Power and Coal Subsector Review

Report No. 4746b-HU Hungary Powerand Coal SubsectorReview o-dLEto

Public Disclosure Authorized October 4, 1984 Projects Department Europe,Middle Eastand North Africa Regional Office

FOR OFFICIAL USE ONLY Public Disclosure Authorized Public Disclosure Authorized

Document of the World Bank Public Disclosure Authorized 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 (as of May, 1983)

Currency unit = Forint (Ft) Official rate 1T7'orint (Ft 1) = US$0.025 Ft 40 = US$1.00

WEIGHTS AND MEASURES

1 kilowatt (kW) = 1,000 watts (103 W) 1 Megawatt (MW) = 1,000 kilowatts (103 kW) 1 Gigawatt (GW) = 1 million kilowatts (106kW) 1 kilowatt-hour (kWh) = 1,000 watt-hours (103 Wh) 1 Megawatt-hour (MWh) = 1,000 kWh (10 3 kWh) 1 Gigawatt-hour (GWh) = 1,000,000 kWh (106 kWh) 1 Terawatt-hour (TWh) = 1,000 million kWh (lO9kWh) 1 kilovolt (kV) = 1,000 volt (103V) 1 kilovolt-ampere (kVA) = 1,000 volt-amperes (103 VA) 1 Megavolt-ampere (MVA) = 1,000 kilovolt-amperes (103 kVA) 1 kilocalorie (kcal) = 3.968 British thermal units (Btu) = 4.1868 kilojoules (kJ) 1 kilojoule (kJ) = 0.2388 kilocalorie (kcal) 1 Megajoule (MJ) = 1,000 kilojoules 10 3 kJ) 1 Gigajoule (GJ) = 1,000,000 kilojoules (106 kJ) 1 Terajoule (TJ) = 1,000 million kilojoules (109 kJ) 1 Petajoule (PJ) = 1,000,000 million kilojoules (l012 kJ) 1 tonne of oil equivalent (toe) = 10,200,000 kilocalories = 42.7 Gigajoules 1 Hertz (unit of frequency) (Hz) = 1 cycle per second I bar (unit of pressure) = 14.5 lbs per sq. inch 1 kilogram (kg) = 2.206 pounds (lb, 1 ton (metric ton) (t) = 1000 kg = 2,206 lb = 1.102 short ton = 0.984 long ton 1 meter (m) = 3,281 feet (ft) 1 millimeter (mm) = 0.001 m 1 kilometer (km) = 1,000 m = 3,281 ft FOR OFFICIALUSE ONLY

GLOSSARY OF ABBREVIATIONS

AEEF State Authority for Energy Management and Energy Safety CHP Combined Heat and Power (co-generation) CMEA Council for Mutual Economic Assistance (Comecon) DESASZ South-East Hungary Electricity Distribution Company DEMASZ South Hungary Electricity Distribution Compaly EDASZ North-West Hungary Electricity Distribution Company EGI Institute for Energy Conservation ELMU Budapest Electricity Distribution Company EMASZ North Hungary Electricity Distribution Company ERBE Power Station Investment Company EROTERV Engineering Company for Power Station and Network Design FRG Federal Republic of Germany GDP Gross Domestic Product GDR German Democratic Republic GNP Gross National Product HV High voltage IAEA InternationalAtomic Energy Agency IpM Ministry of Industry KBFI Central Mining Development Institute KSH Central Statistical Office LOLP Loss ot Load Probability LPG Liquefied Petroleum Gas LRAIC Long-Run Average Incremental Cost LRMC Long-Run Marginal Cost LV Low Voltage MV Medium Voltage MVMT Hungarian Electric Power Board (Trust) MWe Megawatt electrical output of CHP plant MWg Megawatt generated at generator MWso Megawatt sent out from power station, net of internal consumption MWth Megawatt thermal (heat) output of CHP under heat supply plant NBH National Bank of Hungary NBMP National Board for Materials and Prices NGL Natural gas liquids NDC National (power) Dispatch Centre NPO National Planning Office OAB Atomic Energy Commission OEGH National Energy Authority OES InterconnectedPower System (CMEA) OKGT Hungarian National Oil and Gas Trust OKTH National Environmental Protection Office OMFB State Commission for Technical Development OVIT National (power) Transmission Company PWR Pressurized Water (nuclear) Reactor SAR Staff (project) Appraisal Report (World Bank) SDB State Development Bank TITASZ East Hungary Electricity Distribution Company USSR Union of Soviet Socialist Republics (Soviet Union) VEIKI Institute for Energy VERTESZ Power Station Study and Erection Company VITEV Electricity Industry Civil Engineering and Maintenance Company

This document has a restricteddistribution and may be used by recipientsonly in the performanceof their official duties. Its contents may not otherwisebe disclosed without World Bank authorization. HUNGARY

POWER AND COAL SUBSECTOR REVIEW

ABSTRACT

This report identifies the main issues in Hungary's electric power, coal, and district heating subsectors and presents a strategy for dealing with them. The central issue in the subsectors concerns the selection of the most economic power generation option and any associated coal mining investment. Based on a computer model of the Hungarian power system, the mission recommends that a group of combined heat and power projects followed by a lignite power station is the preferred strategy. An alternative strategy with no CHP projects would be the lignite power station followed by a brown coal power station. Further 1,000 MW nuclear power stations are shown to be a low priority at present. The report contains a number of recommendations for strengthening the planning of the subsectors which involve preparing least-cost investment programs for power, brown coal and district heat development, feasibility studies for projects in these programs and a re-evaluation of the Lias (hard coal) investment program. Prices of power and coal to enterprises are generally in the order of 80-90% of economic cost and the mission recommends raising these prices to their economic costs to improve economic efficiency and to mobilize resources to finance new investment. Consumer energy prices are typically only 30-35% of economic cost. The Government plans to increase them to their economic costs, but the mission recommends that the Government should determine whether the timescale to this could be speeded up. Enterprises in the power and coal subsector are generally well run and adequately staffed. There may exist some scope for modest institutional reforms that would raise efficiency above its already high level and the report recommends areas which the Government could examine. In particular, the mission recommends giving the power utility more responsibility for preparing its investment programs for review and approval by the appropriate Government agencies. HUNGARY

POWER AND COAL SUBSECTOR REVIEW

Table of Contents

Page

I. EXECUTIVE SUMMARY 1

A. Introduction 1 B. The Main Issues 3

II. THE INSTITUTIONAL FRAMEWORK 21

A. Energy Sector Organization 21 B. The Electric Power Subsector 27 C. The Coal Subsector 31 D. The District Heating Subsector 35 E. Subsector Planning 36

1II. COAL AND OTHER ENERGY RESOURCES 39

A. Coal Reserves 39 B. Other Energy Resources 40

IV. PAST CONSUMPTION AND SUPPLY OF POWER, COAL AND DISTRICT HEAT 43

A. Development of Energy Policy 43 B. Overview of Energy Consumption and Supply 44 C. Past Trends in the Consumption of Coal 50 D. Past Trends in the Consumption of Electricity 53 E. Past Consumption of District Heat 56 F. Past Supply of Electricity 58 G. Past Supply of Coal 68 H. Past Supply of District Heat 72

V. PROJECTED CONSUMPTION AND SUPPLY OF POWER, COAL AND DISTRICT HEAT 77

A. Forecast Consumption of Power, Coal and District Heat 77 B. Future Electricity Supply 83 C. Future Coal Supply 97 D. Future Supply of District Heat 103

This report was prepared by; A. McKechnie (economist), H. Hendriks (mining engineer), T.B. Russell (consultant), M. Sharma (consultant), with assistance from H. Boehm (financial analyst), S. Chattopadhya (coal mining engineer), I. Tuncay (power engineer), G. Deuster (consultant), P. Skytta (consultant), W. Buehring (consultant), and L. Poch (consultant). - ii -

Table of Contents (cont'd)

Page

VI. DEMANDMANAGEMENT AND PRICING 107

A. Demand Management 107 B. Historical Overview of Coal and Electricity Prices 108 C. Institutional Responsibility and Basis for Energy Pricing 112 D. Pricing of Coal 112 E. Electricity Tariffs 116 F. Pricing of District Heat 122 G. Household Prices of Power, Coal and District Heat 126

VII. INVESTMENT 130 - iii -

Table of Contents (cont'd)

ANNEXES Page

1. - None

2.1 - Power Subsector Organization (Chart)...... 135 2.2 - Organization of Hungarian Electric Power Trust (MVMT) (Chart). 136 2.3 - Electric Power Subsector Manpower 1975-1985...... 137 2.4 - Wages and Salaries, Electric Power Subsector...... 138 2.5 - Organization of Tatabanya Coal Mining Company (Chart)...... 141 2.6 - Tatabanya Coal Mining Company...... 142 2.7 - Main Provision of Public Law IV of 1962 Concerning the Development, Transmission and Distribution of Electric Power, Decree 40/1962 ...... 144 2.8 - Main Provisions of Act VI of 1977 on State Enterprises and Decree No. 4/1978 of the Council of Ministers on Its Enforcement...... 155

3. Coal Reserves...... 164

4.1 - Consumption of Fuels by Sector...... 168

4.2 - Consumption of Coal and Coal Products ...... 172 Table 1: Primary Coal Consumption by End-Use, 1970-1981..... 172 Table 2: Coal Consumption by Sector, 1970-1981 ...... 173 Table 3: Consumption of Briquettes by Sector, 1970-1981 ..... 174 Table 4: Consumption of Coke by Sector, 1970-1981 ...... 175

4.3 - Electricity Generating Capacity ...... 176 Table 1: Balance of Capacity and Demand, Interconnected System...... 176 Table 2: Details of Power Generating Plant, December 1982 ... 177 Table 3; MVMT Installed Capacity by Fuel Type, 1982...... 179 Table 4: Age Distribution of MVMT Steam Plant ...... 180 Table 5; Size Distribution of MVMT Steam Plant ...... 180 Table 6: Autoproducers Generating Plant ...... 181 Attachment 1 - Electric Power Generating Capacity by Industrial Subsector Socialist Industry (as at December 31, 1981)...... 182

4.4 - Production of Electricity . . . 183 Table 1: National Production and Consumption of Electricity 183 Table 2: National Production of Electricity by Plant Type 184 Table 3; MVMT Power Generation by Fuel Type ...... 185 Table 4: International Trade in Electricity by Country, 1980-1982 ...... 186 - iv -

Table of Contents (cont'd)

ANNEXES Page

4.5 - Power and Heat Fuel Consumption ...... 187 Table 1: Fuels Consumed in the Production of Heat and Electricity 1970-81...... 187 Table 2: Fuel Consumed in the Production of Electricity and Heat, 1975...... 188 Table 3: Fuel Consumed in the Production of Electricity and Heat, 1980...... 189 Table 4: Fuel Consumed by MVMT ...... 190

4.6 - Production Data for District Heating Systems With an Installed Capacity Greater Than 20 MW, 1980...... 191

4.7 - Energy Balances ...... 194

5.1 - Power and Coal Demand Forecasting ...... 195 5.2 - Average Nuclear Construction Time Span ...... 198

5.3 - Analysis Power Generation Investment Options ...... 199 Figure 1 - Quarterly Load Duration Curves (1984-2010) 214 Attachment 1 - Summary Report on a Generation Expansion Plan for Variable Expansion Case Study (1984-2010)...... 215

5.4 - Technical and Cost Data on Potential Heat Production Projects ...... 244 5.5 - Technical and Cost Data on Potential Heat Production Projects ...... 245

6.1 - Demand Management ...... 246 6.2 - MVMT Electricity Tariffs for Producers ...... 253

6.3 - The Long Run Marginal Cost of Electricity ...... 258 Attachment 1: Generation Capacity Additions With and Without a 200-MW Increment in Maximum Demand. 262 Attachment 2: Data for Calculation LRMC of Generating Capacity (US$ '000, 1983 prices)...... 263 Attachment 3: Calculation of LRMC of Generating Capacity ... 264 Attachment 4: Calculation of LRAIC of Transmission ...... 267

6.4 - Marginal Costs and Tariffs ...... 268 Table 1: Marginal Cost of Supplying Tariff Categories ...... 268 Table 2: Comparison of Average Tariff Levels to LRMC ...... 269

6.5 - Economic Cost of District Heat ...... 270 6.6 - Benefits from Metering District Heat ...... 280 Table of Contents (cont'd)

ANNEXES Page

6.7 - Energy Expenditure and Income ...... 283 Table 1: Per Capita Household Energy Expenditure and Per Capita Household Expenditure and Income, 1981 ... 283 Table 2: Expenditure on Energy by Household Income Level, 1981 ...... 284

6.8 - Estimates of Long Run Marginal Production Costs for Typical Brown Coal-Lignite Projects ...... 285

7.1 - A. Coal Subsector Projects Under Construction ...... 287 B. Coal Subsector - Possible Future Projects ...... 288

Maps: IBRD 18191 - Hungary Coal Subsector

IBRD 18105 - Hungary Power Subsector

I. EXECUTIVE SUMMARY

A. Introduction and Summary of Main Conclusions

Background to the Review

1.01 Hungary has a long tradition of coal mining, dating back to the beginning of the last century. Similarly, limited public electricity supply and the manufacture of electrical machinery predates the beginning of this century. Electrification of the country is almost complete, since 99% of households have public electricity supply and the demand for electricity is projected by the Government to grow relatively slowly at rates in the order of 3.5% p.a. until the year 2000. The staff at all levels of power and coal subsector enterprises are highly trained and experienced. In these respects Hungary differs from the majority of Bank borrowers.

1.02 However, in other respects, Hungary shares common problems with the middle income developing countries. Hungary faces a major problem of structural adjustment, having plant in the energy supply and manufacturing industries that was designed when the price of energy was low. Adjustment to present energy prices has been delayed because of the contractual arrangements through which Hungary imports energy and by an acute liquidiltyshortage which has prevented the large scale replacement of uneconomic capacity. Hungary also is in the process of institutional change, having evolved from a centrally planned economy towards more decentralized decision making. The dissolution of the coal trust into several relatively autonomous enterprises was a consequence of this process, yet the power subsector remains to a large extent centrally planned. Hungary is developing its own forma of economic management towards becoming a market economy in a socialist environment. However, in other countries it is the rule rather than the exception for the power and coal subsectors to be part of the public sector, so that ensuring efficient investment pricing and operations in these industries is not a problem unique to Hungary. The issues of structural adjustment, institutional evolution and efficient investment and pricing are major themes in this report.

1.03 In order to assist the Government in developing its energy policies, the report focusses on issues where, we believe, there is potential for improvement or reform. This may give the misleading impression that the subsectors are in a poor state and in need of substantial change, which is unintended. Indeed, it is the mission's opinion that the Govrernment organizations and energy sector enterprises compare favorably with those in the industrialized countries.

1.04 As well as examining the issues and the prospects for structural adjustment in the power and coal subsectors, the report also considers a third subsector, district heating, which involves piping hot water and steam to industrial residential and communal consumers. For technical and institutional reasons, it would be impossible to carry out a power subsector review without a detailed consideration of district heating. -2-

Summary of Main Conclusions

1.05 The major conclusions of the report concern: (a) the adoption of a methodology to carry out investment planning and long run marginal cost calculations on a continuing basis for power, coal and district heat along the lines suggested and examplified in the report; (b) the tentative choice of the Dunamenti combined heat and powr project as the highest priority project on the basis of information presently available to the mission; and (c) the need to increase the prices of power, coal and district heat which for households are substantially below economic costs. In addition, there are a number of subsidiary conclusions relating to institutions and to operational efficiency. The major conclusions are discussed in more detail in the following paragraphs.

1.06 Although the Ministry of Industry has taken substantial steps after the discussions of the initial draft of the Report towards preparing least cost development programs for power, coal and district heat, there remains a need to further refine the methodology so as to enable clear economic decisions to be made. In particular, the report recommends that an approach similar to the WASP computer program of the IAEA (used in the report) be used for long term power system planning, modified if necessary to Hungarian conditions. Moreover, energy investment planning is a continuing process and the main options and their variants should be regularly reviewed. In addition more precise estimates of the long run marginal costs of power, coal and district heat should be prepared using the investment planning models.

1.07 The conclusions of the report on the power investment program are based on options and data made available to the Bank in mid 1983. Since then the Government has been carrying out studies with revised data and new technical alternatives which it expects to be completed in mid 1984. It is recommended, therefore, that the Ministry of Industry review the tentative conclusions of the mission's report by the end of 1984. The conclusions to be reviewed are:

(a) that the Dunamenti combined heat and power project has the highest priority;

(b) that a 1,000 MW nuclear power station is a low priority at present;

(d) that gas turbines have a role in the least cost program;

(e) that the economics of combined cycle plant with and without heating alternatives deserve further investigation; and

(f) that a program for rehabiliting or retiring old generating units needs to be established.

1.08 A further conclusion of the review is that the producer prices of power, coal and district heat are about 85% of their economic costs, while the - 3 -

consumer prices about 30% of economic cost. The overall ratio between price and long run marginal cost of power is of the order of 70%. It is recommended that the Ministry of Industry: (a) refine the long run marginal cost calculations mentioned in para. 1.06 above; (b) extend these calculations to cover the costs of distribution and transport to the consumer; and (c) for electricity, heat and coal, develop prices that reflect long run marginal cost. Following these studies, and within the Government's general policies for narrowing the gap between energy prices and costs, a specific program should be prepared for raising energy prices as rapidly as possible to the level of their economic cost.

1.09 Finally, there are a number of measures which could 'be taken to further improve operational efficiency e.g. electricity distribution loss reduction, improvements in overall labor productivity of coal mining companies. These, together with the major recommendations, are set out in Table 1.2.

B. The Main Issues

Introduction

1.10 The principal issues which the mission identified faLl under four broad headings:

(a) Institutions;

(b) Future Supply and Investment;

(d) Pricing.

The main issues for each of the four subsectors are described briefly under these headings, along with the mission's recommendations for addressing them. The issues and recommendations are also summarized in Table 1.2.

Institutions

1.11 The energy sector is under the jurisdiction of the Mi'nistry of Industry (IpM), within which the National Energy Authority (OE.GH)coordinates energy sector activities. The main energy supply institutions are the Hungarian Electric Power Trust (MVMT), the Hungarian National Oil and Gas Trust (OKGT), the coal mining companies and the municipalities engaged in district heat supply.

1.12 The system of physical planning which existed prior to 1968 has been abolished and national economic plans are intended to give enterprise managers greater autonomy, within an indicative framework supported by credit, wage regulation, exchange rate and price policies. Despite these changes, the Government continues to exercise a large measure of control over activities in the energy sector, particularly planning, investment and pricing. Although -4- the energy sector is generally operating well there appears sufficient grounds for the Government to take a fresh look at some aspects of the organization of the sector to see whether small economies might be made. Such aspects could include the security of tenure for directors, the distribution of functions among technical institutes and responsibility for energy and nuclear safety. In particular, the Government should consider whether MVMT should have greater authority for initiating investment planning studies that would be reviewed and incorporated into energy sector investment programs by OEGH.

1.13 MVMT has 22 member companies which include 11 power stations, 1 transmission enterprise and 6 distribution companies. The autonomy of these enterprises is more apparent than real, partly for institutional reasons and partly because the enterprises form part of an integrated system. Although MVMT is well managed and appears to operate well, it would appear worth examining what savings could be made through modest institutional reforms such as hiving off its ancillary enterprises in the interests of greater autonomy and efficiency.

