Report No. 4135-MOR Morocco LE Y Plower Subsector Study March 19, 1984 Projects Department Europe, Middle East and North Africa Regional Office FOR OFFICIAL USE ONLY Document of the World Bank This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. CURRENCY EQUIVALENTS Currency Unit = Dirham (DH) DH 1 = 100 Centimes (cDH) DH 5.50 = UStl (November 1982) DH 1 = US $0.18 WEIGHTS AND MEASURES 1 kilometer (km) = 0.621 mile 1 ton = 1.102 short ton (sh ton) 0.984 long ton (lg ton) 1 kilowatt (kW) = 1,000 watts 1 megawatt (MW) = 1,000 kilowatts (103 kW) 1 gigawatt = 1 million kilowatts (106 kW) 1 kilowatt-hour (kWh) = 1,000 watt-hours (103 Wh) 1 megawatt-hour (MWh) = 1,000 kilowatt-hours (103 kWh) 1 gigawatt-hour (GWh) = 1,000,000 kWh (106 kWh) 1 kilovolt (kV) = 1,000 volts (103 V) 1 kilovolt-ampere (kVA) = 1,000 volts (103 V) 1 megavolt-ampere (MVA) = 1,000 kVA (103 kVA) GLOSSARY OF ABBREVIATIONS BRPM - Bureau de recherches et participations minieres (Bureau of Mineral Exploration and Participation) FEC - Fonds d'equipement communal (Communal Infrastructure Fund) FSDR - Fonds special pour le developpement regional (Special Regional Development Fund) FDCL - Fonds de developpment des collectivites locales (Local Community Development Fund) HV - High voltage LRAIC - Long-run average incremental cost LRMC - Long-run marginal cost * LV - Low voltage NEM - Ministbre de l1'nergie et des mines (Ministry of of Energy and Mines) MI - Minist!re de l'interieur (Ministry of Interior) MV - Medium voltage ONE - Office national de l1'lectricit6 (National Electricity Authority) FOR OFFICIAL USE ONLY ABSTRACT This report identifies the major issues in Morocco's power subsector and the options open to the Moroccan authorities for dealing with them. It first reviews briefly the country's energy resources whose development may have an impact on the power subsector and recommends in particular that the Government formulate an optimal plan for the development of river basins and integrate it with the least-cost development program for power. The institutional setting of the subsector and the consequences of the fragmentation of its management are then examined, and the need for streamlining and integrating the subsector's operations is recognized. Measures to improve both demand forecasting and system planning are discussed and include inter alia, the collection of detailed data on current electricity consumption at all voltage levels, better coordination between ONE and the distribution regies in developing demand projections, an evaluation by ONE of alternative generation plans using different hydrological conditions and the corresponding sensitivity analysis, and a re-evaluation of all hydropower projects planned for 1990 and after. A detailed review of the system for electricity pricing indicates that the tariff structure is unnecessarily complicated and that tariffs are based neither on marginal costs derived from a least cost plan nor on financial objectives for the regies and ONE. An updating of the tariff study completed in 1978 is strongly recommended following the formulation of a national least-cost development program for the power subsector based on the integration of such plans for ONE and the regies. Finally, the proposed investment program for the development of the subsector between 1981 and 1985 is evaluated in the light of Morocco's current financial constraints, and recommendations are formulated to improve the efficiency of project implementation, finance the expansion of the distribution network, and reform the present system for financing hydropower projects. The need to investigate more closely the regies's operations and investment plans is highlighted and it is suggested to undertake a study of urban distribution as a follow-up to this report. March 1984 This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. I MORROCCO ]POWER SUBSECTOR STUDY Table of Contents Page I. INTRODUCTION 1 II. ENERGY RESOURCES 6 A. Overview 6 B. Hydropower 6 C. Coal 7 D. Oil and Gas 7 E. Oil Shale 8 F. Nuclear Fuel Material and Renewable Energy Resources 9 III. ORGANIZATIONAL STRUCTURE 10 A. Office national de l'electricite (ONE) 10 B. The regies 11 C. Isolated Systems and Autoproducers 14 D. Rural Electrification 15 E. Administration de l'hydraulique 16 F. Intra-Sectorial Coordination 16 IV. HISTORICAL TRENDS IN THE CONSUMPTION AND SUPPLY OF ELECTRICITY 19 A. Past Trends in Electricity Consumption 19 B. Past Trends in the Supply of Electricity 21 V. FORECAST CONSUMPTION ANID SUPPLY OF ELECTRICITY 24 A. Growth of the Economy 24 B. Future Electricity Demand 25 C. Future Electricity Supply 27 This report was prepared by I., Elwan (Senior Economist), J. Chassard (Consultant), and A. McKechnie (Economist), on the basis of a mission undertaken in January-February 1982 by J. Chassard and L. Maistre (consultants). Table of Contents (cont'd) Page VI. ELECTRICITY PRICING 31 A. Historical Review 31 B. Institutional Responsibility for Tariffs 33 C. Level of Existing Tariffs 34 D. Structure of Existing Tariffs 36 E. Strategy for New Electricity Tariffs 38 VII. INVESTMENT AND FINANCING 39 A. ONE's Investments during the 1978-1980 Development Plan 39 B. Planned Investment in the Power Subsector, 1981-1985 43 C. Financing Plan for the 1981-1985 Program 46 ANNEXE S 1. Historical Trends in the Consumption and Supply of Electricity 2. Forecast Consumption and Supply of Electricity 3. Electricity Pricing - iii - ANNEX 1 MOROCCO POWER SUBSECTOR STUDY Historical Trends in the Consumption and supply of Electricity Table of Contents Page A. Past Trends in Electricity Consumption 49 Overall Consumption 49 Electricity Consumption by Economic Sector 50 Electricity Consumption by Households 52 Consumption by Voltage Level 53 Regional Electricity Consumption 54 Distribution of Final Electricity Sales Between ONE and the Regies 55 B. Past Trends in the Supply of Electricity 55 Generating Capacity 55 Electricity Generation 57 Stations Use and Losses 57 Fuel Consumption for Power Generation 58 Transmission 59 Attachments 1. Installed Capacity of The-mal Plants, 1965-1981 60 2. Installed Capacity of Hydrmo Plants, 1965-1980 61 3. Supply of Electricity by Powr Station and Fuel, 1965-1981 62 4. Balance of Demand and Capacity, 1965-1981 63 5. National Electric Power Balance, 1980 64 6. Fuel Consumption for Electricity Generation, 1970-1981 65 7. Electricity Consumption by Sector (GWh) 66 8. Regional Consumption of Electricity (GWh) 67 9. ONE's and the Regies' Comparative Market Share (GWh) 68 - iv - ANNEX 2 MOROCCO POWER SUBSECTOR STUDY Forecast Consumption and Supply of Electricity Table of Contents Page A. Growth of the Economy 69 B. Future Electricity Demand 70 Intensity of Electricity Use 72 Improvements to Electricity Demand Forecasting 73 C. Future Electricity Supply 75 Future Generating Capacity 75 Future Production of Electricity 78 Optimization of Hydro Projects 79 Pricing of Inputs to Power Projects 80 Attachments 1. Forecast Consumption of Electricity by Economic Sector 81 2. Installed Capacity of Thermal Plants (1981-1990) 82 3. Installed Capacity of Hydro Plants, 1980-1995 83 4. Existing and Proposed Hydro Stations 84 5. Balance of Demand and Capacity, 1981-1990 85 6. Supply of Electricity by Power Station and Fuel, 1981-1990 86 - v- ANNEX 3 MOROCCO POWER SUBSECTOR STUDY Electricity Pricing Table of Contents Page A. Historical Review 87 B. Institutional Responsibil:ity for Tariffs 90 C. Level of Existing Tariffs 91 Economic Costs of Supp:Ly 91 Demand-Related Costs 91 Energy-Related Costs 91 Bulk Supply Tariffs 92 Retail Tariffs 93 Medium Voltage 93 Low Voltage 94 D. Structure of Existing Tariffs 95 Bulk Supply Tariffs 95 Retail tariffs 96 Medium Voltage 96 Low Voltage 96 E. Strategy for New Electricity Tariffs 97 Attachments 1. Typical Bulk Supply Tariffs 100 2. Retail Tariffs 101 3. Assumptions Used to Calcu:Late Long Run Average Incremental Costs 105 (0781P) I. INTRODUCTION 1.01 One of the main objectives of Morocco's 1981-1985 economic plan is the implementation of policies aimed at improving the country's balance of payments position. Energy is expected to play the pivotal role in achieving the objective of the plan. The plan calls for the reduction of energy imports by: (a) rationalizing energy prices to restrain the growth of domestic demand; (b) intervening directLy in the industrial processes to reduce energy consumption through retrofitting; and (c) substituting, where possible, relatively cheaper domestic or imported energy for the imported crude and petroleum products. 1.02 The power subsector in Morocco is the largest consumer of petroleum products and coal, accounting for 28% of the total commercial energy consumed (1981). As a result, the straLtegy for its future development, the policies adopted for pricing its output, the efficiency by which it uses energy, and the conservation by its consumers in their consumption of electricity would have a significant impact on determining whether Government energy policies achieve their objectives. 1.03 This report concentraies on identifying the major issues in the power subsector and the options open to the Moroccan authorities for dealing with them. (These are summarized in Table 1.1 below). Consequently, it should not be viewed as a comprehensive document that covers all aspects of the subsector, but as a policy-oriented document that addresses those issues which, in the view of the Bank mission, deserve immediate attention. 1.04 The report is divided in two parts. The first part provides a brief review of the setting for each issue and the recommendations of the mission compartmentalized under six chapters. The second part includes three annexes which provide more detailed support for the analysis presented in the first part. 1.05 Chapter II deals only with the energy resources whose development would have an impact on the power subsector. Therefore, greater emphasis is given to the hydropower potential, coal reserves, oil shale, and to a much lesser degree, the recent discovery of gas and its likely impact on power generation. 1.06 Chapter III presents l:he institutional setting of the power subsector and examines the consequences of the fragmentation of its management. 1.07 Chapter IV addresses ilhe past trends in the consumption and supply of electricity. The detailed ener-gy and capacity balances for the subsector and supporting data are presented as a part of Annex 1 which is intended as a more extensive review of the development of the subsector since 1975. 1.08 The forecast of energy and capacity balances for the power subsector is dealt with in Chapter V, and an assessment of the likely constraints to achieving the projected demand,/supply balance is discussed. - 2 - 1.09 Chapter VI considers the pricing of electricity and compares the structure and level of the prevailing tariffs with those dictated by the economic pricing of power. 1.10 Finally, Chapter VII reviews the investment plan for 1978-1980 and identifies the major constraints experienced in implementing the plan. The Chapter concludes with a detailed review of ONE's plan for 1981-1985. 1.11 The main shortcoming of the report is the absence of a section on the regies' plans for 1978-1980 and 1981-1985 due to the difficulty involved in gathering reliable information from a relatively large number of individual utilities and the lack of centralized data at the Ministry of the Interior. In order to fill the corresponding gap in our knowledge of the power subsector, the mission suggests to follow up on this report by a study focussing on urban distribution of electricity exclusively. Table Li Proposed Strategy for the Developnent of the Power Subsector Issues Objectives Reccmxendations Studies Priority I. EIY RE.SWRCES A. Hydrqxer A large rsmrber of multipurpose (a) Ensure against the development The Goverreant should undertake High dama are being developed without of nultipurpose scheanrs whose scale the formulation of an optimal plan guarantee that their developmcent or mix of uses are not justified on for the developnsent of river basins represents the optimal utiliza- econonic grounds. and the integration of the results tion of water resources in the of this plan with the least-cost country and is part of the (b) ensure against the development developnent program for the power least-cost program for the of marginal hydropcer sites subsector (para. 2.04). expansion of electricity (paras. 2.03-2.04). generation (para 2.03). II. ELECMRCITY PRICIN (a) The level of electricity (a)(i) Ensure the efficient allc- (a)(i) Forniulate a national least- (a) Update the tariff High tariffs is below the ecodioic cation of resources within the cost development program for the study ccpleted in cost of supply, particularly power subsector; (ii) ersure the power subsector based on the inte- 1978 (para. 6.16). the capacity charge; and development of CIE arnd the regies gration of such programs for OM insufficient to ensure the into financially viable public and the regies (para. 6.15); financial viability of the utilities (para. 6.15); (ii) formsulate a system for subsector(paras. 6.0-6.11). gathering, classifying and inte- grating the data pertaining to the consutption and production of electricity throughout the country (para. 6.16); (iii) the average tariff for electricity should be gradually roved to achieved parity with LRC (para. 6.11); (b) the structure of electricity (b)(i) ensure that corr-ect price (b) apply a single tariff at each Medim tariffs is still unneces- signals are given to final con- voltage level and for all regies sarily complicated, anxd sumers; (ii) maintain equity and unless large differerces in the existing regional differences simplicity in the tariff design arrginal costs of supply are do not reflect any significant (para. 6.12); identified (para. 6.12); differences in the marginal costs of supply (paras. 6.12-6.14); (c) CNE's financial performance (c) restore OXE's level. of inter- (c)(i) ocwe the restructuring of Low has deteriorated recently nally generated cash to 20% at electricity tariffs is inplearented, because: (i) it has not been least and allow it to recover the the fuel adjustment clause should allowed to pass on to consumers cost of increased fuel prices be activated and CtE should be given increases in the prices of (pares. 6.02-6.03). the authority to autaratically pass fuels (para. 6.02); (ii) its on to consurers all ircreases in fuel bill has increased substar- its fuel bill (para. 6.02); (ii) the tially because of lower hydro- tariff structure should be rede- generation due to the dmught signed to allow for the emnrgy charge (para 6.03). to be based on fuel consimption in hydmlogically bad years, and a fuel fund should be created to be used for smothing out the increases in the bulk tariffs needed to cover the ircreases in the cperating cost following dry years (para. 6.03). Table 1.1 Proposed Strategy for the Development of the Power Subsector Issues Objectives Recaomendations Studies Priority III. INVESIlfNT AND FINANCIll (a) Numerous restrictions and (a) Provide tIE with greater free- (a) The Goverrmnt should High carplex administrative proce- dom of decision in operating its make the funds earmarked for dures have resulted in slippages system and executing its develop- the utility's irivestmrnt program and delays in the implementa- ment program; available in a tirmly and efficient tion of projects (para. 7.06); manner through the establishment of a "developFaert contrace' with ONE; (b) the Goverment's coverage (b) CtE should be responsible for (b) undertake a Medium of the entire cost of the hydro- covering the cost of all equipment study to determine the electric components of multi- and share of caomon facilities most efficient and purpose das is irconsistent used for the generation, transmis- equitable neans by with its policy of increasing sion and distribution of electricity; which ONE can caopen- the financial autonomy of sate the Goverment public enterprises and with the for service provided principles of efficient resourre by the hydropower ccm- allocation (para. 7.16); ponents of nuitipurpose schenes. (c)(i) the current system for (c) ensure equity and least cost (c) plan the expansion of the Medium finaeming the developmnit of for the extension of the netwvrk. distribution netwrk on the urban distribution discrimi- basis of properly formulated nates against the urban poor; least-cost progrsa. (ii) the development of the retwork is dictated by the willingness and ability of consumars to pay the high cost of initial conmection and does not necessarily follow a least-cost path (paras. 7.17). IV. PLeNIJ; A. Deanad Forecasting (a) GE's forecasting approach (a) Ensure that forecasts of (a) ClE's staff should uork even more Low is simply the extrapolatiorn of demand for electricity are closely with the Ministry of Plannirg past trends, modified by knx- consistent with projected social and ensure that electricity demand ledge of short-term develop- and econcmic developient; forecasts by sector are based on meents in industrial sectors up-to-date detailed and realistic (paras. 5.06-5.07); economic projections; (b) forecastirg the demand (b) inprove electricity demad (b) CM and the regies should start by LV consmers is hampered forecasting, particularly at collecting detailed data on the car- by the limited information the low-voltage level. sumption and numbers of consumers on the LV sales and nmber supplied at LV; of consamers; (c) the rdgies are insuffi- (c) C1E should develop its coordi- Medium ciently involved in demanda nating role by pruviding a forum to forecasting. bring all the utilities' projections together and by assisting the rAgies in improving their forecastirg techniques. -5- Table 1.1 Proposed Strategy for the Development of the Power Subsector Issues Objective! Recamendations Studies Priority B. System Planning CtE's development program Optimize hydroelectric Revaluate the pcser projects High iwxludes a large nmber of projects. planed for commissioning in 1990 hydroelectric pmjects which and after. might overload its nanagement capabilities; in addition, there are uncertainties as to whether they are needed to meat detend or justified econcsnically (paras. 5.16-5.17). V. 0K3ANIZATICNAL STRDCIUIE (a) Tiere is a chronic conflict (a) Inprave the efficiency of the (a) MN and 14 should clarify the Mediu betwen CE and the regies on distribution system; conditions and the territory an the exctension of the latter's whiich CNE is expected to operate distribution perireters and draw up a netwrk nagent (para. 3.20); agreement between OM and the cannues; (b) the existing system does (b) reduce costs of inverntories (b) establish a special ccmittee, Mediun not cjpture the potential for and unify. stanidards; with representatives of both CkE substamtial ecnmanies of scale and the rdgies, to formulate unified in the procureent of ,m standards of proureent and examine equipment (para. 3.21); means by which an iventory cann to all utilities could be set up; (c) proposals for the (c) improve the efficiency by (c) appoint a working group to put Mediwt reorganization of the sector which the sector is Wauged and forth recommendations on the mns have not yet been fornulated developed. by which the operations of the power by the Geoerrnmnt (para. 3.22). subsector could be streamlined. - 6 - II. ENERGY RESOURCES A. Overview 2.01. Morocco's presently known domestic energy resources consist mainly of a large hydropower potential, a single coal deposit, some oil and gas whose reserves are currently being evaluated, large deposits of oil shale and uranium, fuelwood and solar energy. Presently, hydropower, oil and gas, coal and fuelwood are exploited commercially. The Government has recently initiated several pilot and demonstration projects to assess the potential for commercially exploiting the oil shale and solar energy; however, the contribution of these resources to the overall supply of energy in the near future is not expected to be significant. In order to continue its past efforts in accelerating the development of domestic energy resources and reducing the dependence on imported energy, the Government is preparing an overall energy plan that will integrate the development strategies for all the energy subsectors and identify national priorities. A review of energy planning and plan is discussed in more detail in the Energy Assessment Report: Morocco: Issues and Options in the Energy Sector. 1/ B. Hydropower 2.02. Morocco's hydropower potential, estimated at about 4,600 GWh per year under average hydraulic conditions, is located on the rivers Moulouya, Sebou and Oum Er Rbia. Only 40% (1,800 GWh) of that potential has been exploited, and the remaining potential of about 2,800 GWh, will be developed over the next 20 years, in two stages. The first step will involve the construction of 13 hydropower stations to tap about 2,000 GWh and should be carried out over the next 10 years given the advanced stage of the feasibility studies. The second stage will cover the development, between 1991 and 1998, of about 15 sites to harness the remaining potential of about 800 GWh; however, detailed studies need to be undertaken to establish the feasibility of the sites. 2.03. Morocco's hydropower potential would continue to be developed as an integral part of multipurpose dams because of the increasing demand for water for irrigation, water supply and power generation. The competing demands of these sectors dictate the balance of uses at the design stage in order to optimize the net benefit to the economy. However, this is a complex process because of the difficulties involved in allocating the common costs of multipurpose infrastructures between the sectors affected. Accuracy in the allocation of common costs is essential to ensuring that multipurpose schemes with marginal electric power potential are not developed by understating their 1/ Report 4157-MOR. - 7 - share of the costs. In recognizing the difficulties involved in determining the economic mix of uses for multipurpose dams, the Government commissioned a study aimed at the preparation of an integrated plan for the development of each of the river basins. Only the plan for the Oum Er Rbia 2/ has been finalized and its first two stages implemented. Under its 1983 program the Administration de l'hydraulique is to update the plan for the Oum Er Rbia as well as undertake the studies for the development of the Sebou and Bou-Regreg rivers. In addition, a subcommiittee for the development of river basins was recently established to determine the economic viability of all future projects. 2.04 If the hydropower potential is to be developed as a part of the least-cost program for the expansion of generation (thermal and hydro combined), and if each of the multipurpose dams is to be optimally developed and utilized, the plans for the development of the river basins should be completed and integrated with the least-cost plan for power. This would ensure that the development of the hydropower potential is dictated by a comprehensive plan that takes into account the optimal uses of water resources and the overall configuration of the power system. Therefore, in order to guard against the development of marginal hydropower sites, it is recommended that the Government undertake the formulation of an optimal plan for the development of river basins and the integration of the results of this plan with the least-cost development program for the power subsector. C. Coal 2.05 Morocco's proven reserves of coal, estimated at 16 million tons, are located near Jerada. The coal has a relatively high calorific value; ranging between 5,000 kcal/kg and 7,500 kcal/kg. Annual production is estimated at about 750 thousand tons of which 690 thousand tons are used by ONE for power generation, the rest being consumed by the industrial sector. A program to partially mechanize the mine is currently being implemented and would, in a first stage, bring the annual production to 1 million tons. Part of the additional output (about 150,000 tons) would be used by ONE and the rest would go to the production of industrial steam. A target output of 2 million tons would be reached in a second stage and will require the completion of a market study. ONE counts among the potential consumers as new power plants could be adapted to burn this type of coal; they would, however, need to be installed away from Jerada as this site is severely constrained by limited water availability. D. Oil and Gas 2.06. The known oil fields are presently almost depleted with domestic production falling to 17,500 tons in 1981 compared to 143,000 tons in 1963. 2/ SCET International (France); Plan directeur de l'am6nagement de la branche Oum er Rbia, 1975. -8 - In addition, about 78.5 million cubic meters (0.06 million toe) of gas have been produced each year during the period 1975-1981. In 1981, gas was discovered at Meskala, in the Essaouira basin, in what could potentially prove to be a significant reserve with a relatively high proportion of condensates. However, due to the variable and generally poor quality of reservoirs, and the fact that the gas extends over a large area, it is not possible to make an exact estimate of recoverable reserves before 1983 when the assessment of the reserves is completed. If the gas reserves prove to be large, the mix of fuels used in Morocco would be altered significantly, particularly the import of fuel oil and coal. In order to measure the impact of the availability of different quantities of gas on the investment configuration for the power subsector, ONE has already prepared various alternative investment plans which assume different levels of dependence on domestic gas for power generation. The projections indicate that if relatively large quantities of gas were made available to ONE, they would first be used in those power plants which have been designed for dual fire and where gas would advantageously substitute for fuel oil. Given the possibilities for converting both existing units and those under construction, ONE's gas requirements would amount to a maximum annual level of 1.5 million tons by 1990. If additional quantities of gas were made available, they would then be used in the new base load plants planned for commissioning beyond 1990 and where gas would substitute for imported coal. E. Oil Shale 2.07. Morocco's presently known oil shale reserves are put at over 100 billion tons with an estimated oil content of about 6 billion tons. The reserves at Timahdite are the largest; estimated at about 3.3 billion tons of shale. The shale at Timahdite has already been tested for retorting, both in Morocco and abroad. In an effort to compensate for the decline in the domestic production of oil, the Government initiated an extensive program for testing and evaluating the technical and economic viability of the presently known technologies for extracting oil from the shale by retorting. The program, which is supported technically and financially by the Bank, includes the construction of a station for testing the shale, the evaluation of the various retorting processes, and the formulation of a plan for mining the shale. In parallel, ONE, in cooperation with Russian and German firms, has conducted tests and studies on the direct combustion of the shale which indicated that the Timahdite shale could be burnt in a specially designed power plant. However, because of its current financial difficulties and having set as a priority the implementation of its petroleum exploration program, the Government recently reduced its budgetary contribution to the oil shale program very substantially, resulting in the postponement of that program. In particular, the execution of ONE's plan, which involved the construction in the Timahdite area of a first shale-fired unit of 100 MW by 1985, had to be postponed until the issues of water availability, mining conditions, project feasibility and regional planning could be solved. - 9- 2.08 The Government, however, remains anxious to capitalize on the research which has already been carried out in the last few years and seems to have decided in favor of a less ambitious program for using the oil shale in power generation. The possibility of burning the shale in small units of 10-15 MW is currently being explored; the technology selected would be that of fluidized-bed combustion, which has the advantage of being environmentally safer and operationally more efficient than the conventional combustion technology. A detailed evaluation of the presently known technologies is indispensable before proceeding any further with these preliminary plans. F. Nuclear Fuel Material and Renewable Energy Resources 2.09 Morocco's large reserves of phosphate (about 50 billion tons) are estimated to have a uranium content of 150-200 grams per ton. Extraction would, however, be uneconomic with present technology. No commercially exploitable deposits of primary uranium have so far been discovered in Morocco. Renewable energy resources are relatively abundant, mainly in the form of fuelwood, wind energy and solar radiation. Morocco's large natural forests are being overexploited, while its wind and solar energy resources are significantly underutilized. - 10 - III. ORGANIZATIONAL STRUCTURE 3.01 Morocco's power subsector is under the control of the Ministry of Energy and Mines (MEM) and the Ministry of Interior (MI). MEM supervises the operations of the Office national de l'6lectricit& (ONE), a Government-owned utility responsible for the generation and transmission of virtually all the publicly supplied electricity in the country, and its distribution throughout the country with the exception of the main urban centers. MI oversees the operations of the publicly owned utilities entrusted with the distribution of electricity in the main urban areas (regies). In addition, MI is responsible for the formulation of the national rural electrification program whose implementation is entrusted to ONE. A. Office national de l'glectricit6 (ONE) 3.02 ONE was created in 1963 to take over the generation and transmission of electricity throughout Morocco. In 1981, it accounted for 90% of all the electricity generated in the country. The remaining 10% was produced by the large industrial enterprises for their own use. In addition, ONE distributes electricity at both the medium and low voltage levels in the areas not served by the r6gies. In 1981, ONE's sales at the medium and low voltage levels accounted for about 40 % of total sales at the distribution level. 