0 0.0 0.0 1.0 0.5 0.5 0.0 0.0 2.0D 16 0.0 0.0 0.0 0.0 0.0 0.0 2.0 2.0 0.0 0.0 4.0D17 0.0 0.0 0.0 0.0 0.0 2.0 2.0 1.0 1.0 1.0 7.0D18 0.0 0.0 0.0 0.0 0.0 0.0 3.0 2.0 1.0 1.0 7.0El 1.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.0E2 0.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.6

Note: D I = rehab and extension of Nampula distribution systemD2 = rehab and extension of Beira distribution systemD3 = rehab and extension of Quelimane distribution systemD4 = rehab and extension of Nacala distribution systemD5 = rehab and extension of Maputo distribution systemD6 = power supply to BuziD7 = rehab Xai-Xai, Mampula, Nacala substationsD8 = extension Maputo substations SE4, SE5, SE6D9 = primary and secondary distribution Gurue, Cuamba, LichingeDI0= rehab electrification Chimoio and ChokweDI I = rehab electrification southDI 2 = Maputo substation extensionDI 3 = overhaul of Matola distribution systemD 14 = overhaul distribution system Xai-Xai and ChokweDI 5 = overhaul of Angoche distribution systemD16= conversion from to diesel to electric pumping in LimpopoD17= new substation MatolaDI 8 = new substation in Tete and MatundoEl = urbanhouseholdenergyE2 =emergency program Nacala


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Other Investments

24. Additional investments are required for rehabilitating and upgrading the controlfacilities in the Beira corridor (C I), installing a remote center system in Maputo (C2), andimproving EDM's telecommunication system (C3). Another item (C5) covers the plannedexpenditures for expanding EDM's vehicle fleet and construction a new headquarters inMaputo (see Table G.8).

Table G.8: Investment Plan: Miscellaneous (millions of 1995 US dollars)

1996 1997 1998 1999 2000 2001 Total

C 1 0.8 1.0 0.3 0.0 0.0 0.0 2.1

C2 0.0 0.0 0.0 1.5 1.5 0.0 3.0

C3 1.1 1.6 0.3 0.0 0.0 0.0 3.0

C5 0.3 1.3 1.5 1.5 1.0 0.3 5.9

Note: Cl = rehab control system central regionC2 = remote control center MaputoC3 = Telecommunication Phase 11C4 = Cahora Bassa studyC5 = vehicles, equipment, EDM headquarters building


LRAIC

25. Usually, long-run average incremental costs (LRAIC) are defined as

61) j?AC = E = (V, - V,) q" + EnI, q t(l)LRAIC = --

Z=, (X, -

where

Vt = variable costs in period t (US$ million)It = investment costs in period t (US$ million)X, = demand in period t (GWh)q = discount factor (1+i), with i as the discount rate,t = index of time.

84


26. For the sake of convenience, we assume that the investment program leads to astationary state, i.e., from period t = n to t = m demand remains at the level X,. In this case,the denominator of Equation (1) can be expressed as

in, AX, q-(2)

where A Xt denotes incremental demand (GWh) in period t, i.e., A X = Xt-Xt 1, t= 1,2,...,n.

27. Likewise, if the useful life of the additional facilities is uniformly equal to T years,the numerator of (1) becomes

En I V l nI

(3) + -q

A Vt stands for the incremental variable costs in period t.

28. In view of the above transformations, Equation (1) can be rewritten as

(J')LRA4IC = Z1 = , A V, q -' + i( A X, I, q-') / (1 q 7 )

29. In calculating LRAIC on the basis of Equation (1'), the following additionalassumptions are made (apart from those related to the investment program):

(i) Average fuel costs of thermal power generation amount to be 0.08US$/kWh. 6 2

(ii) With the resumption of supply from Cahora Bassa to Eskom, HCB pushesfor higher rates. Renegotiations with Eskom and EDM lead to a ratestructure which is close to what EDM currently pays for power imports fromEskom (see Annex C). The same rates would apply to additional suppliesfrom Cahora Bassa (> 200 MW), since any increase in EDM's share wouldcome at the expense of Eskom's entitlements and, therefore, is tantamount toimporting from the RSA.

62 Specific fuel consumption is 0.3 lIkWh for diesel, 0.4 UIkWh for jet fuel (to run a gas turbine), and 1. Ikg/kWh for coal. Economic costs of fuel use (including lubes) are 0.24 US$/I for diesel, 0.30 US$/1for jet fuel, and 28 US$/t for coal. Average fuel costs are based on a diesel-jet fuel mix of 85:15.

85


(iii) Annual expenditures for operating and maintaining (O+M) the grid areequivalent to 0.75 percent (1.25 percent) of the investments in transmission(distribution) facilities. The useful life of these facilities is 30 years.

(iv) The useful life of the gas turbine proposed for Nacala is 25 years,considering that it will be operated on a standby basis.

(v) The rate of discount is 10 percent a year.

(vi) The projections of the incremental payments for EDM's labor force and theincremental maintenance costs associated with generating plant are shown inTable G.9. The table also presents the scenario-independent changes inthermal generation.