1.14 Prior to 1981 the coal subsector was organized as a trust, similar to MVMT and OKGT. As a consequence of the Government's policies for economic reforms, the coal trust was broken up into eight regional mining companies and a mining equipment company. This organization may not be entirely appropriate since the West Hungarian brown coal producers are probably too small to achieve an economic scale of operations and they are adjacent to one another. During the decline of the coal industry in the 1960's and 1970's mining companies diversified into non-mining activities, often in fields related to mining, to preserve employment. Such activities employ about 40% of the workforce and generate 30% of the industry's gross revenues. Following the abolition of the trust, the mining companies have established technical, marketing and coordination institutes with a danger of overlapping and duplication of activities. The re-organized coal subsector has not yet had time to establish itself and further institutional change at this time would be premature. Nevertheless, once institutions have had time to assimilate the changes initiated in 1981, say in 1986/87, the present organization should be reviewed.

1.15 The major part of plant producing heat for district heating is owned and operated by MVNT. This heat is distributed by institutions, most of which are run by local government, but which report to IpM only on technical matters. Heat distributors are in most cases constituted as local government departments, often in combination with water and sewerage. In contrast to the electricity and gas utilities, the ethos of municipal heat distribution tends more towards the provision of heat as a social service, rather than the economic supply of energy. There is a need for the Government to consider the reorganization of heat supply in order to promote greater efficiency with a view to restructuring it as state enterprises reporting to IpM.

Future Supply and Investment

(a) Electric Power

1.16 The Government projects the demand for electricity on the interconnected system to increase at a rate of 3.8% p.a. during the period - 5 -

1982-1990 from 5,439 MW in 1982 to 7,330 MW in 1990. For the remainder of the century, the projection shows a rate of growth of 3.4% p.a., reaching 10,250 MW in 2000. This forecast is based on the elasticity of electricity consumption with respect to GDP falling from 1.32 observed during 1975-1980, to 1.25 during 1982-1990 and 1.17 during 1990-2000. The decline in elasticity would arise from changes in the structure of industrial output, increases in electricity prices and energy conservation and demand management policies. However, reforms to household and other electricity prices and the improved energy efficiency of new investment might lead to a further reduction in the elasticity of electricity consumption to GDP and the electricity load forecast should therefore be reviewed.

1.17 Future power generation investment can be divided into two periods. First, the medium term 1983-1990 for which investment decisions have been taken. Second, the longer term 1990-2000 for which the authorities need to take a decision on projects to meet the projected demand for electricity in the early 1990's.

1.18 Generation development in the medium term is dominated by the completion of the Paks nuclear power station. The first 440 MW unit successfully entered commercial operation in 1983 after delays of almost three years arising from contractor inexperience with this kind of project and changes to the Soviet design to meet Hungarian requirements. The Government now expects the remaining three units to enter commercial operation in 1984, 1986 and 1989, and in the mission's view this program is realistic. Imports of electricity from the Soviet Union have been contracted to increase from 1,428 MW in 1982 to 1,788 MW in 1985 and then remain constant.

1.19 The main options for meeting the increased demand for electricity in the 1990's are:

(a) a number of projects designed also to increase the proportion of district heat produced in CHP plant and to substitute coal for oil and gas in power generation. The largest of these is a 2x180 MW extension to the Dunamenti power station which would burn brown coal and supply Budapest with heat via a 25 km pipeline.

(b) a lignite-fired mine-mouth power station at BUkkabrany with an ultimate capacity of 2,000 MW;

(c) a steam power station at Bicske burning residual brown coal from coal washing plants, with a capacity of 1,000 MW. One variant envisages some CHP capability to supply Budapest with heat from a 35 km pipeline; and

(d) a 2x1,000 MW extension to the Paks nuclear power station.

1.20 The central issue in the power and coal subsectors, concerns the selection of the most economic power generation option and any associated coal investment. The Government intends to complete studies by mid 1984 which will determine new power and coal investments for the 1986-1990 Five-Year Plan. In order to gain a quantitative appreciation of the issues underlying this decision, the mission used the WASP computer program of the IAEA to model investment choices in the Hungarian power system. The purpose of this study - 6 -

was to obtain a least-cost generation program for Hungary based on the data available to the mission. Since the mission lacked detailed information on investment costs, technical options, system operation and policy constraints the authorities should review the results of the mission's analysis and develop them in greater depth.

1.21 Two strategies were evaluated for generation development. The first consists of CHP plant commissioned in 1991 which enables the large power-only investments to be delayed. The second strategy gives priority to developing power-only plant, with no new CHP plant being commissioned. As well as meeting the growth of electricity demand in the early 1990's, the CHP strategy would lead to a major restructuring of district heat production. Brown coal based CHP heat production would substitute for heat produced in oil or natural gas fired boilers. Investment programs produced by the model that are "optimal" with respect to the data and assumptions are summarized in Table 1.1. A preliminary economic analysis of the two strategies strongly suggests that the CHP strategy is preferred. However, the mission lacked the detailed technical and cost data to confirm this. It is recommended that the Government complete studies to evaluate the economic case and timing of each CHP project in the least-cost development programs for power and heat supply and prepare detailed feasibility studies for those projects in the least-cost programs.

Table 1.1

Summary Results of Mission's Generation Planning Studies

Year CHP Strategy No CHP Strategy

1991 Dunamenti 2x180 MW No Additions Gy-r 2x48 MW North Pest 2x23 MW, 2x46 MW AlmasfUzito 14MW, Szolnok 14 MW Obuda 46 MW, Debrecen 8.6 MW Nyiregyhaza 9.6 MW, Kecskemet 7 MW

1992 -- Gas Turbine 1 100 MW 1993 -- BUkkabrany 1 250 MW Gas Turbine 2 100 MW 1994 -- BUkkabrgny 2, 3 2x250 MW 1995 Biikkabrany 1 250 MW Buikkabrany4 250 MW Gas Turbine 1 100 MW 1996 Biikkabrany 2 250 MW BukkAbrAny 5 250 MW 1997 BUkkabrany 3 250 MW BUkkabrany 6, 7 2x250 MW 1998 Biikkabrany 4, 5 2x 250 MW Biikkabrany8 250 MW 1999 BUkkabrAny 6 250 MW Bicske 1 250 MW 2000 Biikkabrgny 7, 8 2x250 MW Bicske 2, 3 2x250 MW

TOTAL 2,793 MW 2,950 MW

Source: Table 5.7 1.22 After the CHP projects have been implemented, the analysis concludes that, based on the capital and fuel cost data given to the mission, the BUkkabrany lignite-fired station would be the least cost power-only investment. For the no-CHP strategy the conclusion is the same, except that construction would be advanced by two years. An additional brown coal project, e.g. Bicske, would then be preferred to another lignite project. As this station would not be required until the turn of the century, the choice of fuel should be reviewed when better cost data are available for the projects. Preliminary estimates of the marginal costs of brown coal and lignite suggest that they might be 30% and 35% respectively above their financial costs, but the conclusions are insensitive to fuel price changes of this magnitude. Other relevant costs, with the exception of nuclear capital costs which are too low, are close to their economic costs. It is recommended that the Government complete studies to confirm that the Biikkabrany project is the best power-only alternative and carry out detailed feasibility studies by early 1986 to prepare both the lignite mine and power station.

1.23 A clear finding from the mission's studies was that additional 1,000 MW nuclear units appear a low priority at present. A 1,000 MW nuclear unit entered the optimal solution only when its capital cost was cut by 25%, which would correspond to a highly unlikely five-year construction period. Even then, the program scheduled the unit for commissioning in 2006 after the CHP, Biikkabrinyand Bicske projects had been completed. Raising the coal power station capital costs by 20% or the price of brown coal and lignite by 30% and 35% respectively did not put new 1,000 MW nuclear units in the investment program. The conclusion that such nuclear units are a low priority is a consequence of their long lead times and the 12% real discount rate used in project appraisal in Hungary. The conclusion was reached despite what the mission considers optimistic planning data on nuclear capital costs and operating availability (load factor). Analysis by IpM in parallel with the mission's studies has confimed that the 1,000 MW nuclear units are a low priority for the 1990's. It is recommended that further nuclear units should be given low priority at present, but that the prices and production performance of poLential vendors be monitored so that nuclear power could be re-considered as an option after the Biikkabranyproject.

1.24 There is about 2,000 MW of MVMT generating plant, out of a total installed capacity of about 6,146 MW, that was commissioned before 1970 and will be at least 30 years old by the end of the century. About 20 out of the 25 power stations that are candidates for closure have some CHP capability. MVMT's retirement policy is to replace old CHP plant by CHP units of similar capacity, but it might be economic to change the power to heat ratio in these stations. It is recommended that MVMT commission studies to decide the future role of old power stations, taking into account heat supply requirements.

1.25 A finding from the model is that some extra peaking plant is required throughout the 1990-2010 planning period. In the economic studies this was considered to consist of gas turbines. However, combined cycle plant, with or without CHP capability, is a further option that appears economically attractive, particularly if natural gas is available at a cost to the national economy below that of gas oil. It is recommended that the economics of combined cycle be evaluated. -8-

(b) Coal

1.26 The Government's coal development strategy aims to reverse the decline of the coal industry during the 1960's and early 1970's and to replace oil and gas consumption by coal. Medium term plans call for coal production to be stabilized at the current level of about 8 million tons/a of lignite, 15 million tons/a for brown coal and 3 million tons/a of hard coal, all equivalent to about 7 million toe until the early 1990's. Thereafter, coal production would increase, mainly to meet the growing requirements for power generation, so that total production would amount to about 9 million toe in 1995.

1.27 The Government has initiated two major development programs to achieve the goals of its coal development strategy, the Eocene (brown coal) and Lias (hard coal) programs. Mining companies have started their own investments with similar objectives. The Eocene program began in 1976 and the Government sponsored part is estimated to cost US$400 million (of which US$250 has been spent) and the companies' investment amounts to an additional US$190 million. These costs represent mining capacity of 6.8 million tons per year from 1982 until the end of the decade. Only a portion of this capacity is a net addition since the major part will be required to replace depleting mines. The mission estimates the marginal cost of locally mined brown coal to be about US$2.0/GJ (US$26/t) compared to about US$2.6/GJ (US$70/t) for internationally traded coal delivered to Hungary.

1.28 The Government's Lias program began in 1982 and was expected to last 10 years, although this program has now slipped. Present production of about 3 million tons per year could be increased by 0.4 million tons to supply local coking coal to the steel industry. The cost of the Lias program is very high in relation to both the level of output and investment in the Eocene program. At the end of 1981, Government sponsored investment in the Lias program was estimated to amount to about US$58O million which would be augmented by a further US$180 million by the mining companies. The cost of hard coal would rise to US$2.8/GJ, greater than, the cost of imported coal. Coking coal can only be recovered to about 25% from the raw coal and the quality is relatively low. The Government and the Mecsek colliery, which is carrying out the program are now recognizing the need for further economic justification of this project and have therefore embarked on a major cost reduction program. It is recommended that this program be accelerated as quickly as possible in terms of planning and implementation.

1.29 About 10 brown coal mine development projects are in various stages of preparation. Cost data for the projects are not necessarily on a consistent basis and the mission was unable to obtain information on the depletion of existing mines. For the future supply of brown coal to new CHP plants and other consumers it is recommended that the economic cost of brown coal be established and a least-cost development program for brown coal be prepared. Since the Biikkabrany power project also appears to be of high priority (para. 1.22) it is recommended that a detailed feasibility study for the Biikkabrgny lignite mine be prepared which would, inter alia, investigate the phasing of bringing it into operation. -9

1.30 Heat supply is characterized by production capacity that is no longer economic at present level prices. The Government recognizes this and favors a strategy to restructure heat supply by substituting brown coal based CHP heat production for heat produced in boilers fuelled by oil and natural gas. Although heat supply options have been evaluated in some detail for Budapest, projects have not generally been ranked in order of priority and their timings established. Some projects appear to have long, e.g. 10 year, construction times and might be less economic than projects with shorter lead times. In the period before new CHP projects can be brought on stream, measures should be implemented to improve the efficiency of heat supply, e.g. by interconnecting heat distribution networks and reducing losses. The policy for connecting new heat consumers that are not supplied from CHP plant should be reviewed, particularly to consider whether the direct use of natural gas for cooking, as well as water and space heating by households would be preferable to district heating. Use of natural gas in existing or new gas turbines with heat recovery cycles for district heating would appear worth evaluating. There is a need for IpM to establish a least-cost development program for the district heating subsector that would evaluate the ultimate size of the market for district heat, establish policies to achieve savings before the CHP projects are completed and set longer-term investment priorities and timings.

Operational Issues

1.31 Enterprises engaged in electricity supply appear to be well managed and staff are well trained and generally experienced. Coal mines give the impression of being efficiently operated and labor productivity at the face is comparable to Western Europe. However, the productivity drop from mine workings to the overall company is much higher and overall productivity should be closely observed for possible future improvements. In the power subsector labor productivity overall is comparable to similar utilities in Western Europe, but manning levels in power stations are relatively high and it would be worth examining whether there is any scope for economy.

1.32 Internal use of electricity in power stations is high at around 8%, considering the widespread use of oil and gas as fuels, although district heating pumping requirements in old power stations account for a disproportionate amount of internal consumption. Reducing station use to 5% would save about 0.7% of primary energy consumption. It also appears that losses in medium voltage and low voltage distribution networks are high, partly because of the shortage of finance for distribution investment. It is recommended that MVMT identify where power station use could be reduced through retrofitting, use the economic cost of electricity to optimize station use and losses, evaluate the scope for distribution network loss reduction and then implement a program of loss reduction.

Demand Management and Pricing

1.33 Faced with rising prices of imported energy, which had been delayed by the Bucharest Principle of 5 year moving averages of world prices that - 10 - governs intra CMEA trade, and increasing energy investment requirements at a time of acute liquidity shortage, the Government initiated a consistent set of demand management policies in late 1980. Principle instruments of demand management were (a) economic pricing of energy to producers; (b) regulation of energy consumption of enterprises; (c) priority finance for energy rationalization; and (d) technical measures and publicity to encourage energy conservation. The demand management program appears to have been successful. Energy intensity has declined steadily since 1981. With the slowdown in GDP growth and milder winters, energy consumption has stagnated and actually declined by about 2% in 1983.

1.34 MVMT has introduced an audio frequency load management system for household space and water heating to a limited extent. However, because of the absence of cheap off-peak hydro or nuclear energy in Hungary and the need to reinforce distribution networks to supply the off-peak heating loads, this form of load management does not appear to be economically viable at present. There are probably opportunities for industrial load management and it is recommended that MVMT commission a study to investigate the technical and economic opportunities for load management.

1.35 Coal prices are set by the National Board for Materials and Prices in relation to the prices of coal and oil traded in Western Europe. Mining enterprises have been allowed to make losses rather than pass on their costs, although coal prices were increased in early 1984 to improve the finances of the industry.

1.36 The producer price of brown coal was about US$l.7/GJ (US$73/toe) in 1983, compared to the LRMC of brown coal of about US$2.0/GJ (US$85/toe) and US$2.6/GJ (US$110/toe) for coal imported from the West. Lignite was priced at about US$l.l/GJ (US$47/toe) compared to a long run marginal cost (LRMC) of about US$1.5/GJ (US$64/toe). Given the precarious financial situation of the industry, there is a case for increasing coal producer prices towards the level of LRMC. LRMC pricing would also encourage an economic level of coal demand and assist mining companies to invest in projects that are viable from the national viewpoint. However, should the cost of brown coal rise to the level of the c.i.f. price of imports, brown coal should then be priced at the c.i.f. cost of imports and its price should then follow the lower of LRMC or import cost. In such a case, it would be economic to import at the margin and expand brown coal production such that its LRMC was not greater than the cost of imports. Hard coal presently is imported at the margin and should be priced at the c.i.f. import price in equivalent convertible currency. It is recommended that the Government gradually eliminate the economic subsidies on the prices of coal and set prices in relation to the future economic cost of supply, which should be determined after the recommended studies for the BUkkAbrAny lignite mine, the brown coal mining projects and reduced Lias hard coal program have been completed. In order to assist in this process the Government has decided to carry out LRMC studies and efficiency audits at five year intervals, with the first are expected to be available in early 1986. In the intervening years prices can continue to be linked to changes in the prices of internationally traded steam coal.

1.37 Electricity tariffs are based on average accounting costs, whereas it is the LRMC that represents the economic cost of electricity. Tariffs on - 11 - average are about 70% of LRMC. Industrial and other enterprises pay tariffs that are between 76% and 96% of LRMC, but household tariffs are only 36% of LRMC. Some improvements could be made in the tariff structure, to bring it more in line with LRMC, e.g. by increasing demand charges and introducing new rail tariffs with demand or time-of-day charges. It is recommended that MVMT commission a study that would provide accurate estimates of LRMC and, in consultation with the relevant institutions, introduce these tariffs over a period of say, three years.

1.38 As with electricity, the economic cost of district heat is represented by the LRMC. The LRMC of heat produced in CHP plants is calculated net of the benefit of electricity production. Because of the structural imbalance of heat production capacity, the lack of a phased least cost investment program and other data limitations, the estimate of the LRMC of producing heat is subject to a wider margin of error than the LRMC of electricity. The LRMC of producing hot water was estimated to be about US$7.7/GJ and US$6.0/GJ for steam once the heat production capacity has been restructured. There are a large number of heat distribution systems, each with their own tariffs. Typically, residential tariffs are about 16%-25% of LRMC and industrial steam 57%-92% of LRMC. It is recommended that the Government carry out a district heating pricing study for Hungary to improve these rough estimates of LRMC and gradually raise heat tariffs to the level of LRMC.

1.39 Heat supplied to households is not metered. Consumers are charged according to the floor area of the dwelling. As the marginal price of heat is effectively zero, consumers have no incentive to conserve energy or reduce waste. Comparison of natural gas consumption, which is metered, and district heat consumption suggest that metering district heat would reduce heat consumption by about 30%. This would lead to a total annual saving of 170 thousand toe, or about 0.5% of the national gross consumption of energy. The net annual saving after the costs of metering have been taken into account would be about US$3.3 million. The Government is aware of the potential benefits of metering heat and proposes to meter hot water and install automatic space heating controls in new apartments. However, retrofitting existing apartments with heat meters would probably be economically justified. It is recommended that the Government review its heat metering policies and consider (a) retrofitting heat meters in existing dwellings; (b) the relative economics of automatic temperature controls versus meters; and (c) joint metering of district heat for both space heating and domestic hot water.

1.40 Although they have increased by 30-56% since 1979, household energy prices for all fuels except gasoline are deliberately set below economic cost for social and political reasons and to promote the substitution of other fuels for oil. Consumer prices are approximately the following percentages of economic cost: coal 31%, electricity 36%, district heat 16-25%, heating oil 50%, LPG 42%, natural gas 47%; whereas gasoline prices are roughly twice the international price. There appe rs some scope for residential energy conservation. Consumption per m of dwelling area is high compared to West European countries, considering the difference in household incomes and the high proportion of apartments in Hungary, which require less heat than other - 12 - building designs. Household energy price elasticities in Hungary have been shown to be significant.