3.03 ONE's management is supervised by a Board (Conseil d'Administration) chaired by the Prime Minister 1/. The other Board members are representatives of the Ministries of Interior, Finance, Planning, Equipment, Agriculture and Labor. These members are appointed by Royal Decree for a 3-year term which may be renewed. It normally limits itself to general policy and leaves day-to-day operations to ONE's management. ONE's Director General is assisted by a Deputy Director General to whom he delegates most of the day-to-day business. 3.04 At the end of 1981, ONE had a total of 5,766 employees of which about 1,400 were assigned to 9 regional offices for the operation and maintenance of its distribution network, including the rural distribution system. ONE has an efficient training center at Ain Sebaa (Casablanca) with about 250 places where about 400 employees are trained every year in various skills needed by the utility; trainees at all levels are required to remain a number of years in ONE's employment. This requirement was instituted in order to alleviate the problem which ONE experiences at time in recruiting suitably qualified staff. The difficulties encountered in recruiting manpower stems from two factors; (a) a phenomenon common to many enterprises in Morocco which suffer 1/ The latter being most of the time represented by the Minister of Energy and Mines. - 11 - from the country's general shortage of technicians; and (b) the fact, more specific to ONE, that the compensation package offered to young professionals at the recruitment stage represents about 60% of what is offered in the private sector. Although these relatively low salaries are later adjusted through the allocation of substantial fringe benefits, after a minimum number of years of employment with ONE, the current wage policy hampers the rapid recruitment of well-qualified technicians when needed. B. The R6gies 3.05 The remaining 60% of the electricity sold at the low voltage level is distributed by the regies. According to their mandate, the regies are supposed to be financially and administratively autonomous enterprises, responsible, in most cases, for the distribution of water and electricity within an identified perimeter. In reality, however, the regies are tightly controlled by MI, and their finances are heavily dependent on prepayment for services by new consumers, and to a lesser degree, budgetary allocations and soft loans from the local and central governments (paras. 3.10-3.11). Regies are either communal or intercommunal. 1/ Communal regies serve a single urban center or city, and the intercommunal regies provide service to several small communities surrounding an urban center. Since the creation of the first regie at Casablanca in 1962, the number of regies has increased to reach 16 by the end of 1981. Of these, only 10 regies are involved in the distribution of electricity. The remaining six r6gies are, at present, only concerned with the distribution of water. 2/ 3.06 The relative size of the regies in terms of total sales of electricity varies considerably. The regie of Casablanca is by far the largest; accounting for about 51% (1980) of the regies' total sales, compared to the regie of Rabat, the second largest, which accounted for only 13% of total sales, and the regie of El Jadida, the smallest, with a market share of 1%. The market shares of the regies are summarized in Table 3.1 below. 1/ The communal regies are those of Fes, Marrakech and Meknes; the intercommunal regies are those of Casablanca, Rabat, Kenitra, Tangers, Tetouan, Safi and El Jadida. 2/ These include the regies of Settat, Nador, Beni Mellal, Oujda, Taza and Agadir. - 12 - Table 3.1 Electricity Sales by the R6gies in 1980 (GWh) % Share in Medium the Total Voltage Low Medium Total Sales by As % of Voltage Voltage Sales the Regies Total Sales Casablanca 420 670 1,090 51 61 Rabat 164 119 283 13 42 Fes 61 104 165 8 63 Tanger 45 100 142 7 69 Meknes 36 89 125 6 71 Tetouan 35 74 109 5 68 Marrakech 56 38 94 4 40 Kenitra 25 41 65 3 63 Safi 19 21 40 2 53 El Jadida 12 11 23 1 48 Total 872 1,268 2,140 100 59 Moreover, the mix of consumers served by each r6gie, expressed as the ratio of sales at the medium voltage and total sales, also varies significantly; ranging from 71% for the regie of Meknes to 40% for Marrakech. The variation in the size of the regies and the mix of the customers makes the adherence to the Government's rules governing financial and administrative autonomy difficult to attain. 3.07 The right of the communes to establish their own regies has been decreed by law as part of the Government's program for decentralization (Charte Communale, 1976). The main criterion for the establishment of regies is their ability to maintain financial autonomy by covering their operating costs from the sale of water and electricity, and finance their development program without subsidy or budgetary transfers from the Government. The process of creating a new regie usually involves three steps: (a) the expression of interest by the community which is represented either by a municipality in case of a communal regie, or by a syndicate of a group of villages and small towns in the case of an intercommunal rggie; (b) the commissioning of a feasibility study carried out by a commission composed of representatives of various ministries (interior, finance, energy and mines, equipment); and (c) the enactment of the Government decision through a decree signed by all ministries. - 13 - The ministries must all concur before a regie is established. In practice, this requirement has not been fulfilled in all instances: the regie of Taza, and most recently that of Agadir, were established without the approval of the Ministry of Energy and Mines which has consistently resisted the creation of new regies. One of the reasons for the Ministry's opposition to the establishment of new regies is the absence of clear and satisfactory terms on which ONE would transfer its existing infrastructure to the regie. At present, ONE is supposed to relinquish to the new r6gie all the equipment it has installed within the perimeter of the regie, without receiving any financial compensation in return. 3.08 Each regie is managed by a board (conseil d'administration), a managing committee (comite de direction) and a management team headed by the director. Two thirds of the board is composed of representatives elected from the municipal and communal council (or the intercommunal council depending on the type of regie), and the remaining one third, of Government representatives appointed by MI. The latter group usually includes the provincial governor as well as representatives of the Ministers of Interior, Finance and Equipment. 1/ The board is re!sponsible for the formulation of the overall investment and financing plans. The three-member managing committee is an emanation of the board and is responsible for the overall supervision of the regie and the implementation of the decisions made by the board. The regie's management is headed by the director who is appointed by MI. The director manages the daily operations of the regie under the supervision of the board and the managing committee, and is assisted by the chief engineers for the water and power departments and the manager for finance and administration (common to both water and electricity departments). 3.09 The regies rely on three sources for financing their investment programs: (a) internally generated cash; (b) Government contributions and loans; and (c) prepayment of customer connection charges (paras. 7.16-7.17). Little information is available on the contribution of each source to the financing of the regies' investment. This gap in the Bank's knowledge of the finances of the regies would be bridged through the special study on urban electricity distribution proposed in this report. 3.10 Government contributions are allocated either directly from the national budget or indirectly through the budget of the communes. These contributions are essentially local revenues collected by the central government on behalf of the local communities and redistributed back to them. The contributions are not considered as subsidies that compensate for shortfalls in the communes' or the regies' income although an element of subsidy (revenue sharing) may be implied. Direct contributions are disbursed through a special fund for regional development, "Fonds special pour le developpement regional" (FSDR). FSDR, established in 1973 to provide relatively quick grants for the local development of communities in the least 1/ The Ministry of Energy and Mines is represented by a non-voting member only. - 14 - developed regions, is administered by the State Secretariat for Planning. Although little information is available on the use of FSDR funds, it is estimated that FSDR has benefited the regies to a very limited extent. Subsidies from the local communes' budgets, which are financed by allocations from the national budget through the Local Community Development Fund (Fonds de developpement des collectivites locales, FDCL), are also disbursed in a sparse manner because of the chronical shortage of funds available to the local communes in general. 3.11 Regies may secure loans from a communal infrastructure fund, "Fonds d'equipement communal" (FEC), which is an autonomous public corporation whose responsibility is to finance infrastructure projects needed by the communes. The FEC's sources of finance are: loans authorized and guaranteed by the Government, advances from the "Caisse de depot et de gestion" (which supervises FEC's operations), budgetary allocations, interest and repayment from outstanding loans, and grants from other sources. FEC lends to the regies at an interest rate of 8.5% and for periods of 8 to 10 years. Access to FEC resources is however reserved because these are regulated by creditworthiness criteria which tend to favor the wealthiest regies. In addition, the low rate of domestic private and public savings which has prevailed in Morocco for the past few years has contributed to restricting FEC sources of finance. The Government is now encouraging those regies which are financially viable to seek financing from other sources, especially by borrowing from abroad, and securing funds through supplier's credits. However, the commercial interest rates would be significantly higher than the concessionary rates that were paid by the r6gies in the past, and consequently, unless the Government de-controls the tariffs at the low voltage and allows tariffs to be based on a general level of self-financing for the sector, ONE is likely to end up absorbing the incremental cost to the regies of borrowing commercially (para. 6.14). C. Isolated Systems and Autoproducers 3.12 In addition to the power generated by ONE, electricity is made available in limited quantities by isolated systems and a few autoproducers. Isolated systems, consisting of small diesel generators and rudimentary distribution networks, are installed in about 190 remote villages to provide lighting for streets and a few buildings. These installations are owned by MI and financed from its budget for municipal equipment. Daily operation is ensured by the local municipalities, while maintenance is entrusted to ONE. The quality of electricity supply in the isolated systems is poor and generally unreliable. The small diesel generators are often in poor condition, overloaded or deteriorating fast. About 30 of these isolated villages will be connected to the national grid as part of the ongoing national program for village electrification (paras. 3.15-3.16). 3.13 About 10% of the power generated in Morocco is produced by industrial enterprises which have their own generating facilities for standby reasons (mines and oil refineries) or because of specific steam generation - 15 - requirements (sugar refineries and paper mills). Their installed capacity is estimated at about 192 MW (11 of total installed capacity in Morocco) and their production amounted to nearly 500 GWh in 1980. Most of these facilities are connected to the national grid for interchange of energy; however, there is a growing tendency for those enterprises to rely on the central grid because of the continued imprDvement in ONE's operations. 3.14 A recent study undertaken by a Bank consultant on the potential for energy conservation in the industrial sector identified the possibility for several industrial plants to expand their autogeneration and sell their surplus production to ONE. T'he case was made in particular for the sugar refining industry where bagasse could be used to generate electricity. It is recommended therefore that ths Government initiate a detailed study to examine possibilities for expanding cDgeneration in the industrial sector, and integrate it with the preliminary load research and management study undertaken by ONE (para. 5.12). Such a study would formulate a strategy for improving the overall energy efficiency in meeting the future demand for electricity. D. Rural Electrification 3.15 Management of the rural electrification program is the responsibility of the Infrastructural Planning Division of MI, and of ONE's distribution department, under the auspice;s of the Interministerial Committee for Rural Electricification (Commission interministerielle de l'electrification rurale, CIER), chaired by the Minister of Energy and Mines. Before the 15-year national rural electrification program was established in 1978, MI used to draw a list of the villages to be electrified, and the estimate of the cost of implementation was then requested of ONE. Upon receiving these costs from ONE, the MI drew a list of priority villages whose size depended on the budgetary allocation for the program and where the ranking was dictated by the socioeconomic objectives of the Government. 3.16 The overall management of the program continues to be weak because of the short-term nature of its planning cycle, the division of responsibilities between entities involved and serious shortage of staff to manage the program. These weaknesses are still prevailing despite efforts undertaken by the Government, with the Bank's assistance, in formulating a long-term program and strengthening MI's planning capabilities. The first phase of the 15-year national rural electrification program is currently being implemented, with the objective of extending electricity supply to 254 villages and with ONE acting as the executing agency. However, the project is about one year behind schedule, mainly because of delays in the disbursement of funds by the Government. In addition, the list of villages included in the first phase was established in its definite form only after a lengthy review process between ONE, the local communities, the consultant and the various ministries concerned. Therefore, in order to complete the first stage of the rural electrification program on time, it is recommended that the Government disburse funds in a timely and efficient manner. It is further recommended that, before the Government undertake the second phase of the program, the - 16 - list of villages to be electrified be carefully reviewed to ensure that it is the most economic option. E. Administration de l'hydraulique 3.17 ONE works closely with the Administration de l'hydraulique of the Ministry of Equipment in planning the expansion of its hydrogeneration capacity. The Administration is entrusted with the responsibility for the development of river basins in Morocco and the construction of dams to meet the increasing demand for water for irrigation, water supply and power generation. The Ministry of Equipment is well aware of the need for planning the development of water resources in Morocco and recently reorganized the Administration de l'hydraulique in order to strengthen its project preparation and evaluation capabilities. Two new divisions were set up within the administration, responsible respectively for the preparation of the integrated plans for the development of river basins and for the implementation of large hydro projects. The new institutions will be in charge of establishing the economic viability of multi-purpose hydro projects. Moreover, a subcommittee for the development of river basins was created in December 1982 with representatives from ONE, the Office national de l'eau potable (ONEP), the Ministry of Agriculture and the Administration de l'hydraulique. The subcommittee, whose creation should cottribute to better coordination among all entities concerned, is entrusted with the responsibility for determining the feasibility of multipurpose projects on a both technical and economic basis. F. Intra-Sectorial Coordination 3.18 The current institutional setting of the sector, characterized by the fragmentation of responsibilities for its supervision and management, requires close coordination between the various entities involved: between MEM and MI at the policy level, and between ONE and the regies at the implementation level. Coordination is particularly essential in the areas of investment planning and load forecasting, standardization of equipment and network management. At present, however, cooperation between ONE and the regies and between the respective ministries of control is very weak. Lack of coordination results in substantial inefficiencies in the overall management of the sector. 3.19 Investment plans in ONE and the r6gies are drawn up independently from one another and little information seems to flow between the various entities prior to the formulation of these plans. The regies are required by ONE to provide data on projected demand in their respective areas of distribution; however, the quality of the data furnished varies widely from one regie to another, and in general does not reach the level of reliability which would allow ONE and the regies themselves to plan their investments in an optimal fashion. Moreover, investments by ONE and the regies are not - 17 - systematically matched in time, nor in terms of individual projects so that duplication or delays in their execution may occur at times. In addition, there is no guarantee that the overall investment program for the distribution of electricity is least cost (para. 6.14). 3.20 Management of the network also suffers from the present sectorial organization. Complaints are regularly voiced by the regies about ONE's lack of cooperation in meeting the regies' allegedly unforeseeable increase in demand for ONE's electricity and the technical impossibility for ONE to meet it. This is actually the result of the regies' reluctance to participate in the financing of investments required to meet growing demand and in the execution of the related projects. Thus, in addition to the issue of establishing new regies (para. 3.07), there is a chronic conflict between ONE and the existing regies on the extension of the latter's distribution perimeters. A similar problem 'keeps on reoccurring between ONE and the communes where generator sets are managed in a more or less adequate fashion by the commune staff and maintained by ONE. It is recommended therefore that MEM and MI clarify the terms on which ONE is expected to operate and draw up a network management agreement between ONE and the communes, in order to enhance the efficiency of the distribution system. 3.21 Another area where the absence of intrasectorial coordination is leading to substantial diseconomies of scale is the procurement of new ,equipment. At present, the purchase of equipment for the extension of the distribution network is done separately by each institution (ONE and each of the 10 regies) and there is no standardization in the equipment purchased. CJonsequently, each utility carries its own inventories with the corresponding financial burden that this entails. It is recommended therefore that a special committee, with representatives of both ONE and each rggie, be established, in order to formulate unified standards of procurement and examine means by which an inventory common to all utilities could be set up. 3.22 All these problems have been recognized by the Bank as early as 1976 (Loan IBRD 1299-MOR) and the Government was requested to undertake a study for the reorganization of the sector. The study was completed by EDF (France); however, its recommendations were not accepted by the Government because it emphasized the need for centralizing responsibilities for the distribution of electricity under the authority of ONE. In 1978, the Government appointed an interministerial committee to review in detail the recommendations of EDF's study and bring them in line with the institutional setting of Morocco. No report has yet been submitted to the Government by the committee. Since the reorganization of the sector woLuld involve MI and MEM as well as the communes and the central government, it is expected that it would take a relatively long time to reach consensus among all those concerned, on the committee's possible recommendations. In the interim, however, there is an urgent need for the Government to take some measures which would improve the efficiency by which the sector is managed and developed. These measures would cover the formulation of least-cost development plans and the financing of investments. It is therefore recommended that the Government appoint a working group that would put forth recommendations on the means by which the operations of the power subsector could be streamlined and better coordinated. Simultaneously, - 18 - the Bank which so far has not been successful in tackling the sectorial organization issue could assist the Government in dealing with specific measures to improve the subsector's organization through its lending operations. - 19 - IV. HISTORICAL TRENDS IN THE CONSUMPTION AND SUPPLY OF ELECTRICITY A. Past Trends in Electricity Consumption Overall Consumption of Electricity 4.01 Electricity consumption increased during the period 1970-1980, at an average annual rate of 9.6% while maximum demand increased at an average annual rate of about 8.8%. Table 4.1 below summarizes the changes since 1970 in the consumption of electricity, maximum demand and the average load factor. Rapid growth of industrial electricity consumption, and stagnation or decline in access of households to supply explains other trends which occurred in the demand for electricity. On a per capita basis, gross national electricity consumption grew from 138 kWh in 1970 to 262 kWh in 1980, corresponding to an average rate of 6.6% per year. Despite the high proportion sold to industry, per capita consumption of electricity remains relatively low in comparison to other countries in the region. This reflects, to a large extent, the very low degree of electrification in rural areas, where only 6% of the population has access to public electricity supply. Table 4.1 Growth in Electricity Demand, 1965-1980 Annual Rate of Growth (%) 1970 1975 1980 1970-1975 1975-1980 Electricity Consumption (GWh) 2,108 3,269 5,247 9.2 9.9 Interconnected System Gross Generation (GWh)I1 1,957 3,038 4,762 9.2 9.4 Maximum Demand (MW) 384 596 910 9.2 8.8 Load Factor (%) 48.3 58.7 61.6 /1 Including production by Electras Morroquies and purchases. 4.02 Electricity consumption per dollar of GDP 1/ increased at an average annual rate of about 4%; from 525 kWh/US$l,000 in 1970 to 783 kWh in 1980. The increase in the intensity of electricity consumption is primarily attributed to the expansion of the industrial, agricultural and service sectors. This was responsible Eor the fairly high elasticity of electricity ,^onsumption with respect to GDP which averaged 1.8 for the period 1970-1980. 1/ Measured in 1970 prices. - 20 - Electricity Consumption by Economic Sector 4.03 The sectoral consumption of the publicly supplied electricity is shown in Table 4.2 1/ below. Among the major sectors of the Moroccan economy, public administration had the highest rate of growth, followed by services, industry, and agriculture. There was a decline in the share of transport and mining, from 22% of total electricity sold in 1970, to 16% in 1980. The extension of irrigated areas, in addition to the 1980-1981 drought which increased irrigation requirements, resulted in the consumption of electricity by agriculture growing at an average annual rate of about 12.8%. Table 4.2 Sectoral Consumption of Electricity (Public Supply System) Annual Rate 1970 1980 of Growth (%) GWh % GWh % 1970-1980 Agriculture 49.0 3.0 163.6 4.1 12.8 Mining 252.1 15.7 482.0 12.2 6.7 Industry 529.1 32.9 1,439.8 36.4 10.5 Services 60.7 3.8 203.4 5.1 12.9 Transport 104.0 6.5 160.0 4.0 4.4 Public Administration 38.1 2.4 187.8 4.7 17.3 Residential & Commercial 402.5 25.1 983.5 24.9 9.4 others /1 170.0 10.6 334.9 8.5 7.0 TOTAL 1,605.5 100.0 3,955.0 100.0 9.4 /1 Includes public lighting, energy, and water distribution. 4.04 The overall sectoral consumption of electricity presented in Table 4.2 does not take account of autogeneration in the industrial, mining, and agricultural sectors. Net consumption by autoproducers 2/ is estimated to have increased from 134 GWh in 1970 to 463 GWh in 1980; representing an average annual rate of increase of about 13.2%. Thus, the consumption of electricity generated by the autoproducers grew at a slightly higher rate than the consumption of publicly supplied electricity by the industrial and mining sectors. As a result, the proportion of all industrial electricity supplied by autoproducers rose from 20% in 1970 to 22% in 1980. By contrast, the growth of consumption by the agricultural sector of publicly supplied 1/ Excluding autoproducers, isolated systems run by the Ministry of Interior, and others for which no sectoral breakdown is available. 