Table G.9: Selected Incremental Costs andIncremental Thermal Generation

Year ISA La IMG0 IOM(f1996 0.0 0.0 -21997 0.1 0.0 01998 0.1 0.1 11999 0.1 0.0 12000 0.3 0.0 02001 0.4 -0. 1 12002 0.2 -0. 1 -162003 0.1 0.0 12004 0.1 0.0 02005 0.2 0.0 02006 0.2 -0. 1 02007 0.2 0.0 22008 0.2 0.0 02009 0.2 0.0 02010 0.2 0.0 0

a. Incremental salaries (US$ million); total salaries 1995: US$ 7.6million.

b. Incremental maintenance in generation (US$ million); total costs in1995: US$ 2 million.

c. Incremental thermal generation (GWh); total thermal generation in1995: 38 GWh.


86


30. As shown in Table G. 10, total LRAIC vary significantly in direct proportion to theprojected increase in demand. Under the low-growth-cum-high-tariffs scenario, totalincremental costs net of technical losses amount to 9.13 UScents/kWh, which is consistentwith the underlying tariff assumption (i.e., EDM's target level of 9.5 UScents/kWh). Withmedium GDP-growth and a targeted tariff level of 7.5 UScents/kWh, the correspondingcosts work out at 5.98 UScents/kWh.

Table G.10: LRAIC of Power Supply

Low Growth, High Tariffs AMedium Growth, Low Tariffs

Generation:'UScents/kWh 2.795 2.803

Transmission:US$/kW/year 164.93 82.81UScents/kWh 2.853 1.432

Distribution:US$/kW/year 150.68 75.66UScents/kWh 2.606 1.308

Total T+D.US$/kW/year 315.61 158.47UScents/kWh 5.459 2.740

O+M (UScents/kWh):Transmission 0.202 0.101Distribution 0.307 0.154

MiscellaneousUScents/kWh: 0.367 0.184

Total 9.13 5.98

Note: In constant prices of 1995.

a. Based on investment costs and expenditures for fiuel, maintenance, etc.

Source: Mission estirnates.

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31. At the generation end, the scenario-dependent incremental costs lie close together(about 2.8 UScents/kWh). This is because the higher (investment) costs incurred under themediurn growth forecast are distributed over larger volumes of consumption and becausethe scenarios do not affect the principal sources of supply. Similarly, there is a considerablegap between the scenario-dependent transmission and distribution costs (5.46 vs. 2.74UScents/kWh) since the respective investment programs are insensitive to the rate at whichdemand is projected to grow.6 3

32. Assuming that the investments aimed at reinforcing and extending the grid areuseful and have been fashioned in a prudent way, it can be concluded that in EDM's systemthe T+D functions account for an exceptionally large share of costs. While this reflects thelow level of consumption relative to the size of the T+D assets (apart from the low level ofgeneration costs), it also implies that the development of future demand is a key variable indetermining the trend for long-run incremental costs of power supply.

63 It should be noted that we have already trimmed the T+D investment program submitted by EDM.Without these revisions, the long-run incremental costs would be even higher. By contrast, postponingsome investments would reduce the cost. For instance, a two years delay of the entire T+D investmentprogram would, certeris paribus, reduce the incremental T+D costs to 4.47 UScents/kWh for the lowgrowth scenario, and to 2.23 UScents/kWh for the medium growth scenario.

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BASIC FEATURES OF A REVISED TARIFF SYSTEM

1. The main concern of a revised tariff regime should be that it more closely signals toconsumers the structure and level of costs they impose on the system. Moreover, tariffsshould be transparent, non-distortionary, easy to implement, tailored to the customers' loadprofile, and account for their contribution to the system peak.

2. With the present load pattern and consumer characteristics and given that (low cost)hydropower is the main source of supply, there is no need for a sophisticated and highlyresponsive tariff system (e.g., time-of-use pricing). EDM should opt instead for a simpletwo-part tariff which distinguishes between capacity (kW of coincident peak) and energycosts, and discriminates across voltage levels. Should the picture change in the future,refinements (e.g. advanced peak-load pricing) could be easily introduced. While EDMwould be obliged to serve all customers at the proposed tariffs, it should be permitted tonegotiate separate contracts with large, strategically important users if they wish to do soand qualify for such agreements. In the same vein, EDM should be allowed to contract anddispatch power from independent, private producers operating under the new ElectricityLaw, which is currently under preparation. In such circumstances, EDM's benchmark fornegotiations would be its avoided costs at the point of delivery or injection (node pricing).Finally, the new sector legislation as well as concomitant sector reforms may eventuallylead to a partial or entire separation of generation, transmission, and distribution, or to anunbundling of services. In this event, the proposed tariff system, while becomingredundant, would still be a reasonable point of reference for a more competitive and fine-tuned rate structure.

3. Based on the LRAIC-estimates presented in Annex G, the proposed structure andlevel of tariffs is determined as follows:

4. At the generation end, we assume that the peaker plant is a gas turbine. The annualcapacity costs, including fixed expenditures for maintenance and repair, amount to 90US$/kW.64 At a load factor of 0.66, this is equivalent to 1.6 UScents/kWh.65 Since totalincremental costs of bulk supply (generation plus imports and/or acquisitions) work out at2.8 UScents/kWh, the balance of 1.2 UScents/kWh is attributable to variable costs which

64 Specific investment costs: 650 US$ per installed kW; useful life of 20 years; interest of 10% a year;annual maintenance of 14 US$/kW.

65 Note that the load factor of 0.66 is an (essentially arbitrary) assumption made to convert capacity costsinto a per-kWh rate. It should not be confused with the load factor of a plant used to serve peak load,which depends on the length of the peak period and would only be relevant in the case of strict peak-load pricing.