1.41 The mission appreciates the political difficulties of raising household energy prices, especially since wages are low compared to the West. Expenditure on energy in 1981 was 3.4% of household income for two-income households and 6.2% for the economically inactive. Raising household energy prices to their economic cost without corresponding wage increases or reduced consumption of energy would result in Hungarians paying a larger proportion of their income on energy than in most countries. Nevertheless the mission believes that the savings in reduced energy imports and lower investment in energy supply arising from efficient pricing of household energy would be large. The Government is aware of the inconsistency between its energy demand management and household energy pricing policies and is committed to gradually phasing them out. However, the mission recommends that the Government should review the program for eliminating consumer energy price subsidies to see whether it could be speeded up, especially by compensating low income households through transfer payments (e.g. increased pensions) or by having higher prices of electricity, heat and gas above a basic level of consumption.

Summary

1.42 Table 1.2 summarizes the main issues in the subsectors and the mission's recommendations for addressing them. - 13 -

Table 1.2

Prwposed Stratewy for the Developmert of the Power & Coal Subsector

Issues Objectives Recammerdatioi Studies Priority

II. flE INlSrTllI8A4L FRAMUO(

A. Eoargy Sector Organization

(a) Autonmay of enterprises more Viable, efficient enterprises AltIxauh the energy sector is Review of energy sector Third apparent than real (para. with reasonable altoncmy ard generally operating well and organization. 2.08). appropriate size puwrsuig clear institutions are well managed, objectives. Gosrnnrent should take a (b) Potentially owrlappirg fresh look at the organiza- functions, particularly of tion of the enery sector to technical institutes (par. see whether there is scope 2.10). for small eccmies (para. 2.11).

(d) Enterprise directors lack security of tenure ( para. 2.09).

B. The Coal Subsector

(a) Possibly too many brown coal Viable efficient coal enterprises GCaernment huuld review Review of coal subsector Third mining carpanies and of appropriate size. organization of coal subsertor, organization. institutios. say in 1986, after the industry bas had time to assimilate the (b) Possible lack of coordination chages initiated in 1981 in project preparation and in (para. 2.28). coal subsector' s relations with Gorerimnat.

(c) N-nninirg activities might better be carried out by separate enterprises and separate accounts should be establisied for these activities (para. 2.28). - 14 -

Table 1.2

Proposed Strategy for the Developsert of the Power & Coal Subsector

Issues Objectives Recomnendationa Studies Priority

D. The District Heating Stbsector

District beat supply enter- Viable efficient energy supply Gaverrment should exmoine whether Government review of heat Second prises lack clear econanic enterprises with reasouable district beat subsector should supply subsector objectives, and report to autonaiy pursuing clear eccaimic be restructured as a nutber of organization. different ministries objectives. state enterprises reporting (paras. 2.32-2.33) to IpM (para. 2.34)

Other Organizational Issues

Power station emaming levels Enterprise efficiercy. WMT should critically review MMr review. Third appear high (para. 2.21). mrening levels in power stations to ascertain what econanies are possible in the future (para. 2.21).

Overall labor produictivity in Enterprise efficiency. Labor productivity should be Review by mrining enterprises. Ihird coal minirg appears low cotpared reviewed for future improvement to Western Europe (pam 2.30). (para 2.30).

TW's role in investment Enterprise atona'y and ecomay MV1MTshould be given greater Government review of energy Third planning is srmll (paras. efficieny. authority to initiate power sector organizations. 2.36-2.40). investsnert planning studies (para 2.40).

IV. PASr CCN&SwnHI AND)SPLY (IF PIzR, COALAND ESmRICr UEAT

E. Past Supply of Electricity

Consmwttion of electricity Savings in fuel ard future (a) )Wff should examine scope for ME loss reduction study. Third within power stations generating capaity. reducing power consumption of appears high (para 4.25). existing power stations.

(b) Poaer station designers should optimize station power consrsption using the econonic cost of electricity (para 4.25).

1t and LV distributicn losses Re&ce losses to an econcmic WH shluld carry aut loss WT loss reduction study. Third seem hi# (para 4.39). level. reducticn study andi isplerient its findings (para. 4.39). - 15 -

Table 1.2

Proposed Strategy for the Developtent of the Paor & Coal Subsector

Issu1es Objectives Recam2eniations Studies Priority

V. PR1ED CCNlUR ICN AND aWUft CF P(ER, CAL ANDDISRCT EAT

A. Forecast Consumption of Pawer, Coal and District Heat

Electricity demand forecasts Apropriate level of investnat. Covernment review of load Electricity demrd forecast First may be too higi (para 5.06). forecasts that wuld consider review. the effect of higher consmr electricity prices, charges to tariffs and industrial load nEngent (para 5.06).

B. Future Electricity Suply

Role of CHP in power generation Least-cost develqnmet program. CHP projects (irrluding Dwmseiti Governat to cailete studies First program (para. 5.21). extensicn) proably are priority to confirm justification and investments (para. 5.22). timing of earh CHP project in power investment prcgran.

Choice of powr-only investamt Least-cost develcptent prcgran. B[ikkhbr&by lignite-based power Gowrr¢et to ccxplete studies Secord (paras. 5.22-5.23). plant appears next priority to confirm this ard to prepare after Durmeti (para. 5.23). detailed feasibility studies. - 16 -

Table 1.2

Proposed Strategy for the Developqent of the Power & Coal Subeector

Issues Objectives Reccmexdations Studies Priority

B. Future Electricity Supply (cnrt'd)

Role of nuclear power (paras. Least-ost developent program. I ,09O K ruclear units Part of power generation 5.24-5.25). should be given a low planmirg stuiies. priority at present (para. 5.25).

M5an old CiP staticns that will Least-cost power progran. MAT diould study future role of Part of orgoiu power generati=n Third need to be retired or refur- old power station takirg heat plamirg studies. bished in 1990s (para. 5.27). suply requirents into accaont (para. 5.27).

Role of combined-cycle plant Least-cost power progran. Ecanamics of canbined cycle gas Part of argoing power generatial First (para. 5.30). turbine plant, with and without plamirg studiea. CHP aould be evabiated (para. 5.30). - 17 -

Table 1.2

Prxposed Strategy for the Development of the Poer & Coal Subsector

Issues Objectives Recamerdations Studies Priority

C. Future Coal S4>ply

lhe ecnmanic viability of the Eccranic coal developmet Goverset dshuld accelerate (a) Review of existing plans for First Lias progtram (hard coal) in program. its review of the Lias prgran cost-redckirg modifications. its original fonm is doubtful for possible cost savings (para. 5.37). ad evaluate other sources (b) Evaluatimn of tests and for supply of coke or ookidg studies for coke fran brown coal (para. 5.37). coal and operpit mind lignite.

There are too ney brown coal Least-cost developent progr. IpM shuld prepare a development (a) Depletion rate of existing First projects for possible inclusion plan (pare. 5.42). mines; in the investment prorm Priorities need to be set (b) partial replanoemt of brown (paras. 5.39-5.42). coal by lignite briquettes frmn ope-pit mines.

Timely developsent aid final Optimal developqext plan for mine IEi shold camiisicn feasibility Detailed feasibility study of First capacity of Wid&fbr&pj mine ard power plant. study (para. 5.43). uldchbrhny that would exaine undefined (para. 5.43). project cost ard inpleatation. - 18 -

Table 1.2

Proposed Strategy for the Development of the Pawer & Coal Subsector

Issues Objectives Recamendations Studies Priority

D. Future Supply of District Heat

Heat prodictici capacity needs Prodxction of district heat at (a) IpM commission a least-cost Least-cost investmnt progran First restructuring and investment least cost, taking economic investment program for the studies for main district heating priorities need to be set benefits of electricity prodtcticn districting heating sub- systems ard for the country as a (paras. 5.53-5.58). into accoumt. sector (para. 5.53). whole. First

(b) Undertake immediate investigation to identify Ad-hoc technical and economic potential operational savings studies. from small investments (para. 5.55).

(c) Review policy of comnectirg new consumers before heat production restructured ard review projection of district heat consuiption in relation to potential sibstitution by natural gas (para. 5.56).

(d) Consider using existing or rew gas tLrbines for heat producticn especially in ccrbiuied cycle steam power productim (pam. 5.57).

(e) It uuuld be risky to rely an mrslear district heating plants to restructure beat production (para. 5.58).

Custruction period for sane Quick realization of project (a) Technical re-evaluation of Technical studies related to First projects appears lcng benefits. Duiamenti project to see if feasibility study for Dunmnti (para. 5.54). constnrction time could be project. shortened (para 5.54).

(b) Use of discounted cash flow techniques to program investment (para 5.54). - 19 -

Table 1.2

Prposed Strateaj for the Developsent of the Pouer & Coal Subsector

Issues Objectives Recamiendations Studies Priority

VI. DD^D MOfNA T ANDPRICIN

A. Demnd Mnagemeit

Residential electricity load Ensure that the load mmenag t MM hould evaluate options ard, MV load managent study. Third nagement does not appear program is econanically if justified, implenent a load eccnomic, but load msnagaeast justified. n nt pxogran (para. 6.0Y). might be eccnomic for saae industries (paras. 6.03-6.0X).

D. Pricing of Coal

Coal prices are too low in Prices to enxourage econnmic use (a) Subsidies for coal to Coal pricing study based on Second relation to eccasaic costs and asndproducticn of ooal that would producers and consumers inestmert prcgran ard project the finarrial requirements of also improve the resaorce slwld be gradually reduced. studies. the industry (paras. 6.22-6.25). generaticn of the coal industry. (b) Coal prices to be set at their ecncmic cost (para. 6.25).

E. Electricity Tariffs

(a) Electricity tariffs are based (a) Prioes to enrcurage efficient Electricity tariffs should 1J L[MC tariff study, based Secorid on average accountirg oost use of electricity. reflect IUC, and tariffs to on investment ard operations rather than Ll!C (para. producers should reach the level planning models. 6.12). (b) Mobilization of resources of IRC over, say, 3 years (para. to finame investment. 6.40). (b) Tariff levels are about 70% of LIRC (para. 6.33).

A,^ - 20 -

Table 1.2

Proposed Strategy for the Developuent of the Power & Coal Subsector

Issues Objectives Recamnedatijos Stidies Priority

F. Pricirg of District Heat

District heatirg tariffs are Prices to eraiorage efficient Raise heat tariffs towards IRc Govrniaent heat L1*C pricing Second not based on IRC (para. 6.44). use of heat aid to mobilize (para 6.44). study. resources.

Household consumpti±c of Reduce waste of district heat. Meter district heat (para 6.45). Confinn benefits of metering First heat is not metered, and this district heat. encourages the wste of fuel used in producing it, especially oil and gas (para (6.45).

C. Household Prices of Power, Coal aid District Heat

(a) Housmold prices of poer, Prices to encourage efficient Goernment should review its Govenment review. First ooal, and heat are little use of energy, subject to program for phasing out e-rIr sure than 3(M of ecmanic ability of households to pay. price subsidies to see whether it cost (para 6.46). could be speeded up (para 6.52).

(b) Enargy cmsunpticn of housdeolds in Hungary is relatively high (pars 6.48).

nk - 21 -

II. THE INSTITUTIONAL FRAMEWORK

A. Energy Sector Organization

overview

2.01 The energy sector is under the jurisdiction of the Ministry of Industry (UpM). Within the ministry the National Energy Authority (OEGH), under the Secretary of State for Energy, a deputy minister, supervises and coordinates energy sector activities (Figure 2.1). The main energy supply institutions are the Hungarian Electric Power Trust (MVMT), the Hungarian National Oil and Gas Trust (OKGT), the coal mining companies and the municipalities engaged in district heat supply. There are also five agencies under IpM responsible for various aspects of energy planning, design, research and development and safety.

2.02 The electric power, coal and district heating subsectors are dealt with separately later in this chapter. The main functions and features of the other institutions referred to are summarized below (see Annex 1 for details):

(a) National Energy Authority (OEGH)

This has a professional staff of 30. It has four main departments, responsible respectively for short (one-year), medium (five-year) and long-term (20-year) energy plans; coordination of energy research and development and work on energy safety; supervision of the district heating activities of the municipalities; and guidance for the senior energy managers responsible for implementation of the energy conservation program in large energy-using industries.

(b) Hungarian National Oil and Gas Trust (OKGT)

OKGT controls virtually the whole oil and gas subsector. It comprises 23 state enterprises, employing about 50,000 people, whose activities cover oil and gas exploration, production, refining of crude oil, marketing of petroleum products, gas distribution, pipeline design and manufacture, and research and development. Hydrocarbon imports and exports, however, are handled by Mineral Impex, a subsidiary of the Ministry of Foreign Trade. Despite their separate legal existence, the individual enterprises of the trust function in practice like the district and operational subdivisions of international oil companies, reporting to operational directors of OKGT, who report in turn to OKGT deputy general managers. All major projects are designed, executed and financed by the central organization of OKGT. HUNGARY POWERAND COAL SUBSECTOR REVIEW EnergySector Organization

Councilof Ministers

Mk*ft ~of ~ ~ NatoalNatoatO Board NfI Xordbuct~ I- y-- tr

Secretarfy SkI Ofstate - Dowruopmfen for Energy ci

Energ

r ~----1

H-ungackion Hungarlan StateAuthorIty Engineerng k""Cnr t* Ekoctriccrflonal il Miningfor Energy rs" Corrpany for fo arwgy DAlpfn MunicOdRim EoetrITc G'osTaistn MsCainin Maonogement& of Energy Powe Stotion~& Rsac att Uf~hOIPd Pcy~qeTrus &OKGasTrutAsito EnergvSatety (EGI) NetworkrDesign (\EII)eKR (tA'SMT)(OI(GT) ~~~~~~~~~~(AEEF) (EROTERV) (~()((R

HeatSuppty carpmies ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~Woid0an-25273 - 23 -

This is an operating agency of IpM and works closely with OEGH. Its Energy Management Department, with 250 of the agency's 560 employees, is primarily responsible for enforcing the implementation in industry of the energy conservation program. It controls the issue of the permits required for the supply of the various forms of energy to large consumers; checks energy-consuming equipment for compliance with the prescribed efficiency standards; supervises and coordinates the work of the industrial energy managers; and collects national statistics of energy production, distribution and consumption. The Energy Safety Technology Department, with 200 employees, is responsible for the safety aspects of energy-producing and consuming activities, issuing licenses for the manufacture and installation of boilers and carrying out regular inspections of all operating boilers. It has separate sections for gas and oil production equipment, electrical safety, nuclear safety and materials testing.

(d) Institute for Energy (EGI)

This has some 850 employees engaged in research and development work on energy utilization, including studies related to the planning of energy utilization and the rational use of energy; technical-economic design of energy systems and equipment; coordination of industrial research on energy utilization; and maintenance and repair of energy-using installations. It operates like a state enterprise, deriving most of its income from work for industry at home and abroad on the design of steam-raising facilities, district-heating schemes, combined heat and power schemes, utilization of waste heat, refrigeration plant and water-handling and conservation. EGI is the agency responsible for supervising the implementation of the subprojects to be financed by the Bank through the energy rationalization facility of the Industrial Energy Diversification and Conservation Project.

(e) Engineering Company for Power Station and Network Design (EROTERV)

This is a state enterprise with 800 employees, including 220 graduate engineers. Its Technical Development Department carries out power system feasibility and planning studies in collaboration with AEEF (which provides the power demand data), under the general coordination of OEGH, which finances the long-term planning studies. The Design Department, where most of the staff are employed, undertakes engineering design of power stations, substations and networks. Its main customers are MVMT and its member enterprises, but its export business has been developing rapidly and accounts for about half of its income.

(f) Institute for Energy Research (VEIKI)

This also operates like a state enterprise, with 650 employees, of whom 25% are university graduates, mainly engineers of various kinds, but including mathematicians, physicists, chemists and economists. - 24 -

Its director is appointed by the Minister of Industry, as in the case of the other institutes, but, unlike them, for a fixed term of five years. Its research is mainly on the problems of electricity generation, transmission and distribution and of the industries manufacturing electric power equipment. It includes work on combustion engineering, mainly in connection with problems arising from the relatively low quality of Hungarian coal, water treatment for thermal power stations, stress conditions in high-voltage transmission equipment (VEIKI has the largest outdoor HV laboratory in Central Europe established in connection with the introduction of the 750-kV transmission lines); automatic control and protection; and computer engineering. 90% of its work is for MVMT and industry, and 10% for IpM and other Government bodies.

Sectoral Policies and Objectives

2.03 The institutional arrangements and organization of the energy sector have to be viewed within the context of national energy policies and objectives. These sectoral policies, in turn, cannot be considered in isolation from the Government's broader economic policies and strategy. The main feature of the latter is the economic management system introduced in 1968, the so-called New Economic Mechanism, designed to correct the major inefficiencies in the Hungarian economy and assist in its more effective integration into the world economy. The associated economic reforms suffered some setback between 1972 and 1978, partly in an effort to insulate the Hungarian economy from the unfavorable economic repercussions of the 1973/74 oil price increases, but have been resumed since 1979. The main objectives are: (a) restoration of external equilibrium through effective management of domestic demand and the use of foreign loans for high-priority and quick-yielding projects; (b) structural transformation to make productive units more efficient and internationally competitive in convertible currency markets; and (c) maintenance of living standards, subject to some reduction of consumption levels in the short term. At the same time, maintenance of full employment and equitable income distribution remain important social objectives, which create problems in the achievement of the restructuring changes.

2.04 To achieve the restructuring objectives, the system of physical economic planning which existed prior to 1968 has been abolished, although the state retains ownership of the means of production. The national economic plans no longer have physical input allocations and output targets, but are intended to provide an indicative framework of Government policy guiding all enterprises. The object is to give enterprise managers greater autonomy in formulating their own plans within the framework of the national plan, as specifically provided for in the law of 1977 on state enterprises interest rates, selective credit provided through the banking system, wage regulation, exchange rate policy and price policy.

Role of Government

2.05 The institutional reforms associated with the policy of decentralization (para. 2.03) led to a substantial reduction in direct - 25 -

operational interventions by ministries in the enterprises' decision-making. The main changes affecting the energy sector have been: (a) the merging (January 1981) of the three previous ministries for industry into a single ministry with only about half the staff of the original ministries; (b) the transfer of price setting from the ministry to the National Board for Materials and Prices (NBMP); (c) greater freedom for enterprises in setting wages within approved national scales, accompanied by the downgrading of the Ministry of Labor to a Labor Office; (d) the decision to break up some of the large horizontal industrial trusts, including the coal mining trust, in order to increase efficiency and competition; and (e) the decision, effective January 1, 1983, to allow directors of state enterprises to appoint their own deputy directors (previously appointed by IpM), although IpM keeps the right to appoint and dismiss the directors themselves.