2/ Excluding station use and sales to ONE. - 21 - electricity was higher than the rate of growth of electricity produced by the isolated systems, reflecting mainly the preference of consumers for electricity provided at subsidized tariffs to autogenerated electricity using diesel oil whose price has been brought in line with its border price since 1976. 4.05 Detailed data on the consumption by industry of publicly supplied electricity shows considerable variation in the consumption pattern of the various industrial subsectors (Annex 1, para. 5). The changes in the rates of growth over the period 1970-1980 is a clear indication of Morocco's industrial strategy over the 10-year period, and the emphasis on electricity-intensive industries. Chemicals, construction materials, cement and engineering equipment had the highest rates of growth in electricity consumption over the last five years of the decade; ranging from 31% for chemicals to 12.7% for engineering equipment. The increased consumption of electricity by the transport sector, particularly rail, since 1975 reflects the substitution in the public transport system of electricity for high-value petroleum products in response to higher oil prices. 4.06 Consumption by the residential and commercial sector remained at about 25% of total electricity consumption (Annex 1, para. 6). Although no breakdown between households and commerce is available, it appears that access to supply did not improve much during the second half of the 1970s and may actually have decreased. This decline, or at best, lack of improvement in access to public supply of electricity has been a consequence of the policies for financing the extensions of the distribution networks (para. 7.17). Initial consumers are responsib'Le for financing in part, facilities that are subsequently used by others. Distribution of Final Electricity Sales between ONE and the Regies 4.07 ONE has been able to continuously increase its share of the market relative to the share of the regies (Annex 1, para. 10). The increase in ONE's share is primarily due to the direct service extended to the growing industrial sector; the decline in the rate at which the regies connect new Low-voltage consumers relative to the pace maintained by ONE in extending its service; and the extension of ONTE's distribution network in the rural areas. ONE's direct sales to final consumers now account for 46% of total electricity sales in Morocco, compared to 44% in 1970. B. Past Trends in the Supply of Electricity Generation 4.08 ONE's generating capacity has increased substantially over the past ten years, from 532 MW in 1970 to 1,560 MW in 1981; representing an average annual rate of increase of about 10.3%. Since 1970, the bulk (71%) of the new capacity was provided by the installation of new thermal generating f'acilities, mainly oil-fired steam power plants. The greatest increases in oil-fired capacity occurred between 1975 and 1979. As a result, by the end of - 22 - 1981, ONE's installed capacity consisted of 613 MW of hydroelectric capacity located for the most part on the Oum Er R'bia river and 947 MW of thermal units, including 735 MW of steam power plants and 120 MW of gas turbines. Details are provided in Annex 1, Attachments 1 and 2. 4.09 The available capacity fluctuated considerably during the period 1975-1981 because of the variations in hydrological conditions and their impact on the production potential of the hydro power plants (Annex 1, Attachment 4). 1/ Average capacity available at peak during 1975-1981 was 73% of installed capacity for hydro and 80% for thermal plant. Since peak demand has increased steadily since 1970 from 380 MW to 960 MW in 1981, the effective reserve margin has ranged between 56 MW and 204 MW equivalent to 6% and 23% of maximum demand respectively. However, the absolute margin of installed capacity to demand has been much higher, ranging from a minimum 30% in 1976-1977 to a maximum of 63% in 1981 (Annex 1, para. 12). 4.10 Total generation by ONE reached 5,099.6 GWh in 1981, compared to 1,908 GWh in 1970, which represents an average growth of 9.3% per year. The share of thermally generated electricity has increased substantially during the last 15 years reflecting the steady shift by ONE toward increased dependence on thermal capacities for electricity supply (Annex 1, para. 13). Thermal facilities produced about 79% of total electricity generated by ONE in 1980, compared to only 11% in 1965. Hydro production fell as low as 20% in 1981 because of the drought. Production by autoproducers was mainly from thermal plants and represented about 10% of total electricity generation for the country. 4.11 ONE power station use in 1980 amounted to 1.8% of gross generation for the hydro plants and 8.6% for the thermal plants. Losses in transmission, amounted to 7% of energy delivered to the network. These losses are relatively high, reflecting the slippages in ONE's program for the reinforcement and expansion of the national transmission network (para. 7.05). Distribution losses were 2.8% for the ONE system and 6% for the regies, which seem low. Nationally, it is estimated that about 16% of electricity generated was either used by the power stations for their own needs, or lost in transmission and distribution. The level of losses at each of the stages involving the production, transport and delivery of electricity cannot be determined accurately because of inadequate data on the areas served by the regies. Reduction of losses is one of the main means for abating the increase in the cost of electricity. It is recommended therefore that a study be undertaken for determining losses at each voltage level in the public system and to propose a set of actions for reducing them. 1/ Actual hydro generation may vary within a 30% margin around the average, depending on the year's rainfall. - 23 - 4.12 As seen from Table 4.3, since 1970, the growth in the share of oil-fired thermal power stations in ONE's generating system has resulted in an increased dependence on fuel oiL which is either imported directly or produced locally from imported crude oil. (Details are provided in Annex 1, para. 16.) Table 4.3 Distribution of Power Generation by Primary Energy Source (ONE) 1970 1980 1981 % Share % Share % Share GWh in l'otal GWh in Total GWh in Total Coal 557.4 29 980.0 21 1,190.1 24 E'uel Oil -- -- 2,180.8 47 2,863.9 56 Gas Oil/Diesel 34.2 2 5.7 -- 21.7 -- Hydroelectricity 1,316.4 69 1,514.6 32 1,023.9 20 TOTAL 1,908.0 100 4,733.1 100 5,099.6 100 NOTE -- = Negligible (less than half a percentage point). While practically all the electricity generated in 1970 was produced using domestic resources (coal or hydropower), this share has dropped to about 50% in 1980 and because of the drought, to an even lower level in 1981. The balance was met by generating power in steam plants burning fuel oil. Transmission 4.13 The transmission network has been extended and improved in line with the expansion of system generating capacity. The 225-kV grid is progressively replacing the former 150-kV system. A 60-kV subtransmission network transports energy to the distribution system at 22 kV. A plan for interconnecting the Moroccan system to the Algerian one has been contemplated for several years now. This interconnection would contribute to a more economic utilization of generation facilities in both countries and therefore, the Government should give serious consideration to initiating the link since it would make possible the reduction of the stand-by capacities in the two systems. - 24 - V. FORECAST CONSUMPTION AND SUPPLY OF ELECTRICITY A. Growth of the Economy 5.01 Morocco's economy experienced a relatively slow rate of economic growth over the period 1978-1980 as a result of strict fiscal and monetary policies implemented by the Government to stabilize the economy. During this period, GDP increased in real terms at an average annual rate of 3.8%. According to Bank staff projections, GDP would grow at an average rate of about 4.5% for the period 1981-1985 and accelerate slightly to 5% for the period 1985-1990. Value added in agriculture is expected to grow at 5.5% per year from 1981 to 1985, and at 2.5% thereafter, as recovery from the 1981 drought would spread over several years. The growth of the industrial sector is projected to be low in 1982, but to rise afterwards, so that it could reach, in real terms, an average annual rate of about 4.7% for the period 1981-1985, and 5.5% for 1985-1990. The higher growth rate of industry in 1981-1985, compared to the one achieved in 1977-1980 (2.3%), is expected because of the size of planned industrial investments. If the gas reserves currently being assessed prove as large as expected, gas production in the middle 1980's would stimulate further the growth of the industrial sector. In the case of the service sector, value added in transport, commerce and services is expected to follow the increased demand arising from agriculture and industry. However, the projected reduction in Government consumption should induce a slowdown in the overall growth rate of the service sector to 4.2% per year from 1981-1985, compared to 5.2% for 1977-1980. The historical and projected growth rates of the main sectors of Morocco's economy are presented in Table 5.1 below; Table 5.1 Historical and Projected Real Growth Rates for the Main Sectors of Morocco's Economy /1 (%) Actual Projected 1977-1980 1981-1985 1985-1990 Agriculture 7.2 5.5 2.5 Industry 2.3 4.7 5.5 Services 5.2 4.2 5.5 GDP 3.8 4.5 5.1 /1 World Bank projections. - 25 - B. Future Electricity Demand 5.02 The future demand for electricity was examined using income and price elasticities for the main categories of consumers, estimated from historical observations. The long-run elasticity of domestic electricity consumption per consumer with respect to real per capita expenditure was estimated to be about 1.2, while the long-run price elasticity was -0.1. This indicates that demand is more influenced by changes in real per capita expenditures than by changes in real electricity prices. Since real electricity prices did not rise during the period over which the elasticities were estimated, the actual response of consumers in Morocco to higher electricity tariffs should therefore be higher than estimated. Studies in other countries indicate that price elasticities may be higher when prices are rising than when they are falling. Nevertheless, in the short to medium term, increases in electricity prices to LV consumers to align them with marginal costs, are unlikely to lead to large losses in the potential income of utilities. 5.03 Analysis for the mining and services sectors where consumption was related to real GDP for the sector and real electricity prices produced the following elasticities: Mining Services Income elasticity - short run 0.50 1.30 - long run 1.60 1.70 Price elasticity - short run -0.09 -0.06 - long run -0.30 -0.08 Coefficient of determination (CR2) 0.97 0.98 These results indicate that net output has had the dominant effect on demand. Services respond to changes in net output or electricity prices faster than mining, which is to be expected, given the lumpy capital stock of the mining industry. 5.04 Lack of adequate data and its aggregated nature made it difficult to accurately estimate the elasticities for industry. Preliminary results indicate a long-run GDP elasticity for industry of about 1.7. This analysis of the relationship between electricity consumption and the factors which influence it has produced promi.sing results. However, there is a need to acquire better data on electricity consumption, and to estimate a wider range of models. The results to date indicate that demand is relatively insensitive to price, and that incomes or output tend to dominate demand. 5.05 The demand forecast derived from the analysis presented above projected a global electricity demand consistent with the demand forecast prepared by ONE in 1981 for the entire subsector. According to ONE's projections, maximum demand and gross generation are projected to grow at an annual average rate of 9% until 1990, which represents a slight decline in the rate of growth in the 1980's, compared to the 1970's. - 26 - Table 5.2 Forecast Consumption of Electricity by Economic Sector, 1980-1990 Annual Rate of Growth (%) 1980 (Actual) 1985 1990 1980- 1985- (GWh) ( (GWh) (%) (GWh) (%) 1985 1990 Agriculture and fishing 163.5 3 295 4 520 5 12.5 12.0 Mining 482.0 10 620 8 785 7 5.2 4.8 Food processing 247.5 5 380 5 570 5 9.0 8.5 Textiles 273.6 6 365 5 480 4 5.9 5.5 Chemicals 215.5 5 335 5 515 5 9.2 8.4 Cement and construction materials 442.7 9 820 11 1,480 13 13.1 13.0 Other manufacturing 314.0 7 440 6 610 5 7.0 7.0 Water supply 188.0 4 290 4 440 4 9.1 9.0 Trade, hotels, and services 203.4 4 440 6 940 8 16.7 16.5 Railways 106.6 2 130 2 155 1 3.6 3.5 Radio, TV, Army, and Government 187.8 4 310 4 495 4 10.7 10.0 LV sales /1 1,130.4 24 1,635 22 2,385 21 7.7 7.9 Total sales 3,955.0 83 6,060 83 9,375 83 8.9 9.1 Losses & station use 807 17 1,265 17 1,890 17 9.4 8.4 Gross generation 4,762 100 7,325 100 11,265 100 9.0 9.0 Maximum demand (MW) 855 1300 2,000 8.7 9.0 /1 LV consumers are mainly residential, but also include small consumers in other categories, e.g. shops, offices, schools, post offices, etc. The forecast of sales by consumer group presented in Table 5.2 (details are provided in Annex 2, Attachment 1) shows that private and public services, cement and agriculture are expected to have the highest rates of growth. Railways, textiles and mining are forecast to have the slowest growth rates. The proportion of electricity sold at LV is expected to decrease slightly from 24% to 21% of gross generation. Station use and transmission and distribution losses are expected to remain constant at 17%. 5.06 Improvements to Electricity Demand Forecasting: Assuming the projected rates of growth for the major sectors of the economy, ONE's forecast - 27 - of overall electricity sales seems reasonable. However, substantial improve- ments could be made to the methodology used. The approach adopted by ONE is essentially the extrapolation of past trends, modified by knowledge of short- term developments in industria.l sectors. It would however be necessary to check that medium-term electricity demand forecasts are consistent with pro- jected economic development in each subsector and to obtain a rational basis for projecting longer-term demand. Forecasting the demand by LV consumers is hampered by the limited information available on the LV sales and the number of consumers (Annex 2, para. 10). Moreover, in forecasting demand by house- hold consumers, no explicit account is taken of the relationships between the number of domestic electricity consumers and population growth, household formation and access to supply (Annex 2, para. 11). Nor is the effect of household income, energy prices, and weather conditions on the consumption of electricity in a household taken into consideration (Annex 2, para. 12). 5.07 In order to improve electricity demand forecasting and ensure that forecasts are consistent with projected social and economic development, it is recommended that: (a) ONE's staff work even more closely with the Ministry of Planning to ensure that electricity demand forecasts by sector are based on up-to-date detailed and consistent economic projections; (b) ONE and the regies start collecting detailed data on the consumption and numbers of consumers of households and various service, industrial and other subsectors supplied at low voltage; and (c) ONE develop its coordinating role by providing a forum to bring all the utilities' projections together and by assisting the r6gies in improving their forecasting techniques. C. Future Electricity Supply 5.08 ONE is responsible for all generation and transmission planning. It is also responsible for distribution planning in the areas it serves. Ultimately, ONE requires the approval of NEM for its investment program. The regies are responsible for most of the distribution planning in Morocco. Little information is available at the Bank on their investment plans. However, it is known that regies tend to prepare investment budgets for the year ahead and that at least one regie prepares a five-year plan of capital expenditures. This chapter covers generation planning only, because of the lack of information on distribution plans. Future Generating Capacity 5.09 ONE does not plan to commission any new plant on the interconnected system until 1984-1985 when two additional 150-MW units will be completed at the Mohammedia steam station. Unlike the existing 2x150-MW units at Mohammedia which burn fuel oil, the new units will burn imported coal. No further thermal plant is planned except for a 4x250-MW steam station burning imported coal to be commissioned in 1993. Annex 2, Attachment 2 shows projected thermal capacity until 1990. - 28 - 5.10 ONE is planning an ambitious program of hydro development. Four stations are planned for commissioning in the 1980s with a total capacity of 451 MW (Annex 2, para. 17). Another 16 hydroelectric stations, with a total capacity of 1,215 MW, are planned for 1990-1994. Four more stations are proposed for 1995-1996 which will add a further 169 MW to the system (Annex 2, Attachments 3 and 4). Almost all of Morocco's surveyed hydro potential will be exhausted after the planned development program has been completed. ONE then proposes to commission a 600-MW nuclear power station towards the late 1990's to meet base load demand and has initiated contacts with the International Atomic Energy Agency (IAEA) for assistance in the preparation of its nuclear program. In addition, an agreement was recently signed with Sofratome (France) to carry out a study on the feasibility and the location of the first nuclear plant. Many of the proposed hydro projects are part of multipurpose schemes which are primarily intended for irrigation, water supply, or flood control. Most of the projects are small, and their energy (GWh) output would be small in relation to their capacity. In a mean hydrological year, only 7 out of the proposed 25 projects will have a load factor greater than 15%. This raises an issue as to the role of hydro in future system development and the optimization of station size (paras. 5.14-5.17). 5.11 As seen from Table 5.3 below which summarizes the balance of demand and capacity, the hydro program described above will result in hydro capacity increasing from nearly 40% of total installed capacity at present to almost 54% in 1990. The proportion of thermal plant will continue to increase to 68% in 1985 and then decline. The gross reserve margin, is forecast to fall from its highest for many years of 43% in 1981, to 31% in 1985 and 23% in 1990. Table 5.3 Planned Generating Capacity (ONE Interconnected System) --Actual--- --------Planned-------- 1981 1985 1990 (MW) (%) (MW) (%) (Tw T ) 7% Hydro 604.2 39 616 32 1,286 50 Thermal 949.4 61 1,305 68 1,305 50 of which: Steam 784.0 50 1,185 62 1,185 46 Gas Turbine and Diesel 165.4 9 120 6 120 4 TOTAL 1,553.6 100 1,921 100 2,591 100 Maximum Demand 880 1,330 2,000 Gross Reserve Margin 43% 31% 23% - 29 - 5.12 No information is available on any planned increases in the capacity of autoproducers. ONE plans its system on the basis of no import from autoproducers since the sale of surplus energy by autoproducers is not guaranteed. However, there may be scope for increasing the level of imports, particularly if industrial peak demands occur at a different time to the interconnected system peak. Further savings could be made by using purchases to reduce gas turbine generation. Given that autoproducers have almost 200 MW of plant capacity, ONE should review its existing contractual arrangements with autoproducers with the view to integrating them further into the interconnected system. ONE should examine particularly the methods of charging for purchases and sales to ensure that both parties are given the correct marginal cost signals and incentives to supply each other at both peak and off peak times. In April 1983 ONE undertook a sectorial survey with the purpose of collecting data on the structure of electricity consumption by the industrial sector. The survey should contribute to determining the opportunities for some industries to shift their unessential demand from peak to off-peak periods and thus for ONE to defer new capacity. It is recommended, however, to ensure that this preleminary load research and management study be accompanied by a review of ONE's contractual arrangements and, in particular, of its tariffs to industrial consumers. 5.13 The forecast of electricity consumption which serves as a basis for planning the expansion of ONE's generating capacity assumes that station use, and transmission and distribution losses would remain at their present level of 17% (para. 5.05). The data collection exercise to be undertaken for the proposed tariff study (para. 6.16) should permit to determine more accurately the sources of the high losses in the public systems and identify ways by which these losses could be reduced. Capacity cost savings could in turn be achieved by deferring the need to install new capacity. A rough calculation shows that a reduction in losses from their present level of 17% to about 12% in 1990 would save about 140 NW of additional capacity. Future Production of Electricity 5.14 In its generation planning studies, ONE formulates its investment plans under the assumption that the most adverse hydrological conditions would persist over the entire planning horizon. This analysis is undertaken to ensure that sufficient supply of energy will be available under the worst possible case for hydropower generation. In addition, ONE also determines the outputs of generating units and their cost of operation under mean hydrological conditions (Annex 2, para. 21). According to ONE's forecast of generation, the share of hydrogeneration during years of average hydrology will rise to 27% of total energy available in 1985, and to 31% in 1990, as a large number of hydropower sites are developed. Thermal generation will fall to about 73% of available supply in 1985, and to 69% in 1990. Towards the end of the 1980's, about one third of total electricity generation by ONE will be supplied by hydropower plants, another third by coal-fired steam stations, and the last third by oil-fired steam stations. The contribution of gas turbines and small diesel plants will be minimal. - 30 - 5.15 Under poor hydrological conditions, however, where hydrogeneration could be reduced by as much as 40%, the shortfall of energy available would be mainly supplied by oil-fired steam plants and by gas turbines. The margin of spare energy available in a dry year above the projected demand for energy will amount to about 33% in 1985, which suggests that there will be no problem in supplying energy; meeting peak demand will thus be the most important constraint. Thereafter, the margin will fall to 0% in 1990. However, the margin of available energy does not include support from autoproducers or bringing back plant from cold storage, which could raise the 1990 margin to over 5%. Optimization of Hydro Projects 5.16 Most hydro schemes in Morocco are multipurpose, and have been appraised in the past by taking the decision to build the dam as given and regarding the incremental power plant costs as an input to the least cost power development plan. This approach would be correct if the decision to construct a multipurpose project to a stated design on a particular site was in fact independent of the power aspects of the project. In practice though, the power requirements will influence the choice of site, dam height, etc. (Annex 2, para. 25). There may be some hydro projects worth undertaking for the power benefits alone. For these projects, it is necessary to firstly identify the sites and secondly to rank them in terms of economic attractiveness. It is recommended, therefore, that the Administration de l'hydraulique, in collaboration with ONE, establish an inventory of potential hydro sites based on a methodology for determining their optimal use (Annex 2, para. 26). These projects should then be ranked and integrated with thermal power projects in a least cost generation development plan. 5.17 ONE plans to commission 25 hydroelectric stations during the ten years 1986-1996. Even though many of these projects are small, their manpower requirements will be similar to a much larger station with the same number of generating units. A large training program will be required to man these stations adequately. At present such a program does not exist. Furthermore, constructing this number of projects will be likely to overload the management resources involved in design, procurement, and construction. For these reasons, as well as the uncertainty as to whether the hydro plant is needed to meet demand, or justified economically, it is recommended that ONE revaluate, in a more detailed fashion, the power projects planned for commissioning in 1990 and after, to ensure that the longer term development plan is the least-cost solution. - 31 - VI,. ELECTRICITY PRICING A. Historical Review 6.01 As seen from Table 6.1 below, the average tariff paid by ONE's high and medium voltage consumers increased, in nominal terms, at an average annual rate of about 11.5% during the period 1972-1981. In real terms, however, the increase was substantially lower averaging only about 4%. By contrast, the tariff paid by the low voltage consumers increased, in nominal terms, at an average annual rate of about 7.3%, but remained unchanged in real terms. The failure of the low voltage tariff to reflect the real increase in the bulk supply tariffs resulted in the erosion of ONE's level of internally generated revenue, and in turn, the level of its contribution to the overall cost of its development program (para. 6.02). Table 6.1 Average Electricity Tariffs (ONE), 1972-1981 (cDH/kWh) Index High, for the Low Voltage Tariff Medium Voltage Tariff General Current 1972 Prices Current 1972 Prices Price Year Prices cDH/kWh Index /1 Prices cDH/kWh Index /1 Level /1 1972 31.1 31.1 100 11.0 11.0 100 100 1973 32.5 31.3 101 11.0 10.6 96 104 1974 33.3 31.1 100 11.7 10.9 99 107 1975 34.2 31.1 100 11.9 10.8 98 110 1976 39.1 31.0 100 14.1 11.2 102 126 1977 45.9 31.0 100 17.2 11.6 106 148 1978 49.5 31.1 100 19.7 12.4 113 159 1979 51.1 31.2 100 23.0 14.0 127 164 1980 55.5 31.2 100 25.3 14.2 129 178 1981 58.8 31.6 102 29.2 15.7 143 186 /1 1972 = 100 6.02 During the period 1972-1979, ONE's financial performance fluctuated between extremes; that is, for some years ONE managed to cover all of its operating costs and contribute from internal sources between 25% and 30% of the overall cost of its development program, and for the other years, its internal cash contribution dropped to less than 5%. This fluctuation has been primarily attributed to the delays by the Government in adjusting the tariffs for higher fuel prices, and the fact that a large proportion of ONE's - 32 - electricity supply depends on hydroelectric plants, and in turn, on the level of rainfall (para. 6.03). Since 1979, ONE's financial position has been steadily deteriorating because of the substantial increases in its fuel bill and the delays by the Government in reflecting these increases in the tariffs. As seen from Table 6.2 below, over the three-year period, the fuel cost per kWh increased by about 167% and non-fuel cost by about 27%, while the average revenue increased by only 32%. Table 6.2 ONE's Average Operating Cost and Revenue (cDH/kWh) Percentage of 1979 1980 1981 Change (1979-1981) Average Operating Cost Fuel 8.1 11.3 21.6 167 Others 8.2 8.6 10.2 24 Depreciation 6.5 6.4 5.2 -20 Total 22.8 26.3 37.0 62 Average Revenue 24.4 27.0 32.1 32 Moreover, despite the fact that 1980 was a dry year and 1981 was exceptionally dry, which increased ONE's dependence on thermally generated electricity, increases in the bulk tariffs were less than needed to cover the rise in its cost of operation. As a result, ONE's net operating income decreased from about DH 112 million in 1979 to DH 87 million in 1980, and a loss of about DH 129 million in 1981, and its internal cash contribution decreased from 21% in 1979 to only 9% in 1981. The Government had earlier agreed to the inclusion of a fuel adjustment clause in ONE tariff structure; however, as seen from the discussion above, ONE has been prevented from putting it into operation. 