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should be recovered through an energy rate. In addition, we suggest to adjust the energyrate so as to make up for the miscellaneous investment costs.

5. Overall technical losses are assumed to devour 14 percent of bulk supply: 6 percentat the high voltage (HV) level, 2.5 percent at the medium voltage (MV) level, and 5.5percent at the low voltage (LV) level.

6. Incremental transmission costs are charged at the HV level, while primary andsecondary distribution costs are apportioned among LV and MV consumption on a 2:1basis. Transmission-related O+M expenditures are factored into the HV rates, and those forthe distribution system are charged at the LV level.

7. Under present conditions, it does not seem expedient to differentiate tariffs byregion or location. Once the northern and central system are interconnected and thesouthern region has access to power from HCB, the average cost of bulk supplies becomefairly uniform across the subsystems. Furthermore, average network losses in the southernand northern-central region tend to converge. Clearly, there are significant locationaldifferences in transmission losses. For example, along the northern grid losses increasefrom I percent at Tete to about 6 percent in Mucuba, and to 10 percent in Nacala. Unlessdemand becomes more diversified than is currently the case, however, there is nocompelling economic reason why these losses should not be treated as a public bad.

8. A stronger case could be made for regionally discriminatory tariffs on account of thegeographic distribution of EDM's planned investrnents. About two-thirds of the proposedexpenditures are accounted for by projects aimed at strengthening and expanding thenetwork in the northern and central part of the country. The Government would justify theimplied cross-subsidies on political grounds. While this is a valid point which is not at thediscretion of EDM, it does not relieve EDM of the need to select solutions that meetpolitical imperatives at least cost, which is what we tried to accomplish by streamliningEDM's investment program (see Annex G).

9. Table H. 1 presents in skeletal form the structure of a tariff system based on theabove assumptions and considerations. The level of tariffs varies with the rate at whichconsumption is expected to increase. Tariffs do not account for non-technical losses.

10. Table H.2 gives an idea of how the proposed two-part tariffs would translate into(notional) average rates depending on voltage-specific load factors. It also shows that thecorresponding system average tariffs vary between 6.95 UScents/kWh (medium growth)and 10.43 UScents/kWh (low growth).

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Table H.1: Structure of a Revised Tariff SystemLow Growth, High Tariffs Medium Growth, Low Tariffs

CumulativeTechnical Capacity Energy Capacity Energy

Losses (°) (S/k W/fonth) (UScents/k Wh) (USS/kl/month) (UScents/lk Wh)Generationa 7.50 1.57 7.50 1.38Transmission 13.75 0.20 6.90 0.10Losses 1.36 0.11 0.92 0.09

Total HV 6.0 22.61 1.88 15.32 1.57Primary Distrib. 4.17 2.10Losses 1.00 0.06 0.61 0.05

Total MV 8.5 27.78 1.94 18.03 1.62Secondary Distrib. 8.39 0.31 4.2 0.16Losses 3.14 0.17 1.85 0.13

Total LV 14.0 39.14 2.42 24.08 1.91

Note: In prices of 1995.

a. Energy rate is adjusted so as to recover miscellaneous investment costs.


Table H.2: Notional Average Tariffs (UScents/kWh)LFa Low Growth Medium Growth

HV 0.65 6.65 4.79MV 0.58 8.50 5.88LV 0.54 12.35 8.02System Averageb 10.43 6.95

a. Assumed load factor.b. Demand is assumed to be composed of 8 percent HV, 38 percent MV and 54 percent LV.


11. For comparison, in May 1995 average tariffs amounted to 6.35 UScents/kWh for"tarifa social" customers, varied between 6.98 and 9.78 UScents/kWh for LV-users (from1.1 to 19.8 kVA), were 8.50 UScents/kWh for short-utilization MV-customers, 4.68UScents/kWh for long-utilization MV-customers, and 4.12 UScents/kWh for long-utilization HV-customers.66 Hence, the tariffs associated with the medium growth scenariowould make most customers neither better nor worse off, compared to what they paid inmnid- 1995.

66 Figures apply to the Southern System at 8000 MT/US$. It should be also borne in mind that the tariffaverages include what customers were charged for rated capacity, which was more than twice as muchas what they would have had to pay if their contribution to the system peak had been measuredaccurately.

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12. This study takes the more optimistic view that EDM should adopt the tariff systembased on the medium-growth scenario rather than that corresponding to the low-growthscenario, since the latter is tantamount to assuming that Mozambique will fail to makereasonably satisfactory economic progress, with no scope for increases in per-capitaincome. In any case, EDM could embark on setting the tariffs at the medium-growth leveland revise this decision if and when GDP and electricity consumption grow at a lower ratethan is needed to meet its revenue requirements.

13. In the following lines, the above approach to structuring EDM's tariffs is appliedto accounting cost estimates underlying the financial projections agreed upon by EDMand the Ministry of Finance. To simplify matters, the financial data used cover the period1996-2000 (rather than 1996-2005). It should be stressed that this exercise servesillustrative purposes. It is not meant as a revision of the methodology and the estimatespresented above.

14. The assumptions EDM made to forecast its financial performance are shown inTable H.3. In particular, EDM assumes that

* HCB-power is available in the southern system at 0.25 UScents/kWh by 1998,* depreciation charges are proportional to the book value of existing assets as

agreed upon in the financial restructuring program,* technical losses amount to 11.4 percent of gross supply, and* nontechnical losses are not accounted for.