2.06 Despite these changes, the Government retains a large measure of control over activities in the energy sector. This is exercised primarily through OEGH, but often central agencies play important roles in the sector, as described below:

(a) National Energy Authority (OEGH)

OEGH is responsible for ensuring that the agencies and enterprises in the energy sector are operated in accordance with the objectives of the national economic plan and national energy policy. It plays a key role in energy planning, including the preparation of energy balances, with the object of ensuring adequate and reliable energy supplies. It collaborates with other ministries on energy matters through two committees for which it is responsible: the Energy Management Committee, which meets every two weeks under the Secretary of State for Energy to review the general energy situation and the state of the energy program, including the energy conservation program; and the Energy Policy Committee, which meets half-yearly to review longer-term issues of energy policy. In addition, OEGH is represented on the Economic Committee, under a Deputy Prime Minister, which covers the management of the whole economy and reviews the energy situation periodically.

(b) National Planning Office (NPO)

NPO provides the basic economic data for the preparation of energy plans and coordinates them with the plans of other sectors. It also reviews proposed major energy projects and monitors their implementation.

NBMP is responsible for determining producer and consumer prices for all fuels and electricity, although it discusses its proposals with the agencies concerned (e.g., MVMT in the case of electricity) before submitting them for the formal approval of the Council of Ministers. The resulting producer prices are close to international prices, but consumer prices to households are heavily subsidized to maintain living standards in the face of increased world energy prices. The - 26 -

Government accepts the desirability in principle of eliminating these subsidies, but regards this as essentially a long-term objective.

Issues in Sector Organization

2.07 The energy institutions reviewed, from the IpM downwards, are well organized and managed, with well qualified and competent staff. The quality of work in the various technical institutes is high. The arrangements for the coordination of activities within the sector, and between the various institutions, are also satisfactory. However, there are a number of issues in sector organization, which in the view of the mission, the Government should examine to determine whether there is scope for raising efficiency above its already high level.

2.08 There is a dilemma between the Government's need to regulate industries that are near monopolies and strategically important and the general official policy of encouraging greater autonomy of state enterprises. Government regulation of pricing in the energy industries is nearly universal and it is not uncommon for Governments to approve large energy investments. The issue is the mechanisms by which the Government seeks to influence the enterprises and the degree to which it is involved in their day-to-day affairs. Changes such as the recent grant to enterprise directors of the right to appoint their deputy directors and greater freedom in setting wages (para. 2.05) are a significant step towards greater enterprise autonomy. However, the power subsector remains centrally planned (paras. 2.37 to 2.41) and the Government exercises tight control over investment by taxing away profits to make the enterprises dependent on the state banking system for investment funds. In the mission's view, the Government should examine whether the enterprises should be given more responsibility for planning and investment programming, subject of course to review and approval by IpM and NPO. A corollary of this is that they should be permitted to retain a sufficient share of their profits to finance a reasonable proportion of their investment program from their own resources.

2.09 Similarly, the IpM retains the right to appoint enterprise directors, who have no security of tenure (with one exception) once appointed, since the Minister is also free to dismiss them. In our view, the directors of state enterprises should be given greater security of tenure and independence by appointing them for fixed terms, e.g., five years, as is the case at present for the director of VEIKI. In this connection, there is merit in a current proposal in Hungary that vacancies for these positions should be publicly advertised when they occur so as to attract as many qualified candidates as possible. Consideration should be given to adopting the French system of basing such appointments on a "program contract", which would define the objectives of the enterprise on a firm, well-understood basis, while delegating full authority to the director to determine how to achieve them. Directors would have security of tenure, but IpM would have the right to dismiss them if they failed to meet objectives stated clearly under the "program contract". - 27 -

2.10 The present functions of the major technical institutes in the sector (AEEF, EGI, EROTERV and VEIKI) seem to have resulted largely from a process of ad hoc accretions over the years. AEEF, for example, was originally responsible only for electrical safety, but now covers the whole range of energy safety, from conventional boilers to nuclear power, as well as being responsible for the energy management and conservation program and the collection of national energy statistics. There can be no guarantee that the resulting division of functions amongst these institutes is optimal. There would also seem to be some danger of unnecessary duplication and overlapping of functions (e.g., between AEEF and EGI). Although these institutes appear well run and produce work of a high technical standard a case could be made for reviewing the present functions and responsibilities of AEEF, EGI, EROTERV and VEIKI in the energy sector, to determine whether any reallocation of tasks is desirable in the interests of greater economy and efficiency, and the elimination of any unnecessary duplication.

2.11 The combination of the responsibility for energy conservation and energy safety in a single agency (AEEF) is unusual. The arrangement has certain advantages; for example, an inspector carrying out a boiler inspection for safety can check at the same time that the operator has the necessary fuel permit, and also that the boiler complies with the prescribed performance standards, thus economizing in the use of limited technical expertise. Nevertheless, this dual responsibility of AEEF seems to be the result of historical accident rather than logical necessity and is not self-evidently the most desirable arrangement in present circumstances. It would appear worth the Government establishing whether the advantages of combining energy conservation and non-nuclear energy safety in one organization outweigh the disadvantages and if they do not, implementing the necessary institutional changes. Although the mission considers that the energy sector is generally operating well and that institutions are well managed, it considers that the Government should take a fresh look at the organization of the sector, particularly (a) the degree of autonomy of enterprises; (b) security of tenure of directors; (c) energy safety; and (d) the role of the technical institutes, to see whether there is scope for small economies.

B. The Electric Power Subsector

Hungarian Electric Power Trust (MVMT)

2.12 The electricity supply industry, like the oil and gas industry (para. 2.02), but unlike the coal mining industry, is organized as a trust, the Hungarian Electric Power Trust (MVMT). A trust is a legal entity which consists of a group of enterprises, and itself operates on the model of an enterprise. MVMT has 22 member enterprises, comprising 11 power stations, a power station maintenance company, a national transmission company, six distribution companies and three other companies (for finance of investment, civil engineering work and erection of power station equipment)(Annex 1.1). Under the Electricity Act of 1962 (Annex 1.7), MVMT has the responsibility for ensuring an adequate and continuous supply of electricity at a satisfactory standard of service. It supplies about 71% of the country's electricity requirements, the remainder consisting of imports (25%) and generation by - 28 - captive industrial plants (14%). In addition, its power stations satisfy 80% of the heat requirements of municipal district heating systems and heat purchased by industry in the form of process steam or hot water.

2.13 MVMT is under a general manager, who is appointed by IpM. Until recently, IpM had appointed the two deputy general managers, but since the beginning of 1983 the general manager has the right to appoint them, in accordance with the policy of increasing the autonomy of state enterprises (para. 2.05). The general manager is advised by.a board of directors, comprising the deputy general managers, the directors of the member enterprises and representatives of the power industry trade union, the Hungarian Socialist Workers' Party and of the workers employed by MVMT. The Board authorizes the annual and five-year plans and considers major investment proposals, but it has no right of decision, and the general manager is not obliged to accept its advice. The MVMT organization chart is shown in Annex 2.2.

2.14 Like all state enterprises, MVMT is subject to state supervision and control, in accordance with the law on state enterprises. As the supervising ministry for the subsector, IpM, through OEGH, is responsible for ensuring that MVMT and its enterprises are operated in accordance with the objectives of the national energy policy. All major investment proposals and investment plans have to be submitted to IpM for approval, and also to NPO. Subject to these requirements, MVMT is supposed to enjoy autonomy in the conduct of its affairs.

2.15 MVNT's main lateral links are with other agencies in the energy sector. With OKGT and the coal industry the links are contractual, relating to the supply of fuel for MVMT's power stations, and the same is true of the municipalities to which MVMT power stations supply heat for district heating. There are also close working links with EGI on district heating schemes, with EROTERV and VEIKI for engineering design and research work and with AEEF.

The Enterprises

2.16 According to the law on state enterprises (Annex 2.8), the member enterprises of MVMT are supposed to have a large measure of independence and control over their own affairs, particularly as regards investment, technological development, employment policy, pricing, sales and procurement, organization and financial and commercial arrangements. To some extent, such independence is difficult to achieve in practice because the technology of electricity supply requires central coordination, e.g., in generation operations. Enterprise directors are appointed by the general manager of MVMN, although, in an attempt to give them more freedom of action, they have recently been given the right to appoint their own deputy directors (para. 2.05). The directors have also been given greater freedom to determine wages and salaries (within the nationally prescribed scales) and award bonuses as incentives to efficiency. Consequently, the enterprises function essentially, not as independent companies, but as operating units of MVNT. Judging from visits made by the mission to several power stations, the national transmission company and a distribution company, the enterprises are well organized and managed with competent and well qualified staff. - 29 -

Organizational Issues in the Power Subsector

2.17 The autonomy which MVMT is supposed to enjoy in theory is strictly circumscribed in practice. In particular, despite its responsibility under the electricity law for ensuring an adequate and reliable supply of electricity, in the key areas of load forecasting and system planning the lead is taken by IpM. Since investment decisions are one of the major determinants of power utility performance, we examine this issue in greater depth later (see paras. 2.36 to 2.41). IpM also has the right to appoint and dismiss the director of MVMT and the Government should consider adopting an alternative procedure (para. 2.09) for appointing directors of institutions in the energy sector, i.e., fixed-term appointments, based on a "program contract" should apply to MVMT.

2.18 The autonomy of the member enterprises of MVMT is also more nominal than real. This is due partly to institutional factors (the centralization of key functions in MVNT and the reservation of major investment decisions to IpM and NPO), and partly to the fact that technically the enterprises cannot operate independently since they form part of an integrated system. Moreover, as suppliers of energy, the distribution companies have little influence over their own prices, since these are set nationally by NBMP. MVMT, although well managed and with well qualified and competent staff, appears slightly unwieldy. The question arises whether some of the existing member enterprises should be hived off in the interests of greater autonomy and efficiency. Although MVNT appears to be operating well it would seem worth examining the extent to which savings could be made through modest institutional reforms, such as hiving off the ancillary enterprises concerned with investment financing, civil engineering and power equipment intallation.

Nuclear Power

2.19 Apart from the Paks nuclear power station, which is a member enterprise of MVMT, there are two specialized institutions with nuclear energy responsibilities, which are not members of MVMT. The first is the National Atomic Energy Commission (OAB), an advisory body under the Council of Ministers, which is concerned with the peaceful uses of nuclear energy, nuclear safety criteria, environmental aspects of nuclear energy, nuclear safeguards and international relations in nuclear energy. Its members, all nominated by the Council of Ministers, include senior representatives of interested ministries and the directors of various national scientific institutes, and its chairman is the Chairman of the State Commission for Technical Development. It has a small permanent office with a staff of 15. Its main regulatory function relates to the application of the safeguards agreement for Paks concluded with the International Atomic Energy Agency (Hungary is also a signatory of the nuclear non-proliferation treaty). Its only licensing powers relate to nuclear research reactors. The issue of licenses for nuclear power stations is the responsibility of IpM, although the consent of OAB is required.

2.20 The other specialized agency concerned with nuclear power is AEEF (para. 2.02). This has a Nuclear Safety Department, which is responsible for the safety assessment of nuclear power station designs, equipment and completed stations, and for advising IpM on the issue of construction and - 30 - operating licenses for nuclear power stations. AEEF's responsibility for nuclear safety, in addition to its own functions, seems inappropriate. It is generally considered undesirable to vest this reponsibility in an agency concerned with energy demand and supply. The Government's view is that OAB bears the necessary independence and ultimate responsibility for nuclear safety. However, in the mission's view the Government should review these arrangements. In particular, to avoid any potential conflict of interest, and ensure objectivity in determining nuclear safety issues, during the review of energy sector organization (para. 2.11), the Government should investigate whether responsibility for nuclear safety should be transferred from AEEF to an independent agency, e.g., a strengthened OAB, which would be answerable directly to the Council of Ministers, like the mining safety inspectorate.

Manpower and Training

2.21 MVMT and its member enterprises employ about 38,000 people (1982). This is about 5% below the 1975 figures but is projected to rise to 39,500 in 1985 (see Annex 2.3). The 1982 figure implies that each MVMT employee serves, on average, 109 customers, which compares with a 1979 figure for Romania of 103 and a 1981 figure of 123 for a well run power utility of comparable size in a European developed country. A comparison of the respective numbers employed at generating stations in the MVMT and the reference European system is much less favorable for MVMT, for which the ratio of MW of installed capacity per employee is 0.34, compared with 2.06 for the comparable system. Part of the reasons for this big difference is the much larger number of relatively small generating units in the MVMT system (about 100, with an average capacity of 52 MW, against only 45 in the comparable system with an average capacity of 206 MW). 1/ Even allowing for this, the magnitude of the difference suggests that there may be over-manning at the MVMT stations. 2/ On the other hand, each MVMT employee in transmission and distribution serves on average 222 customers, while the comparable figure for the reference utility in 1981 was 168 customers per employee. Since power stations employ about 40% of MVMT's workforce, it is recommended that MVMT review the manning levels in power stations to determine whether there is any scope for economies.

2.22 The respective shares of manual and non-manual workers in the industry's work force are expected to remain relatively stable at 65% and

1/ The staffing level in about 80% of MVMT's capacity is less than 2 employees/MW, but very high ratios for small power stations as high as 10 employees/MW lower the average. Despite indications of overmanning at power stations MVMT has difficulty in attracting shift workers because of the high marginal tax rates that would be applied to shift allowances. 2/ The difference is not nearly so marked in the case of MVMT's most modern station, the Paks nuclear power station, which has 1,400 staff (although this may increase), for 1,760 MW, or 0.79 employees/MW, compared with 0.68 employees/MW for a comparable nuclear station in the reference European utility. - 31 -

35%. MVMT makes medium-term (5-year) and long-term (15-year) manpower plans, and maintains close contact with universities, regular schools and the various specialized schools and institutes to make sure its requirements of various skills are widely known. There have not so far been any particular problems in recruiting the various categories of staff required, although the three-shift system at power stations is not popular with young people.

2.23 Salary and wage scales are set nationally and range from a minimum of 1,350 Forints (USt34)/month for the lowest paid worker to a maximum of 15,000 Forints (US$390)/month for the director of an enterprise at the top of the directors' scale (see Annex 2.4). However, adjusting these salaries to reflect their purchasing power parity for consumer goods would roughly increase them to US$63/month and US$727/month respectively 1/.

2.24 Training appears to be well organized. MVMT and its member enterprises have 72 training workshops for skilled workers throughout the country and also provide specialized training for skilled workers with the necessary aptitude and experience to become technicians. Twenty-two of the specialized secondary schools in the national educational system provide special classes in subjects specifically related to electricity supply. The only significant problem concerns the training of operating personnel for Paks nuclear power station, which has to be done abroad. About 1,000 are undergoing training at present, mostly in the USSR and German Democratic Republic (GDR), but the power systems in these countries do not correspond very closely to those in Hungary. MVMT would like to import a nuclear power station simulator to train its staff in Hungary, but is still seeking a source of finance for the convertible foreign exchange cost of about US$4.5 million.

C. The Coal Subsector

Overview

2.25 The organization of the coal industry has undergone several changes in recent years. Prior to 1981, the industry was organized as a trust, along the lines of OKGT and MVMT. The coal trust was abolished at the end of 1980, as part of the policy of breaking up some of the large horizontal trusts to increase autonomy and efficiency. Its member enterprises were regrouped into eight regional coal-mining companies and a mining equipment supply company. The coal mining companies range in size from Matraalja, the largest, which produced 7.3 million tons of lignite in 1982, to Dorog, the smallest, with an output of 0.5 million tons of brown coal in 1982. Non-mining activities, such as the manufacture of mining and other equipment, civil engineering work and housing construction, are important for most of the coal-mining companies. Countrywide, about 40% of their workers are engaged in non-mining activities, which generate about 30% of the industry's gross revenues. The mining

1/ Based on 1975 data from the International Comparison Project. See World Bank "World Tables - 3rd Edition" 1983. - 32 - equipment company specializes particularly in the manufacture of roof supports, both power and hydraulic, and supplies most of the needs of the underground mines in Hungary, as well as exporting. The organization of a typical mining enterprise is shown in Annex 2.5.

Central Institutions

2.26 Following the abolition of the coal mining trust, the independent coal companies decided that they needed to enter into some collaborative arrangements to serve their common interests. Initially, they established two organizations, a Coordination Office and an Information Service, but since the beginning of 1983 these have expanded to four, as follows:

(a) The Mining Association

This has been in existence only since the beginning of 1983. Its purpose is to promote the mutual interests of its members and assist them in their operations and development through studies and advice. It has sixteen members, including the eight coal-mining companies. The directors of the member enterprises comprise the board of directors. The Association's central office, with a staff of 60, of whom 35 are university graduates, including 28 engineers, is financed by annual contributions from the member enterprises in proportion to their wage bills.

(b) The Mining Information and Computer Technical Service

This provides a central information service for the mining industry and coordinates activities relating to the use of computers. It also provides a central transport service to the Mining Association and Mining Technological Service. It has a staff of 150, including 40 university graduates. Its board of directors consists of the directors of the member enterprises. It is financed partly by its members in proportion to their wage bills, and partly from payments for its services. It collects technical and economic data on the industry, which are summarized in a statistical yearbook given restricted circulation. The computing services department is trying to overcome the relative backwardness of the mining industry in computerization, attributable to the previous depressed state of the industry and consequent lack of finance for acquiring computers. It proposes to make a start by installing small computers in member companies but is still seeking a source of finance.

This bureau, with 23 staff at present (11 university graduates) handles only large coal contracts, involving more than one supplying mine. These represent 85% of total coal sales of 26 million tons, coal mining company direct sales accounting for the remaining 15%. It also collects statistics on coal production, sales and stocks. It is financed by its member companies in proportion to their wage bills. - 33 -

(d) The Mining Technological Service

This was established by the coal mining companies and mining equipment company to carry out studies, research and development, and advise the companies, on all aspects of mining operations, including the application of foreign mining technology in Hungary. It also maintains a central store for materials and parts, which supplies about 20% of the requirements of the coal mining companies. It has a staff of 45 (including 25 engineers and technicians) which it is planned to be increased to 70. It is financed by its member companies at present in proportion to their wage bills, but the intention is that by 1986 it should be self-supporting from fees charged for its services. An interesting feature of its procedural rules is that they provide specifically for the holding of joint sessions with the Mining Association as necessary to avoid too frequent meetings for its board of directors, comprising the directors of the member enterprises.

2.27 Central Mining Development Institute (KBFI). This institute was formed in 1979 by merging two previous institutions into a single organization responsible for research and development for all aspects of mining from exploration to utilization of mineral resources. It also prepares development plans for the mining industry, and designs large mining projects, collaborating with the coal mining companies and other institutions in the energy sector, such as EGI, VEIKI and MVMT. It is a member of the Mining Association and the Mining Information service. It has a large staff of nearly 1,100, including 365 university graduates, two-thirds of them engineers of various kinds. It finances its own activities from fees for its services. Its director is appointed by IpM, which also plays a large part in determining the research and development program. Its export and import activities relating to mining equipment are conducted through a state foreign trading company. The sale of knowledge or designs resulting from its work, however, is handled by a special company, GEOMINCO, set up by the mining industry, whose chairman is the director of KBFI.