1/ In order for ONE to recover the cost of higher fuel prices and maintain the level of its internally generated cash unaltered, it is recommended that, once the program for the restructuring of electricity tariffs (para. 6.15) is implemented, the fuel adjustment clause be activated and that ONE be given the authority to automatically pass on to consumers all increases in its fuel bill. 6.03 The large contribution of the hydropower plants to ONE's total electricity production increases the vulnerability of its financial position to changes in the hydrological conditions. In years with above average rainfall, the utility manages to reduce its operating costs by decreasing 1/ The introduction of a fuel adjustment clause is a covenant under IBRD Loan 1299-MOR. - 33 - thermal generation, and in turn, its fuel bill. In dry years, however, fuel consumption increases, and if the financial position is to remain intact, upward adjustment in the tariffs are needed to cover the unexpected increase in the fuel bill. At times, these adjustments could be fairly high, and frequently, socially and politically impractical to apply; particularly if several dry years occur in sequence. Deficits in internal cash generation in dry years may be difficult to finance, or upset the financing of new investment. A possible approach to offsetting the financial risks of a dry year would be to base the energy component of the tariffs (price/kWh) on the level of fuel consumption that would prevail under adverse rather than mean hydrological conditions. 1/ This would avoid the need for frequent and disproportionately large Increases in tariffs, and would allow for the creation of a fuel fund which would be replenished during the years of good or average hydrological conditions, and used to smooth out the adverse impact on ONE's finances during the hydrologically poor years. Therefore, it is recommended that the Government and ONE consider the redesign of the tariff structure to allow for the energy charge to be based on the fuel consumption in hydrologically bad years, and the creation of a fuel fund to be used for smoothing out the increases in the bulk tariffs needed to cover the increases in the operating cost and maintain the utility's internal cash contribution at a relatively stable level following hydrologically bad years. B. Institutional Responsibilty for Tariffs 15.04 ONE is responsible for proposing global tariff adjustments to compensate for increases in its operating costs due to higher fuel prices and to ensure, to the extent possibLe, a minimum cash generation ratio. However, ;the actual rate of increase and its distribution among various consumers are diecided upon by the Prime Minisler upon ONE's proposal. Tariffs are then set for each voltage level, each consumer category, and each distribution r6gie. ;[t is worth mentioning that tar:iffs applied to the regies, both for purchases and sales of electricity, are set so as to leave the financial position of the r6gies unaltered, i.e., to maintain the net operating income of the regies at the level that prevailed prior 1:o the tariff adjustment. 6.05 The practice for setting tariffs results in differences in the rates paid by the regies for electric:Lty supplied by ONE. These differences are dictated by the financial posit:ion of the regies, and since large and well established regies, such as Casablanca, Rabat, etc., are usually in a relatively better financial position than the smaller or new r6gies, such as El Jadida and Safi, the large rligies cover part of the difference between the rate requested by ONE and the rate finally paid by the subsidized regies. The rest of the difference is covered by ONE. Moreover, by ensuring that the iinancial positions of the regies remain unaffected by the increases in the bulk and retail tariffs, the regies are not induced to improve their operating efficiencies or their internal cash generation (para. 7.16). l/ A detailed review of the principle is presented in Annex 3, paragraph 4. - 34 - 6.06 These practices result in serious departure from the principles of economic pricing of electricity. Economic pricing dictates that tariffs be set at levels that convey to consumers the real cost to the economy of the resources used in meeting their demand for electricity. Adopting these principles would result in the elimination of the current practices for setting bulk tariffs primarily on the basis of the financial targets of the rggies and indirect cross-subsidization among them. They should be replaced by a system where tariffs are based on the average incremental cost of supply derived from a unified national least-cost program (generation, transmission, and distribution for both ONE and the regies). This is discussed in greater detail in para. 6.15. C. Level of Existing Tariffs 6.07 The present level of tariffs is compared here to the marginal cost of electricity supply as estimated by the World Bank for different voltage levels. These estimates are based on ONE's medium-term investment program (1983-1990) as it was submitted to the Bank in February 1982; assumptions used to calculate marginal costs are presented in detail in Annex 3, attachment 3. The results obtained by the Bank are somewhat different from the figures estimated by ONE, particularly for the capacity costs. ONE's estimates, however, are based on a study carried out in 1979 and updated for fuel price adjustments only. The marginal cost estimates thus obtained do not reflect changes in ONE's long-term development program. It is, therefore, recommended that ONE carry out a complete update of this study. Bulk Supply Tariffs 6.08 Energy components in the bulk supply tariffs covering the sale of electricity by ONE to the regies and large industrial consumers are, on the average, equal to, and in some cases higher than, the marginal cost for energy (Annex 3, para. 14). On the other hand, the capacity component is set substantially lower than the average incremental cost of the resources used. Table 6.3 below compares the bulk supply tariffs and the economic cost of supply (energy and capicity charges) for selected regies and industries. - 35 - Table 6.3 Comparison Between Bulk Supply Tariffs and Economic Costs (prevailing charges as a % of economic costs) Max Demand Energy (cDH/kWh) Tariff (DH/kVA/Year) Day Night Economic Cost 844/739 /1 37.5 32.1 Casablanca 60 43.1 34.5 (largest r6gie) (7) (115) (108) Meknbs 62 44.6 35.7 (highest bulk tariff) (7) (119) (111) El Jadida 52 37.0 29.6 (lowest bulk tariff) (6) (99) (92) Industry 173 40.2 32.2 (main MNV system) (23) (107) (100) /1 R6gies/industry assuming a power factor of 0.8 and coincidence factors of 0.9 for r6gies and 0.7 for industry. Retail Tariffs 6.09 Medium Voltage. At the medium voltage level, the relationship between the two components of tariff (energy and capacity charges) and their economic costs is similar to that of the bulk supply tariffs. As indicated by Table 6.4 below, capacity charges are in the order of 9% of the economic cost, while energy charges are about 30% to 40% above the marginal cost of energy. Table 6.4 Comparison Between MV Tariffs and Economic Costs (prevailing charges as a % of economic costs) Max Demand Energy (cDH/kWh) Total /2 Region (DH/kVA/Year) Day Night (cDH/kWh) a. Economic cost 1,295 /1 39.1 33.4 83.9 b. Tariff 110 55 44.0 56.2 (9) (141) (132) (67) ,/1 Based on a 0.8 power factor and a coincidence factor of 0.75. /2 Assuming a 40% load factor and day/night kWh 75%/25%. 6.10 Low Voltage. It is difficult to compare the LV tariffs to economic costs because of the lack of dal:a on consumer load characteristics. - 36 - Residential and commercial consumers in Casablanca, as well as small industrial consumers, pay an average tariff that is slightly higher than half of the economic cost. LV consumers in some of the areas served by ONE pay as much as 70% of the economic cost. On the average, however, LV tariffs are well below the economic costs of supply. The Government control over the increases in the low voltage tariff since 1972 has maintained the real price of electricity to the households and small commercial consumers virtually unchanged while allowing the tariffs for bulk sales to increase in real terms by about 43% (para. 6.01). This has had the effect of lowering the internal cash generation of the subsector, mainly ONE, and increasing the dependence of the subsector on budgetary allocations to finance the development programs of the regies and ONE. The budgetary contribution by the Government represents a compensation to the subsector for subsidies that are passed on to consumers. In particular, the Government subsidizes the LV consumers to maintain households' expenditures on energy at a reasonable level relative to their income; particularly for the low income groups. However, the extension of subsidy for electricity to all the LV consumers is unjustified on both economic and social grounds. The subsidy for the large LV consumers (households and commercial consumers) lowers the average price of electricity which encourages their uneconomic use of electricity and denies the Government the resources which could otherwise be mobilized, if the LV tariffs reflected the economic cost of supply. Subsidy for the electricity consumption of the low income consumers could be accommodated by introducing a system involving a two-tier tariff for electricity: a subsidized tariff for a minimum level of consumption needed to meet the electric energy needs for basic lighting and household needs; and a tariff that is at or above the economic cost for consumption above the minimum level. 6.11 Economic pricing is essential for the efficient use of electricity, particularly in view of the recent efforts by the Government in bringing the domestic prices for petroleum products in line with their cost to the economy. Maintaining tariffs below economic cost distorts the price of electricity relative to the competing fuels and results in their use in a sub-optimal mix. Therefore, in order to maintain the price of electricity, relative to the competing fuels, at a level that would ensure their efficient use, and given the potential resources that could be mobilized by pricing electricity on the basis of economic cost, it is recommended that the Government gradually move the average tariff for electricity to achieve parity with the LRMC. The optimal strategy for moving the tariffs upwards would be dealt with in the tariff study proposed below (para. 6.16). D. Structure of Existing Tariffs Bulk Supply Tariffs 6.12 Although some features of the bulk supply tariff structure are consistent with the principles of economic pricing of electricity, the regional differences in ONE's bulk supply tariffs do not reflect differences in the cost of supply. Unless there is strong evidence of substantial - 37 - differences in transmission costs, each regie should face the same tariff for supply at the same voltage. Differences in the costs of connecting a regie to the main system, which are unique to that regie, could be levied as annual fixed charges. This could also serve as the vehicle for any cross- subsidization to achieve regional equity. Fixed charges could be calculated to make up any difference between income derived from a bulk supply tariff set equal to marginal cost and ONE's financial requirements. As this would effectively be a tax on the regie, regies in established areas could pay higher fixed charges in relation to their size than r6gies expanding their networks. Alternatively, if the income from a marginal cost based bulk supply tariff exceeds ONE's financial requirements, tariffs should continue to be set equal to economic cost to ensure efficiency, and a mechanism established for transferring the surplus accruing to ONE to a fund that would finance the development programs of the regies; for example, the FEC would be ideal for managing such a fund. It is therefore recommended that a single tariff for bulk supply be applied for all regies, unless large differences in the marginal costs of supply are identified, in order to ensure that correct price -signals are given to final consuimers, and that principles of equity and simplicity are included in the tariff design. Retail Tariffs 06.13 Medium Voltage: The structure of MV tariffs charged by the regies is consistent with the marginal costs of supply. In addition, the structure of ONE's MV tariffs is also largely consistent with the structure dictated by LRMC. 6.14 Low Voltage: The exist:ence in the tariff schedule of five consumer classifications for LV tariffs for each regie and ONE does not appear tnreasonable, although the definition of some consumer groups should be examined in the proposed tariff study (para. 6.15). There is scope for a considerable reduction in the number of tariffs by grouping together consumers with similar cost structures. Different tariffs should apply at a particular voltage level only where differences in marginal cost can be identified. The optimal number of consumer categories and the definition of each with respect to the cost of supply would be addressed in the tariff study. Moreover, the block sizes in the present domestic tariff are defined according to the number of rooms in the household. Although electricity consumption is highly correlated with the number of rooms, their contribution to the system peak will depend also on the number cf lights switched on and their ratings. Other appliances, the ownership and use of which is likely to be related only remotely to the number of rooms, will also contribute to peak demand. This definition of kWh block size distorts the marginal cost message given to consumers. It also leads to administrative problems in changing tariffs when consumers add rooms to their home. The proposed tariff study should define the consumption blocks on the basis of kWhs consumed rather than the number of rooms in the consumers' households (para. 6.10). Finally, differences in the LV tariffs among regies are justified if tariffs are to reflect the cost of supply and the financial target of each regie. However, the large number of regional variations in ONE LV tariffs has been substantially reduced after the last tariff increase of December 1982 for the purpose of greater efficiency and equity. - 38 - E. Strategy for New Electricity Tariffs 6.15 Although many aspects of the tariff structure are consistent with marginal costs, the present tariffs are based on financial rather than economic criteria. On economic grounds, tariffs should be based on a properly formulated least-cost development plan and financial targets that would ensure the development of the regies and ONE into self-financing public utilities. To achieve this objective, ONE and each regie should first formulate least-cost development programs from which the economic cost of electricity could be determined. Then, long-term financial targets should be set for ONE and the regies in order to ultimately evolve towards a satisfactory level of self-financing for the power subsector. However, in view of the difference in the financial positions of the regies and the recent deterioration in ONE's self-financing capabilities, a strategy should be set for gradually achieving the long-term financial objective over a relatively long period of time, to avoid the need for unrealistically high increases in tariff over the next 2 to 3 years. The time horizon for achieving self-financing could be adjusted for each regie to accommodate the need for a longer time horizon for newly created utilities to achieve the targeted level of internal cash generation. Therefore, in order to ensure the economic and efficient use of electricity and provide sufficient funds needed for the development of the subsector from the internal sources of the utilities, it is recommended that the government formulate a national least-cost development program for the sector based on the integration of such programs for ONE and the r6gies, and set tariffs at levels that would reflect the economic cost of supply while ensuring the gradual move of the power subsector towards self-financing. 6.16 Under Loan 1299-MOR, the Government undertook a study of the energy sector which included, among other things, a tariff study based on marginal cost pricing. The study set the principles on which all subsequent tariff adjustments have been based and have contributed to bringing about the much needed reforms and simplifications in the tariff structure. However, in view of the changes that have taken place since the tariff study was completed in 1978, and given the fact that the study concentrated its analysis on ONE's development program rather than an integrated program for the entire power subsector, the Government should update the tariff study. A major problem in updating the study is expected to be the lack of data that is detailed enough to allow for an accurate estimate of the economic cost of supply. Most, if not all, regies suffer from poor quality data on their consumers' patterns of electricity consumption. A consistent system for gathering and classifying data from all the utilities in the power subsector is urgently needed. This system could be in place in a relatively short period of time because some of the data covering the r6gies are presently available at the rdgies' data center in Cassablanca. The new data would serve as a basis for the formulation of a least-cost development plan for the power subsector, and in turn, the estimation of the long-term average incremental costs (LRAIC) and electricity tariffs. Therefore it is recommended that the Government consider the formulation of a system for gathering, classifying and integrating the data pertaining to the consumption and production of electricity throughout the country, and the use of this data for updating the tariff study completed in 1978. Annex 4 (para. 26) lists the areas to be covered in the proposed data collection exercise. - 39 - VII. INVESTMENT AND FINANCING 7.01 As discussed in Chapter III, the major weakness of the subsector is the fragmentation of its manage:ment between ministries and entities between which coordination is, in most cases, minimal. The weakness in coordination between ONE and the r6gies is reflected in the absence of a national least-cost development program that identifies investment priorities and serves as a means for mobilizing financial resources for its implementation. ONE provided the mission with an accurate account of its investment plans. The mission was unable to gather similar information for the regies. Consequently, this section of the report is limited to the review of ONE's investment planning. The absence of similar coverage for the regies is but another example of the gap in the Bank's knowledge of the urban distribution. Bridging this gap will be given high priority and would be undertaken through a specific study on urban electricity distribution. A. ONE's Investments During the 1978-1980 levelopment Plan General Program 7.02 Total planned investments by ONE under its general program (programme general) for the period 1978-1980 amounted to about DH 2,280 million (US$ 550 million). The development of generation was expected to account for about 75% of the total investment, transmission another 18%, distribution 3%, and the rest was to cover the cost of buildings and technical equipment for the offices, laboratories and workshops. However, by the end of 1980, DH 2,041 million was disbursed; representing about 90% of the planned investment. In addition, there was marked departure from the originally planned allocation with the share of generation increasing from 75% of total planned investment to 82% of the actual. The increase in the share of generation was at the expense of transmission which de!creased from 18% of planned investment to 14% of the actual. Table 7.1 below compares ONE's planned and actual investment for the period 1978-1980. - 40 - Table 7.1 ONE's Investment Program for 1978-1980 (DH million) Planned Actual Actual/Planned % of % of Amount Total Amount Total (%) Hydro generation 419 18 396 19 94.3 Thermal generation 1,305 57 1,288 63 98.7 Total Generation 1,724 75 1,684 82 97.6 Transmission 402 18 277 14 68.9 Distribution 60 3 38 2 63.0 Others 93 4 42 2 45.0 TOTAL 2,280 100 2,041 100 90.0 Generation has had the highest rate of success with 98% of the planned expenditures disbursed, followed by transmission with 69%, distribution with 63%, and finally, the category covering all other aspects of the development program with actual outlays amounting only to 45% of their planned figure. In addition to investments included in the general program undertaken and partly self-financed by ONE to meet increases in future demand, a number of other programs are implemented by ONE which acts as an executing agency and for which it does not contribute financially. These investments amounted to about DH 302 million for the 1978-1980 period and were distributed as follows: DH Million - Special Fund 36 - Rural Electrification 27 - Customer Connections 239 7.03 ONE's investments under its general program were financed by the Government, loans and supplier's credits, and the utility itself. The sources of financing for the program are summarized in Table 7.2 below. Table 7.2 Sources of Financing for ONE's 1978-1980 Investment Program (DH million) Source Amount % of Total Government 566 28 Loans & supplier's credits 1,135 55 ONE 340 17 2,041 100 - 41 - ONE's contribution-to-expansion ratio, as computed according to a Bank loan covenant (IBRD Loan 1299-MOR) dropped to about 9% in 1980 from 22% in 1979 and 24% in 1978. This significant: drop was caused by: the substantial increase in the utility's fuel bill brought about by the Government's decision to bring the domestic prices of petroleum products and coal in line with their opportunity cost to the economy; and the unexpected increase in the overall fuel bill, resulting from the fact that 1980 was a relatively dry year which reduced the contribution of ONE's hydroelectric plants to the overall supply of electricity and forced the utility to increase its dependence on thermal power plants. However, the reluctance of the Government to allow ONE to pass on all increases in its fuel bill to its customers was the main reason for the erosion in ONE's level of self-financing. 7.04 The contribution of the Government to the overall cost of ONE's investment program, amounting to DH 566 million, represents about DH 0.050/kWh or a 20% increase in the average tariff for the 3-year period. This would have been in addition to the increases needed to compensate ONE for the increased cost of fuel. The analysis shows that complete financial independence of ONE (financial autonomy) could have been achieved between 1978 and 1980 with a relatively modest yearly increase in the utility's average tariff. This would ensure the financial autonomy of ONE and mobilize resources from the consumers, and release a sizeable amount of the national budget for the non-revenue earning sectors. 7.05 In spite of the fact that 90% of the overall planned expenditures were disbursed, the projects included in the 1978-1980 plan had, in most cases, slipped, and their date of completion and the financing of their cost overruns are now included in the plan for 1981-1985. The dependence of ONE on Government funds for implementing its development program and the delays in the disbursement of these funds have been primarily responsible for both the slippages in implementing the investment program, and most of the resulting cost overruns experienced. The delays in the disbursement were particularly severe for the multipurpose projects which involved several ministries and entities, each with its own budgetary constraints and priorities. Details of project implementation under the 1978-1980 plan is summarized below: Generation: The expansion of ONE's generating capacity included the completion of three hydroelectric projects (Idriss I, Al Massira, and Oued El Makhazine), the expansion of an existing hydro power plant (Lalla Takerkoust), the installation of four gas turbines, and the construction of the 4x75-MW steam power station at Kenitra and of the 4x150-MW fuel-fired p:Lant at Mohammedia. Delays were incurred in the execution of the hydropower projects (Al Massira, Lalla Takerkoust), and in the construction of the Mohammedia plant. These resulted in some significant cost overruns; ranging between 5% and 25% (Lalla Takerkoust 25%, Al Massira 11.2%, etc.). Transmission and Distribution: The program for the expansion of the transmission network was significantly curtailed, with less than 70% of the planned expenditures actually disbursed; primarily because of a shortage of funds. The reduction was even greater in the case of the distribution program financed by ONE (63%) and the category - 42 - covering buildings and specialized equipment (45%). This has actually been a recurring trend in the implementation of ONE's investment programs. Contrary to initial plans, most of the scarce funds actually made available go to the expansion of ONE's generating capacity, leaving insufficient resources for the reinforcement and extension of the rest of the power facilities. 7.06 The review of ONE's investment program for 1978-1980 made possible the identification of the main constraints or bottlenecks to the timely and efficient implementation of the development program. These are: (a) Erosion in ONE's Level of Internal Cash Generation: The Government's control of tariffs and the continued increase in the cost of fuel used for power generation, coupled with the hydrologically dry years, resulted in a significant deterioration in ONE's ability to maintain a healthy level of internal cash generation. As a result, a relatively efficient revenue-earning utility has moved from an adequate level of self-financing of more than 20% in 1978 and 1979 to 9% in 1980. This increased its competition with the non-revenue earning public entities for the scarce revenues of the Government. This bottleneck could be resolved by allowing ONE to activate the fuel adjustment clause in its tariff structure and allow the utility to pass on to its consumers all increases in the cost of fuel. In addition, the elimination of control over tariffs and indirect subsidies to the regies at the expense of ONE's finances, and the creation of a fuel cost stabilization fund would go a long way in smoothing the increases needed by ONE to cover unexpected increases in its cost of operation and providing the funds needed for the implementation of its development program; (b) Organizational Control of ONE: According to its mandate, ONE is supposed to be a financially and administratively autonomous enterprise. In reality, however, the utility is beset by administrative regulations and controls which affects the efficiency of its operations. Procurement laws restrict ONE's acquisition of material and services to a maximum of DH 50,000 (US$9,000) and DH 500,000 (US$90,000) respectively. Otherwise, permission of the Ministry of Finance is required which is usually granted after considerable delays. Disbursement by the Government of funds for projects undertaken by ONE in cooperation with other ministries and institutions, involves in most cases, concurrence by the Ministry of Finance and all ministries involved. These concurrences are usually marked with delays because of the complexity of the administrative procedure. If the plan for 1981-1985 is to be implemented efficiently and cost overruns to be avoided, the Government should take all the necessary steps to ensure that the administrative autonomy of ONE is guaranteed and that the funds allocated from the national budget for its development program are provided at the beginning of each fiscal year and placed under the full disposal of the utility. - 43 - As stated earlier (para. 6.02), ONE's financial autonomy should be ensured by removing the control over tariffs, the activation of the fuel adjustment clause, the creation of a fuel fund, the elimination of indirect subsidies to the regies and gradually moving the utility towards an acceptable level of self-financing. These are long-term measures whose implementation would take time. In the interim, however, it is recommended that the Government reduce the administrative restrictions and complex procedures to provide ONE greater freedom of decision in operating its system and executing its development program, and make the funds earmarked for the utility's investment program available in a timely and efficient manner to ensure against slippages and delays in the implementation of projects. Such measures, which would implicitly lead to a radical change in Morocco's system of public enterprises' financial control, could be introduced more smoothly through the establishment of a special "development contract" with ONE in the same manner as is being implemented with Royal Air Maroc (RAM) which aims at substituting a system of management by objectives for the present strict a priori Government financial control. B. Planned Investment in the Power Subsector, 1981-1985 7.07 ONE's planned investment for 1981-1985,included in its general program, amounts to about DH 3,932 million (US$710 million), 1/ of which about 50% (DH 2130 million, or US$385 million) will be in direct foreign exchange cost. Relative to the overall investment program planned for the energy sector as a whole, it represents the largest investment, or about 55% of the total. The allocation of ONE's planned investment is summarized in Table 7.3 below. Table 7.3 ONE's Investments, 1978-1980 and 1981-1985 (DH Million) 1978-1980 1981-1985 % Share % Share Amount /1 in Total Amount /2 in Total Generation 1,684 82 2,877 73 Transmission 277 14 620 16 Distribution 38 2 160 4 Others 42 2 275 7 Total 2,041 100 3,932 100 /1 In current terms. 