15. In addition, we assume that

* EDM earns a 3.6 percent rate of return over the entire period underconsideration (before taxes and including "extraordinary costs"), 67

* the cost of capital (including profits) or, equivalently, the discount rate, is 10percent a year,

* the system load factor is 0.66 (an assumption about the load factor is neededto obtain the system peaks implied by the forecast of gross consumption).

16. Another assumption is that interest payments and profits are allocated across thedifferent assets in proportion to their relative size. Both items constitute the cost ofcapital.

67 By contrast, EDM assumes that a 3.6 percent rate of return will be achieved not before 1998 whenaverage tariff revenues are expected to reach the target level of 9.5 UScents/kWh.

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17. Discounting the different cost streams at a uniform rate of 10 percent gives thecorresponding present values (in constant prices of 1995) shown in the second column ofTable H.3.

Table H.3: EDM's Projected Financial Performance, 1996-2000PV 1996 1997 1998 1999 2000

Gross Cons.(GWh) 3,691 908.8 938.5 975.7 1020.8 1060.6

System Peak(MW) 638.1 157 162 169 177 183

Var. GeneralCosts 57,188 19,970 21,156 9,838 10,532 11,216

Other Var.Costs 42,514 10.393 11,716 11,051 11,396 11,752

O+MTransmission 8.091 1,531 1,942 2,294 2,525 2,651

O+MDistribution 12,813 2,450 2,994 3,586 3,979 4,348

DepreciationGeneral 34,448 8,723 8,984 9,116 9,345 9,559

DepreciationTransmission 22,042 4,404 4,872 6,064 7,011 7,516

DepreciationDistribution 20,698 4,297 4,618 5,533 6,508 7,043

DepreciationAdmin. 21,280 5,052 5,352 5,663 5,984 6,316

Total

Depreciation 98,467Interest 5,075 9,417 14,962 18,229 18,977Profits 10,000 10,000 14,286 10,688 10,184

Note: Cost in US$ 1000; variable generating costs comprise power purchases, EDM supplies andgenerating O+M; other variable costs include salaries, administrative and miscellaneous costs;O+M stands for operation and maintenance; PV denotes present value in 1995.


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18. To compute the corresponding long-run average costs of power generation,variable generation costs, miscellaneous variable costs, and amortizations pertaining toEDM's plant and administrative assets (including the respective cost of capital) arelumped together. 68 The ratio of the present value of these costs to the present value ofprojected gross consumption gives an estimate of the average cost of power generation (=

5.585 UScents/kWh).

19. Likewise, long-run average costs of power transmission and distribution areapproximated by dividing the present value of the depreciation streams (plus the cost ofcapital) by the present value of projected peaks. The resulting estimates are 65.98US$1kW (transmission) and 61.96 US$/kW (distribution). For the costs of operating andmaintaining the network, we use the discounted sum of gross consumption as adenominator. The estimates are 0.22 UScents/kWh (transmission) and 0.35UScents/kWh (distribution).

20. The above estimates are then transformed into voltage-specific two-part tariffsconsisting of a capacity charge, which should account for each customers' contribution tothe system peak, and an energy fee (see Table H.4). To this end, the followingassumptions are made:

* The peaker plant would be a gas turbine with installed costs of 90 US$/kW.With a load factor of 0.66, this is equivalent to 1.625 UScents/kWh. Theremainder of the estimated long-run generation costs (5.585 - 1.625 = 3.96UScents/kWh) is accounted for as an energy fee.

* Technical losses are made up by 5 percent at HV, 2 percent at MV and 4.4percent at LV.

* Transmission costs are charged at HV.* Distribution costs are apportioned between LV and MV on a 2:1 basis.

21. The resulting tariff structure is shown in Table H.4. The estimate of systemaverage costs rests on the assumption that demand is composed of 8 percent RV, 38percent MV, and 54 percent LV consumption, respectively.

22. The methodological difference between the example based on EDM's financialprojections and the figures presented in this study is that the latter are future-oriented,while the financial estimates reflect historic (revalued) costs.

68 Administrative costs are considered as overheads charged to all customers supplied by EDM.

94

Annex HPage 7 of 7

Table H.4: Illustrative Structure of Tariffs Based on EDM's Financial ProjectionsCapacity Energy Average Costs

(S/kW/month) (Uscents/kWh) LF cents/kWhGeneration 7.500 3.96 0.66 5.585Transmission 5.500 0.22Losses (5%) 0.684 0.22

Total HV 13.684 4.40 0.65 7.284

Primary Dist. 1.722 0.12Losses (2%) 0.314 0.092

Total MV 15.720 4.612 0.58 8.325

Secondary Dis 3.444 0.230Losses (4.4%) 0.882 0.223

Total LV 20.046 5.065 0.54 10.150

System Average 9.227


23. In particular, the numerical differences between the tariffs based on the medium-growth scenario and the tariffs shown in Table H.4 can be explained mainly by the factthat in EDM's financial accounts the absolute and relative level of generation costs ishigher than would be justified on the basis of planned future investments. The highabsolute level of generation costs is due to the fact that the financial figures representlarge recent investments in generation plants (e.g. Maputo gas turbine, Corumanahydropower plant, etc.), which more than offset the assumed savings from low cost HCB-power. The relative difference can be attributed to the fact that in the investment programadvanced in this study there are almost no future investments in generation and there aremany future investments to reinforce and expand the network (hence, higher T+D chargesin the estimates associated with the medium-growth scenario than in the financialexample).