Institutional Issues in the Coal Subsector

2.28 Since the coal industry was reorganized as recently as 1981, it may be too soon to make firm judgements about the effectivenes of the new organization. However, a number of potential issues seem to exist. In particular:

(a) While the abolition of the previous coal trust was logical, given the geographical dispersion of the mines and the diverse mining conditions, it is not clear why so many separate companies were formed in the brown coal area west of Budapest (Dorog, Oroszlany, Tatabanya and Veszprem). A reduced number of West Hungarian brown coal producers would appear to facilitate the investment planning and decision-making process and improve technical services to individual mines;

(b) There has been a proliferation of institutions set up by the coal-mining companies to serve their common interests (para. 2.24). - 34 -

This creates the danger of overlapping and duplication of activities amongst these institutions and between them and KBFI. It also makes excessive demands on the time of the directors of the coal-mining companies, who also serve on the boards of directors of these new institutions;

(c) The newly-formed Mining Association has still to establish itself as the normal channel of communication between the mining industry and the Government, which sometimes deals with the industry through the Association, but also deals directly with the individual companies. This made it difficult at the beginning for the Association to fulfill its coordinating role. These problems have been recognized and measures are being taken to redress them;

(d) Mining companies often prefer to undertake complex feasibility studies and project preparation themselves rather than utilize the services of the common institutions or KBFI. Although mining companies are responsible for undertaking project feasibility studies and project preparation, they should utilize the services of KBFI and other expert institutions to improve project preparation, unless adequate project preparation can be conducted in-house;

(e) It appears that the non-mining activities have been taken on by the mining companies mainly for historical/social reasons during the time of shrinkage of the mining industry (many of these industries have close linkages in the mining industry, e.g. the manufacture of essential inputs). In the interest of better efficiency, it may however be better that these activities be carried out by separate, specialized companies which could also regroup some of these activities into larger units. As an immediate first step, separate accounts should be prepared for the non-mining activities; and

(f) As elsewhere in the energy sector, the autonomy of the coal-mining companies is more apparent than real, especially in view of the levels at which the Government controls prices. The producer prices set by NBMP allow the industry to make only modest average profits, and some companies make losses. As a result, 85% of the investment in the industry has to be met by state loans or grants. This severely restricts the financial independence, and hence autonomy, of the coal-mining companies.

Once the reorganized coal industry has had time to assimilate the changes initiated in 1981, say in 1986, the mission recommends that the present organization be critically reviewed. Such a review should pay particular attention to (a) the merits of combining the western brown coal companies into a single West Hungarian brown coal company to improve investment planning and decision-making, and provide better technical services to the individual mines; (b) defining more clearly the respective roles of the mining companies; the Mining Association and KBFI in project preparation and decision-making: and (c) establishing separate accounts for the non-mining activities of the coal mining companies and then determining whether, in the interest of efficiency, they should be transferred to separate, specialized companies, possibly with some regrouping into larger units. - 35 -

Manpower and Training

2.29 Total employment in the coal-mining enterprises is 48,000 (non-coal activities excluded). No projections of future manpower plans and requirements are available. The average age of the underground work force has been rising - from 37 in 1965 to 43 in 1982 - but efforts to recruit younger men are being intensified through higher pay, preferential allocation of housing and exemption from military service (for underground workers signing a 10-year contract). The wages compare very favorably, for example, with those in the electricity supply industry (US$3,600-3,900 per year for a skilled underground face worker compared with US$1,500-2,400 for a skilled electricity worker). Details of employment and salaries in a typical mining company are shown in Annex 2.6.

2.30 The labor force of the mining companies is high. During the mission, the visited mines gave the impression of being efficiently operated and the productivity figures presented by the mining companies for underground workings were very comparable to mines in western Europe. However, the productivity drop from the level of the mine workings to the overall company level is much higher than in western Europe. It is recommended that the overall productivity in the industry should be closely observed for possible future improvements.

2.31 Training facilities in the industry appear to be adequate. There are two training schools, financed by the coal-mining companies, for underground workers, but there is said to be a shortage of suitable applicants for admission. The university at Miskolc has a mining engineering faculty. Mining engineering as a profession had fallen out of favor during the period of decline in the coal industry's fortunes in the 1960's and 1970's. Only 10-20 mining engineers have been graduating each year, which seems insufficient to strengthen the coal-mining industry.

D. The District Heating Subsector

2.32 The major part of the heat production capacity is owned and operated by the Hungarian Electric Power Board (MV!T). This includes both combined heat and power (CHP) units and boiler plants on power station sites. In addition, there are CHP plants operated by industry which provide process heat for internal use and in some cases, supply heat to the public network or neighboring factories. There are also a number of heat production stations owned and operated by municipalities. Municipal heat production stations tend to consist of boiler plants without power generation. Heat distribution is usually the responsibility of municipalities, although there are a number of heat distribution pipelines operated by MVMT and industry, particularly for steam.

2.33 Heat distributors are in most cases constituted as local government, e.g. megye, departments, often in combination with water supply and sewerage. Some of the distribution institutions lack adequate technical capacity, e.g., to distribute steam, or to carry out maintenance. In contrast to the - 36 - electricity and gas supply industries, the ethos of heat suppliers is often more the provision of heat as a social service, than the economic supply of energy. Heat distributors tend to lack autonomy, such that their finances usually are not separated from other activities of local government. Moreover, the lines of authority from the heat distributors to the Government are not clear since heat distributors report to local councils and then ultimately to the Ministry of Housing, Public Construction and Urban Development. On the other hand, they are responsible to IpM for technical matters.

2.34 There are a number of major institutional issues in the district heating subsector which, in our view, need careful consideration. These include: (a) the appropriate role of MVMT in heat distribution; (b) the degree of involvement of local government in heat supply; and (c) whether control of heat distribution should be the responsibility of IpM. Based on the preliminary findings of the mission, there appear to be grounds for strengthening the autonomy of heat distributors by constituting the regional heat supply companies as state enterprises. In order to achieve consistency in energy policy among the subsectors, transferring the control of the heat enterprises to IpM would appear advantageous, in view of the high priority the Government attaches to energy policy. A major reorganization of the heat supply subsector would cause disruption in the short term and local issues would need resolving. Before such a reorganization begins, the Government would need assurance that the short-term costs would be justified and that the optimal organization would result. It is therefore recommended that the Government commission a study to enquire into the organization of the heat supply subsector, with a view to restructuring it as autonomous state enterprises reporting to IpM.

E. Subsector Planning

Institutional Responsibilities

2.35 The planning of the three subsectors, power, coal and district heat, is in principle interrelated and is consequently linked to the overall planning of the energy sector. There are good reasons for this. First, the choice of fuels for power generation is not independent from the requirements of other users. The brown and black coal burned in power stations is usually the low-grade fraction remaining after the needs of premium customers have been satisfied. Natural gas consumed in power stations is mainly the residual between fixed supply and the needs of consumers placing a higher value on the gas. Second, power generation is the largest user of coal, accounting for almost 50% of total coal consumed on a heat equivalent basis. Any major investment in power generation is therefore likely to have a major impact on the coal industry. Third, CHP projects to supply district heat influence overall investment in power generation. Fourth, there are potential interfuel substitutions on the demand side, e.g., district heat supplied from CHP stations is a substitute for coal and natural gas.

2.36 Compared to most other countries the institutional arrangements for planning the power and district heat subsectors are unusual. The planning of - 37 - major investments, i.e., feasibility studies, is the responsibility of IpM. Within IpM, OEGH is the agency with formal responsibilities for investment planning in the energy supply industries. OEGH has only 30 staff and undertakes little analytical work itself. In the case of power and heat supply, the consulting engineering companies EROTERV and EGI are responsible for carrying out technical and economic studies of design options. Broadly, EROTERV is responsible for large-scale generation, transmission and distribution, while EGI specializes in CHP and district heating. MVMT is not involved formally in investment planning, other than to provide data, although in practice, MVMT is consulted during the planning process.

2.37 An investment proposal prepared by IpM for either the power, coal or district heating subsector is discussed among interested parties such as NBH, SDB, MVMT and the Mining Association under the auspices of NPO. If the project is large, such as a major power station or a new coal mine, a Government Commission, chaired by a Deputy Prime Minister is formed to review the proposal. Membership of the Commission includes the Minister of Industry and the President of NPO. The final proposal is then sent to the Council of Ministers for approval, after which the execution of the project commences. Once the project has been prepared, the enterprise, e.g., MVMT, assumes responsibilities for detailed engineering and procurement.

2.38 The energy planning process appears to be successful in achieving reasonable consistency among the plans of each of the subsectors. The exhaustive review and consultation process enables a consensus to be reached that has the support of all parties, but at the cost of delays in decision-making and the possibility that a compromise among vocal or influential lobbies may not necessarily result in least-cost investments from the national viewpoint. Delays in taking decisions may not be important, provided that decisions can be quickly adapted if circumstances, e.g., energy demand, change and that the planning process is begun sufficiently early, as appears to be the case, so as not to delay project completion.

2.39 We have some reservations about the degree of involvement of IpM in power subsector investment planning. OEGH has a regulatory and review function which is especially important because the technical expertise it possesses is not available elsewhere within Government Ministries. There is a clear role for OEGH in ensuring that: (a) the investment programs for each energy subsector are compatible; (b) these programs represent the most economic path of development; (c) projects are implemented on time; (d) projects embody appropriate technology and scale; and (e) the international aspects of energy planning are in accord with Government policy. However, there may be a conflict of interest between the role of OEGH as a regulatory agency and as an agency responsible for formulating the major decisions affecting the energy sector. Moreover, it is difficult for OEGH to carry out subsector planning at the necessary level of detail when it has also the responsibility for aggregate sectorwide planning.

2.40 Unlike almost all other power utilities in the world, MVMT's role in planning its investment is small. This reduces the autonomy of the enterprise substantially since investment costs are almost outside of its control. It weakens the authority of the utility's management since it is responsible only for implementing construction and then operating a plant, although investment - 38 - decisions affect future fuel and staff costs, as well as the cost of the investment itself. The issue as to which institution should have prime responsibility for power subsector planning appears of sufficient importance to warrant further investigation. Consideration should be given to whether MVMT should be required to initiate the preparation of an indicative long-term power development program and project feasibility studies itself, although it might wish to continue to contract this work to EROTERV and EGI. The Government has retained central planning for power generation, unlike coal or oil and gas, because of the size of power investments in relation to the economy. However, it is not clear whether the quality of investment decisions would deteriorate if they were initiated by MVMT and reviewed by OEGH. After the next major power investments are taken, which will establish a long-term power investment strategy, there would appear to be a prima facie case for the Government to review the institutional procedures for power system planning. This review would define the relationship between sectoral and subsectoral planning and establish whether the present procedures are the best solution to meeting the objectives of enterprise autonomy and national economic efficiency. It is therefore recommended that the Government review the present arrangements for power subsector planning, with a view to giving MVMT greater authority to initiate investment planning studies, while retaining OEGH's roles as regulating agency and for preparing national investment programs for the energy sector. - 39 -

III. COAL AND OTHER ENERGY RESOURCES

A. Coal Reserves

Coal Reserves

3.01 Hungarian coal reserves of lignite, brown coal and hard coal are fairly large compared to the present level of production (2.8 billion tons of reserves versus 26 million tons of annual production, equivalent to 108 years lifetime). 1/ However, the average calorific value (2,200 kcal/kg) is low, and expressed in terms of internationally traded steam coal the reserves are equivalent to only 900 million tons, or about 750 million toe. There are three different types of coal: lignite, brown coal, and hard coal, occurring in several basins in West, South and North Hungary (see Map IBRD 18191). Table 3.1 gives an overview of the coal reserves for the three different types of coal. A more detailed description of the coal reserves is given in Annex 3.

Table 3.1

Hungarian Coal Reserves

Mining areas under Outside existing exploitation mining areas Total Reserves Reserves Lifetime /1 Reserves Lifetime /1 Million Million (Million Tcns) (Years) (Million Tons) (Years) Tons Toe

Lignite 139 /2 17 /3 1,28 13) 1,424 239 Brown Coal 456 28 476 31 891 304 Hard coal 178 59 332 110 510 207

Total 773 3) 2,093 81 2,825 750

Source: KBFI/Central Office of Geology.

/1 At present annual production rates. /2 98 million tons open pit (Visonta) (13 years) and 41 million tons underground (Varpalota). /3 Weigited average of Visonta (13 years) and Varpalota (41 years).

3.02 With the exception of the lignite reserves at B-ukkabrAny and Torony, all coal basins are being exploited. Due to the country's coal-mining tradition of 200 years, reserves in general are well known and no further

1/ All reserve figures in this report refer to proven, mineable reserves only. - 40 - general exploration work is necessary. Only development drilling is required for new projects and mine expansions. Such drilling is presently undertaken for the Lias hard coal in South Hungary 1/, and for some of the Eocene brown coal in West Hungary. 2/

3.03 The amount of proven mineaoblereserves is sufficient for considerable expansion of coal production. In absolute terms as well as in relation to the present production rate, reserves are highest for lignite (1.4 billion tons, equivalent to 170 years lifetime). Reserves are also high, relative to the present production rate for hard coal (170 years). Brown coal reserves, although in absolute terms 1.7 times higher than hard coal reserves, are the most limited in relation to the present production rate (60 years). The remaining life of the reserves of lignite and brown coal would be more than adequate if these fuels were chosen for the major power investments required in the 1990's. In terms of energy equivalent, the coal reserves are distributed as follows; lignite 32%, brown coal 40%, and hard coal 28%.

Coal Quality

3.04 The quality of the Hungarian coal presents a serious restriction for large expansion of the production, in particular for brown coal and hard coal which is to be mined underground under relatively difficult conditions. For the surface mineable lignite, the low heating value of only 1,500 to 1,800 kcal/kg, is compensated by relatively favorable mining conditions allowing for large-scale open-pit mining. For all coal types, the sulphur and ash content is relatively high (2-4% and 20-30%, respectively). Washing could remove a portion of the ash but practically no sulphur. The relatively high sulphur and ash contents present a serious limitation for the direct use of Hungarian coal in households and by smaller industrial consumers near urban centres.

B. Other Energy Resources

Crude Oil

3.05 The presently known exploitable reserves of crude oil are estimated to be about 20 million tons, with current production of 2.0 million tons per year (t/a) (40,000 bbl/day) representing about 20% of domestic requirements. In addition, about 0.7 million toe/a of natural gas liquids are recovered. Hungary spans an area of which 70% has good prospects for the discovery of petroleum; however, because of the complex geology, discoveries are expected to be relatively small in size, and would require extensive geological work and costly drilling during both the exploration and production phases. Bank staff, together with OKGT, have evaluated the known petroleum prospects and estimate that there is an 80% probability that up to 130 million tons of

1/ Maza South. 2/ Aika, Bokod, Dudar/Balinka. - 41 -

producible oil and 400 billion m3 of gas can be added to the resource base. 1/ At the 1982 level of production the known reserves would last, at least, for another decade, although production from existing fields (with enhanced oil recovery) would fall to about 1.4 million t/a in 1990 if new fields are not developed. However, production from identified fields and new discoveries would mean that annual production in 1990 would remain at the present level of 2.0 million tons. Most Hungarian crude oil is a light, low sulphur crude similar to the North Sea, Nigerian or Libyan crude.

Gas

3.06 'Proven and recoverable reserves of natural gas are estimated at about 120 billion normal cubic meters (m 3 ), of which 90 billion m3 (72 million toe) are pipeline grade. The remainding 30 million m3 is of lower quality, consisting of methane with up to 83% of inert gases, mainly C02 . This lower quality gas is beginning to be used for power generation at the Tisza power station, mixing with higher grade gas and local industrial users. A program of deep drilling and exploration in new areas is being undertaken to discover new reserves and there are good chances that considerable additions to the reserves will be achieved. Current net production of natural gas is about 6.5 billion m3 per year (5.2 million toe) and production is planned to remain around this level for at least the next 15 years. Hungary has supplied about 60% of its domestic gas requirements and imported the remaining 40% from CMEA countries, mainly the USSR. In addition to domestic natural gas, which yields mainly methane but also some LPG, additional quantities of LPG and town gas are produced from naphtha reformers. It is planned to convert the remaining naphtha reformers to natural gas, which is more economical and will enable naphtha imports to be reduced. The first priority attached by the Government to the use of natural gas is in industries as a feedstock, or where other fuels are unsuitable, e.g., for ammonia and fertilizer production; the second priority is a substitute for oil in household and communal uses, as well as industry. Remaining quantities would be used for electricity generation and heat production.

3.07 The costs of finding and exploiting new petroleum reserves are substantially lower than the imported cost of oil and gas. The Bank has estimated that exploration and appraisal costs amount to about US$16/toe (1983 prices) and development and production costs to amount to US$20/toe and US$6/toe respectively. The total average economic cost therefore amounts to US$42/toe, compared to international import prices of US$215/toe for crude oil and US$173/toe for natural gas. 2/

Hydropower

3.08 Hungary's prime remaining hydropower potential is about 880 MW, located at multipurpose sites in the north near the Czechoslovakian border. A

1/ See Staff Appraisal Report, Hungary - Petroleum I Project (Report 4896-HU) (1984). 2/ See Petroleum I Project SAR. - 42 - project was prepared for exploiting this potential, but because of a shortage of funds it was postponed indefinitely, although there have been recent reports of the project being revived. A number of smaller hydroelectric sites exist on the Drava River near the border with Yugoslavia and near Csongrad on the Tisza River. The Drava scheme is apparently being developed by the Yugoslav authorities with the agreement of the Hungarian Government. The Csongrad scheme is a multipurpose project with power generation a secondary objective, but is reportedly not a high priority at present.

Uranium

3.09 Details of uranium resources and production are not published. An open-pit mine exists in the south of the country and production is exported to the Soviet Union.

Geothermal Water

3.10 Abundant reserves of geothermal water exist, but to our knowledge have not been quantified. The Hungarian energy statistics give production in 1982 as 1.3 million toe. Production increased by 7% between 1980 and 1982 as projects to substitute geothermal water for hydrocarbon fuels were implemented as part of the Energy Action Program. No detailed breakdown of the end-use of geothermal water is available, but most appears to be used in swimming pools or spas, with smaller amounts being used to heat greenhouses and to supply district heat to roughly 300 apartments. Expansion of geothermal utilization is limited by the low temperature of the water (typically 600 C) and high calcium content, which fouls pipes. However, the Government is taking some measures to increase the use of geothermal water. Research is being undertaken by KBFI to address the fouling problem. OKGT is carrying out research to establish whether hot water could be obtained from dry oil/gas exploration holes. A high thermal gradient exists in Hungary and it is hoped to produce water with a temperature of 60-700 C for use in the agricultural sector.

Biomass

3.11 In 1982 consumption of firewood and forestry wastes was 547 thousand toe and a further 530 thousand toe of crop residues was also consumed. Out of a total consumption of commercial firewood of 340 thousand toe, consumption, 286 thousand toe (84%) was consumed by households and the remainder mainly by agriculture and charcoal producers. - 43 -

IV. PAST CONSUMPTION AND SUPPLY OF POWER, COAL AND DISTRICT HEAT

A. Development of Energy Policy

4.01 Energy development and policy since 1970 may be characterized by three periods. The first was during 1970-1976 when economic development was based on capital intensive investment. Such investment was also energy intensive. Cheap oil and gas imports from the Soviet Union encouraged the substitution of these fuels for coal. The result was a sharp decline in coal production of over 20%, in terms of energy content, between 1970 and 1976. Domestic coal accounted for only 27% of gross domestic consumption of commercial energy in 1976, compared to 42% in 1970. The Government believed that the increase in oil prices that occurred in 1973 would not be sustained and Hungary's CMEA trading relations insulated it from higher energy prices. This period saw little change in energy prices in Hungary above the level of the mid 1960's. The production capacity of the electric power and district heat supply industries became increasingly dependent on oil. Energy consumers invested in plant that was both energy intensive and reliant on oil.