77 In 1981 prices. 1/ In 1981 prices. - 44 - About 73% of these investments will be allocated to the expansion of the generating capacity, which represents a slight decrease in its share of total investment as compared to the previous plan period (82%). This is offset by an increase in the relative share of transmission which will rise from less than 14% during 1978-1980 to 16% between 1981 and 1985, of distribution (from 2 to 4%) and of other investments (from 2 to 7%). 7.08. The investment program presented in Table 7.3 excludes: (a) the sector's contribution to the joint costs of multi-purpose hydroprojects (according to Morocco's five-year plan, the construction of dams is classified under the Ministry of Equipment's investment program); and (b) investments undertaken by the regies to develop their urban distribution networks. Very limited information is available on the regies' investment programs which, in most cases, are established on a short-term basis, contrary to ONE's programs. Further investigation into each regie's planning is necessary to obtain an estimate of their yearly investment in electricity distribution facilities, covering both the reinforcement and extension of their respective supply networks, and to determine how they fit into ONE's expansion program, and whether they represent a least-cost development program. Most of the data could be collected under the electricity tariff study proposed in Chapter VI. Moreover, the investment program presented in this chapter for the 1981-1985 period does not take account of the changes currently under way as a result of Morocco's financial difficulties. Generation 7.09 The program for the expansion of the generating capacity consists of: (a) The development of 6 hydroelectric sites, 5 of which are multipurpose projects (para. 5.10). Total expenditures during 1981-1985 will amount to about DH 713 million, equivalent to 25% of the proposed investment in generation; this amount might, however, be reduced due to the postponement by 6 months to 2 years of three of the 6 projects; (b) The completion of the 4x150-MW steam power plant at Mohammedia, including the conversion to dual-fired operations of the last two units coming on stream in 1985. Total outlays will reach DH 1,124 million, of which DH 890 million corresponds to the cost of the coal conversion; (c) The initiation of an oil shale direct combustion program with the construction of a 100-MW pilot power station at Timahdite with a total cost of about DH 2,300 million, of which DH 1,000 million would be disbursed between 1981 and 1985. However, given the recent Government decision to substantially reduce its budgetary contribution to the financing of the oil shale program, it is most likely that ONE will defer its investment expenditures beyond 1985. Transmission 7.10 Investment outlays for the extension of the transmission network are expected to reach about DH 620 million (US$115 million) between 1981 and - 45 - 1985. Beside the connection of Mohammedia to the national grid, the main thrust of the investment program is the reinforcement and extension of the 225-kV network through the addition of 1,052 km of lines which will mainly be used to transport electricity from Mohammedia to the load centers in the south. The 60-kV transmission system will also be expanded through the installation of 1,540 km of new lines, part of which will come from the downgrading of 150-kV lines. Distribution 7.11 Investments included in the general program for distribution amount to about DH 160 million (US$ 29 million) between 1981 and 1985. Most of the budget will cover the reinforcement and extension of the 22-kV distribution network. 7.12 In addition, ONE plans to invest about DH 1,023 million under its other programs. About DH 330 million is expected to cover the cost of connecting new customers to ONE's supply system. ONE's objective is to reach a 75% urban electrification ratio by 1990 with the connection of 250,000 additional customers to public electricity supply. The rest will be devoted to rural electrification through the implementation of three programs: (a) ONE's special fund program (DH 138 million) which consists essentially of the much needed maintenance, reinforcement and extension of its distribution network in the rural areas in order to improve the quality of service to its customers; (b) The program for the electrification of the Saharan provinces which is executed by ONE on behalf of the Government. This program is expected to cost about DH 105 million over a three-year period starting in 1982; and (c) The national program for rural electrification which, under its first phase, is expected to connect 254 villages to the national grid at an estimated cost of DH 450 million. Initiated in 1977 by MI which requested Bank assistance for its formulation and financing (IBRD Loan 1695-MOR), it is currently being implemented, with ONE acting as the executing agency. The program is however about 1 year behind schedule, mainly because of the slow space of disbursement of Government funds and of the delays incurred in establishing the list of villages to connect. Overall, ONE plans to double the number of its LV consumers before the end of 1990 with the connection of 700,000 new customers in both urban and rural areas. Buildings and Technical Equipment 7.13 About DH 275 million (US$50 million) are budgeted for additional works to be undertaken by ONE, of which the construction of a dispatching center constitutes the largest investment. - 46 - C. Financing Plan for the 1981-1985 Program 7.14 It is estimated that about 37% of the overall investment program will be financed out of the national budget, 39% from external borrowings and 20% from domestic borrowings. ONE would contribute about 4% from its internally generated cash, and the balance of about 12% would be covered by customers' contributions. Table 7.4 below summarizes thc share of each financial source in the planned investment program. Table 7.4 Financing Plan for the 1981-1985 Investment Program /1 (DH million) Amount % Share in Total Government 1,455 37 External Borrowings 1,533 39 Domestic Borrowings 786 20 ONE 157 4 TOTAL 3,932 100 /1 In 1981 prices. 7.15 The Government plans to continue its coverage of the cost of the hydroelectric components of the multipurpose dams from budgetary allocations extended through the Ministry of Equipment. Although this approach to financing some of ONE's new hydroelectric plants has a favorable impact on the utility's financial position, it is inconsistent with the Government's recent policy of increasing the financial autonomy of public enterprises to reduce their burden on the national budget. It also adds further to the complex financial environment in which ONE operates with controlled tariffs, indirect subsidies to the regies at the expense of ONE and the large r4gies, and equity transfers to ONE at the expense of the already overstrained budget. On the pricing side, ONE should be entrusted with the determination of its own tariffs to cover its operating costs and provide the desired level of internal cash generation. On the cost side, ONE should be responsible for covering the cost of all equipment and share of common facilities used for the generation, transmission and distribution of electricity. However, this responsibility should only cover the cost of facilities which are a part of ONE's least-cost program. It is, therefore, recommended that the Government undertake a study for determining the most efficient and equitable means by which ONE can compensate the Government for the service provided by the hydropower components of multipurpose schemes. The study should allow for the formulation of a gradual strategy for ONE's achievement of financial autonomy which could, however, be implemented only after ONE's financial viability has been restored and electricity tariffs have been sufficiently increased. - 47 - 7.16 A large proportion, even higher than that provided to ONE, of the development programs of the r6gies is covered by the Government through two channels: budgetary allocations disbursed through MI; and concessionary loans from the Fonds d'Equipment Comnunal (FEC) (para. 3.10). As in the case of ONE, the Government is foregoing a substantial amount of resources to provide funds for the development prog:rams, which are not necessarily least cost from the national point of view, and whose finance could be secured by capturing some of the surplus accruing to the low and medium voltage consumers. The prevailing law, which ensures :'he neutrality of the effects of new tariffs on the financial positions of the regies, is inconsistent with the Government's policy for fiscal austerity because it does not provide the incentives to the regies to achieve a greater level of self-financing or improve the efficiency of their operations. Although the regies are supposed to be financially autonomous utilities, their financial objectives are not clear (no set targets for self-financing), and the concept of autonomy is not associated with a fixed level of internal cash generation. Consequently, the level of self-financing for the rggies fluctuates from one year to the next; depending on the number of new consumers connected, the success of the management of each r6gie in securing soft loans from the FEC, and the Government. Moreover, the regies are not induced to improve their efficiency because the law ensuring the financial neutrality of changes in tariffs, reduces the r6gies to being transmitters of changes initiated by ONE to the ultimate consumers; almost as would exist in a sysl:em where electric service is provided on a cost plus basis. Therefore, if the r6gies are to improve their technical and operating efficiencies, and move towards financial autonomy, it is recommended that the Government start by requiring each regie to formulate a least-cost investment program, and integrate these programs and that of ONE into a national development program for power, then eliminate the indirect subsidies to the small r6gies, and finally set financial targets that would gradually be adjusted upwards to ensure that: all utilities are financially viable. 7.17 Customer contributions constitute an important element in the financial resources of both ON: and the regies. Customer contributions are in essence a prepayment for equiprient and material used to connect new consumers. The rules governing the payment by new consumers require that they cover the total cost of the facilities needed for their supply of public electricity. All new customers are required to pay connection charges before service is provided. In the case of a small consumer (domestic), the entire charge must be paid before worlk begins in extending the service. In the case of a large consumer (industrial), the connection charge can be paid in four or less installments (depending upon the utility and the nature of the new consumer). In both cases, the customer is expected to prepay for all costs (equipment, lines, additions to transformer capacity, etc.) that will be incurred by the utility in providing the service. Prepayment for the domestic consumer is required and at least 60% (depending upon the r6gie) of the domestic customers living in a development to be provided with power must ask for the service and prepay before work to service the development begins. If a large consumer requires the expansion of facilities for his exclusive use, the total cost incurred by the utility must be prepaid by that customer. Later on, if the facilities are used by other customers during a qualifying period (five years for the medium voltage and ten years for the low voltage), - 48 - the customer is reimbursed a segment of his connection charge proportional to the ratio of the magnitude of the service to be received by the new customers and the maximum potential service paid for by the first customer. This process continues until the facilities are fully utilized. The consumer loses the right to any reimbursement, if within the qualifying period the facilities are not used by additional customers. This system for financing the development of urban distribution has two main shortcomings. The first is that it discriminates against the urban poor who usually settle around the perimeters of the urban centers. The consumers are usually unable to afford the initial payment for distribution facilities, and as a result, unable to gain access to public supply of electricity. This is reflected by the fact that the percentage of urban population with access to electricity has been steadily declining over the past 10 years. The second shortcoming of depending on consumer contributions for financing distribution is that the development of the network does not follow a least-cost path, but instead, is dictated by the willingness and ability of consumers to pay the high cost of the initial investments. If the distribution network is to be developed in accordance with a least-cost plan, and considering the adverse impact the prevailing system has from the point of view of equity within a consumer category (low voltage urban), it is recommended that the Government consider the expansion of the distribution network on the basis of properly formulated least-cost programs. Recommendations for a reform of the connection charge system could only be formulated once a detailed investigation of the urban distribution of electricity is carried out, as proposed in this report. March 19, 1984 (0781P) - 49 - ANNEX 1 Page 1 of 11 MOROCCO POWER SUBSECTOR STUDY Historical Trends in the Consumption and Supply of Electricity A. Past Trends in Electricity Consumption Dverall Consumption 1. Electricity consumptiom increased during the period 1970-1980, at an average annual rate of 9.6% while maximum demand increased at an average annual rate of about 8.8%. Table 1 below summarizes the changes since 1970 in the consumption of electricity, maximum demand and the average load factor. Rapid growth of industrial elecitricity consumption, and stagnation or decline in access of households to suppLy explains other trends which occurred in the demand for electricity. On a per capita basis, gross national electricity consumption grew from 138 kWh in 1970 to 262 kWh in 1980, corresponding to an average rate of 6.6% per year. Despite the high proportion sold to industry, lper capita consumption of electricity remains relatively low in comparison to oDther countries in the region (Algeria: 307, Tunisia: 364, Jordan: 445, Egypt: 455 kWh). This reflects, to a large extent, the very low degree of ,electrification in rural areas, where only 6% of the population has access to Ipublic electricity supply. Table 1 Growth in Electricity Demand, 1965-1980 Annual Rate of Growth (%) 1970 1975 1980 1970-1975 1975-1980 Electricity Consumption (GWh) 2,108 3,269 5,247 9.2 9.9 Interconnected System Gross Generation (GWh) /1 1,957 3,038 4,762 9.2 9.4 Maximum Demand (MW) 384 596 880 9.2 8.8 Load Factor (%) 48.3 58.7 61.6 /1 Including production by Electras Marroquies and purchases. -50 - ANNEX 1 Page 2 of 11 2. Electricity consumption per dollar of GDP 1/ increased at an average annual rate of about 4%; from 525 kWh/US$1,000 in 1970 to 783 kWh in 1980. The increase in the intensity of electricity consumption is primarily attributed to the expansion of the industrial, agricultural and service sectors. This was responsible for the fairly high elasticity of electricity consumption with respect to GDP which averaged 1.8 for the period 1970-1980. Electricity Consumption by Economic Sector 3. The sectoral consumption of the publicly supplied electricity is shown in Table 2 2/ below. Among the major sectors of the Moroccan economy, public administration had the highest rate of growth, followed by services, industry, and agriculture. There was a decline in the share of transport and mining, from 22% of total electricity sold in 1970, to 16% in 1980. The extension of irrigated areas, in addition to the 1980-1981 drought which increased irrigation requirements, resulted in the consumption of electricity by agriculture growing at an average annual rate of about 12.8%. In 1981 which was an extremely dry year, the electricity consumption of the agricultural sector increased by 55%, most of which was for irrigation pumping. Table 2 Sectoral Consumption of Electricity (Public Supply System) Annual Rate 1970 1980 of Growth (%) GWh % GWh Z 1970-1980 Agriculture 49.0 3.0 163.6 4.1 12.8 Mining 252.1 15.7 482.0 12.2 6.7 Industry 529.1 32.9 1,439.8 36.4 10.5 Services 60.7 3.8 203.4 5.1 12.9 Transport 104.0 6.5 160.0 4.0 4.4 Public Administration 38.1 2.4 187.8 4.7 17.3 Residential & Commercial 402.5 25.1 983.5 24.9 9.4 Others /1 170.0 10.6 334.9 8.5 7.0 TOTAL 1,605.5 100.0 3,955.0 100.0 9.4 /1 Includes public lighting, energy, and water distribution. 4. The overall sectoral consumption of electricity presented in Table 2 is understated because it does not take account of autogeneration in the 1/ Measured in 1970 prices. 2/ Excluding autoproducers, isolated systems run by the Ministry of Interior, and others for which no sectoral breakdown is available. - 51 - ANNEX 1 Page 3 of 11 industrial, mining, and agricultural sectors. Net consumption by asutoproducers /1 is estimated ta have increased from 134 GWh in 1970 to 463 GWh in 1980; representing an average annual rate of increase of about 13.2%. As seen from Table 2 above, the consumption of electricity generated by the autoproducers grew at a slightly higher rate than the consumption of publicly supplied electricity by the industrial and mining sectors. As a result, the proportion of all industrial electricity supplied by autoproducers rose from 20% in 1970 to 22% in 1980. By contrast, the growth of consumption by the agricultural sector of publicly supplied electricity was higher than the rate of growth of electricity produced by the isolated systems, reflecting mainly the preference of consumers for electricity provided at subsidized tariffs to autogenerated electricity using diesel oil whose price has been brought in line with its border price since 1976. 5. Detailed data on the consumption by industry of publicly supplied electricity shows considerable variations in the consumption pattern of the various industrial subsectors. Table 3 provides a summary of the consumption by type of industry. Details are presented in Attachment 7. Table 3 Consumption of Electricity by Economic Subsector (GWh) (Public Supply System) Annual Rate of Growth (%) 1970- 1975- Subsector 1970 1975 1980 1975 1980 Mining 252.1 414.6 482.0 10.5 3.1 Phosphates 142.9 225.4 298.5 9.5 5.8 Coal 31.9 41.7 46.8 5.5 2.3 Other 77.3 147.5 136.7 13.8 -1.5 Industry 578.1 828.4 1,507.2 7.5 12.7 Engineering 19.7 34.2 78.4 11.7 18.0 Cement 110.7 162.0 339.5 7.9 15.9 Chemicals 40.3 55.9 215.5 6.8 31.0 Food Processing 126.1 168.0 247.5 5.9 8.1 Textiles 123.5 183.1 273.6 8.2 8.4 Construction and Construction Materials 31.4 39.2 103.2 4.5 21.4 Others /2 126.4 186.0 249.5 8.0 6.1 Transport 104.0 113.0 160.0 1.7 7.2 Rail 73.3 74.9 106.6 0.4 7.3 Other 30.7 38.1 53.4 4.4 7.0 /1 Excluding station use and sales to ONE. 7T Others include glass and ceramics, leather, wood, paper, plastics, and industries supplied at low voltage. - 52 - ANNEX I Page 4 of 11 The changes in the rates of growth over the period 1970-1980 is a clear indication of Morocco's industrial strategy over the 10-year period, and the emphasis on electricity-intensive industries. Chemicals, construction materials, cement and engineering equipment had the highest rates of growth in electricity consumption over the last five years of the decade; ranging from 31% for chemicals to 12.7% for engineering equipment. The increased consumption of electricity by the transport sector, particularly rail, since 1975 reflects the substitution in the public transport system of electricity for high-value petroleum products in response to higher oil prices. Electricity Consumption by Households 6. Little reliable information is available on the consumption of electricity by households and their access to supply. Electricity sales to households is divided between the regies and ONE. As the regies report to a different ministry, the responsibility for gathering data to cover the entire subsector is lacking. Estimated numbers of household consumers and their consumption are shown for ONE and three regies in Table 4. Since 1975, the annual rate of growth in the number of household consumers has averaged between 4.0% and 4.8%, depending on the utility. This is compared to an average annual growth for the population over the same period of about 3% and 5% for the urban population. Based on the limited information available, it appears that access to supply did not improve much during the second half of the 1970s and may actually have decreased. A Bank study carried out in 1977 estimated that the population with access to supply in the predominately urban areas supplied by the regies fell from 63% in 1972 to 57% in 1977. 1/ This decline, or at best, lack of improvement in access to public supply of electricity has been a consequence of the policies for financing the extensions of the distribution networks. Initial consumers are responsible for financing in part, facilities that are subsequently used by others. 1/ Yellow Cover report on Urban Electricity Distribution in Morocco, June 29, 1978. -53- ANNEX 1 Pa-ge 5of 11 Table 4 Household Electricity Consumption /1 Annual Rate of Growth (%) 1970 1975 1980 1970-1975 1975-1980 Number of Consumers ONE Supplied Areas 177,231 249,043 305,475 7.0 4.2 Casablanca /2 -- 240,924 /3 286,712 -- 4.4 Fes 36,488 45,525 55,365 4.5 4.0 Rabat 66,249 81,627 103,051 4.3 4.8 Consumption (GWh) ONE Supplied Areas 55.3 103.7 161.7 13.4 9.3 Casablanca /2 -- 317.1 /3 419.6 -- 7.3 FEs 21.1 30.3 50.9 7.5 10.9 Rabat 57.6 85.7 129.5 8.3 8.6 Specific Consumption (kWh/Consumer) ONE Supplied Areas 312 417 529 6.0 4.9 Casablance /2 -- 1,316 /3 1,464 -- 2.7 Fbs 580 666 919 2.8 6.7 Rabat 869 1,050 1,257 3.9 3.7 /1 Data are for the following tariffs: eclairage prive, tarif mixte, and tarif triple. /2 Casablance data are for all LV sales. /3 Data for 1976. 7. Table 4 also shows how the average consumption per consumer has changed between 1970 and 1980. In 1980, households taking supply from ONE consumed about 530 kWh compared to nearly 1,260 kWh in Rabat. These levels of consumption are similar in other countries in the region. The differences in average household electricity consumption among the utilities arise from rural consumers having lower consumption. This also accounts for the differences in growth rates in average consumption per consumer. Consumption by Voltage Level 8. Consumption increased most rapidly at the medium and high voltage levels at an average rate of about 9.8% per year for the period 1970-1980; reflecting the high proportion of electricity consumed by industry. Low voltage consumption increased at an average rate of 8.6% per year (Attachment 9). - 54 - ANNEX 1 Page 6 of 11 Regional Electricity Consumption 9. Electricity consumption in Morocco is heavily concentrated in the central region of the country where most of the population and the largest industries are located. As can be seen from Table 5 below, Casablanca, Rabat, and their surroundings account for two-thirds of total consumption. Details are given in Attachment 8. Demand from the south has been growing fast as a result of economic and military developments in this area. Table 5 Regional Consumption of Electricity Annual Rate 1970 1980 of Growth (%) Province GWh % GWh % 1970-80 Centre 775.8 48.3 1,691.8 42.8 8.1 Northwest 321.5 20.0 907.3 22.9 10.9 Tensift 127.3 7.9 378.9 9.6 11.5 East 115.1 7.2 283.8 7.2 9.4 South 65.1 4.0 251.8 6.4 14.5 Center-South 115.1 7.2 226.5 5.7 7.0 Center-North 86.6 5.4 214.9 5.4 9.5 TOTAL 1,606.5 100.0 3,955.0 100.0 Distribution of Final Electricity Sales Between ONE and the R6gies 10. ONE has been able to continuously increase its share of the market relative to the share of the regies. The increase in ONE's share is primarily due to the direct service extended to the growing industrial sector; the decline in the rate at which the r6gies connect new low-voltage consumers relative to the pace maintained by ONE in extending its service; and the extension of ONE's distribution network in the rural areas. ONE's direct sales to final consumers now account for 46% of total electricity sales in Morocco, compared to 44% in 1970. ONE's and the regies' comparative market share has evolved as shown in Table 6 (Attachment 9). -55 - ANNEX 1 Page 7 of 11 Table 6 ONE's and the :Ukgies' Comparative Market Share Annual Rate 1970 1980 of Growth (%) GWh % GWh % 1970-1980 Low Voltage Sales ONE 92.0 18 256.8 23 10.8 R6gies 403.5 82 872.6 77 8.0 TOTAL (1) 495.5 100 1,129.4 100 8.6 Medium and High Voltage Sales ONE 551.0 50 1,557.4 55 10.9 R6gies 560.0 50 1,268 45 8.5 TOTAL (2) 1,111.0 100 2,825.6 100 9.8 All Voltage Sales ONE 643.0 40 1,814.2 46 10.9 Regies 963.6 60 2,140.8 54 8.3 TOTAL (1)+(2) 1,606.5 100 3,955.0 100 9.4 B. Past Trencs in the Supply of Electricity Generating Capacity 11. ONE's generating capacity has increased substantially over the past ten years, from 532 MW in 1970 to 1,560 MW in 1981; representing an average annual rate of increase of about 10.3%. Since 1970, the bulk (71%) of the new capacity was provided by the installation of new thermal generating facilities, mainly oil-fired steam power plants. The greatest increases in oil-fired capacity occurred between 1975 and 1979. As a result, by the end of 1981, ONE's installed capacity consisted of 613 MW of hydroelectric capacity located for the most part on the Oum Er R'bia river and 947 MW of thermal units, including 735 MW of steam power plants and 120 MW of gas turbines. In addition, 49 MW of dual coal/oil-fired steam plant and 15.5 MW of gas turbines had been placed in cold storage. Table 7 summarizes ONE's installed capacity from 1965 to 1981. Further details are given in Attachments 1 and 2. -56 - ANNEX 1 Page 8 of 11 Table 7 ONE's Installed Capacity (MW) 1965 1970 1975 1981 Hydro 332 362 397 613 Thermal - Steam; Coal -- -- 165 165 Fuel Oil -- -- 60 510 Coal/Fuel Oil /1 57 117 109 109 - Gas Turbines; Fuel Oil -- -- 60 120 Gas Oil -- 16 16 16 - Diesel 22 33 24 20 - Isolated Systems 3 4 3 8 Total Installed Capacity 414 532 833 1,560 /1 Dual-fired plants. 