Joint UNDP/World BankENERGY SECTOR MANAGEMENT ASSISTANCE PROGRAMME (ESMAP)

LIST OF REPORTS ON COMPLETED ACTIVITIES

Region/Country .4ctivity/Report Title Date Number

SUB-SAHAIRAN AFRICA (AFR)

Africa Regional Anglophone Africa Household Energy Workshop (English) 07/88 085/88Regional Power Seminar on Reducing Electric Power SystemLosses in Africa (English) 08/88 087/88

Institutional Evaluation of EGL (English) 02/89 098/89Biomass Mapping Regional Workshops (English) 05/89--Francophone Household Energy Workshop (French) 08/89 103/89Interafrican Electrical Engineering College: Proposals for Short-and Long-Term Development (English) 03/90 112/90

Biomass Assessment and Mapping (English) 03/90 --Angola Energy Assessment (English and Portuguese) 05/89 4708-ANG

Power Rehabilitation and Technical Assistance (English) 10/91 142/91Benin Energy Assessment (English and French) 06/85 5222-BENBotswana Energy Assessment (English) 09/84 4998-BT

Pump Electrification Prefeasibility Study (English) 01/86 047/86Review of Electricity Service Connection Policy (English) 07/87 071/87Tuli Block Farms Electrification Study (English) 07/87 072/87Household Energy Issues Study (English) 02/88 --Urban Household Energy Strategy Study (English) 05/91 132/91

Burkina Faso Energy Assessment (English and French) 01/86 5730-BURTechnical Assistance Program (English) 03/86 052/86Urban Household Energy Strategy Study (English and French) 06/91 134/91

Burundi Energy Assessment (English) 06/82 3778-BUPetroleum Supply Management (English) 01/84 012/84Status Report (English and French) 02/84 011/84Presentation of Energy Projects for the Fourth Five-Year Plan(1983-1987) (English and French) 05/85 036/85

Improved Charcoal Cookstove Strategy (English and French) 09/85 042/85Peat Utilization Project (English) 11/85 046/85Energy Assessment (English and French) 01/92 9215-BU

Cape Verde Energy Assessment (English and Portuguese) 08/84 5073-CVHousehold Energy Strategy Study (English) 02/90 110/90

Central AfricanRepublic Energy Assessement (French) 08/92 9898-CAR

Chad Elements of Strategy for Urban Household EnergyThe Case of N'djamena (French) 12/93 160/94

Comoros Energy Assessment (English and French) 01/88 7104-COMCongo Energy Assessment (English) 01/88 6420-COB

Power Development Plan (English and French) 03/90 106/90C6te d'lvoire Energy Assessment (English and French) 04/85 5250-IVC

Improved Biomass Utilization (English and French) 04/87 069/87Power System Efficiency Study (English) 12/87 --Power Sector Efficiency Study (French) 02/92 140/91Project of Energy Efficiency in Buildings 09/95 175/95

Ethiopia Energy Assessment (English) 07/84 474 1-ET

-2-

Region/Country Activitv/Report Title Date Number

Ethiopia Power System Efficiency Study (English) 10185 045/85Agricultural Residue Briquetting Pilot Project (English) 12/86 062/86Bagasse Study (English) 12/86 063/86Cooking Efficiency Project (English) 12/87 --Energy Assessment 02/96 179/96

Gabon Energy Assessment (English) 07/88 6915-GAThe Gambia Energy Assessment (English) 11/83 4743-GM

Solar Water Heating Retrofit Project (English) 02/85 030/85Solar Photovoltaic Applications (English) 03/85 032/85Petroleum Supply Management Assistance (English) 04/85 035/85

Ghana Energy Assessment (English) 11/86 6234-GHEnergy Rationalization in the Industrial Sector (English) 06/88 084/88Sawmill Residues Utilization Study (English) 11/88 074/87Industrial Energy Efficiency (English) 11/92 148/92

Guinea Energy Assessment (English) 11/86 6137-GUIHousehold Energy Strategy (English and French) 01/94 163/94

Guinea-Bissau Energy Assessment (English and Portuguese) 08/84 5083-GUBRecommended Technical Assistance Projects (English &Portuguese) 04/85 033/85

Management Options for the Electric Power and Water SupplySubsectors (English) 02/90 100/90

Power and Water Institutional Restructuring (French) 04/91 118/91Kenya Energy Assessment (English) 05/82 3800-KE

Power System Efficiency Study (English) 03/84 014/84Status Report (English) 05/84 016/84Coal Conversion Action Plan (English) 02/87 --Solar Water Heating Study (English) 02/87 066/87Peri-Urban Woodfuel Development (English) 10/87 076/87Power Master Plan (English) 11/87 --

Lesotho Energy Assessment (English) 01/84 4676-LSOLiberia Energy Assessment (English) 12/84 5279-LBR

Recommended Technical Assistance Projects (English) 06/85 038/85Power System Efficiency Study (English) 12/87 081/87

Madagascar Energy Assessment (English) 01/87 5700-MAGPower System Efficiency Study (English and French) 12/87 075/87Environmental Impact of Woodfuels (French) 10/95 176/95

Malawi Energy Assessment (English) 08/82 3903-MALTechnical Assistance to Improve the Efficiency of FuelwoodUse in the Tobacco Industry (English) 11/83 009/83