4.02 Changes to the Bucharest Principle in 1976, which linked the prices of energy exported from the Soviet Union to lagged world prices, ushered in the second period of Hungary's recent energy development. This was a period of transition from energy intensive development and growing import dependence to the major policy changes arising from the acute balance of payments crisis of 1979. During this second period projects came on stream that were based on oil and gas, e.g. power stations, which were unsuitable for conversion to other fuels for technical reasons. Domestic energy prices for both producers and consumers remained unchanged in nominal terms at the levels of the 1960's until 1975-76, when producer prices were more than doubled for oil and increased during 1975-76, particularly for coal (15%), heating oil (20%) and gasoline (48%).

4.03 The third period began in 1979. Hungary came to face the increased energy prices of the early 1970's at a time when the second round of world oil price increases was occurring. Energy demand had been growing faster than projected in the 5-Year Plan, so that the Economic Committee of the Government prepared a set of measures to physically limit energy consumption during the winter of 1978-79, which in event were not implemented. The balance of payments crisis necessitated that the growth of energy imports be curbed. In addition, the shortage of liquidity would not enable investment to expand energy supply to meet the growing demand. It became clear to the Government that measures would have to be introduced to restrain the growth in energy consumption. The Energy Action Program announced in December 1980 for the 1981-85 5-Year Plan was a major shift in policy, from the acceptance of continuing growth in energy consumption and supply, towards explicit policies for energy demand management, conservation and fuel substitution. Principle instruments of this program were: (a) reform of energy prices; (b) priority - 44 - credits for energy conservation and rationalization i.e. import substitution; and (c) licenses for energy consumption above defined limits, coupled to the dissemination of information on conservation and import substitution possibilities. These policies led to the rapid substitution of natural gas for oil since additional gas supplies become available at an import price substantially less than that for fuel oil. In addition, some energy supply projects were canceled or postponed, e.g. the Bicske and Nagymaros power stations, and investments were initiated to increase production of coal, oil and gas.

4.04 The shift in policy which took place during 1979-1980 was a recognition of the need for structural adjustment. Structural adjustment in the energy sector may be defined as the adaptation of energy producers and consumers to the changes to world energy prices that took place in the 1970's, the impact of which was delayed until about 1979 through the mechanism of the Bucharest principle. There are three broad objectives of structural adjustment in the energy sector:

(a) reducing energy imports so as to improve the balance of payments by means of energy conservation and by developing indigenous energy resources, where these are economically justified;

(b) improving overall productivity in the energy producing industries and the consuming sectors through energy conservation and the acquisition of modern technology; and

The changes in policy since 1979 and the commitment of the Government to structural adjustment in the energy sector explain much of the recent trends in consumption and investment in the power, coal and district heating subsectors.

B. Overview of Energy Consumption and Supply

Total Energy Consumption

4.05 As illustrated in Table 4.1, the growth of gross domestic consumption of energy has corresponded to the three phases in the development of energy policy. During the first two phases (1970-1978), it grew rapidly at an average annual rate of 4.0%. However, growth was slower during the first phase (3.3% p.a. during 1970-75) then the second phase (5.1% p.a. during 1975-78) despite slower economic growth during the second period. The reasons for the implied decrease in energy intensity between 1970 and 1975, followed by roughly constant intensity thereafter are not entirely clear, but were probably due to oil and gas substituting for coal which has a lower end use efficiency, the economic reforms of 1968 which promoted economic efficiency, and the higher energy efficiency of investment embodying modern technology. - 45 -

4.06 The re-orientation of policy towards demand management after 1978 has had a dramatic effect on energy consumption. Growth in gross domestic consumption has been minimal and consumption actually decreased in 1983 for the first time in recent history. Since 1980 there has been a sustained decline in energy intensity such that intensity has declined at an average annual rate of 1.9% p.a. since 1978. This decline in intensity and stagnation in energy consumption has been a consequence of: (a) the slowdown in economic growth; (b) the effect of energy price increases in 1980, 1981 and 1982; (c) the implementation of energy conservation and demand management policies; and (d) mild winters. Since 1978 economic growth has been achieved without increases in energy consumption. By contrast, the GDP elasticity was 0.99 in the preceeding 1975-78 period and 0.54 during 1970-75.

Table 4.1

Consumption of Energy in Relation to Real GDP and Population, 1970-1981

Gross Domes- tic Energy GDP /1 Energy Intensity Per Capita Consumption (Billions Population (toe per million Consumption Year ('000 toe) /3 of Forints) ('000) /3 Forints) (toe)

1970 23,068 462.7 10,322 49.8 2.23 1975 27,181 626.8 10,501 43.4 2.59 1978 31,593 729.8 10,660 43.3 2.96 1983 /2 31,578 801.5 10,700 39.4 2.95

Average Annual Growth Rate (%)

1970-1975 3.3 6.3 0.3 -2.7 3.0 1975-1978 5.1 5.2 0.5 - 4.5 1978-1983 -0.0 1.9 0.07 -1.9 -0.1

Source: AEEF/OEGH, World Bank

/1 At 1981 prices. 77 PreliminaryFigures. /3 Includes non-commercial energy. - 46 -

4.07 As shown in Table 4.2, Hungary's intensity of energy consumption continues to be substantially higher than that of the middle-income and industrial economies, indicating that the potential for improving efficiency, through rationalization of consumption and conservation, is still substantial. However international comparisons of energy intensity, especially between CMEA countries and market economies, are complicated by the difficulties in establishing GDP on a comparable basis. Although the energy intensity in Hungary is high, per capita consumption is low, compared to the European industrialized countries, but high compared to other middle income developing countries. Specific energy consumption remains high for major industries when calculated on a consumption per physical unit of output basis. For example, aluminum smelting in Hungary required 15,600 kWh per ton of aluminum product in 1982, compared to 13,500-14,300 kWh/t for plants elsewhere.

Table 4.2

Hungary's Energy Consumption and its Relationship to that of Some Middle-Income and Industrial Countries /1 (toe)

Per Capita Energy Consumption Energy Per Capita per US$1000 GNP Consumption Income (US$)

Japan 0.323 2.840 8,810 Denmark 0.335 3.985 11,900 France 0.349 3.330 9,550 Switzerland 0.390 3.245 13,920 Austria 0.402 3.425 13,920 Turkey 0.404 0.538 1,330 Belgium 0.412 4.497 10,920 Spain 0.429 1.881 4,380 Italy 0.437 2.292 5,250 Portugal 0.455 0.997 2,180 Chile 0.470 0.795 1,690 Greece 0.478 1.894 3,960 U.K. 0.595 3.750 6,320 Jordan 0.617 0.753 1,180 Ireland 0.605 2.545 4,210 Hungary /2 1.430 2.757 1,930

Source: World Development Report, 1981; and mission estimates.

/1 Data are for 1979. /2 Hungary data are for 1980. GNP and GNP per capita are from 1983 World Bank Atlas. - 47 -

Structure of Energy Demand and Supply

4.08 Increasing imports of oil, gas and electricity resulted in net imports steadily increasing from about 34% of gross domestic consumption of energy in 1970 to a peak of about 48% in 1980. Since 1980, import dependence has decreased to about 45% in 1982, a consequence of increased domestic production of both commercial and non commercial energy (see Table 4.3). Composition of energy imports in 1983 by fuel was officially estimated to be crude oil 39%, natural gas 22%, electricity 16% (fossil fuel equivalent of net imports), oil products 9%, coal 6%, coke 5% and household coal products 2%. Together these amounted to 14.5 million toe (620.8 PJ), compared to estimated production of 15.3 million toe (654.8 PJ). Considering domestic production of energy, coal accounted for the greatest part which amounted to 37% in 1983 (6.6 million toe), although this had declined both relatively and absolutely from 56% (9.0% million toe) in 1970. The decline in coal production was largely offset by increased production of natural gas (2.9 million toe in 1970, increasing by 77% to 5.1 million toe in 1983) and NGL (0.21 million toe in 1970, rising to 0.73 million toe in 1983) which together increased from 20% of energy production in 1970 to 33% in 1983. The production of renewables also increased during the period by 47% to an estimated 2.9 million toe in 1983. Primary electricity amounted to 3.3% of total production in 1983, compared to less than 1% in earlier years, because of the commissioning of the first Paks nuclear reactor and increased imports from the Soviet Union.

Energy Balance

4.09 A summary of the 1981 balance is shown in Table 4.4 Industry consumed the greatest proportion of final energy, accounting for about 43% in 1981. The household and services sector consumed an additional 37%. This picture changed slowly during the 1970's. In 1970 industry consumed 45% and the household/services sector took 33%. This change in shares reflects the relative decline of heavy energy intensive industry in GDP and rising household incomes and low energy prices to households, as well as increased ownership of automobiles and the growing role of the service sector in GDP. Coal accounted for the largest share of domestic energy production (40%), followed by natural gas and natural gas liquids (33%), crude oil (12%) and renewables (geothermal, gas biomass and hydro) (15%). Imports of energy were almost as large as domestic production and amounted to 46% of gross supply, compared to 55% for domestic production. Imports consisted of crude oil and petroleum products (58%), natural gas (22%), coal, coke and briquettes (14%) and electricity (6%, on a fossil fuel equivalent basis). Energy consumption by sector is described in Annex 4.1. - 48 -

Table 4.3

Outline of Energy Balances 1970-82 (toe million)

Gross Supply 1970 1975 1980 1981 1982

Production 15.92 15.46 17.05 17.10 17.67 Imports /1 8.49 12.12 16.20 15.43 15.47 Primary Exports (0.05) (0.06) (0.02) (0.02) (0.02) Stock Decrease (0.59) (0.43) (0.44) (0.07) (0.18)

Total Available 23.78 27.10 32.78 32.44 32.94

Of which Commercial /2 22.18 25.21 30.54 30.10 30.52

Conversions & Distribution Losses (5.41) (6.48) (7.53) (7.63) (7.89)

Net Supply Available /3 16.76 18.73 23.01 22.47 22.63

Secondary Exports (0.70) (0.37) (1.02) (0.71) (0.87)

Net Domestic Consumption /3 16.06 18.36 21.99 21.75 21.76

Consumption by Sector /3

Agriculture & Water 0.94 1.55 1.80 1.81 1.79 Mining 0.51 0.45 0.59 0.58 0.54 Industry 7.23 8.73 9.95 9.60 9.42 Construction 0.29 0.37 0.41 0.38 0.36 Transport & Communications 1.70 1.57 1.54 1.49 1.42 Public Utilities 0.06 0.06 0.06 0.05 0.05 Household & Services 5.24 6.05 7.57 7.75 8.14 Non Energy Use 0.50 0.65 0.50 0.49 0.45 Balancing Item (0.41) (1.07) (0.44) (0.40) (0.41)

Total Consumption of Commercial Energy 16.06 18.36 21.99 21.75 21.76

Source; OEGH/AEFF, "Energia Gazadaikoddsi Statisztikai Evk6nyv 1982".

/1 Electricity imports are net and converted to fuel equivalent at average thermal efficiency for the year. /2 Commercial energy excludes production of non-marketed renewables, i.e., geothermal water, agricultural waste, and some firewood. /3 Commercial energy only. - 49 -

Table 4.4

Summry Eneg Blance, 1981 /1 (toe million)

Secondary Energy Prinry Energy Coal Petroleum Manufactured Oil Gas Others Products Products Heat Electricity/3 Gases Total

Gross Supply

Production 6.82 1.94 4.84 2.76 - 0.73 /1 - - - 17.10 Inmorts 0.99 6.78 3.16 - 1.03 1.43 - 2.05 - 15.47 Exports (0.01) - (0.01) ------(0.02) Stock Decrease (0.10) 0.16 (0) 0.00 (0.03) (0.08) - - - (0.07)

Total Available 7.70 8.87 8.00 2.76 (0.99) 2.08 - 2.05 - 32.95 Of kihich Camerical 7.70 8.87 8.00 0.39 0.99 2.08 - 2.05 - 30.52

Coversion /2

Petroleun Refiniu - (8.85) (0.05) - - 8.54 (0.20) (0.02) - (0.58) Briquettirg (0.47) - - - 0.57 (0.11) (0.01) (0.00) - (0.03) Cdoe Ovens (0.84) - (0.02) - 0.64 - (0.01) (0.05) 0.09 (0.13) Powr & Heat Production (4.41) - (4.34) (0.05) (0.07) (2.38) 4.49 0.67 (0.22) (6.28) Power & Heat Distribution - - - - _ (0.12) (0.43) - (0.55) Others (0.08) - (0.14) (0.02) 0.09 (0.03) (0.00) (0.00) 0.16 (0.02) Net Supply Available 1.89 0.02 3.4 0.32 2.22 8.10 4.15 2.27 0.03 22.50 Secanary Exports - - - - (0.01) (0.70) - - - (0.71) Net Daamstic Cmoumpti /2 1.89 0.02 3.44 0.32 2.21 7.39 4.15 2.27 0.03 21.79

Consumptio by Sector /2

Agriculture 0.03 - 0.07 0.02 0.02 1.39 0.09 0.19 0.00 1.81 Minixe 0.01 0.02 0.27 - 0.05 0.07 0.07 0.13 0.00 0.58 Industry 0.35 - 2.33 0.01 1.24 1.58 2.70 1.08 0.30 9.60 Services 0.11 - 0.08 0.01 0.02 1.32 0.30 0.18 0.05 2.01 Household & Ccamunal 1.38 - 0.09 0.28 0.91 2.55 1.00 0.69 0.15 7.66 Non Energy - - - - 0.02 0.47 - - - 0.49 BaLancirg Iten 0.01 - - - - 0.01 - - (0.42) (0.41)

TOM 1.89 0.02 3.44 0.32 2.21 7.39 4.15 2.27 0.03 21.79

Source: AEEF/CEA, (Arri 4.7)

/1 Raws nd colunis may not add to totals because of rouxnirg errors. 77 Commrclal enrgy anly. 7T Electricity inports and hydro generation conerted to toe at average efficierxy in thental pwer generation. - 50 -

C. Past Trends in the Consumption of Coal

Consumption of Coal

4.10 Because Hungary could import oil and natural gas at concessionary prices from the Soviet Union, the authorities promoted the use of these energy products to the detriment of coal. As shown in Table 4.5, in physical quantities, as opposed to energy content, the consumption of coal declined only slightly between 1970 and 1982 by 4.9%, from 29.9 million tons in 1970 to 28.4 million tons in 1982. In terms of heat equivalent, coal consumption declined much more, declining by 21.8%, from 10.2 million toe in 1970 to 8.0 million toe in 1982. This fall in average heat content was mainly due to low-grade lignite forming a greater proportion of the coal mined and to the effects of increased mechanization in the underground mines, in particular for brown coal. The consumption of lignite increased from 4.7 million tons in 1970 to 8.4 million tons in 1982, as the Gagarin power station was completed yielding an average annual growth rate of 4.9%, or 3.5% p.a. in energy equivalent. In contrast, the consumption of hard and brown coal declined for reasons described below.

Table 4.5

Consumption of Coal, 1970-1982

Growth Rate (% p.a.) 1970 1975 1980 1982 1970-75 1975-80 1980-82 '000 tons

Hard Coal 3,893 3,156 3,249 3,338 -4.1 0.6 1.4 Brown Coal 18,735 14,816 14,121 15,059 -4.6 -1.0 3.3 Lignite 4,725 6,837 8,473 8,393 7.7 4.4 -0.5 Coking Coal -2514 1,808 1,695 1,618 -6.4 -1.3 -2.3

Total 29,872 26,617 27,538 28,408 -2.3 0.7 -1.6

'000 toe

Hard Coal 1,496 1,202 1,091 1,155 -4.3 -1.9 -2.9 Brown Coal 6,260 4,760 4,261 4,530 -5.3 -2.2 -3.1 Lignite 881 1,119 1,369 1,325 4.9 -0.3 -1.6 Coking Coal 1,534 1,110 1,026 959 -6.5 -1.6 -3.3

Total 10,193 8,191 7,747 7,969 -4.3 -1.1 -1.4

Source: AEEF/OEGH "Energia Gazdaikodasi Statisztikai Evkonyv" (Energy Economy Statistical Yearbooks). - 51 -

4.11 The consumption of coal, both directly and in the energy conversion industries, declined steadily during the period 1970 to 1982, but the rate of decline was substantially higher for direct consumption (-5.0% p.a.) than for conversion (-0.7% p.a.). As Table 46 shows, the most significant decline was in power and heat production outside the public utility, MVMT, where coal consumption declined by about 1.0 million toe, or 60%, between 1970 and 1982. This sector includes part of the industrial boiler fuel market where competition from natural gas and oil on price and quality has been especially severe. 'Consumption has continued to decline since 1980, despite the introduction of price and other measures to encourage the substitution of coal for hydrocarbons, probably because of the comparatively young age of the boiler stock, which was converted from coal to oil/gas in the mid 60's and 70's and financial constraints to replacing boilers that are not time expired. Consumption by coke ovens declined by 20% between 1970 and 1982, reflecting the fortunes of the steel industry and a tendency to import coke during the 1970's to compensate for the decline in the production of coking coals in Hungary.

4.12 The household/communal sector was the largest final consumer of coal outside of the energy industries, accounting for 19% of all coal consumption in 1982. Consumption fell steadily during the period 1970-80. Government measures to promote the use of coal in this sector, e.g. by encouraging communal coal-fired boilers, have been successful in reversing the decline in consumption. Between 1980 and 1982, coal consumption by households increased by 13.5% to a total 1,346 thousand toe and the consumption of communal services (e.g. schools, hospitals) by 20.0% to 167 thousand toe. Final consumption by other sectors is comparatively small and has continued to decline because of past price differentials and quality factors. For example replacement of coal locomotives by diesels and railway electrification resulted in coal consumption in the transport sector declining from 800 thousand toe in 1970, to 81 thousand toe in 1982. Details of the consumption of coal and coal products are given in Annex 4.2

Consumption of Coal Products

4.13 Concomitant with the decline in the consumption of coal between 1970 and 1981, the consumption of coal products declined as well (Table 4.7). About 94% of briquettes was consumed by the household and communal sector. Despite some decline during the first half of the 1970's, consumption of briquettes by households achieved an increase in 1981 of 8.9% above the 1970 level as a result of policies to promote the use of coal. However, this increase was offset by declines in other sectors, so that the total consumption of briquettes fell slightly by 3.5% between 1970 and 1981. Coke consumption increased by 1.3% p.a. during the period 1970-75 and then declined so that in 1981 it was 4% below the 1970 level, reflecting the fortunes of the iron and steel industry. - 52 -

Table 4.6

Consumption of Coal by Sector 1970-82 (Primary Energy Basis) (toe '000)

1970 1975 1980 1982

Intermediate Consumption

MVMT 3,114 3,557 3,738 3,889 Other power & heat 1,632 937 742 662 Briquetting 573 405 466 546 Lignite drying 143 87 82 78 Coke ovens 1,010 876 853 810 Gas works 58 - - -

Subtotal 6,530 5,862 5,881 5,985

Final Consumption

Industry & mining 669 543 382 348 Household & communal 2,146 1,332 1,325 1,513 Other 849 455 161 123

Subtotal 3,664 2,330 1,868 1,984

Total Consumption 10,194 8,192 7,749 7,969

Source; AEEF/OEGH, "Energia Gzzdalkodasi Statisztikai Evk6nyv".