12. The available capacity fluctuated considerably during the period 1975-1981 because of the variation of the hydrological conditions and their impact on the production potential of the hydro power plants (Attachment 4). 1/ Average capacity available at peak during 1975-1981 was 73% of installed capacity for hydro and 80% for thermal plant. Hydro availability ranged from 59% to 90%. As a result, the system's effective reserve margin fluctuated substantially from one year to another, in addition to the usual variations arising from the commissioning of new units. Since peak demand has increased steadily since 1970 from 384 MW to 960 MW in 1981, the effective reserve margin has ranged between 56 MW and 204 MW equivalent to 6% and 23% of maximum demand respectively. Because of severe hydrological conditions in 1980 and 1981, the effective reserve margin in 1981 amounted to only 60 MW, which represented 6% of the year's peak demand. However, the absolute margin of installed capacity to demand has been much higher, ranging from a minimum 30% in 1976-1977 to a maximum of 63% in 1981. There is no significant seasonal variation in monthly peak demand. It varies by about 5-7% above the average in winter and the same amount below in summer. However, the effective reserve margin will vary by more than this because of seasonal variation in hydro output. 1/ Actual hydro generation may vary within a 30% margin around the average, depending on the year's rainfall. - 57 - ANNEX I Page 9 of 11 Electricity Generation 13. Total generation by ONE reached 5,099.6 GWh in 1981, compared to 1,908 GWh in 1970, which represents an average growth of 9.3% per year. As summarized in Table 8 below (see Attachment 4 for details), the share of thermally generated electricity has increased substantially during the last 15 years reflecting the steady shift by ONE toward increased dependence on thermal capacities for electricity supply. Thermal facilities produced about 80% of total electricity generated by ONE in 1980, compared to only 11% in 1965. Hydro production fell as low as 20% in 1981 because of the drought. Table 8 Pattern of ONE's Electricity Production, 1965-1981 (% of Total Production) 1965 1970 1975 1980 1981 Hydro Power Stations 89 69 34 32 20 Thermal Power Stations 11 31 66 68 80 - Steam Power Plants 10 29 61 67 79 - Combustion Turbines /1 1 2 5 1 1 TOTAL 100 100 100 100 100 /1 Including isolated and autonomous diesel generators. 14. Production by autopro,lucers has been mainly from thermal plants. During the period 1975-1980, hydro production by autoproducers accounted for less than 5% of total generation by this group of producers. Although little reliable information is available on electricity production outside the public supply system, an estimate was made of the overall balance of electricity production and consumption for 1980 (Attachment 5). It shows that 90% of all electricity generated nationalLy was produced by thermal plants with ONE accounting for 90% of all eleclricity generated. In 1980, autoproducers sold 6% of their output to ONE, but their sales to ONE had been as high as 11% in 1977. Of the total electricity used by final consumers, 41% was sold by ONE, 49% by the regies, 9% was produced by autoproducers for their own use and the remainder was supplied by MI to the isolated villages whose public services are being managed by the Minist:ry. Station Use and Losses 15. ONE power station use in 1980 amounted to 1.8% of gross generation for the hydro plants and 8.6% for the thermal plants. Losses in transmission, i.e., before sales to bulk consumers, amounted to 7% of energy delivered to the network. These losses are relatively high, reflecting the slippages in ONE's program for the reinforcement and expansion of the national transmission -58 - ANNEX 1 Page 10 of 11 network. Distribution losses were 2.8% for the ONE system and 6% for the regies, which seem low. Attachment 5 shows that nationally, about 16% of electricity generated was either used by the power stations for their own needs, or lost in transmission and distribution. The level of losses at each of the stages involving the production, transport and delivery of electricity cannot be determined accurately because of inadequate data on the areas served by the rSgies. Reduction of losses is one of the main means for abating the increase in the cost of electricity. It is recommended that a study be undertaken to determine losses at each voltage level in the public systems and to propose a set of actions for reducing them. Fuel consumption for Power Generation 16. The growing predominance of oil-fired thermal power stations in ONE's generating system has resulted in a large increase in its fuel oil consumption since 1970, as summarized in Table 9 below (Attachment 6). Table 9 Fuel Consumption for Electricity Generation, 1970-1981 (ONE) 1970 1980 1981 GWh '000 Tons GWh '000 Tons GWh '000 Tons Produced Consumed Produced Consumed Produced Consumed Coal 557.4 254 1,032.1 595 1,167.2 690 Fuel Oil -- -- 2,180.8 570 2,886.8 745 Gas Oil/Diesel 34.2 5 5.7 3 21.7 3 Average thermal efficiency was about 27%, until the commissioning of the Kenitra oil-fired station in 1978 raised it to its present level of about 30%. The efficiency of all fuel oil-fired units is about 35%, whereas the coal-fired units have an efficiency of around 25%. 17. The increasing trend in fuel consumption has been exacerbated by the drought that has affected Morocco in the past two years which reduced ONE's hydrogeneration. The adverse effect of rising fuel consumption has been compounded by successive increases in the prices of fuel. Fuel price increases have been enforced following the Government's determination to progressively eliminate subsidies for petroleum products. ONE has not been allowed to raise its electricity tariffs systematically to compensate for higher fuel costs, so that it has been unable to meet its financial targets in 1980 and 1981 (para. 6.02). This highlights the need for ONE both to adjust its tariffs upward and to reduce its dependence on petroleum fuels. Taken globally, this dependence has risen dramatically during the last decade. Table 10 presents the distribution of ONE's electricity generation by primary energy source (including hydroelectricity). -59 - ANNEX 1 Page 11 of 11 Table 10 Distribution of Power Generation by Primary Energy Source (ONE ) 1970 1980 1981 %' Share % Share % Share GWh irn Total GWh in Total GWh in Total Coal 557.4 29 980.0 21 I,190.1 24 Fuel Oil -- -- 2,232.8 46 2,863.9 56 Gas Oil/Diesel 34.2 2 5.7 -- 21.7 -- Hydroelectricity 1,316.4 69 1,514.6 32 1,023.9 20 TOTAL 1,908.0 100 4,733.2 100 5,099.6 100 Note -- = Negligible (less than half a percentage point). While practically all the electricity generated in 1970 was produced using domestic resources (coal or hydropower), this share has dropped to about 50% in 1980 and because of the drcught, to an even lower level in 1981. The power subsector has thus contributed significantly to the increase in Morocco's dependence on imported energy, especially petroleum products. 1/ Transmission 18. The transmission network has been extended and improved in line with the expansion of system generating capacity. The 225-kV grid is progressively replacing the former 150-kV system. A 60-kV subtransmission network transports energy to the distribution system at 22 kV. A plan for interconnecting the Moroccan system to the Algerian one has been contemplated for several years now. This interconnection would contribute to a more economic utilization of generation facilities in both countries and therefore, the Government should give serious consideration to initiating the link since it would make possible the reduction of the stand-by capacities in the two systems. 1/ If power generation by autoproducers is taken into account, the dependence of the power subsector on imported fuels would be even greater. February 1984 (0756P) - 60 - ANEX 1 Attachbent 1 POM SUBSn Sn Installed Capacity of Thermal Plants, 1965-1981 (MW) Plant 1965 1970 1975 1976 1977 1978 1979 1980 1981 Jerada - - 165 165 165 165 165 165 165 Roches Noires Unit 1 32 32 32 32 32 32 32 32 32 Unit 2 - 60 60 60 60 60 60 60 60 Unit 3 - - 60 60 60 60 60 60 60 Kenitra - - - - - 75 300 300 300 Oujda 24.5 24.5 17 17 17 17 17 17 17 Moanmndia - - - - - - - - 150 Total Stean Plants 56.5 116.5 334 334 334 409 634 634 784 Sidi Kacem - 15.5 15.5 15.5 15.5 15.5 15.5 15.5 15.5 Agadir - - 20 20 40 40 40 40 40 Tangier - - 20 20 40 40 40 40 40 Tetouan - - 20 20 40 40 40 40 40 Total Combustion Turbines - 15.5 75.5 75.5 135.5 135.5 135.5 135.5 135.5 Tangier 10 10 10 10 6.4 6.4 6.4 6.4 6.4 Sidi Kacem 7.2 7.2 7.2 7.2 7.2 7.2 7.2 7.2 7.2 Other diesel ergines 4.7 15.9 6.7 4.5 5.3 6.4 6.4 6.4 6.4 Total Diesel Plants 21.9 33.1 23.9 21.7 18.9 20.0 20.0 20.0 20.0 Standby plants 3.3 4.4 3.0 5.0 5.1 5.3 6.2 7.6 7.6 Total Thermal Plants 81.7 169.5 436.4 436.2 493.5 569.8 795.7 797.1 947.1 Ncr-intercannected plant - - 1.8 4.8 5.3 6.4 6.4 6.3 - Autoproducers - 104.3 120.7 127.0 154.0 154.7 192.0 192.0 192.0 NATINAL MUAL 81.7 273.8 559.0 568.0 653.0 731.0 994.0 995.0 1,L39.0 (0436P) - 61 - ANlEX 1 Attaclmt 2 PORR STB5EX0 S1U Installed Ccpacity of Hydro Plants, 1965-1980 /1 (sW) Plant 1965 1970 1975 1976 1977 1978 1979 1980 1 1981 Ccmnissioned before 1965 345.4 345.4 345.4 345.4 345.4 345.4 345.4 345.4 345.4 Aikammed E1 Kbamis - 23,2 23.2 23.2 23.2 23.2 23.2 23.2 23.2 BW Areg - 6,4 6.4 6.4 6.4 6.4 6.4 6.4 6.4 Mkulay Youssef - - 24 24 24 24 24 24 24 Mansour Ed Dhabi - - 10 10 10 10 10 10 10 Idriss lst - - - - - 40 40 40 40 Oued Makhazine - - - - - - 36 36 36 Al Massira - - - - - - - 128 128 Total Hydro Plants 345.4 375.0 409.0 409.0 409.0 449.0 485.0 613.0 613.0 /1 At erid of year. (04S36P) - 62 - ANNEX 1 Attachment 3 POWER SJBS1Z' SIuU Supply of Electricity by Power Station and Fuel, 1965-1981 (GWh) 1965 1970 1975 1976 1977 1978 1979 1980 1981 Hydro 1,168 1,316 1,016 998 1,365 1,416 1,582 1,515 1,024 Thennal Coal-fired stean Jerada - - 1,138 1,175 1,188 1,218 865 864 1,167 Roches-Noires 2 - 557 /1 - - - - - 93 23 Oujda 67 27 31 15 23 - Total Coal-Fired Steam - 557 1,138 1,242 1,215 1,249 880 980 1,190 Oil-fired steam Roches-Noires 1,2 & 3 129 - 726 930 856 845 741 613 669 Kenitra 1-4 - - - - - 122 1,012 1,566 1,809 M'ibanmedia 1 & 2 - - - - - - - 121 Total Oil-Fired Steam 129 - 726 930 856 967 1,753 2,179 2,599 Gas turbines - 10 95 132 190 329 110 54 277 Diesel & purchases 15 28 60 37 44 37 47 34 57 Total Available 1,312 1,911 3,035 3,339 3,670 3,998 4,372 4,762 5,147 /1 Irrludes generation from Roches Noires 1. (0436P) - 63 - ANNEX 1 AtEtaiient 4 POWER SJBXCTCR SLU Balarre of Demand and Capacity, 1965-1981 (Intercornected System, a 1965 19;70 1975 1976 1977 1978 1979 1980 1981 Mdinun derwand (1) 267 380 590 640 695 750 815 880 960 Installed Capacity Hydro (2) 332 362 397 397 409 449 485 613 613 Thennal (3) 82 170 436 436 494 570 796 797 947 Total (4) 414 532 833 833 903 1,019 1,281 1,410 1,560 Capacity Available at Peak Hydro (5) 308 312 298 359 350 305 382 407 360 Thermal (6) 82 1281 349 418 450 522 489 677 660 Total (7) 390 440 647 777 800 827 871 1,084 1,020 Rfeserve Margin (%) Total capacity (4)/(l) 55 40 41 30 30 36 57 60 63 Available capacity (7)/(1) 46 16 10 21 15 10 7 23 6 Average Plant Availability (%) Hydro (5)/(2) 93 86 75 90 86 68 79 66 59 Thenmal(6)/(3) 100 7'i 80 96 91 92 61 85 70 Total (7)/(4) 94 83 78 93 89 81 68 77 65 (C0436) -64 - At 1 AttachmEit 5 POWER SUBMM SnIM National Electric Power Balance, 1980 (GWh) Ministry of Auto- OM~E Regies Interior Producers Others /3 TOMCL Gross Generation Hydro (1) 1,514.6 - - 13.3 - 1,527.9 Therml (2) 3,218.5 15.6 456.5 (28.9) 3,719.5 Total (1)+(2) = (3) 4,733.1 - 15.6 469.8 28.9 5,247.4 Power Station Use Hydro (4) -27.9 - (-0.3) -28.2 Thermal (5) -276.4 - -0.7 (-27.9) (-1.4) -306.4 Total (4)+(5) = (6) -304.3 - -0.7 -28.2 -1.4 -334.6 Net Generation (3)+(6) = (7) 4,428.8 - 14.9 441.6 27.5 4,912.8 Transmission Losses (8) -312.3 - - - -312.3 Available for Bulk supply (7)-(8) = (9) 4,116.5 - 14.9 441.6 27.5 4,600.5 Purchases (+) by Producers CE ( 10) +28.9 - - -28.9 - Regies (11) -2,288.9 +2,288.9 - Autoproducers (12) /2 /2 Total Purchased (10)+(11)+(12) = (13) -2,260.0 2,288.9 - - 28.9 Available for Final Consumption (9)+(13) = (14) 1,856.5 2,288.9 14.9 412.7 27.5 4,600.5 Distribution Losses (15) - 51.6 -138.8 (-1.5) - (-2.8) -194.7 Final Consumqtion (14)-(15) 1,804.9 2,150.1 13.4 412.7 24.7 4,405.8 of which: Agriculture 163.5 - - - 163.5 Industry 2,177.3 - 412.7 - 2,590.0 Services 630.8 - - - 630.8 Houseiolds & Camerce 983.5 (13.4) - (24.7) 10,021.6 /1 Figures in brackets () are Bank estimates. /2 Any purchase by autoproducers fran public system is irnluded in final consumption. 73 "Others" imludes statistical discrepancy. (0436P) - 65 - ANEX 1 Attaclment 6 MbROC1O PER SUBSICR SIM Fuel Consumption fcr Electricity Generation, 1970-1981 1970 1975 1976 1977 1978 1979 1980 1981 Thermal Electricity Generation by Fuel Source (GWh) Coal 557.4 1,138.4 1,175.2 1,187.8 1,218.5 865.5 980.0 1,190.1 Fuel oil - 794.8 1,094.7 1,070.8 1,319.0 1,873.6 2,232.8 2,863.9 G,as oil 34.2 82.7 63.8 10.1 17.1 9.2 5.7 21.7 Total 591.6 2,015.9 2,333.7 2,268.7 2,554.6 2,748.3 3,218.5 4,075.7 Thennal Electri city Generation by Fuel Source (% of total thernmal generation) Coal 94 57 50 52.5 48 31.5 27 28.5 Fuel oil - 39 47 47 51 68 73 71 Gas oil 6 4 3 0.5 1 0.5 .. 0.5 Total 100 100 1130 100 100 100 100 100 Fossil Fuel Constmption for Electricity Generation ('000 tons) Coal 254 645 636 691 711 524 595 690 Fuel oil - 222 286 312 396 492 570 745 Gas oil 5 44 41 7 9 6 3 3 Average Tlhermal Efficiency (%) /1 TOtAL 33.2 27.0 27.0 27.0 26.9 29.5 30.2 30.6 /1 Thermal efficiency calculated using follcwing calorific values: Coal 5,835 Kcal/kg, fuel oil 9,950 Kcal/kg, gas oil 10,375 Kcal/kg, and electricity 1 G1h = 8.60 x 108 iCcal. (436P) -66 - AN?X 1 tEaient 7 POWER SUBSWrR san Electricity Cons&mption by Sector (GWh) 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 Residential 337.1 381.9 402.5 451.2 492.8 544.3 569.7 616.5 695.2 740.5 823.0 887.7 983.5 Public Lighting 38.1 42.4 44.4 48.2 49.0 51.3 55.1 60.8 64.9 75.1 72.5 76.6 79.6 Motive Power 42.4 48.9 48.6 51.9 55.7 55.8 56.6 58.3 61.0 64.8 65.7 65.7 67.3 Total Low Voltage 417.6 473.2 495.5 551.3 597.5 651.4 681.4 735.6 821.1 830.4 961.2 1,030.0 1,130.4 Agriculture 38.4 40.5 49.0 49.5 56.4 68.2 67.3 98.2 101.1 112.0 120.7 129.7 163.6 Mining 260.3 256.0 252.1 272.1 311.5 373.5 42.8 414.6 407.8 463.5 454.9 473.4 482.0 of which: Phosphates 128.6 138.1 142.9 165.2 193.8 218.3 246.9 225.4 227.6 262.2 285.5 301.3 298.5 Coal 26.8 29.6 31.9 33.0 34.9 37.6 38.9 41.7 42.0 45.7 47.0 44.3 46.8 Industry 467.5 534.5 607.1 632.0 694.6 785.1 818.5 903.1 1,012.7 1,108.5 1,254.9 1,496.0 1,627.8 of which: Cerent 80.4 92.2 110.7 114.5 117.0 123.7 145.4 162.1 179.9 209.8 223.8 322.1 339.5 Machine Tools 17.7 18.5 19.7 21.6 23.1 26.9 27.8 34.2 60.8 62.2 66.7 70.9 78.4 Chemicals 38.9 42.3 50.4 50.2 52.5 65.1 68.4 71.7 85.8 92.2 142.2 200.8 215.5 Textiles 106.0 121.1 123.5 129.4 157.7 171.9 174.3 183.1 204.1 205.7 224.3 244.0 273.6 Construction & 21.8 21.9 31.3 36.6 34.4 34.3 30.7 39.2 57.3 71.8 73.3 89.3 103.2 Public Wrks /1 Food Processirj 91.3 108.0 126.1 126.0 132.1 149.5 156.6 168.0 183.8 203.5 221.2 238.0 247.5 Services 41.3 54.0 60.7 70.4 82.6 91.9 97.1 99.5 114.5 147.1 178.4 175.3 203.4 Traszportation 95.8 97.2 101.0 106.8 110.0 118.0 127.5 113.0 134.3 149.0 152.9 148.3 160.0 of which: Rail Transport 70.0 69.2 73.3 75.5 79.8 85.3 88.5 75.0 90.1 100.4 103.2 87.6 106.6 Public Adiniistration 26.7 30.8 38.1 45.6 53.8 72.5 72.0 89.8 142.9 145.4 154.1 173.2 187.8 Total Medim and High Voltage 930.0 1,012.0 1,111.0 1,176.4 1,308.9 1,509.2 1,605.2 1,718.2 1,913.3 2,125.6 2,315.9 2,59.0 2,824.6 Total CSuption 137.6 1,485.2 1,65 1,727.7 1,9064 2,160.6 2,286.6 2,453.8 _2,73.4 3,060 3,277.1 3,626.0 3,9550 Source: CtE - Plwming departnait /L Excludirg cemrnt. Septem*ber 1982 (0436P) - 67 - ANEW 1 XEaE-c t 8 P30ER aJBSlE STUY Regiona3 ConsL.ption of Electricity (GWh) Regi-! 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 Center 667.3 732.3 775.8 1333.0 908.6 1,024.7 1,074.5 1,116.6 1,199.9 1,337.5 1,506.0 1,588.6 1,691.8 of which: CasabLanca /1 479.8 518.1 540.9 .592.0 629.2 712.7 735.5 795.9 871.4 963.5 1,091.3 1,161.7 1,250.8 Northwest 240.0 285.1 321.5 :140.7 385.8 442.6 468.5 532.2 621.5 679.7 729.6 819.1 907.3 of which. Rabat /1 97.2 109.8 119.2 .42.7 160.8 179.2 196.3 213.3 238.0 267.9 293.3 336.3 384.4 Tetsift 109.5 119.8 127.3 136.7 148.9 169.2 179.3 193.8 243.6 263.0 295.7 356.4 378.9 East 134.0 125.0 115.1 118.4 118.9 143.5 161.5 181.3 184.0 206.9 175.6 249.0 283.8 Sxoth 43.6 51.0 65.1 80.0 83.2 95.6 102.6 135.9 154.7 168.8 190.1 213.2 251.8 Center-South 81.5 92.7 115.1 118.5 139.3 156.6 167.5 165.6 173.0 185.0 193.0 204.2 226.5 Center-aNoth 71.7 81.6 86.6 99.7 121.6 12.5 132.2 128.8 157.7 165.1 187.1 194.8 214.9 _ 1,347.6~~~~1 1,487,5 1,60.5 1,727.0 1,906,3 2,160.7 2,286,3L 2 453-8 2,734.4 3,006,0 3,277,1 3,625,3 3955.0 /1 Prefectures Source: CtE - Distribution Departnmt July 1982 (0436P) - 68 - ANNEX I titacTiFent 9 MDROCOO POWR SJBSEC)R STUD Ct 's ard the Regies' Caiparative Market Share (GWh) 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 Lw voltage sales cE 92.0 104.3 115.8 123.7 138.3 150.9 175.8 195.9 214.3 226.8 256.8 Regies 403.5 447.0 481.8 527.4 543.1 584.8 645.7 684.5 747.1 803.2 872.6 Total lw voltage sales 495.5 551.3 597.6 651.1 681.4 735.7 821.5 880.4 961.4 1,030.0 1,129.4 Mediannand High Va tage sale CNE 551.0 587.6 654.9 771.4 826.8 874.1 965.4 1,095.4 1,214.2 1,418.9 1,557.4 Regies 560.0 588.8 654.0 738.1 778.4 844.0 947.5 1,030.2 1,101.5 1,177.1 1,268.2 Total M1dimn ard Higi Voltage Sales 1,111.0 1,176.4 1,308.9 1,509.5 1,605.2 1,718.1 1,912.9 2,125.6 2,315.7 2,596.0 2,825.6 All voltage Sales aiE 643.0 691.9 770.7 895.1 965.1 1,025.0 1,141.2 1,291.3 1,428.5 1,645.7 1,814.2 Regies 963.5 1,035.8 1,135.8 1,265.5 1,321.5 1,428.8 1,593.2 1,714.7 1,848.6 1,980.3 2,140.8 Total Sales 1,606.5 1,727.7 1,906.5 2,160.6 2,286.6 2,453.8 2,734.4 3,C06.0 3,277.1 3,626.0 3,955.0 July 1982 (0436P) -69- ANNEX 2 Page 1 of 12 MOROCCO PO_ER SUBSECTOR STUDY Forecast Consumption and Supply of Electricity A. Growth of the Economy 1. Morocco's economy expe:rienced a relatively slow rate of economic growth over the period 1978-1981) as a result of strict fiscal and monetary policies implemented by the Government to stabilize the economy. Thus, GDP increased in real terms at an average annual rate of 3.8%. According to Bank staff projections, GDP would grow at an average rate of about 4.5% for the period 1981-1985 and accelerate slightly to 5% for the period 1985-1990. 'Value added in agriculture is expected to grow at 5.5% per year from 1981 to 1985, and at 2.5% thereafter, as recovery from the 1981 drought would spread over several years. The growth of the industrial sector is projected to be low in 1982, but to rise afterwards, so that it could reach, in real terms, an average annual rate of about 4.7% for the period 1981-1985, and 5.5% for 1985-1990. The higher growth rate of industry in 1981-1985, compared to the .,ne achieved in 1977-1980 (2.3%;), is due first of all to planned investment and strong external demand for phosphoric acid and manufactured products. Production of natural gas could grow rapidly after 1983 and stimulate further the overall growth rate. In the case of the service sector, value added in transport, commerce and services; is expected to follow the increased demand arising from agriculture and industry. However, the projected reduction in Government consumption should induce a slowdown in the overall growth rate of the service sector to 4.2% per year from 1981 to 1985, compared to 5.2% for 1L977-1980. The historical and projected growth rates of the main sectors of Morocco's economy are presented in Table 1 below: Table 1 Historical and Projected Real Growth Rates for the Main Sectors of Morocco's Economy /1 (%) Actual Projected 1977-1980 1981-1985 1985-1990 Agriculture 7.2 5.5 2.5 Industry 2.3 4.7 5.5 Services 5.2 4.2 5.5 GDP 3.8 4.5 5.1 /1 World Bank projections. - 70 - ANNEX 2 Page 2 of 12 B. Future Electricity Demand 2. The future demand for electricity was examined using income and price elasticities for the main categories of consumers, estimated from historical observations. The elasticity of domestic electricity consumption per consumer with respect to real per capita expenditure was estimated to be about 1.2, while the long-run price elasticity was -0.1. This indicates that demand is influenced more by changes in real per capita expenditures, than by changes in real electricity prices. However, real electricity prices did not rise during the period over which the elasticities were estimated. Studies in other countries indicate that price elasticities may be higher when prices are rising than when they are falling. Nevertheless, in the short to medium term, increases in electricity prices to LV consumers in order to align them with marginal costs, are unlikely to lead to large losses in the potential income of utilities. 3. Analysis for the mining and services sectors where consumption was related to real GDP for the sector and real electricity prices produced the following elasticities: Mining Services Income elasticity - short run 0.50 1.30 - long run 1.60 1.70 Price elasticity - short run -0.09 -0.06 - long run -0.30 -0.08 Coefficient of determination (R2) 0.97 0.98 These results indicate that net output has had the dominant effect on demand. Services respond to changes in net output or electricity prices faster than mining, which is to be expected, given the lumpy capital stock of the mining industry. 4. Lack of adequate data and its aggregated nature made it difficult to accurately estimate the elasticities for industry. Preliminary results indicate a long-run GDP elasticity for industry of about 1.7. This analysis of the relationship between electricity consumption and the factors which influence it has produced promising results. However, there is a need to acquire better data on electricity consumption, and to estimate a wider range of models. The results to date indicate that demand is relatively insensitive to price, and that incomes or output tend to dominate demand. 5. The demand forecast derived from the analysis presented above projected a global electricity demand consistent with the demand forecast prepared by ONE in 1981 for the entire subsector. According to ONE's projections, maximum demand and gross generation are projected to grow at an annual average rate of 9% until 1990. As summarized in Table 2 below, the forecast represents a slight decline in the rate of growth in the 1980's, compared to the 1970's. - 71 - ANNEX 2 Page 3 of 12 Table 2 Electricity Demand Forecast Gross Generation Maximum Demand Load Factor Year (GWh) (MW) % …-…---------- Actual --------------- 1970 1,912 384 56.8 1975 3,034 600 57.7 1980 4,762 855 63.5 1981 5,147 920 63.9 ---------------Forecast-------------- 1982 5,657 1,015 63.6 1983 6,165 1,100 64.0 1984 6,720 1,200 63.9 1985 7,325 1,300 64.3 1986 7,985 1,420 64.2 1987 8,703 1,545 64.3 1988 9,487 1,680 64.5 1989 10,340 1,830 64.5 1990 11,271 2,000 64.3 Growth rates (% p.a.) 1970-1975 9.7 9.3 1975-1980 9.4 7.3 1980-1985 9.0 8.7 1985-1990 9.0 9.0 15. The forecast of sales by consumer group presented in Table 3 (details are provided in Attachment 1) shows that private and public services, cement and agriculture are expected to have the highest rates of growth. Railways, textiles and mining are forecast: to have the slowest growth rates. The proportion of electricity sold at LV is expected to decrease slightly from 24% to 21% of gross generation. Station use and T&D losses are expected to remain constant at 17%. - 72 - ANNEX 2 Page 4 of 12 Table 3 Forecast Consumption of Electricity by Economic Sector, 1980-1990 Annual Rate of Growth (%) 1980 (Actual) 1985 1990 1980- 1985- (GWh) (GWh) (%) (GWh) (%) 1985 1990 Agriculture and fishing 163.5 3 295 4 520 5 12.5 12.0 Mining 482.0 10 620 8 785 7 5.2 4.8 Food processing 247.5 5 380 5 570 5 9.0 8.5 Textiles 273.6 6 365 5 480 4 5.9 5.5 Chemicals 215.5 5 335 5 515 5 9.2 8.4 Cement and construction materials 442.7 9 820 11 1,480 13 13.1 13.0 Other manufacturing 314.0 7 440 6 610 5 7.0 7.0 Water supply 188.0 4 290 4 440 4 9.1 9.0 Trade, hotels, and services 203.4 4 440 6 940 8 16.7 16.5 Railways 106.6 2 130 2 155 1 3.6 3.5 Radio, TV, Army, and Government 187.8 4 310 4 495 4 10.7 10.0 LV sales /1 1,130.4 24 1,635 22 2,385 21 7.7 7.9 Total sales 3,955.0 83 6,060 83 9,375 83 8.9 9.1 Losses & station use 807 17 1,265 17 1,890 17 9.4 8.4 Gross generation 4,762 100 7,325 100 11,265 100 9.0 9.0 /1 LV consumers are mainly residential, but also include small consumers in other categories, e.g. shops, offices, schools, post offices, etc. 7. Intensity of Electricity Use: Table 4 below shows the intensity of electricity use by sector, as well as the kWh consumed by households per DH 1,000 of private consumption expenditure. LV consumption was allocated among households, industry, and services in the same proportions observed in 1980 because detailed breakdown at the distribution level is not available. The growth forecasts of the value added by sector were prepared by the Bank in mid-1982. -73 - ANNEX 2 Page 5 of 12 Table 4 Intensity of Electricity Use (kWh per DH 1 000 of value added, 1969 prices) Annual Rate Actual Projected of Growth (%) 1970 1975 1980 1985 Sector 1970 1975 1980 1985 1990 -75 -80 -85 -90 Agriculture 13 28 38 65 101 16.6 6.3 11.3 9.2 Industry 176 183 229 296 339 1.2 4.6 5.3 2.9 Services 26 30 38 50 68 2.9 4.8 5.6 6.3 TOTAL 83 100 122 161 195 3.8 4.1 5.7 3.9 Households /1 28 36 46 57 57 5.2 5.0 4.4 - /1 Electricity consumption (kWh) per DR 1,000 of private consumption expenditure 8. The intensity of electricity use in agriculture increased at an accelerated rate for the period 1970-1975 because of a structural shift towards the use of electricity for irrigation pumping. This increase tapered down significantly for the period 1975-1980 as the irrigation pumping market become more saturated. The intensity of electricity use in agriculture is projected to grow at a rate lower than that recorded in 1970-1975. However, the electricity used per unit of agricultural value added is projected to more than double between 1980 and 1990. Intensity in industry is forecast to accelerate during 1980-1985, and taper down thereafter as a result of projected investments in energy conservation. For services, intensity is expected to continue increasing at about 6% per year during the 1980s. The household electricity consumption per DH 1,000 of private consumption expenditure is forecast to rises up until 1985 and to remain at its 1985 level thereafter. 9. Improvements to Electricity Demand Forecasting: Assuming the projected rates of growth for tWhe major sectors of the economy, ONE's forecast of overall electricity sales seems reasonable. However, substantial improvements could be made to t:he methodology used. The approach adopted by ONE is essentially the extrapoLation of past trends, modified by knowledge of short-term developments in industrial sectors. This is a useful approach for sectors where large projects are planned. However, information on new - 74 - ANNEX 2 Page 6 of 12 projects is usually available for less than five years ahead, a short period in relation to the lead time of power projects. It is therefore necessary to check that medium-term electricity demand forecasts are consistent with projected economic development in each subsector and to obtain a rational basis for projecting longer term demand. This could be achieved by quantifying the relationships between electricity demand and economic activity in each subsector. Electricity demand projections should then be calculated on the basis of the projections of economic growth for each subsector. This would require ONE staff to work even more closely with the Ministry of Planning so that electricity demand forecasts are based on up-to-date detailed and consistent economic forecasts. 