Status Report (English) 01/84 013/84Mali Energy Assessment (English and French) 11/91 8423-MLI

Household Energy Strategy (English and French) 03/92 147/92Islamic Republicof Mauritania Energy Assessment (English and French) 04/85 5224-MAU

Household Energy Strategy Study (English and French) 07/90 123/90Mauritius Energy Assessment (English) 12/81 3510-MAS

Status Report (English) 10/83 008/83Power System Efficiency Audit (English) 05/87 070/87Bagasse Power Potential (English) 10/87 077/87Energy Sector Review (English) 12/94 3643-MAS

Morocco Energy Sector Institutional Development Study (English andFrench) 07/95 173/95

-3-

Region/Country Activity/Report Title Date NVumber

Mozambique Energy Assessment (English) 01/87 6128-MOZHousehold Electricity Utilization Study (English) 03/90 113/90Electricity Tariffs Study 06/96 181/96

Namibia Energy Assessment (English) 03/93 11320-NAMNiger Energy Assessment (French) 05/84 4642-NIR

Status Report (English and French) 02/86 051/86Improved Stoves Project (English and French) 12/87 080/87Household Energy Conservation and Substitution (Englishand French) 01/88 082/88

Nigeria Energy Assessment (English) 08/83 4440-UNIEnergy Assessment (English) 07/93 11672-UNI

Republic ofSouth Africa Options for the Structure and Regulation of Natural Gas

Industry (English) 05/95 172/95Rwanda Energy Assessment (English) 06/82 3779-RW

Energy Assessment (English and French) 07/91 8017-RWStatus Report (English and French) 05/84 017/84Improved Charcoal Cookstove Strategy (English and French) 08/86 059/86Improved Charcoal Production Techniques (English and French) 02/87 065/87Commercialization of Improved Charcoal Stoves and CarbonizationTechniques Mid-Tern Progress Report (English and French) 12/91 141/91

SADC SADC Regional Power Interconnection Study, Vol. I-IV (English) 12/93 --SADCC SADCC Regional Sector: Regional Capacity-Building Program

for Energy Surveys and Policy Analysis (English) 11/91Sao Tomeand Principe Energy Assessment (English) 10/85 5803-STP

Senegal Energy Assessment (English) 07/83 4182-SEStatus Report (English and French) 10/84 025/84Industrial Energy Conservation Study (English) 05/85 037/85Preparatory Assistance for Donor Meeting (English and French) 04/86 056/86Urban Household Energy Strategy (English) 02/89 096/89Industrial Energy Conservation Program 05/94 165/94

Seychelles Energy Assessment (English) 01/84 4693-SEYElectric Power System Efficiency Study (English) 08/84 021/84

Sierra Leone Energy Assessment (English) 10/87 6597-SLSomalia Energy Assessment (English) 12/85 5796-SORepublic of Options for the Structure and Regulation of Natural

South Africa Gas Industry (English) 05/95 172/95Sudan Management Assistance to the Ministry of Energy and Mining 05/83 003/83

Energy Assessment (English) 07/83 4511-SUPower System Efficiency Study (English) 06/84 018/84Status Report (English) 11/84 026/84Wood Energy/Forestry Feasibility (English) 07/87 073/87

Swaziland Energy Assessment (English) 02/87 6262-SWTanzania Energy Assessment (English) 11/84 4969-TA

Peri-Urban Woodfuels Feasibility Study (English) 08/88 086/88Tobacco Curing Efficiency Study (English) 05/89 102/89Remote Sensing and Mapping of Woodlands (English) 06/90 --Industrial Energy Efficiency Technical Assistance (English) 08/90 122/90

Togo Energy Assessment (English) 06/85 5221 -TOWood Recovery in the Nangbeto Lake (English and French) 04/86 055/86

- 4 -

Region/Country Activity/Report Title Date Number

Togo Power Efficiency Improvement (English and French) 12187 078/87Uganda Energy Assessment (English) 07/83 4453-UG

Status Report (English) 08/84 020/84Institutional Review of the Energy Sector (English) 01/85 029/85Energy Efficiency in Tobacco Curing Industry (English) 02/86 049/86Fuelwood/Forestry Feasibility Study (English) 03/86 053/86Power System Efficiency Study (English) 12/88 092/88Energy Efficiency Improvement in the Brick andTile Industry (English) 02/89 097/89

Tobacco Curing Pilot Project (English) 03/89 UNDP TerminalReport

Zaire Energy Assessment (English) 05/86 5837-ZRZambia Energy Assessment (English) 01/83 4110-ZA

Status Report (English) 08/85 039/85Energy Sector Institutional Review (English) 11/86 060/86

Zambia Power Subsector Efficiency Study (English) 02/89 093/88Energy Strategy Study (English) 02/89 094/88Urban Household Energy Strategy Study (English) 08/90 121/90

Zimbabwe Energy Assessment (English) 06/82 3765-ZIMPower System Efficiency Study (English) 06/83 005/83Status Report (English) 08/84 019/84Power Sector Management Assistance Project (English) 04/85 034/85Petroleum Management Assistance (English) 12/89 109/89Power Sector Management Institution Building (English) 09/89 --Charcoal Utilization Prefeasibility Study (English) 06/90 119/90Integrated Energy Strategy Evaluation (English) 01/92 8768-ZIMEnergy Efficiency Technical Assistance Project:Strategic Framework for a National Energy EfficiencyImprovement Program (English) 04/94 --