Table 4.7

Consumption of Coal Products, 1970-1981 (toe '000)

Rate of Growth (%) 1970- 1975- 1980- 1970- 1970 1975 1980 1981 1975 1980 1981 1981

Briquettes 901 772 870 852 -3.0 2.4 -2.1 -0.5 Dry Lignite 134 85 79 79 -8.8 -1.3 -0.9 -4.7 Coke 980 1,047 1,002 937 1.3 -0.9 -6.5 -0.4 Other Coal Products 56 47 42 41 -3.2 -2.5 -1.2 -2.7

Source: AEEF/OEGH, ibid. - 53 -

D. Past Trends in the Consumption of Electricity

4.14 Consumption of electricity by final consumers increased from 14.7 TWh in 1970 to 28.5 TWh in 1981, but its rate of growth declined from 7.3% a year between 1970 and 1975, to 4.9% a year and 1.4% a year during the periods 1975-1980 and 1980-1982, respectively (Table 4.9). Correspondingly, consumption of electricity per MVMT consumer also increased at a declining rates of growth (Table 4.8). Furthermore, although the rate of economic growth declined from 6.3% a year for the period 1970-1975 to 3.7% over the next five years, and to 2.5% between 1980 and 1981, the elasticity of national demand for electricity to real GDP increased from 1.16 between 1970 and 1975, to 1.32 between 1975 and 1980, and then declined slightly to 1.28 between 1980 and 1982.

Table 4.8

Electricity Consumption MVMT, 1970-1981

GrowthRate (x) 1970 1975 1980 1982 1976-75 1975-80 18-82 1970-82

Number of Consumers 3,146,241 3,572,257 4,003,304 4,164,418 2.6 2.3 2.0 2.4

Electricity Sold /1 14,140 20,067 25,680 27,412 7.3 5.1 3.3 5.7

Average Consurtion 4,494 5,617 6,415 6,582 4.6 2.7 1.3 3.2 per cowsmer /2

Source: MKMW

/1 Final coiumption by MM consmmrs ((Wh). /2 kWh/per comsumer. - 54 -

4.15 The trends are a consequence of the changing sectoral pattern of national electricity consumption. The growth of electricity consumption by main consumer class summarized in Table 4.9 shows that the agricultural and household sectors had the highest rates of growth, followed by the transport and service sectors. The rate of growth was the lowest for the industrial sector, averaging about 3.8% a year between 1970 and 1982. During this period the sectoral shares remained virtually unchanged for all except the household and industrial sectors. As shown, the share of households increased from 20% in 1970 to 31% in 1982. In contrast, the share of the industry declined from 59% in 1970 to 47% in 1982. The decline in the share of industrial consumption was a consequence of the shift in the structure of industrial production away from energy intensive heavy industries, e.g. metallurgy, towards less energy intensive activities. The declining real prices of electricity to households, together with rising incomes, stimulated growth in this sector.

4.16 Concomitant with the increase in the elasticity of demand for electricity to GDP, the intensity of electricity consumption increased as well, from 47.9 kWh/l,000 Forints in 1970 to 52.0 kWh/l,000 Forints in 1981 (at 1970 prices). As summarized in Table 4.10 below, this increase occurred in all except the industrial sector, whose intensity of electricity consumption declined from 65.8 kWhIl,000 Forints in 1970 to 51.0 kWh/l,000 Forints in 1981, largely due to the decline in the growth of the output of the energy-intensive industries. Most of the increase in the intensity of electricity consumption in the other sectors would probably be accounted for by the adoption of more modern technology, which is often electricity-intensive and in a few cases, by the substitution of electricity for oil, e.g., railway electrification.

Consumption of Electricity by Households

4.17 The total consumption of electricity by households has grown at declining growth rates, from 12.9% p.a. during the period 1965-70 to 8.4% p.a. in 1980-82 (Table 4.11). Most of this growth has been accounted for by increased consumption per consumer, which grew at an average rate of 7.6% p.a. during the period 1970-82. The growth rate in the number of residential consumers has been less than 3% since 1965 and only 2% p.a. between 1980 and 1982. This reflects the low growth rate of population (Table 4.1) and the high level of electrification in Hungary, since 98.8% of houses had public electricity supply in January 1983. The average consumption of electricity per household consumer is relatively low by European standards. This is probably due to the prevalence of district heat, gas and coal for space and water heating, and LPG and gas for cooking, since these end-uses account by far for the greater part of domestic energy requirements. However, levels of appliance ownership are high for a developing country. In 1980 there was one refrigerator for every 3.4 persons compared to one for every 9.7 persons in 1970; one washing-machine for every 3.3 (one for every 5.6 person in 1970) and one TV set for every 3.9 persons (one for 5.8 in 1970). While some electricity is used for space heating, the relatively small average size of dwellings in Hungary 1/ compared to other European countries with a similar climate limits the maximum consumption of electricity.

1/ See Table 6.13. - 55 -

Table 4.9

National Electricity Consumption by Sector 1970-82

1970 /1 1975 1980 1982 1Gb (Z) (Gw)h) (I TUNW-71) (G-w) (%

Agriculture, forestry and water m 922 6 1,666 8 2,185 8 2,409 8 Mining 1,196 8 1,315 6 1,479 6 1,546 5 Metallurgy 2,889 20 3,490 17 3,882 15 4,014 114 Ergineerirg 1,288 9 1,526 7 1,817 7 1,841 6 Buildirg materials 624 4 880 4 1,126 4 1,099 4 Chemicals 1,973 13 2,724 13 3,548 13 1,636 6 Light irdustry 1,128 8 1,517 7 1,683 13 1,636 6 Food products 619 4 904 4 1,155 4 1,261 4 Other industry 92 1 146 1 140 1 127 -

Total 8,613 59 11,167 53 13,351 50 13,440 47

Ccnstruction 177 1 300 1 358 1 359 1 Transport & cmaimmications 794 5 1,218 6 1,488 6 1,564 5 Trade 12 - 28 - 21 - 22 - Services 18 - 74 - 118 - 264 1 Cammal & household 2,975 20 3,186 15 7,352 28 8,720 31 Others - - 1,951 9 177 1 190 1

National Total 14,707 100 20,905 100 26,529 100 28,504 100

Sourre: AFEF/CEDHibid.

/1 1970 data are not strictly comparable to later years.

Table 4.10

Intensity of Gross Electricity Consumption by Sector, 1970-1981 (kWh per Ft '000 of GDP, 1970 prices)

1970 1975 1980 1981

Agriculture 10.5 15.7 18.8 18.6 Industry 65.8 56.8 53.9 51.8 Construction 5.6 6.2 6.3 6.3 Transport/Communication 21.8 25.9 27.1 26.8 Public Works 29.7 29.9 34.6 34.6

ALL SECTORS 47.9 48.6 51.5 52.0

Source: Mission estimates - 56 -

Table 4.11

Consumption of Electricity by Households, 1960-1982

Total No. Consumers Consumption Year Consumption Dec. 31 per Consumer (GWh) ('000) (kWh)

1960 548 2,041 269 1965 990 2,498 396 1970 1,817 2,846 638 1975 3,186 3,251 980 1980 5,020 4,675 1,366 1982 5,899 3,821 1,544 1983 6,400

Average Rate of Growth (% p.a.)

1960-65 12.6 4.1 8.0 1965-70 12.9 2.6 10.0 1970-75 11.9 2.7 9.9 1975-80 9.5 2.5 6.9 1980-82 8.4 2.0 6.3 1982-83 8.5

Source: MVMT

E. Past Consumption of District Heat

Consumption

4.18 The gross consumption of district heat increased at 8.6% p.a. during the period 1970-75, and 6.4% during 1975-80, but declined slightly in 1981 (Table 4.12). In 1981, district heat accounted for 8% of final energy consumption. The proportion of heat sold to industries has been declining, from 78% in 1970 to 55% in 1981. Heat sold to households has been growing rapidly at 19.5% p.a. during the period 1970-75 and 11.0% p.a. during 1975-80, so that in 1981, it accounted for 35% of heat sales, compared to 17% in 1970. District heat accounted for 37% of the heat consumed by industry in 1981. For residential and commercial consumers, the proportion of district heat in total heat supply increased sharply from 46% in 1970 to 79% in 1981. - 57 -

Table 4.12

Gross C nsimpticzof Heat Supplied by District Heating Networks, 1970-1981 (TJ)

Anrmal Growth Share (%) Rate (X p.a.) Sector 1970 1975 1980 1981 1970 1975 1980 1981 1970-75 1975-80 1980-81

District Heat

Irlustry 30,714 39,473 47,529 44,619 78 66 59 55 5.1 3.8 -6.1 Residential 66,544 15,977 26,974 27,779 17 27 33 35 19.5 11.0 3.0 Commercial 2,135 3,977 4,257 5,876 5 7 5 7 13.2 1.4 38.0 Others - - 2,144 2,504 - - 3 3 16.8

Total 39,393 59,427 80,904 80,778 100 100 100 100 8.6 6.4 -0.2

Total Heat Cmsumption /1

Industry 90,786 108,011 123,432 119,984 3.5 2.7 -2.8 Residential & Ccmercial 18,941 27,917 41,315 42,600 8.1 8.2 3.1 Others 5,753 11,075 14,624 14,716 14.0 5.7 0.6

Total 115,480 147,003 179,371 177,300 4.9 4.1 -1.2

District Heat as % of Total Heat Cans1tion

Irdustry 34 37 39 37 Residential & Camnercial 46 71 76 79 Others - - 15 17

Total 34 40 45 46

Sources: B I, MWI/IpM, trgi idlkodhsi Statisztikai Ek"nyv"

/1 Total heat consuption includes heat produced in CQPor boiler plant an the cnsmErs' prenises.

4.19 The growth in the consumption of district heat by households was due almost entirely to the connection of new consumers (Table 4.13). In 1981, there were about 476,000 households connected to district heating networks, amounting to about 13% of all housing units. The proportion of dwellings with - 58 - district heat supply has been steadily increasing from 1.5% in 1965, to 3.5% in 1970, and 7.6% in 1975. By contrast,more than twice as many dwellings (961,000)had piped gas supply in 1981, but the growth in gas connections (6.1% p.a. for 1970-75 and 5.4% p.a. for 1975-80) was considerablyless. 1/ The number of industrial district heat consumers is small, 1,174 in 1981, yet these account for over half the consumptionof district heat.

Table 4.13

Number of District Heating Consumers 1980-81

Sector 1960 1970 1975 1980 1981 1960-70 1970-75 1975-8D 1980-81

Households 6,750 109,483255,608 440,021 475,626 32.1 18.5 11.5 8.1 Industrial 11 223 672 928 1,17435.1 24.7 6.7 26.5 Cammercial L30 1,500 3,220 5,120 5,750 27.7 16.5 9.7 11.4

of whicl: mapest

Households 4,829 50,050 105,407 162,281 175,385 26.3 16.1 9.0 8.1 Industry 6 176 285 332 337 40.2 10.1 3.1 1.5 Commercial 84 783 1,914 3,149 3,338 25.0 19.6 10.5 6.0

Source: EGI

F. Past Supply of Electricity

National Generating Capacity

4.20 The installed generating capacity in Hungary amounted to 6,146 MW in 1983. Over 91% of this (5,652 MW) was operated by MVMT. Most of the remainder (461 MW) was industrial plant, of which abvout 212 MW was operated jointly with MVMT in the interconnected system (Table 4.14). Details of electricity generating capacity are given in Annex 4.3.

1/ Statistical Yearbook, 1981. - 59 -

Table 4.14

InstalledPower Generating Capacity, 1983

MVMT 5,652 Autoproducers 212

Total interconnectedsystem 5,864

Non-interconnectedpower utilities 33 Other industrialproducers 249

Total installedcapacity 6,146

Source: MVMT "ResultatsTechniques Provisoires",KSH "Iparstatisztikai Evk-nyv, 1981", Mission estimates.

Note: Interconnectedsystem capacity estimated as 1982 installed capacity plus Paks 1 (440 MW). Total capacity of non-MVMT produces assumed unchanged from 1981.

Supply Available to the InterconnectedSystem

4.21 In 1982 MVMT installed capacity amounted to 5,212 MW, of which 5,165 MW was availableafter derating and allowing for seasonal hydro capability. The available capacity was 77% of the supply available to the interconnectedsystem (Table 4.15). Imports, mainly from the Soviet Union, amounted to an average 1,312 MW during working days in the peak month of December, or 20% of available supply. The remaining 3% was supplied by industrial autoproducers. Annex 4.4 describes the production of electricity in detail.

Generating Capacity

4.22 Of MVMT total installedcapacity at the end of 1982, 4,962 MW (95%) was steam plant, 48 MW (1%) was hydro and the remaining 202 MW (4%) consisted of three gas turbines. Faced with pending increases in the price 'of imported oil, the Government initiateda policy in 1979-80 to substituteother fuels for oil. Around the same time, there was an increase in natural gas supplies from domestic sources and the Soviet Union. Power generationwas able to convert quickly from oil to gas and thus absorb the large additional supplies of low-cost imported gas. Prior to 1979 the greater part of MVMT steam capacity was oil-fired. As a consequenceof the policy change, in December 1982, 2,863 MW (55% of total installed capacity)was using natural gas as its main fuel, with fuel oil as a secondary fuel; 1,994 MW (38%) burned coal or lignite; and only 105 MW (2%) of steam plant burned oil as its main fuel. - 60 -

Table 4.15

Supply Available to the Interconnected System 1950-1982 (Gross generated output, MW)

Rate of Ircrease (% p.a.) 1950 1955 1960 1965 1970 1975 1982 1950-60 1960-70 1970-82

Installed Capacity mHfT 559 911 1,251 1,808 2,692 4,006 5,212 8.4 8.0 5.7 Autoproilcers 116 185 197 229 228 222 212 5.1 1.5 -0.6

Total 675 1,096 1,448 2,037 2,920 4,223 5,424 7.9 7.3 5.3

Available Capacity M'MT 515 818 1,148 1,610 2,292 3,98E 5,165 8.3 7.2 7.0 Autbprodkcers 105 219 225 190 152 188 184 7.9 -3.8 1.6

S9btotal 623 1,037 1,373 1,8X4 2,444 4,168 5,349 8.3 5.9 6.7 IMiPrt - 45 109 249 559 603 1,312 - 17.8 7.4

Total Available 623 1,082 1,482 2,049 3,C03 4,771 6,661 9.1 7.3 6.9

MLximin Daid 486 885 1,293 1,993 2,983 4,185 5,439 10.3 8.7 5.1

Resexve Brgin () 28 22 15 3 1 14 22

Sotrce; M4T "'R8sultats Tedniques Prt,isoires, 1982", Attac&mwnt 1.

4.23 Steam power stations commissioned before 1970 have some dual-purpose capability, producing heat for industrial or municipal use as well as electricity. Of the 4,637 MW of gross output which MVMT steam plant was capable of generating in December 1982, about 678 MW (15%) was capable of CHP operation. Almost all industrial autoproducer plant is also CHP.

4.24 The median age of MVMT's generating plant is betwen 6 to 10 years, but this is mainly due to three large power stations, commissioned during the 1970's, which account for 57% of MVMT's capacity. The age of the remaining plant is high, with 20% of installed capacity being more than 20 years old (see Annex 4.3, Table 4). The oldest plant tends to be CHP stations located in or near urban areas. Most of this capacity will need replacement or extensive refurbishment in the 1990's. - 61 -

Supply of Electrical Energy

4.25 The national electricity supply balance is summarized in Table 4.16 below. The rate of growth in the net supply of electricity 1/ has declined since the 1950's, from 10.5% p.a. in 1950-60, to 5.5% p.a. during 1970-82. Because of the growing share of net imports, which increased from 7.2% of net supply in 1960 to 27.0% in 1982, net electricity production within Hungary has grown more slowly at 6.6% p.a. during 1960-70 and 4.8% p.a. in the period 1970-82. The consumption of electricity within power stations was about 10% of gross generation for most of the 1960's and the early 1970's, but declined to 8.2% in 1979. Because self-consumption in coal-fired stations is higher than in oil/gas-fired stations and district heating pumping energy is considered as self-consumption, the greater tendency towards generating electricity from natural gas in large power-only stations during the late 1970's led to a corresponding decline in the use of electricity within power stations. Despite these improvements station use is still high by international standards, especially considering the large scale use of natural gas as a fuel, but this is mainly due to old power stations with small unit sizes and pumping requirements for district heating. However, significant savings have been achieved in other countries through retrofitting and changes to operating procedures within power stations. Reducing station use to 5% would, if technically feasible, make available an extra 790 GWh, which is roughly equivalent to the increase in gross generation in 1982, or 0.2 million toe p.a. of fuel equivalent to 0.7% of total primary energy supply. The degree to which reductions in station use can be made is limited in existing power stations, which were designed during an era of low fuel prices. However, even within these stations there would appear to be scope for savings from refurbishment and some retrofitting. In the design of new power stations the appropriate long-run marginal cost of electricity produced on the system should be used to arrive at the economic level of station use. It is therefore recommended that; (a) as part of a wider study to reduce system losses (para. 4.35), MVMT examine the possibilities for further power and energy savings within existing power stations and prepare a program to achieve them; and (b) ensure that the power stations designers use the economic cost of electricity to the system to optimize the designs of new power stations.

Generation of Electricity

4.26 In 1982, 98% of electricity generated in Hungary was generated for the interconnected system. Of the 24,739 GWh generated in 1982, autoproducers generated 1,199 GWh (4.8%), of which 768 GWh, or 64% of their production, was supplied to the interconnected system. The total production of autoproducers has remained virtually constant since the mid-1950's, although the proportion of their output supplied to the interconnected system has gradually declined (Table 4.17).

1/ Net supply is defined as gross generation, less power station consumption, plus imports and less exports. - 62 -

Table 4.16

Electricity &'pply alace, mgEry, 1950-1982

Amual Rate of Irase (2 p.a.) 1950 1955 1960 1965 1970 1975 1982 /1 1950J- 196-M0 1970-75 1975-82

Gross Generatian 3,001 5,428 7,617 11,177 14,542 20,472 25,03) 9.8 6.7 7.1 2.9 Statian Use 253 486 713 1,108 1,416 1,834 2,041

Net Gaeaticn 2,748 4,942 6,9D4 10,069 13,126 16,638 22,989 9.6 6.6 4.9 4.7 3mport 3 256 537 1,387 4,058 5,8D2 10,505 68.0 22.4 7.4 8.9 Exports 5 8 1 98 663 1,678 1,995 -14.9 91.5 20.4 2.5

Net Supply 2,746 5,190 7,440 11,358 16,521 22,762 31,499 10.5 8.3 6.6 4.8 lietwk Losses 245 499 754 9b8 1,513 1,955 3,09)

Final CcnsulptiCn 2,501 4,691 6,686 10,410 15,008 20,8D7 28,409 10.2 8.4 6.8 4.5

Souwce; MT, '"esultats techniques prOvisOires, 1982"

A Figxres for 1982 are preliminary.