10. Improvements could also be made to forecasting the demand by LV consumers which accounts for almost 30% of electricity sold. ONE has prepared good data on the consumption of electricity by industrial subsectors at medium and high voltage. However, little information is available on the breakdown of LV sales and the number of LV consumers. Most of this data is collected by the regies, but no consistent analysis has been undertaken to establish the consumption and numbers of consumers of households and various service, industrial and other subsectors supplied at LV. Because most LV consumers are residential, it should be reasonably straightforward to categorize the remaining non-household consumers. A classification of consumers by economic activity that is consistent with other national statistics should be adopted. Non-household LV demand should be projected along with MV demand for each subsector. 11. Part of the past growth in the demand for electricity by households has been caused by connecting new households in areas already with supply and extending distribution networks to areas without supply. In the future the growth of population is expected to fall from an annual average rate of 3.2% at present to 2.8% during 1990-1995. This will ultimately lead to a slowdown in the growth of new households. The number of those with access to supply will depend on specific rural and urban distribution plans. Ultimately, the proportion of households with electricity supply will approach saturation. The relationships between the number of domestic electricity consumers and population growth, household formation and access to supply need to be considered explicitly in the demand forecast. 12. The consumption of electricity in a household depends on the household's stock of appliances and their utilization. These in turn depend, inter alia, on household income, energy prices, and weather conditions. Ownership of particular appliances, e.g., irons, tends to approach saturation and eventually ceases to contribute to the growth in electricity demand. The extent to which these processes can be modelled depends on the data available. It is recommended that ONE and the regies start to collect this data, e.g., on numbers of consumers by district, and forecast household electricity demand taking the factors which influence it into explicit account. -75 - ANNEX 2 Page 7 of 12 13. There is also some scope for the rggies to intensify their involvement in overall demand forecasting. Each regie requires its own demand forecast for financial analysis and to prepare its least-cost development plan. Regies are in a positicn to acquire information on local developments that affect electricity demand, e.g., applications for supply, information on proposed projects, implications of land use planning, etc. They are, therefore, ideally placed to prepare market survey type forecasts for, say, up to five years ahead. However, an individual rggie alone is unlikely to be able to ensure that its forecast, when added to the forecasts of the other utilities, is consistent with overall economic development. It is recommended, therefore, that ONE develop its coordinating role by providing a forum to bring all the utilities' projections together and by assisting the r6gies in improving their forecasting techniques, to ensure that electricity demand forecasts are consistent with economic and social development. C. Future Electricity Supply 14. ONE is responsible for all generation and transmission planning. It is also responsible for distribution planning in the areas it serves. Ultimately, ONE requires the approval of M?M for its investment program. The r6gies are responsible for most of the distribution planning in Morocco. Little information is available at the Bank on their investment plans. However, it is known that r6gies tend to prepare investment budgets for the year ahead and that at least one rEgie prepares a five-year plan of capital expenditures. This section of the annex covers generation planning only, because of the lack of information on distribution plans. 15. ONE has an obligation to provide an adequate supply of electricity at the lowest cost. In the case of Morocco where hydrogeneration plays a major role, security of supply requires that there be sufficient reserve thermal capacity to maintain supplies during a hydrologically dry year. This section examines first how maximum demand (MW) will be met in the future, then considers the plan to ensure sufficient energy (GWh), and finally reviews whether ONE's power system planning practices result in a least-cost generation plan. Future Generating Capacity 16. ONE does not plan to commission any new plant on the interconnected system until 1984-1985 when two additional 150-MW units will be completed at the Mohammedia steam station. Unlike the existing 2xl5O-MW units at Mohammedia which burn fuel oil, the new units will burn imported coal. No further thermal plant is planned except for a 4x250-MW steam station burning imported coal is commissioned in 1993. With the exceptions of Roches Noires Unit I and Oujda which are being placed into cold storage, all existing steam plants will be refurbished when necessary so as to remain in service at the end of the century. The three existing gas turbines at Agadir, Tangier, - 76 - ANNEX 2 Page 8 of 12 and Tetouan are to be retired in 1994. All diesel plants on the interconnected system are planned to be retired in 1982. Attachment 2 shows projected thermal capacity until 1990. 17. ONE is planning an ambitious program of hydro development. Stations planned for commissioning in the 1980s are: Amougguez 67 MW 1987 Dchar el Oued 92 MW 1988 M'dez 52 MW 1988 M'jara 240 MW 1989 451 MW Another 16 hydroelectric stations, with a total capacity of 1,215 MW, are planned for 1990-1994. Four more stations are proposed for 1995-1996 which will add a further 169 MW to the system. Attachment 4 lists the 25 proposed projects, which will have a total installed capacity of 1,845 MW and would ultimately be capable of producing an additional 2,832 GWh in a mean hydrological year. Attachment 3 shows the buildup of hydro capacity. Almost all of Morocco's surveyed hydro potential will be exhausted after the planned development program has been completed. ONE then proposes to commission a 600-MW nuclear power station in 2000-01 to meet base load demand, and has already initiated contacts with the International Atomic Energy Agency (IAEA) to seek assistance in the preparation of its program. 18. Many of the proposed hydro projects are part of multipurpose schemes which are primarily intended for irrigation, water supply, or flood control. Most of the projects are small; 16 of them will have an installed capacity less than or equal to 60 MW. Furthermore, the energy (GWh) output of most of the schemes is small in relation to their capacity. In a mean hydrological year, only 7 out of the proposed 25 projects will have a load factor greater than 15%. This raises an issue as to the role of hydro in future system development and the optimization of station size (paras. 24-28). 19. Attachment 5 shows the balance of demand and capacity which is summarized below in Table 5. The hydro program described above will result in hydro capacity increasing from nearly 40% of total installed capacity at present to almost 50% in 1990. The proportion of thermal plant will continue to increase to 68% in 1985 and then decline. The gross reserve margin, i.e. excluding adjustments for plant availability or averaging of daily peak demands, is forecast to fall from its highest for many years of 43% in 1981, to 31% in 1985 and 23% in 1990. - 77 - ANNEX 2 Page 9 of 12 Table 5 Planned Generating Capacity (ONE Interconnected System) Actual Planned 1981 1985 1990 T-W) (7)T (M) ( (MW) (%) Hydro 604.2 39 616 32 1,286 50 Thermal 949.4 61 1,305 68 1,305 50 of which: Steam 784 50 1,185 62 1,185 46 Gas Turbine 135 9 120 6 120 4 Diesel 30.4 2 -- -- -- -- TOTAL 1,553.6 100 1,921 100 2,828 100 Maximum Demand /1 880 1,330 2,000 Gross Reserve Margin 43% 31% 23% /1 Maximum demand is the estimated hourly peak for the year, not the average of winter daily peaks shovn in Table 2. 20. No information is available on any planned increases in the capacity of autoproducers. ONE plans its system on the basis of no import from autoproducers since the sale of surplus energy by autoproducers is not guaranteed. However, there may be scope for increasing the level of imports, particularly if industrial peak demands occur at a different time to the interconnected system peak. Further savings could be made by using imports to reduce gas turbine generation. Given that autoproducers have almost 200 MW of plant capacity, ONE should review its existing contractual arrangements with autoproducers with the view to integrating them further into the interconnected system. ONE should examine particularly the methods of charging for purchases and sales to ensure that both parties are given the correct marginal cost signals and incentives to supply each other at both peak and off peak times. In April 1983 ONE undertook a sectorial survey with the purpose of collecting data on the structure of electricity consumption by the industrial sector. The survey should contribute to determining the opportunities for some industries to shift their unessential demand from peak to off-peak periods and thus for ONE to defer new capacity. It is recommended, however, to ensure that this preliminary load research and management study be accompanied by a review of ONE's contractual arrangements and, in particular, of its tariffs to industrial consumers. - 78 - ANNEX 2 Page 10 of 12 Future Production of Electricity 21. In its generation planning studies, ONE formulates its investment plans under the assumption that the most adverse hydrological conditions would persist over the entire planning horizon. This analysis is undertaken to ensure that sufficient supply of energy will be available under the worst possible case for hydropower generation In addition, ONE determines the outputs of generating units and their cost of operation under mean hydrological conditions. Table 6 below presents a summary of projected available supply of electricity in a mean hydrological year and compares it with electricity generation in a dry year. Details are provided in Attachment 6. Table 6 Projected Available Supply of Electricity (Interconnected System) Actual Projected 1981 1985 1990 (Gwh) (%)- (Gwh) (%) (G-wh) M% In an average year Hydro 1,024 20 1,940 27 3,450 31 Thermal 4,076 79 5,360 73 7,850 69 of which: steam (coal) 1,190 23 3,250 73 3,700 23 steam (oil) 2,598 50 2,080 28 4,120 36 G/T & diesel 288 6 30 - 30 - Import 47 1 -- -- -- Energy Demand 5,147 100 7,330 100 11,300 100 In a dry year Hydro 1,205 12 1,924 18 Thermal 8,520 88 9,256 82 Total available 9,735 100 11,180 100 Margin 33% 0% 22. The table shows that, in an average hydrological year, the share of hydroenergy will rise to 27% of total energy available in 1985, and to 31% in 1990, as a large number of hydropower sites are developed. Thermal generation will fall to about 73% of available supply in 1985, and to 69% in 1990. Towards the end of the 1980's, about one third of total electricity generation by ONE will be supplied by hydropower plants, - 79 - ANNEX 2 Page 11 of 12 another third by coal-fired sl:eam stations, and the last third by oil-fired steam stations. The contribul:ion of gas turbines and small diesel plants will be minimal. 23. Under poor hydrologic:al conditions, however, where hydro3eneration could be reduced by as much as 40%, the shortfall of energy available would be mainly supplied by oil-fired steam plants and by gas turbines. The margin of spare energy available in a dry year above the projected demand for energy will amount to about 33% in 1985, which suggests that there will be no problem in supplying energy; meeting poeak demand will thus be the most important constraint. Thereafter, the mlargin will fall to 0% in 1990. However, the margin of available energy does not include support from autoproducers or bringing back plant from cold storage, which could raise the 1990 margin to over 5%. Optimization of Hydro Projects 24. Most hydro schemes in Morocco are multipurpose. Indeed, power benefits are often regarded of secondary importance to those from irrigation and water supply. Hydro projects have been appraised in the past by taking the decision to build the dam as given and regarding the incremental power plant costs as an input to the least-cost power development plan. This approach would be correct if the decision to construct a multipurpose project to a stated design on a particular site was in fact independent of the power aspects of the project. In practice though, the power requirements will influence the choice of site, dam height, etc. For example, is it worthwhile to choose a site which would allow greater power benefits and equal or larger irrigation benefits? Would it be worth reducing the irrigation benefits slightly to allow greater power output? 25. It is recommended that the tradeoffs between different benefits of a multipurpose project be examined intensively during the preparation of the project. This will involve careful calculation of the benefits from hydro power, which simply are not the power output multiplied by the average income from electricity sales. Power benefits are related to the difference in present value power system costs between the best plans with and without the project. In some circumstances it may be better to delay construction of the power house until the electricity is required or until lower cost schemes have been commissioned first. 26. There may be some hydro projects worth undertaking for the power benefits alone. For these projects, it is necessary to firstly identify the sites and secondly to rank them in terms of economic attractiveness. To date this has not been done. It is recommended that the Administration de l'hydraulique, in collaboration with ONE, establish an inventory of potential hydro sites, carry out preliminary design work, and estimate project costs. These projects should then be ranked and integrated with multipurpose and thermal power projects in a least-cost generation development plan. - 80 - ANNEX 2 Page 12 of 12 27. For both multipurpose and single purpose hydro schemes the designer has to decide what proportion of the potential hydro energy is worth capturing, taking the annual and seasonal variation in water flows into account. A tradeoff has to be achieved between the costs of installing more MW of hydro capacity and the benefits of the additional capacity to the system. The low load factors of many of the proposed hydro stations (Attachment 4) suggest that the MW capacity of some may be too large in relation to the water resource. ONE does not appear to have optimized the capacity of these stations as an element of an integrated hydro-thermal system. It is recommended that the capacity of the proposed hydro schemes be optimized when each project is revaluated. 28. ONE plans to commission 25 hydroelectric stations during the ten years 1986-1996. Even though many of these projects are small, their manpower requirements will be similar to a much larger station with the same number of generating units. A large training program will be required to man these stations adequately. At present such a program does not exist. Furthermore, constructing this number of projects will be likely to overload the management resources involved in design, procurement, and construction. For these reasons, as well as the uncertainty as to whether the hydro plant is needed to meet demand, or justified economically, it is recommended that ONE revaluate the power projects planned for commissioning in 1990 and after, to ensure that the longer term development plan is the least-cost solution. Pricing of Inputs to Power Projects 29. Power projects should be appraised using border prices to ensure that projects selected make the best use of national resources. Previous power projects in Morocco have been evaluated using the actual prices paid by ONE. These prices have included import duties, trade and commodity taxes, and fuel subsidies which are transfers rather than resource costs. The choice between hydro and thermal generation is strongly influenced by the price of fuel. While, in the past, fuel prices have been distorted by subsidies, they are now close to border prices. However, it is recommended that in future project appraisal, ONE make certain that border prices are used for fuel and other imports. 30. Because of the opportunities for emigration, labor may, in some cases, be considered a "tradeable commodity", but this is less true today. The resource cost of labor in Morocco will depend on the alternative employment of workers engaged in construction and power station operation. It is likely that this will be less than the wages and other labor costs actually incurred. If skilled labor, such as hydro station managers, is scarce, then there may be grounds for having a shadow wage rate in excess of actual labor costs. It is recommended that the resource cost of labor, the "shadow wage rate", be used in the evaluation of future projects. February 1984 (0756P) 81 - ANNEX 2 A7Irnent 1 PO,R SUBSECR SnI Forecast Conswsption of Electricity by Economic Sector (GWh) Actual Forecast IW8F 1WT 1983 1984 1985 1986 1987 1988 1989 1990 Agric:ulture and fishing 253.6 200 230 260 295 330 370 415 465 52D Minirg 497.5 530 560 590 620 650 680 715 750 785 Food processirg 260.8 295 320 350 380 415 450 490 530 570 Textiles 270.5 305 325 345 365 385 410 430 455 480 Chemicals 205.9 255 280 305 335 365 395 435 475 515 Cemnet and construction materials 450.7 590 660 740 820 925 1,045 1,170 1,310 1,480 Other manufacturirg 335.9 360 385 410 440 470 500 535 570 610 Water supply 205.3 220 240 265 290 315 340 370 405 440 Trade, hotels & services 187.2 275 320 375 440 510 600 700 810 940 Railways 108.6 115 120 125 130 135 140 145 150 155 Radio, TV, Amniy and Government 206.3 230 255 280 310 340 375 410 450 495 LV sales /1 1,177.1 1,300 1,405 1,515 1,635 1,765 1,905 2,050 2,210 2,385 Total Sales 4,159.4 4,675 5,100 5,560 6,060 6,605 7,210 7,865 8,580 9,375 Losses & station use 987.6 975 1,060 1,140 1,240 1,395 1,490 1,635 1,770 1,890 Total Generation 5,147.0 5,650 6,160 6,700 7,300 8,000 8,700 9,500 10,350 11,265 /1 LV consumers are mainly residential, but also irrlude small consumers in other categories, e.g. shops, offices, eitc. .September 1982 (0756I') - 82 - ANNEX 2 Attacmhent 2 MDROOCO POkER SUBSECOR S ' Installed Capacity of Thermal Plants (1981-1990) /1 Actual Forecast Plant 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 Jerada 165 165 165 165 165 165 165 165 165 165 Roches Noires: Unit 1 32 - /2 - - - - - - - - Unit 2 60 60 60 60 60 60 60 60 60 60 Unit 3 60 60 60 60 60 60 60 60 60 60 Kenitra 300 300 300 300 300 300 300 300 300 300 Oujda 17 - /2 - - - - - - - - Mohammedia 150 300 300 450 600 600 600 6C0 600 600 TOMAL Steam Plant 784 885 885 1,035 1,195 1,185 1,185 1,185 1,185 1,185 Sidi Kacem 15.5 - /2 - - - - - - - - Agadir 40 40 40 40 40 40 40 40 40 40 Targer 40 40 40 40 40 40 40 40 40 40 Tetouan 40 40 40 40 40 40 40 40 40 40 TCrAL Cambustion Turbines 135.5 120 120 120 120 120 120 120 120 120 Agadir - - - - - - - - - - Tanger 6.4 - - - - - - - - - Sidi Kacem 7.2 - - - - - - - - - Other Diesel Engines 6.4 - - - - - - - - - TOIAL Diesel Plants 20 _ - - - - - - - - Standby Plants 7.6 - /2 - - - _ - - - - TOMAL THERMOL PLANTS 947 1,005 1,005 1,15305 1305 1,305 1,305 1,305 1,305 Autoproducers /3 192 192 192 192 192 192 192 192 192 192 NATIONAL TOLAL 1,139 1,197 1,347 1,497 1,497 1,497 1,497 1,497 1,497 1,497 /1 At the end of the year. /2 Plant placed into cold storage. 7T Capacity of autoproducers inrludes a very small amnunt of hydro. February 1984 (0756P) -83 - AMEX 2 Attachient 3 M0 2PCAER SUB5CI(XR Srl Installed Capacity of Hydro Plants, 1980-1995 /1 (MW) 1980 1985 1986 1987 1988 1989 1990 1995 Existing CaHnissioned before 1975 400 4CX) 400 400 400 400 400 400 Idriss I 40 40 40 40 40 40 40 40 Oued el Makhazine 36 36 36 36 36 36 36 36 Al Massira 128 128 128 128 128 128 128 128 La:Lla Takerkoust - 12 12 12 12 12 12 12 Amxugguez - - - 67 67 67 67 67 Dciar el Oued - - - - 92 92 92 92 Sebkha Tah - - - - 10 10 10 10 M'dez - - - - 52 52 52 52 M'jara - - - - - - 160 240 Matmata - - - - - 241 241 241 El Menzel - - - - - - 148 148 Merija - - - - - - 60 60 Iimzdilfane (1991) - - - - - - - 68 Taskdert (1991) - - - - - - - 32 Tajemout (1991) - - - - - - - 28 TaI2afit (1992) - - - - - - - 33 El Borj (1992) - - - - - - - 17 Tilougguit (1993) - - - - - - - 65 Tanajjout (1993) - - - - - - - 55 Taiga (1993) - - - - - - - 20 Ait: Abbas (1993) - - - - - - - 15 ToLlahar (1994) - - - - - - - 25 Bab Ouender (1994) - - - - - - - 38 Rai: sa (1994) - - - - - - - 30 El Menzel (usine de transfert) (1994) - - - - - - - 340 Afartane (Laou) (1995) - - - - - - - 25 Tifiou (1995) - - - - - - - 19 Oux er Rbia (1995) - - - - - - 65 TOlAL 604 616 616 683 1,078 1,078 1,286 2,401 /1 At the end of year. February 1984 (0756P) - 84 - ARiX 2 Attachment 4 ~R0 POSER SUB R S= Existing and Proposed Hydro Stations Installed Ultimate Load Capacity Production Factor Statiao (NW) (GWn/a) (%) Type Camnission Date Existin (December 1980) Bine el Ouidine 135 265 22 Storage October 1953 Alfourer 94 525 64 Storage January 1955 Imfout 31 150 55 FOR December 1947 Mohamned el Khamis 23 85 42 Storage September 1967 Sidi Said Maechou 21 60 33 ROR December 1929 Daourat 17 90 60 RdR May 1950 El Kansera 14 30 24 Storage December 1934 Lalla Takerkoust /2 9 12 15 Storage October 1938 Kasba Zidania 7 17 28 R(C November 1935 Bou Ar/e! 6 35 67 RdR October 1969 LaouL _11 50 52 R8R 1934/July 1942 Taurart /2 2 10 57 ROR October 1951 Six Small Run of River 5 20 46 ROR 1925 to 1939 Mansour ed Dabbi 10 27 31 Storage July 1973 Moulay Youssef 24 60 29 Storage September 1974 Idriss I 40 130 37 Storage July 1978 Oued el Maldhazine 36 65 21 Storage September 1979 Al Massira 128 240 21 Storage July 1980 m TM 7t Proposed Amugguez 67 115 20 Storage 1987 Dchar el Oued 92 200 25 Storage 1988 Sebkha Tab 10 25 29 1988 M'jara 240 390 19 Storage 1992 M'dez 52 50 11 Storage 1988 Matmata 241 265 13 ROR 1988/89 El Memzel 148 320 25 RdR 1990 Merija 60 120 23 ROR 1990 Ieizdilfane 68 110 18 RdR 1991 Taskdert 32 55 20 ROR 1991 Tajemout 28 50 20 ROR 1991 Tanafit 33 170 59 ROR 1992 El Borj 17 90 60 ROR 1992 Tilougguit 65 90 16 ROR 1992 Taiujjout 55 120 25 ROR 1993 Tamga 20 65 37 RdR 1993 Ait Abbas 15 30 23 llOR 1993 Touahar 25 40 18 ROR 1994 Barb Ouender 38 55 17 Storage 1994 Rufsai 30 47 18 Storage 1994 Afartane (Laou) /2 25 95 43 ROR 1995 Tirkou 19 30 18 Storage 1995 Oum er Rbia Amont 65 160 28 ROR 1995 Oum er Rbia Aval 60 140 27 ROR 1996 El Menel (usine de 340 - 1994 transfert) 1,845 2,832 18 NOTE: ROR = Rurr-of-River or "Eclusee" types of station. /1 The installed capacity and average annual production will rise to 12 NW and 15 GWh. /2 These plants will be retired when Afartane is retired. September 1982 (0756P) -85- ANNEX 2 7.riiit 5 MDROODD POER SJBMCIR SM Balanre of Demarki and Capacity, 1981-1990 (Interconnected System) Actual FORECASr Ti- T982 1983 1984 1985 1986 1987 1988 1989 1990 1-axiimn Demand (Average Winter Day) (1) 920 975 1,045 1,115 1,190 1,270 1,355 1,450 1,550 1,655 xdmn Daand (Hourly) (2) 960 1,015 1,085 1,160 1,240 1,320 1,410 1,510 1,610 1,720 Installed Capacity Hydro (3) 6C4 6Y4 616 616 616 616 683 1,078 1,078 1,286 Thermal (4) 949 1,005 1,005 1,155 1,305 1,305 1,305 1,305 1,305 1,305 I'otal (5) 1,553 1,6)9 1,621 1,771 1,921 1,921 1,988 2,383 2,383 2,591 Capacit Available at Peak Hydro (6) 360 472 472 472 472 524 524 642 827 1,173 Thermal (7) 660 854 854 982 1,109 1,109 1,109 1,109 1,109 1,109 Total (8) 1,020 1,326 1,326 1,454 1,581 1,633 1,633 1,751 1,936 2,282 Reserve Margins (%) Total Capacity (5)t(2) 63 .59 49 52 55 50 41 48 48 64 Available Capacity (8)/(2) 6 :31 22 25 28 24 16 16 20 33 Average Winter Available (8)/(1) 11 :36 27 30 33 29 21 21 25 38 AergePlant Availabilitv ( Hydro (6)/(3) 59 '77 77 77 77 77 77 77 77 77 Thermal (7)/(4) 70 135 85 85 85 85 85 85 85 85 Total (8)/(5) 65 82 82 82 82 82 82 82 81 81 Februaxy 1984 (0756P) -86 - AUMEX 2 t-taXcFent 6 KJFDR0C POER SUB SIsn Supply of Electricity by Powr Station and Fuel, 1981-1990 /1 Actual Forecast 1961 1982 1983 1984 1985 1986 1987 1988 1989 1990 Energy Supplied (Gross) 5,147 5,455 5,840 6,245 6,685 7,150 7,650 8,190 8,760 9,375 Hydro of thich plants existing at end-1980: 1,024 900 1,215 1,210 1,205 1,210 1,195 1,200 1,205 1,200 Anxugguez 10 45 45 45 Dchar el Oued 20 115 115 M'dez 15 26 26 M'jara _ Matnata 80 210 210 El Menzel 248 Merija 80 TCTAL HYDRO 1,024 900 1,215 1,210 1,205 1,210 1,205 1,360 1,601 1,924 Therml Coal-Fired Steam: Jerada ) 1,167 1,150 1,150 1,150 1,150 1,150 1,150 1,150 1,150 1,150 Roches Noires 2 ) 23 - 150 360 360 360 360 360 360 360 Oujda ) - - - - - - - - - - Mohamndia 3 & 4 ) 150 1,800 1,800 1,800 1,800 0 1,800 TOTAL CCAL-FIRED SrEAM ) 1,190 1,150 1,300 1,660 3,310 3,310 3,310 3,310 3,310 3,310 Oil-Fired Steam: Roches Noires 1, 2, and 3 ) 669 840 690 420 420 420 420 420 420 420 Kenitra 1-4 ) 1,809 2,100 2,100 2,100 2,100 2,100 2,100 2,100 2,100 2,100 Moharmedia 1 and 2 ) 121 1,700 2,100 2,100 2,100 2,100 2,100 2,100 2,100 2,100 TOTAL OIL-FIRED STEAM ) 2,599 4,640 4,890 4,620 4,620 4,620 4,620 4,620 4,620 4,620 Gas Turbines 227 600 600 600 600 600 600 600 600 600 Diesel & Purchases 57 - - - - - - - - - TOTAL AVATLAEL 5,147 7,290 8,005 8,090 9,735 9,740 9,735 9,890 10,131 10,454 Margin of Available/Denmand 34% 37% 30 46% 36% 27% 21% 16% 12% /1 Projections of hydro output are for a dry year. February 1984 (0756P) - 87 - ANNEX 3 Page 1 of 13 MOROCCO POVER SUBSECTOR STUDY Electricity Pricing A. Historical Review :1. As seen from Table 1 below, the average tariff paid by ONE's high and medium voltage consumers increased in nominal terms at an average annual rate of 11.5% during the period 1972-1981. In real terms, however, the increase was substantially lower, averag-ing only about 4%. By contrast, the tariff paid by the low-voltage consumers increased, in nominal terms, at an average annual rate of about 7.3%, but remained unchanged in real terms. Table 1 Average Electricity Tariffs (ONE), 1972-1981 (cDH/kWh) High, Medium Index for Low Voltage Tariff Voltage Tariff the Gene- Current 1972 Prices Current 1972 Prices ral Price Year Prices cDH/kWh Index /1 Prices cDH/kWh Index /1 Level /1 1972 31.1 31.1 100 11.0 11.0 100 100 1973 32.5 31.3 101 11.0 10.6 96 104 1974 33.3 31.1 100 11.7 10.9 99 107 1975 34.2 31.1 100 11.9 10.8 98 110 1976 39.1 31.0 100 14.1 11.2 102 126 1977 45.9 31.0 100 17.2 11.6 106 148 1978 49.5 31.1 100 19.7 12.4 113 159 1979 51.1 31.2 100 23.0 14.0 127 164 1980 55.5 31.2 100 25.3 14.2 129 178 1981 58.8 31.6 102 29.2 15.7 143 186 /1 1972 = 100 2. Although the increase in the tariff levels for sales at the low, medium and high voltage levels have, by and large, kept up with the increase in the general price level, the increase fell short of covering the substantial increase in ONE's fuel bill. Since 1972, the price paid by ONE for fuel oil and coal increased 3y about 800% and 400%, respectively, and as a - 88 - ANNEX 3 Page 2 of 13 result, the higher cost of fuel was absorbed by ONE at the expense of its ability for self financing. Table 2 shows the changes over time of the domestic prices paid by ONE for fuel oil and coal and the changes in the average bulk tariff. Table 2 Price Indices of Fuels Used for Electricity Generation (Current prices, 1972=100) Year Fuel Oil Coal Average Bulk Tariff 1972 100 100 100 1973 100 125 100 1974 100 168 106 1975 139 187 108 1976 199 222 128 1977 199 222 156 1978 297 222 179 1979 353 275 209 1980 572 345 230 1981 865 479 266 3. During the period 1972-1979, ONE's financial performance has fluctuated between extremes; that is, for some years ONE managed to cover all of its operating costs and contribute from internal sources between 25% and 30% of the overall cost of its development program, and for the other years, its internal cash contribution dropped to less than 5%. This fluctuation has been primarily attributed to the delays by the Government in adjusting the tariffs for higher fuel prices, and the fact that a large proportion of ONE's electricity supply depends on hydroelectric plants, and in turn, on the level of rainfall (para. 4). Since 1979, however, ONE's financial position has been steadily deteriorating. Over the three-year period, the fuel cost per kWh increased by about 167% and non-fuel cost by about 27% while the average revenue increased by 32% only, as summarized in Table 3. In addition, Table 3 ONE'S Average Operating Cost and Revenue (cDH/kWh) Percentage of 1979 1980 1981 Change (1979-1981) Average Operating Cost Fuel 8.1 11.3 21.6 167 Others 8.2 8.6 10.2 24 Depreciation 6.5 6.4 5.2 -20 Total 22.8 26.3 37.0 62 Average Revenue 24.4 27.0 32.1 32 89- ANNEX 3 Page 3 of 13 1981 was an exceptionally dry year which increased ONE's dependence on thermally generated electricity. However, despite the adverse effects of higher fuel costs and dry years on the utility's financial position, the increase in the bulk tariffs were less than needed to compensate ONE for the rise in its cost of operation., As a result, ONE's net operating income decreased from about DH 112 million in 1979, to DH 87 million in 1980 and to a loss of about DH 134 million in 1981. Its internal cash contribution decreased form 21% in 1979 to only 9% in 1981. The Government had earlier agreed to the inclusion of a fuel adjustment clause in ONE's tariff structure. However, as seen 1rom the discussion above, ONE has been prevented from putting it into operation. 