Capacity Building for the National Energy EfficiencyImprovement Programme (NEEIP) 12/94 --

EAST ASIA AND PACIFIC (EAP)

Asia Regional Pacific Household and Rural Energy Seminar (English) 11/90China County-Level Rural Energy Assessments (English) 05/89 101/89

Fuelwood Forestry Preinvestment Study (English) 12/89 105/89Strategic Options for Power Sector Reform in China (English) 07/93 156/93Energy Efficiency and Pollution Control in Township andVillage Enterprises (TVE) Industry (English) 11/94 168/94

Fiji Energy Assessment (English) 06/83 4462-FIJIndonesia Energy Assessment (English) 11/81 3543-IND

Status Report (English) 09/84 022/84Power Generation Efficiency Study (English) 02/86 050/86Energy Efficiency in the Brick, Tile andLime Industries (English) 04/87 067/87

Diesel Generating Plant Efficiency Study (English) 12/88 095/88Urban Household Energy Strategy Study (English) 02/90 107/90Biomass Gasifier Preinvestment Study Vols. I & II (English) 12/90 124/90

- 5 -


Indonesia Prospects for Biomass Power Generation with Emphasis onPalm Oil, Sugar, Rubberwood and Plywood Residues (English) 11/94 167/94

Lao PDR Urban Electricity Demand Assessment Study (English) 03/93 154/93Malaysia Sabah Power System Efficiency Study (English) 03/87 068/87

Gas Utilization Study (English) 09/91 9645-MAMyanmar Energy Assessment (English) 06/85 5416-BAPapua NewGuinea Energy Assessment (English) 06/82 3882-PNG

Status Report (English) 07/83 006/83Energy Strategy Paper (English)Institutional Review in the Energy Sector (English) 10/84 023/84Power Tariff Study (English) 10/84 024/84

Philippines Commercial Potential for Power Production fromAgricultural Residues (English) 12/93 157/93Energy Conservation Study (English) 08/94 --

Solomon Islands Energy Assessment (English) 06/83 4404-SOLEnergy Assessment (English) 01/92 979/SOL

South Pacific Petroleum Transport in the South Pacific (English) 05/86 --Thailand Energy Assessment (English) 09/85 5793-TH

Rural Energy Issues and Options (English) 09/85 044/85Accelerated Dissemination of Improved Stoves andCharcoal Kilns (English) 09/87 079/87

Northeast Region Village Forestry and WoodfuelsPreinvestment Study (English) 02/88 083/88

Impact of Lower Oil Prices (English) 08/88 --Coal Development and Utilization Study (English) 10/89 --

Tonga Energy Assessment (English) 06/85 5498-TONVanuatu Energy Assessment (English) 06/85 5577-VAVietnam Rural and Household Energy-Issues and Options (English) 01/94 161/94

Power Sector Reform and Restructuring in Vietnam: Final Reportto the Steering Committee (English and Vietnamese) 09/95 174/95Household Energy Technical Assistance: Improved CoalBriquetting and Commercialized Dissemination of HigherEfficiency Biomass and Coal Stoves (English) 01/96 178/96

Western Samoa Energy Assessment (English) 06/85 5497-WSO

SOUTH ASIA (SAS)

Bangladesh Energy Assessment (English) 10/82 3873-BDPriority Investment Program (English) 05/83 002/83Status Report (English) 04/84 015/84Power System Efficiency Study (English) 02/85 031/85Small Scale Uses of Gas Prefeasibility Study (English) 12/88

India Opportunities for Commercialization of NonconventionalEnergy Systems (English) 11/88 091/88

Maharashtra Bagasse Energy Efficiency Project (English) 07/90 120/90Mini-Hydro Development on Irrigation Dams andCanal Drops Vols. I, II and III (English) 07/91 139/91

WindFarn Pre-Investment Study (English) 12/92 150/92Power Sector Reform Seminar (English) 04/94 166/94

-6 -


Nepal Energy Assessment (English) 08/83 4474-NEPStatus Report (English) 01/85 028/84NepalEnergy Efficiency & Fuel Substitution in Industries (English) 06/93 158/93

Pakistan Household Energy Assessment (English) 05/88 --Assessment of Photovoltaic Programs, Applications, andMarkets (English) 10/89 103/89

National Household Energy Survey and Strategy FomulationStudy: Project Terminal Report (English) 03/94 --

Managing the Energy Transition (English) 10/94Lighting Efficiency Improvement ProgramPhase 1: Commercial Buildings Five Year Plan (English) 10/94

Sri Lanka Energy Assessment (English) 05/82 3792-CEPower System Loss Reduction Study (English) 07/83 007/83Status Report (English) 01/84 010/84Industrial Energy Conservation Study (English) 03/86 054/86

EUROPE AND CENTRAL ASIA (ECA)

Eastern Europe The Future of Natural Gas in Eastern Europe (English) 08/92 149/92Poland Energy Sector Restructuring Program Vols. I-V (English) 01/93 153/93Portugal Energy Assessment (English) 04/84 4824-POTurkey Energy Assessment (English) 03/83 3877-TU

MIDDLE EAST AND NORTH AFRICA (MNA)

Morocco Energy Assessment (English and French) 03/84 4157-MORStatus Report (English and French) 01/86 048/86Energy Sector Institutional Development Study (English and French) 05/95 173/95