1/ In order for ONE to recover the cost of higher fuel prices and maintain the level of its internally generated cash unaltered, it is recommended that, once the program for the restructuringof electricity tariffs is implemented (para. 22), this fuel adjustment clause be activated and that ONE be given the authority to automatically pass on to consumer all increases in its fuel bill. 4. The large contribution of the hydropower plants to ONE's total electricity production increases the sensitivity of its financial position to changes in the hydrological conditions. Changes in the rainfall affect the financial position of any utility with sizeable hydroelectric generation. In years with above average rainfall, the utility manages to reduce its operating costs; mainly by decreasing thermal generation and thus fuel consumption. In dry years, however, fuel consumption increases and if the financial position of the utility is to remain unaltered, additional increases in the tariffs to cover the fuel cost are needed. These increases may tend to be exceptionally high, and consequently socially and politically impractical to apply; particularly if several dry years occur in sequence. Tariffs based on mean hydrological conditions should, in principle, give sufficient income to cover fuel costs over a long period. Surpluses produced in wet years should subsidize deficits in dry years. However, in practice this has not occurred. The relationship between tariff levels and hydrology has been observed by the tariff setting process and inflation. Deficits arising from dry years are difficult to finance and surpluses are politically unacceptable. A possible approach to overcoming this difficulty would be to base the energy component of the tariffs on the level of fuel consumption that would prevail under the adverse hydrological conditions. This would avoid the need for frequent and disproportionately large increases in tariffs and would allow for the creation of a fuel fund which would be replenished during the years of good or average hydrological conditions, and used to smooth out the adverse impact on ONE's finances during hydrologically poor years. Therefore, it is recommended that the Government and ONE consider the redesign of the tariff structure to allow for the energy charge to be based on the fuel consumption in hydrologically bad years, and t:he creation of a fuel fund to be used for 1/ The introduction of a fuel adjustment clause is a covenant under IBRD Loan 1299-MOR. 90- ANNEX 3 Page 4 of 13 smoothing out the increases in the bulk tariffs needed to cover the increases in the operating cost and maintaining the internal cash contribution of the utility at a relatively stable level following hydrologically bad years. B. Institutional Responsibilty for Tariffs 5. ONE is responsible for proposing global tariff adjustments to compensate for increases in its operating costs due to higher fuel prices and to ensure, to the extent possible, a minimum cash generation ratio. However, the actual rate of increase and its distribution among various consumers are decided upon by the Prime Minister upon ONE's proposal. Tariffs are then set for each voltage level, each consumer category, and each distribution regie. It is worth mentioning that tariffs applied to the regies, both for purchases and sales of electricity, are set so as to leave the financial position of the regies unaltered, i.e., to maintain the net operating income of the regies at the level that prevailed prior to the tariff adjustment. 6. The practice for setting tariff results in differences in the rates paid by the regies for electricity supplied by ONE. These differences are dictated by the financial position of the regies, and since large and well established regies, such as Casablanca, Rabat, etc., are usually in a relatively better financial position than the smaller or new regies, such as El Jadida and Safi, the large regies cover part of the difference between the rate requested by ONE and the rate finally paid by the smaller r6gies. The rest of the difference is covered by ONE. However, by ensuring that the financial position of the regies remain unaffected by the increases in the bulk and retail tariffs, the regies are not induced to improve their operating efficiency or their internal cash generation. 7. These practices result in serious departure from the principles pertaining to the economic pricing of electricity. Economic pricing of electricity dictates that tariffs be set at levels that convey to consumers the real cost to the economy of the resources used to meet their demand. Adopting these principles would result in the elimination of the current practices for setting bulk tariffs primarily on the basis of the financial targets of the regies and indirect cross-subsidization among them. They would De replaced by a system where tariffs are based on the average incremental cost of supply derived from a unified national least-cost program (generation, transmission, and distribution for both ONE and the regies). This is discussed in greater detail in para. 22. -91 - ANNEX 3 Page 5 of 13 C. Level of Existing Tariffs Economic Costs of Supply 8. The economic cost of electricity is equal to the long-run marginal cost (LRMC). LRMC is derived from the least-cost program for the development of the power subsector. It refers to the increase in the capital and operating costs (generation, transmission and distribution) needed to meet the demand for additional kWhs in the future. However, because of the lumpiness of investment in power facilities (indivisibilities), the long-run average incremental cost (LRAIC) is taken as a proxy for the LRMC. The LRAIC is usually comprised of two elements: (a) capacity cost involving the capital and operations and maintenance costs associated with the expansion of the power system to meet an extra kW of peak demand (demand-related cost); and (b) the fuel and other costs :Lnvolved in supplying an extra kWh at different times of the day and year. 9. Demand-Related Costs; LRAIC's of meeting additional peak demand are shown in Table 4 below. These LRAIC's were calculated using a 10% discount rate and prices which excluded taxes and duties. Other assumptions are given in Attachment 3. Table 4 LRAIC of Generation, Transmission and Distribution Capacity (DH/ FWa, December 1981 prices) Voltage Transmission and Distribution Level Generation HV MV LV Total Generation 1,088 --- 1,088 HV 1,133 186 --- --- 1,319 MV 1,206 199 754 --- 2,159 LV 1,325 218 829 536 2,908 10. Energy-Related Costs: The energy related components of LRMC are the costs of generating an extra klWh at each time of the day and year. At a particular time, the extra kWh is supplied from the plant with the highest marginal operating cost per kWh. The plant operating at the margin on the ONE system will depend on the output of hydro plant at the time in question. Hydro output is determined by the overall water resources available, which are influenced by rainfall, other uses of the water and by the procedures for managing hydro reservoirs. The plant operating at the margin and the consequential marginal costs can only be determined precisely by a simulation of system operation that takes seasonal water availability into account. -92 - ANNEX 3 Page 6 of 13 11. To estimate marginal costs it has been assumed that on average a thermal plant burning fuel oil is always operating at the margin. Reservoirs are assumed to be operated so that hydro energy is used first where it has the greatest value, i.e., to replace the highest cost thermal peaking plant. This tends to smooth marginal energy costs during the day and year. Estimates of marginal energy costs for 1982 are shown in Table 5. Table 5 Marginal Energy Cost, 1982 (cDH per kWh generated, December 1981 prices) Fuel Price Marginal Delivered Marginal Costs Period Time Station (DH/tonne) Fuel Other /1 Total Night 2300-0700 Mohammedia 1-2 1,240 27.9 1.7 29.6 Day (0700-1700) K6nitra 1-4 1,272 31.8 2.4 34.2 (2200-2300) Peak 1700-2200 Roches Noires 2-3 1,248 32.5 2.7 35.2 /1 Other costs include station labor costs which, strictly speaking, are marginal with respect to station capacity rather than station kWh output. Adjusting for 6% station use and 2% transmission losses, and combining the day and peak costs by weighting them by consumption, the marginal energy costs corresponding to ONE's HV tariffs are: Day (0700-2300) 37.5 cDH/kWh Night (2300-0700) 32.1 cDH/kWh Bulk Supply Tariffs 12. A comparison between the bulk supply tariffs for several regies and industries and the economic costs of supply is shown in Table 6. - 93 - ANNEX 3 Page 7 of 13 Table 6 Comparison Between Bulk Supply Tariffs and Economic Costs (prevailing charges as a % of economic costs) Max Demand Energy (cDH/kWh) Tariff (DH/kVA/Year) Day Night Economic Cost 844/739 /1 37.5 32.1 Casablanca 60 43.1 34.5 (largest rggie) (7) (115) (108) Meknes (highest 62 44.6 35.7 bulk tariff) (7) (119) (111) El Jadida (lowest 52 37.0 29.6 bulk tariff) (6) (99) (92) Industry (main 173 40.2 32.2 MV system) (23) (107) (100) /1 Regies/industry assuming a power factor of 0.8 and coincidence factors of 0.9 for regies and 0.7 for industry. Energy rates are close to, or even higher than, the economic cost. Capacity charges are considerably below the estimated economic cost. Some of the difference is accounted for by the omission of fuel savings from the economic cost. However, a rough calculation based on the cost/kW of a gas turbine which produces no fuel savings, shows that present capacity charges of around 50 DH/kVA/a are about 18% of the most conservative estimate of LRMC of about 280 DH/kVA/a. 1/ Therefore, it is safe to conclude that capacity charges in the present bulk supply tariffs are substantially lower than their economic costs. Retail Tariffs 13. Medium Voltage: A comparison of selected MV tariffs and the economic cost of supplying ONE's MV consumers is shown in Table 7. 1/ Based on a gas turbine cost of US$300/kW, 15-year life, 20% reserve margin, and transmission costs being half those shown in Table 3. ONE has no plans to commission further gas turbines. - 94 - ANNEX 3 Page 8 of 13 Table 7 Comparison Between MV Tariffs and Economic Costs (prevailing charges as a % of economic costs) Max. Demand Energy (cDH/kWh) Total /2 Region (DH/kVA/Year) Day Night (cDH/kWh) (a) Economic cost 1,295 /1 39.1 33.4 83.9 (b) Tariff 110 55.0 44.0 56.2 (9) (141) (132) (67) /1 Based on a 0.8 power factor and a coincidence factor of 0.75. /2 Assuming a 40% load factor and day/night kWh 75%/25%. The relation between tariff rates and economic costs is similar to that for the bulk supply tariffs. Capacity charges are in the order of 9% of the economic cost. Energy rates are 30% to 40% above the economic costs. Regies incur no energy costs, since they purchase their energy from ONE. The difference between energy rates in the MV tariffs charged by the regies and the ONE bulk supply tariff is much larger than the adjustment to compensate for losses. For example, the MV tariff for Casablanca implies average losses greater than 20%, whereas the losses for both MV and LV given by the regie are only 5.3%. There is, therefore, cross subsidization from the capacity charges to the energy rates. Consumers with low load factors are paying proportionately less than the economic costs of supplying them than high load factors consumers. 14. Low Voltage: It is difficult to compare the LV tariffs to economic costs because of the lack of data on consumer load characteristics. Residential and commercial consumers in Casablanca pay 52 cDH/kWh which is half the estimated economic cost. Small industrial consumers also pay about half the economic cost. LV consumers in some of the areas served by ONE pay as much as 70% of the economic cost. On the average, LV tariffs are well below the economic costs of supply (LRAIC). The Government control over the increases in the low voltage tariff since 1972 has maintained the real price of electricity to the households and small commercial consumers virtually unchanged while allowing the tariffs for bulk sales to increase in real terms by about 143%. This has had the effect of lowering the internal cash generation of the subsector, mainly ONE, and increasing the dependence of the subsector on budgetary allocations to finance the regies' and ONE's development programs. The budgetary contribution by the Government represents a compensation to the subsector for subsidies that are passed on to consumers. - 95 - ANNEX 3 Page 9 of 13 In particular, the Government subsidizes the LV consumers to maintain households' expenditures on energy at a reasonable level relative to their income; particularly for the low income groups. However, the extension of subsidy for electricity to all the LV consumers is unjustified on both economic and social grounds. The subsidy for the large LV consumers (households and commercial consumers) lowers the marginal price of electricity. This encourages the uneconomic use of electricity and denies the Government the resources which could otherwise be mobilized, if the LV tariffs reflected the economic cost of supply. Subsidy for the electricity consumption of the low income consumers could be accormodated by introducing a system involving a two-tier tariff for electricity: a) a subsidized tariff for a minimum level of consumption needed to meet the electric energy needs for basic lighting and househcld needs; and b) a tariff that is at or above the economic cost for consumption above the minimum level. 15. Overall, the level of electricity tariffs in Morocco is below the economic cost of supply; particularly capacity charges. The failure of the tariffs to cover the economic cost of capacity is primarily responsible for the inability of the power subsector to achieve an acceptable level of internal cash contribution and the need for budgetary support from the Government. Economic pricing is essential for the efficient use of electricity, particularly in view of the recent efforts by the Government in bringing the domestic prices for petroleum products in line with their cost to the economy. Maintaining tariffs below economic cost distorts the price of electricity relative to the competing fuels and results in their use in a sub-optimal mix. Therefore, in order to maintain the price of electricity relative to the competing fuels at a level that would ensure their efficient use, and given the potential resources that could be mobilized by pricing electricity on the basis of ec3nomic cost, it is recommended that the Government gradually move the average tariff for electricity to achieve parity with the LRMC. The optimal strategy for moving the tariffs upwards would be dealt with in the tariff study proposed below (para. 23). D. Structure of Existing Tariffs Bulk Supply Tariffs 16. Some features of the bulk supply tariff structure are consistent with charging consumers for the burden which they impose on the system. For example, charging for demand in kVA instead of kW gives an incentive to improve power factors. The dilferent day and night energy rates also indicate differences in marginal generation at different times of the day. However, the regional differences in ONE bulk supply tariffs do not reflect differences in the cost of supply. Furthermore, the declining scale of demand and energy charges does not reflect marginal costs and their elimination should be considered in the proposed tariff study (para. 23). - 96 - ANNEX 3 Page 10 of 13 17. Unless there is strong evidence of substantial differences in transmission costs, each regie should face the same bulk supply tariff for supply at the same voltage. Differences in the costs of connecting a regie to the main system, which are unique to that regie, could be levied as annual fixed charges. This could also serve as the vehicle for any cross subsidization to achieve regional equity. Fixed charges could be calculated to make up any difference between income derived from a bulk supply tariff set equal to marginal cost and ONE's financial requirements. As this would effectively be a tax on the regie, regies in established areas could pay higher fixed charges in relation to their size than regies expanding their networks. Alternatively, if the income from a marginal cost based bulk supply tariff exceeds ONE's financial requirements, tariffs should continue to be set equal to economic cost to ensure efficiency, and a mechanism established for transferring the surplus accruing to ONE to a fund that would finance the development plans of the rggies; for example, the FEC would be ideal for managing such a fund. It is therefore recommended that a single tariff for bulk supply be applied for all regies, unless large differences in the marginal costs are identified, in order to ensure equity and simplicity in tariff design. Retail Tariffs 18. Medium Voltage: The structure of MV tariffs charged by the regies is consistent with the marginal costs of supply. With some exceptions, the structure of ONE's MV tariffs is also consistent with the structure dictated by LRFC. For example, some MV tariffs have time of day kWh charges, plus a maximum demand charge based on kVA. However, in addition to their failure in reflecting marginal costs, other MV tariffs seem unnecessarily complicated for the consumer to understand. An example is the Subscribed Utilization Two kWh Rate tariff (Attachment 2), which has time of day kWh rates that depend on subscribed utilization. If utilization is measured by a maximum demand meter, then the tariff should be abolished in favor of a conventional maximum demand, two kWh rate tariff. If utilization is estimated using other criteria, the consumer is given no benefit for reducing his contribution to the system peak and should be placed on a simpler tariff appropriate to his size. The scale of maximum demand and kWh charges which declines as maximum demand decreases, in the ONE tariff for Special Agreements, does not give a good representation of marginal costs. Costs of connecting a MV consumer may exhibit economies of scale, but are usually sunk. These costs should be recovered either as an initial connection charge or contribution, or as a monthly fixed charge based on the capacity or cost of his connection, adjusted for inflation. Demand and energy should be charged at rates independent of consumption. 19. Low Voltage: The existence in the tariff schedule of five consumer classifications for LV tariffs for eac" regie and ONE does not appear unreasonable, although the definition of some consumer groups should be examined in the proposed tariff study (para. 23). Present consumer classification depends on end use. A household faces a different tariff depending on whether it uses electricity for lighting alone, or for other ANNEX 3 Page 11 of 13 purposes. It is not clear how the tariff is changed if the consumer acquires extra appliances. The classification of LV consumer types should be checked in the proposed tariff study, when better estimates of marginal costs are available. There is scope for a considerable reduction in the number of ONE tariffs by grouping together consumers with similar cost structures. I)ifferent tariffs should apply at a particular voltage level only where differences in marginal cost can be separately identified. The optimal number of consumer categories and the definition of each with respect to the cost of supply would be addressed in the tariff study. 20. The present structure is defining the block sizes in the domestic tariff by the number of rooms in the house. Even though the number of lights will be correlated with the number of rooms, their contribution to the system peak will depend also on the number of lights switched on and their ratings. Other appliances, the ownership and use of which is likely to be related only remotely to the number of rooms, will also contribute to peak demand. This dlefinition of kWh block size confuses the marginal cost message given to consumers. It also leads to admiinistrative problems in changing tariffs when consumers add rooms to their home. The proposed tariff study should define the consumption blocks on the basis of kWhs consumed rather than the number of rooms in the consumers' households. 21. LV tariffs that differ between rggies are justified if tariffs are to reflect the cost of supply and the financial target of each regie. However, the number of regional variations in ONE LV tariffs should be examined in relation to LRMC in the proposed tariff study (para. 23) and should be reduced where justified on efficiency and equity grounds. E. Strategy for New Electricity Tariffs 22. Although many aspects cf the tariff structure are consistent with marginal costs, the present tariffs are based on financial rather than economic criteria. The tariffs for sales by ONE to the regies are set on the basis of negotiations between the supplier and the consumer (regie), while the retail tariff is set by ONE. Therefore, at the input point (bulk purchase), the tariffs do not reflect the economic cost of supply and at the output point (retail sales), the tariffs are based on ONE's evaluation of the rggies' cost of supply rather than on the basis of a least-cost plan and a financial objective for each regie. On economic grounds, tariffs should be based on a properly formulated least-cost development plan and financial targets that would ensure the development of the regies and ONE into self-financing public utilities. To achieve this objective, ONE and each regie should first formulate least-cost development programs from which the economic cost of electricity could be determined. Then, long-term financial targets should be set for ONE and the regies in order to ultimately evolve towards a satisfactory level of self-financing for the power subsector. However, in view of the difference in the financial positions of the rggies and the recent - 98 - ANNEX 3 Page 12 of 13 deterioration in ONE's self-financing capabilities, a strategy should be set for gradually achieving the long-term financial objective over a relatively long period of time, to avoid the need for unrealistically high increases in tariff over the next 2 to 3 years. The time horizon for achieving self-financing could be adjusted for each regie to accommodate the need for a longer time horizon for newly created utilities to achieve the targeted level of internal cash generation. Therefore, in order to ensure the economic and efficient use of electricity and provide sufficient funds needed for the development of the subsector from the internal sources of the utilities, it is recommended that the Government formulate a national least-cost development program for the sector based on the integration of such programs for ONE and the regies, and set tariffs at levels that would reflect the economic cost of supply while ensuring the gradual move of the power subsector towards self-financing. 23. Under Loan 1299-MOR, the Government undertook a detailed tariff study which was subsequently reviewed by the Bank. However, the study's recommendations for a reform of Morocco's system of electricity tariffs have not yet been implemented. In view of the changes that have taken place since the tariff study was completed in 1978, and given the fact that the study concentrated its analysis on ONE's development program rather than an integrated program for the entire power subsector, the Government should update the tariff study. A major problem in updating the study is expected to be the lack of data that is detailed enough to allow for an accurate estimate of the economic cost of supply (LRAIC). Most, if not all, regies suffer from poor quality data on their consumers' patterns of electricity consumption. A consistent system for gathering and classifying data from all the utilities in the power subsector is urgently needed. This system could be in place in a relatively short period of time because some of the data covering the regies are presently available at the regies' data center in Casablanca. The new data would serve as a basis for the formulation of a least-cost development plan for the power subsector, and in turn, the estimation of LRAIC and electricity tariffs. 24. The proposed data collection exercise should concentrate on the following areas: a) Transmission and distribution investment and operating cost data, by voltage level, obtained from least-cost investment plans; b) Peak and average losses by voltage level; c) Marginal energy costs (cDH/kWh) obtained from using or adapting generating system operations models and taking the performance characteristics of thermal plant into account. These costs should be analyzed by time of day and season; -99 - ANNEX 3 Page 13 of 13 d) Consumer load characteristics, especially load factors (utilization), peak coincidence factors, appliance ownership, and demand-to- connected load ratios. These data should be collected particularly for consumers that will face simple kWh tariffs; and e) The distribution of monthly household consumption obtained from billing data. This is essential to design an increasing kWh block tariff. February 1984 (0756P) - 100 - ANNEX 3 Attachment 1 MOROCCO POWER SUBSECTOR STUDY Typical Bulk Supply Tariffs (Effective from December 1, 1982) 1. El Jadida Regie (lowest bulk supply tariff) Subscribed or Actual Max. Demand Energy (DH/kWh) Demand (kVA) (DH/kVA/a) Day Night 0 to 100 57.23 0.37,203 0.29,765 101 to 200 56.29 0.37,172 0.29,738 201 to 500 55.34 0.37,134 0.29,710 501 to 1,000 54.42 0.37,096 0.29,679 1,001 to 2,000 53.19 0.37,047 0.29,640 above 2,000 51.52 0.37,001 0.29,604 2. Meknes Regie (highest bulk tariff) Subscribed or Actual Max. Demand Energy (DH/kWh) Demand (kVA) (DH/kVA/a) Day Night 0 to 100 kVA 69.03 0.44,885 0.35,919 101 to 200 kVA 67.91 0.44,848 0.35,880 201 to 500 kVA 66.79 0.44,807 0.35,846 501 to 1,000 kVA 65.65 0.44,758 0.35,806 1,001 to 2,000 kVA 64.18 0.44,699 0.35,760 above 2,000 kVA 62.17 0.44,643 0.35,717 3. Final Consumers HV and VHV Maximum Max. Demand Energy Charge (DH/kWH) Demand (kVA) Charge (DH/kVA/a) Day Night 25 to 100 176.23 0.40,335 0.32,258 101 to 200 175.66 0.40,316 0.32,242 201 to 500 175.06 0.40,298 0.32,228 501 to 1,000 174.51 0.40,268 0.32,204 1,001 to 2,000 173.73 0.40,240 0.32,182 above 2,000 172.69 0.40,211 0.32,158 4. Final Consumers MV Maximum Demand Energy charge (DH/kWh) charge (DH/kVA/a Day Night 103.40 0.5170 0.4136 February 1984 (0756P) 101 - ANNEX 3 Attachment 2 Page 1 of 4 MOROCCO POWER SUBSECTOR STUDY Retail Tariffs (Effectilve from December 1, 1982) 1.1 MV Tariffs (ONE and regies) /1 Maximum Demand Energy Charges (DH/kWh) DH/kVA/a Day Night 110 0.55 0.44 /1 Taxes included. February 1984 (0756P) -102 - ANNEX 3 tEETFet 2 Page 2 of 4 MN