Syria Energy Assessment (English) 05/86 5822-SYRElectric Power Efficiency Study (English) 09/88 089/88Energy Efficiency Improvement in the Cement Sector (English) 04/89 099/89Energy Efficiency Improvement in the Fertilizer Sector(English) 06/90 115/90

Tunisia Fuel Substitution (English and French) 03/90 --Power Efficiency Study (English and French) 02/92 136/91Energy Management Strategy in the Residential andTertiary Sectors (English) 04/92 146/92

Yemen Energy Assessment (English) 12/84 4892-YAREnergy Investment Priorities (English) 02/87 6376-YARHousehold Energy Strategy Study Phase I (English) 03/91 126/91

LATIN AMERICA AND THE CARIBBEAN (LAC)

LAC Regional Regional Seminar on Electric Power System Loss Reductionin the Caribbean (English) 07/89 --

Bolivia Energy Assessment (English) 04/83 4213-BONational Energy Plan (English) 12/87 --National Energy Plan (Spanish) 08/91 131/91

-7-


Bolivia La Paz Private Power Technical Assistance (English) 11/90 111/90Natural Gas Distribution: Economics and Regulation (English) 03/92 125/92

Bolivia Prefeasibility Evaluation Rural Electrification and DemandAssessment (English and Spanish) 04/91 129/91

Private Power Generation and Transmission (English) 01/92 137/91Household Rural Energy Strategy (English and Spanish) 01/94 162/94Natural Gas Sector Policies and Issues (English and Spanish) 12/93 164/93

Brazil Energy Efficiency & Conservation: Strategic Partnership forEnergy Efficiency in Brazil (English) 01/95 170/95

Chile Energy Sector Review (English) 08/88 7129-CHColombia Energy Strategy Paper (English) 12/86 --

Power Sector Restructuring (English) 11/94 169/94Costa Rica Energy Assessment (English and Spanish) 01/84 4655-CR

Recommended Technical Assistance Projects (English) 11/84 027/84Forest Residues Utilization Study (English and Spanish) 02/90 108/90

DominicanRepublic Energy Assessment (English) 05/91 8234-DO

Ecuador Energy Assessment (Spanish) 12/85 5865-ECEnergy Strategy Phase I (Spanish) 07/88 --

Energy Strategy (English) 04/91Private Minihydropower Development Study (English) 11/92Energy Pricing Subsidies and Interfuel Substitution (English) 08/94 11798-ECEnergy Pricing, Poverty and Social Mitigation (English) 08/94 12831-EC

Guatemala Issues and Options in the Energy Sector (English) 09/93 12160-GUHaiti Energy Assessment (English and French) 06/82 3672-HA

Status Report (English and French) 08/85 041/85Household Energy Strategy (English and French) 12/91 143/91

Honduras Energy Assessment (English) 08/87 6476-HOPetroleum Supply Management (English) 03/91 128/91

Jamaica Energy Assessment (English) 04/85 5466-JMPetroleum Procurement, Refining, andDistribution Study (English) 11/86 061/86

Energy Efficiency Building Code Phase I (English) 03/88 --Energy Efficiency Standards andLabels Phase I (English ) 03/88 --

Management Information System Phase I (English) 03/88 --

Charcoal Production Project (English) 09/88 090/88FIDCO Sawmill Residues Utilization Study (English) 09/88 088/88Energy Sector Strategy and Investment Planning Study (English) 07/92 135/92

Mexico Improved Charcoal Production Within Forest Management for 08/91 138/91the State of Veracruz (English and Spanish)

Energy Efficiency Management Technical Assistance to theComision Nacional para el Ahorro de Energia (CONAE) (English) 04/96 180/96

Panama Power System Efficiency Study (English) 06/83 004/83Paraguay Energy Assessment (English) 10/84 5145-PA

Recommended Technical Assistance Projects (English) 09/85 --Status Report (English and Spanish) 09/85 043/85

Peru Energy Assessment (English) 01/84 4677-PEStatus Report (English) 08/85 040/85Proposal for a Stove Dissemination Program inthe Sierra (English and Spanish) 02/87 064/87

-8 -


Peru Energy Strategy (English and Spanish) 12/90 --Study of Energy Taxation and Liberalizationof the Hydrocarbons Sector (English and Spanish) 120/93 159/93

Saint Lucia Energy Assessment (English) 09/84 5111-SLUSt. Vincent andthe Grenadines Energy Assessment (English) 09/84 5103-STV

Trinidad andTobago Energy Assessment (English) 12/85 5930-TR

GLOBAL

Energy End Use Efficiency: Research and Strategy (English) 11/89Guidelines for Utility Customer Management andMetering (English and Spanish) 07/91 --

Women and Energy--A Resource GuideThe Intemational Network: Policies and Experience (English) 04/90 --

Assessment of Personal Computer Models for EnergyPlanning in Developing Countries (English) 10/91 --

Long-Term Gas Contracts Principles and Applications (English) 02/93 152/93Comparative Behavior of Firms Under Public and PrivateOwnership (English) 05/93 155/93

Development of Regional Electric Power Networks (English) 10/94 --

Roundtable on Energy Efficiency (English) 02/95 171/95Assessing Pollution Abatement Policies with a Case Study of Ankara 11/95 177/95

06/11/96

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Sff§ ---Energy Setor Management Assistance...

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