Table 4.17

Gross Producticn of Electricity, Humgary, 1950-1982

Rate of Growth (Z pa.) 1950 1955 1960 1965 1970 1975 1982 1950-6 1960-7D 1970-75 1975-82

Inter-comnected Systen

Mw4 2,29D 4,237 6,511 9,947 13,386 19,358 23,540 11.0 7.5 7.7 2.8 kitoro&wIcers 467 881 921 1,031 934 885 768 7.0 0.1 -1.1 2.2

Total 2,757 5,118 7,432 10,978 14,329 20,243 24;308 10.4 6.8 7.2 2.6 lNr2-Intercarmected

Auiproiucers /1 244 310 185 199 222 229 431 -2.7 1.8 0.6 9.5

Total Huigary 3,001 5,428 7,617 11,177 14,542 29,472 24,739 9.8 6.7 7.1 2.7

Source: MK*r,'Re&ultats techniques provisoires, 1982"

/1 Grass ccrlxapticn of autoprockers not operating in conjunction with tile interccmiected system. - 63 -

4.27 Over 99% of electricity generated in Hungary in 1981 by both MVMT and autoproducers was produced in steam plant. Less than 1% was produced from hydro plant and gas turbines, and internal combustion engines produced an insignificant amount (Table 4.18). This picture has been the same throughout the 1970's. About 1,812 GWh (8%) of the electricity generated by MVMT steam turbines in 1980 was produced in CHP cycle.

Table 4.18

Gross Production of Electricity by Plant Type, Hungary, 1970-81 (GWh)

Share (%) 1970 1975 1981 1970 1975 1981

MVMT Steam 13,298 19,129 22,933 99.3 98.8 99.2 Gas Turbine - 67 11 - 0.3 0.1 Hydro 88 164 170 0.7 0.8 0.7

Total 13,386 19,360 23,114 100.0 100.0 100.0

Autoproducers Steam 1,152 1,102 1,181 99.7 99.1 99.6 Gas Turbine - - - - - IC Engine 4 10 5 0.3 0.9 0.4

Total 1156 1112 1186 100.0 100.0 100.0

Total Steam 14,450 20,231 24,114 99.4 98.8 99.2 Gas Turbine - 67 11 - 0.3 0.1 IC Engine 4 10 5 - 0.1 - Hydro 88 164 170 0.6 0.8 0.7

Total 14,542 20,472 24,300 100.0 100.0 100.0

Source: AEEF/OEGH, "Energia GazdAlkodAsi Statisztikai Evkonyv" (Energy Economy Statistical Yearbook)

Electricity Generation and Fuel Consumption

4.28 The supply of electricity by MVMT during the 1970's can be summarized as expanding generation in natural gas and oil-fired stations meeting the increase in demand, a massive switch from oil to gas in 1981-82 and a small increase in the output of coal and lignite-fired power stations. In 1970, 67% of the electricity generated by MVMT was from coal-fired stations. By 1982 - 64 - this proportion had fallen to 46%. The proportion of electricityproduced from oil increased from 17% in 1970 to 25% in 1980. As a result of policies initiated in 1979 to substitute natural gas for oil, the proportion of electricity generated from oil more than halved between 1980 and 1982 when 12% of electricity generated by MVMT came from oil-fired stations. As a consequence,the proportion of electricity generated from natural gas increased from 16% in 1970 to 27% in 1980 and to 42% in 1982. Even though the proportion of electricity produced from coal declined, the output of coal-fired stations increased slightly at 2.0% p.a. during the period 1970-80 and 0.8% p.a. in 1981-82. The output of oil and gas-fired stations increased rapidly at 9.3% p.a. and 11.5% p.a. respectively during the 1970's. However, in 1981 and 1982, the conversion of oil-fired stations to dual oil/gas-firing roughly halved the output of oil-fired stations. Details are given in Annex 4.5.

4.29 Consumption of coal by MVMTincreased at declining growth rates until the mid-1970's, but has been essentially static since 1980. The share of coal in total MVMT fuel burned has declined from 98% in 1955, to 82% in 1965, 57% in 1975 and 50% in 1982. Consumption of oil grew rapidly until the mid-1970's, so that by 1975 it accounted for almost a quarter of the fuel burned by MVMT. When the policy to substitute natural gas for oil was implemented in 1980, oil's share fell to 13% by 1982. Consumptionof natural gas increased by 19.7% p.a. during 1965-75 and 14.7% p.a. during 1975-80, so that its share increased from 13.9% in 1970 to 37.5% in 1982 (Table 4.19).

Table 4.19

Fuel Consumed by MVMT 1955-82 (toe)

AverageRate of Increase(%p.a.) Ful 1955 1965 1975 1980 1982 1955-65 1965-75 1975-8D 1980-82

Lignite 453 516 978 1,252 1,196 1.3 6.6 5.1 -2.3 BrownCoal 1,119 2,159 2,130 1,991 2,076 6.8 -0.1 -1.3 2.1 Coal By-Products 96 319 452 484 506 12.7 3.6 1.4 2.2

Subtotal 1,668 2,994 3,560 3,727 3,778 6.0 2.2 0.9 0.7

Oil 39 459 1,496 1,145 971 28.1 12.5 -5.2 -7.9 NaturalGas - 203 1230 2,447 2,853 - 19.7 14.7 8.0

Total 1,706 3,656 6,286 7,319 7,602 7.9 5.6 3.1 1.9

Coal 97.-% 81.9%/56.6% 50.9% 49.7% Oil 2.3% 12.5% 23.8% 15.6% 12.8% NaturalGas - 5.6Z 19.6% 33.4% 37.5% 100% 100% 100% 100% 100%

Source:MVM - 65 -

Foreign Trade in Electricity

4.30 The Hungarian power system is interconnectedwith all neighboring countries,Austria, Czechoslovakia,Romania, Soviet Union and Yugoslavia. Hungary is a member of the CMEA InterconnectedPower System (OES), which consists of the power systems of Bulgaria, Czechoslovakia,GDR, Hungary, Poland, Romania and the USSR South System. At the end of 1981 OES had an installed capacity of 141,563 MW, to which the USSR contributed46,191 MW, although the combined non-interconnectedcapacity of OES-member countries would have amounted to about 300,000 MW.

4.31 There has been a shortage of available capacity on the OES which has necessitatedprolonged load shedding by reducing frequency,particularly during the winter. The frequencyhas fallen as low as 49 Hz, compared to a nominal frequency of 50 Hz. This low frequency causes problems with some industrialmachinery. Since Hungary depends on imports from OES for about a quarter of its electricitysupply and the OES system frequency is controlled from the OES dispatch centre in Prague, system frequency is effectively outside of its control. Austria and Yugoslavia operate at a closely controlled frequencyof 50 Hz. When trading with these countries, the Hungarian system is split into regions, e.g., the Gyor area, which then operate at 50 Hz. Should Hungary wish to trade further with these countries, or to participate in large exchanges between Western Europe and OES, direct current (DC) links would appear necessary because of the low frequencyin OES and potential stability problems.

4.32 Imports of electricity,which are mainly from the Soviet Union, have grown steadily since the mid-1960's and almost doubled during the period 1978-80,when a 750-kV transmissionline between Hungary and the Soviet Union was commissioned. In 1982, net imports accounted for 25% of the gross supply of electrical energy in Hungary. The growth in internationaltrade in electricity is shown in Table 4.20. Exports appear to have grown rapidly, but much of the increase during the 1970's was due to re-exports to Czechoslovakia and Poland from the Soviet Union via Hungary (1,710 GWh in 1982).

Table 4.20

InternationalTrade in Electricity,1950-1982 (GWh)

Rate of Increase (%p.a) 1960 1965 1970 1975 1982 1965-70 1970-75 1975-82

Imports 537 1,387 4,058 5,802 10,503 24.0 7.4 8.9 Exports 1 98 663 1,678 1,995 46.6 20.4 2.5

Net Imports 536 1,289 3,395 4,124 8,510 21.4 4.0 10.9

Source: MVMT, "Rgsultatstechniques provisoires,1982" - 66 -

4.33 When the 750-kV interconnectorwas established,Hungary entered into a long-term agreement with the Soviet Union to import 1,100 MW for a period which extends into the next century. This agreement is linked to Hungarian financialparticipation in a nuclear power station under constructionin the Soviet Union. In addition, there is provision for 5-year agreements for additional imports, which are negotiated under the auspices of CMEA. The present agreement allows for this element of the import to increase to 750 MW in 1985, making a maximum import of 1,850 MW, compared to 1,450 MW in 1983. There is also provision for emergency imports at much higher prices. Prices of electricityand other fuels traded within CMEA are set each year according to the Bucharest Formula, a 5-year moving average of the world price of the fuel in the convertiblecurrency area. Since there is no establishedworld price for electricity,bilateral electricity prices are calculated using a formula to estimate the cost of electricity,which includes considerationsof investmentcosts, fuel costs (includingthe world price of oil) and plant utilization. There is a subjectiveelement in calculatingthese costs so that the final prices are negotiated within the annual CMEA clearing arrangement for each country. The detailed pricing arrangementsare confidential,but one can deduce from published trade data an average price of imported electricity in 1981 of Ft 0.33/kWh (0.97USc/kWh). MVMT published accounts would indicate average prices of imports from all sources of Ft 0.48/kWh (1.4USc/kWh)in 1981 and Ft 0.58/kWh (1.7USc/kWh)in 1982. In terms of financialprices and prevailing exchange rates, these figures suggest that, on average, imported electricitycosts less than production from new power plants (nuclear Ft 1.22/kWh, lignite Ft 1.60/kWh). Because the quantities of electricity traded under CMEA arrangementsare fixed contractually,it is the price of incrementsor decrements that can be negotiated in the amounts traded that is relevant to economic comparisonsof imports versus local generation,not the average price of imports.

System Operation

4.34 The National Dispatch Centre (NDC) in Budapest is responsible for the secure and economic operation of the MVMT power system. NDC is in communicationwith seven regional dispatch centres which are responsible for distributionand the dispatch of small power stations.NDC also communicates with the OES control centre in Prague. Modern computer-controlfacilities were commissionedat NDC in early 1979. This system schedules imports according to the daily agreementwith the OES control centre and arranges the operation of Hungarian power plant to achieve minimum incrementalcost, calculatedusing incrementalheat rates and actual fuel prices paid by MVMT. The outputs of larger generatingunits are controlledautomatically from Budapest to achieve least-costsystem operation. This system is at the forefront of the state of the art and appears to work well and be well managed.

4.35 As a member of OES, MVMT must have spinning reserve available equal to 2% of its peak load, to make good the loss of output, within seconds, of a unit failure to avoid system collapse. This is normally provided from oil or gas-fired power stations, and gas turbines are started if other countries cannot provide emergency spinning reserve. A function of NDC is to carry out - 67 - transmission switching to avoid loss of load in the event of generation or transmission outages. This is a complex task since the stability of the OES is such that events in countries to the north of Hungary may result in the 750-kV interconnector with the USSR being tripped out. An automatic tie-line control system to isolate the Hungarian system from other regions when faults occur outside Hungary is being considered by MVMT.

4.36 Major maintenance of power plants is carried out by EROKAR, MVMT's plant maintenance enterprise. Teams from this central maintenance organization are responsible for major overhauls, with assistance from local staff within the power stations. Regular maintenance is carried out by station staff. Maintenance activities are well organized and plants appear to be well maintained, especially considering the advanced age of some generating units. MVMT staff responsible for the management and operation of the power system are experienced and highly competent. MVMT is establishing a separate plant maintenance team for the Paks nuclear station, although maintenance of the conventional part of the station will be contracted to EROKAR.

Transmission and Distribution

4.37 The backbone of the Hungarian system is a 400-kV network covering the entire country which was commissioned during the 1970's. Secondary voltage levels for transmission are 220 kV and 120 kV. Primary distribution voltages are 20 kV and 10 kV and the low-voltage distribution is 400 V three phases, 50 Hz for the entire country. In 1978, a 750-kV interconnector with the Soviet Union was commissioned which has a length of 481 km between substations in each of the countries.

4.38 Development of the HV system (voltages greater than 120 kV) appears to have kept pace with the growth in system demand (Table 4.21). However, shortages of finance have constrained investment in MV and LV distribution and there is anecdotal evidence of high distribution losses in some regions. In this connection, it is significant that sales to LV consumers (household/ services) have continued to grow at rates over 8.2% p.a. during the period 1975-82 whereas LV distribution lines increased at 2.5% and substation capacitv at onlv 3.3% p.a.

4.39 System losses for all Hungarv (excluding electricity consumed within power stations) were 9.8% in 1982, compared to 8.6% in 1975. Losses appear low because roughlv 60% of electricitv is sold at MV and HV where losses are generallv low. However, losses in distribution are said to be high and the average losses in supplving a LV consumer mav be as high as 14% (see Tables 6.7 and 6.8). Experience elsewhere has shown that investment in loss reduction produces high returns. Because of the potentially large benefits in terms of fuel savings and savings in investment in generation, it is recommended that MVMT identifies those part of the svstem where the scope for loss reduction is highest, evaluate the economics of loss reduction, and where economically justified, initiate a programme to reduce losses, especially at MV and LV. - 68 -

Table 4.21

Development of Transmission and Distribution, 1960-1982

AnnualRate of Increase (% p.a.) 1960 1965 1970 1975 1982 1960-65 1965-70 1970-75 1975-82

Mainun Demand (MW) 1,293 1,993 2,983 4,185 5,439 9.0 8.4 7.0 3.8

HV Transmission (Route km)

1-22(KV 32,260 43,656 49,818 54,877 61,446 6.2 2.7 2.0 1.6 400KV - - 260 509 1065 - - 14.4 11.1 750KV - - - - 268 - - - -

Distribution

10-4(1w 2,467 3,799 4,869 6,198 7,700 6.6 7.5 5.0 3.2 Low Voltage (lKV) 31,083 38,343 47,412 54,314 64,336 4.3 4.3 2.8 2.5

Substation Capacity (MVA)/1

Primary voltage 7501W - - - - 2,200 - - _ - 401WV - - 720 720 3,720 - - - 26.4 220RV 270 520 1,580 3,610 4,410 14.0 24.9 18.0 2.9 less than 220KV 3,760 6,171 8,752 8,635 11,000 /2 10.4 7.2 -0.3 3.5

Total 4,030 6,691 11,052 12,965 21,330 10.7 10.6 3.2 7.4

/1 Substation capacity excludes gererator transformers /2 Preliminary estimate G. Past Supply of Coal

Coal Supply

4.40 The domestic production of all types of coal except lignite declined between 1970 and 1981. As shown in Table 4.22, production of hard coal declined from 3.1 million tons to 2.5 million tons, of brown coal from 19.1 million tons to 14.5 million tons, and of coking coal from 1.3 million tons to 0.9 million tons. In contrast, the production of lignite increased from 4.8 million tons in 1970 to 8.4 million tons in 1981. During this same period, Hungary's imports of briquettes increased by 1.5% a year, from 446 thousand tons in 1970 to 524 thousand tons in 1981. Imports of coking coal declined from 1.3 million tons in 1970 to 0.9 million tons in 1981, averaging about 3.7% a year, whereas the imports of coke remained practically constant at 1.2 million tons per year. - 69 -

Table 4.22

Supplv of Coal, 1970-1981 ('000 tons)

GrowthRate (O 1970 1975 198D 1981 1970-75 1975-8 1980-81 1970-81

Domestic

Hard Coal 3,092 2,382 2,498 2,519 -5.1 0.9 0.8 -1.8 Bron Coal 19,052 14,971 14,165 14,463 -4.7 -1.1 2.1 -2.5 Lignite 4,788 6,910 8,473 8,413 7.6 4.2 -0.7 5.3 CokingCoal 1,310 962 883 860 -6.0 -1.7 -2.6 -3.8

Total 28,242 25,225 26,025 26,255 -2.2 0.6 0.9 -0.7

Briquettes 1,463 1,082 1,250 1,327 -5.9 2.9 6.2 -0.9 Coke 1,167 1,000 975 958 -3.0 -0.5 -1.7 -1.8 Dried Lignite 330 215 204 204 -8.2 -1.0 - -4.2

Inports

HardCoal 905 860 778 771 -1.0 -2.0 0.9 -1.5 Coking Coal 1,300 846 812 863 -8.2 -0.8 6.3 -3.7 Briquettes 446 554 504 524 4.4 -1.9 4.0 1.5 Coke 1,256 1,360 1,468 1,227 1.6 1.5 -16.4 -0.2

Euxports

BrownCoal 99 91 44 42 Lignite - 3 - - Briquettes 7 28 - 5 Coke 1 11 - -

Source:AEEF/CEH, ibid.

4.41 The present coal production,which has been stable over the last eight vears at 25-26 million tons per vear, is made up of about 8 million tons of lignite, of which 7 are mined in the countrv's onlv large open-pit mine, 15 million tons of brown coal and 3 million tons of hard coal, mined from relativelv small undergroundmines, the largest of which produces 1.4 million tons. Table 4.23 below shows production for each coal tvpe and mining companv. - 70 -

Table 4.23

Present Coal Production

Average 1982 Heating Value Production (kcal/kg) (million tons)

Li nite fatraalja 1,500 7.3 BukksbrAnv 1,600 - Vgszprem 2,300 1.0 Total Lignite 8T.

Brown Coal Dorog 4,500 0.5 Tatabanva 3,500 2.3 Oroszlanv 3,100 3.1 Veszprem 3,000 2.6 N6grad 2,700 1.0 Borsod 2,800 5.2 Total Brown Coal 14.7

Hard Coal Mecsek 4,100 3.0

Total 26.0

Source: AEEF/OEGH, ibid.

4.42 While total coal production in terms of tons mined declined at a rate of 0.7% p.a. during the period 1970-1981,the heat content declined bv 2.5% p.a. (Table 4.24). This reflects low-grade lignite forming a greater proportion of the coal mined and the effects of increasedmechanization in the undergroundmines, in particular for brown coal. - 71 -

Table 4.24

Coal Production, 1970-1981 ('000 toe)

1970 1975 1980 1981

Hard coal 1,006 708 683 705 Brown Coal 6,357 4,821 4,275 4,314 Lignite 895 1,134 1,369 1,332 Coking Coal 727 534 481 468

Total 8,985 7,197 6,808 6,819

Average Heat Content (GJ/t)

Hard coal 13.9 12.7 11.7 12.0 Brown Coal 14.2 13.7 12.9 12.7 Lignite 8.0 7.0 6.9 6.8 Coking coal 23.7 23.7 23.3 23.2

Total 13.6 12.2 11.2 11.1

Source: AEEF/OEGH, ibid.

Production Cost

4.43 The average production cost of Hungarian coal in 1982 was Ft 660/t (US$16.5/t). At the average heating value of 2,700 kcal/kg this is equivalent to US$1.5/GJ (US$64.1/toe). Whereas brown and hard coals have similar production cost per heat unit, open-pit mined lignite presentlv costs onlv about two thirds (US$1.0/GJ or US$43/toe). Table 4.25 shows present production cost.

4.44 Bv comparison, :he f.o.b. price of internationallv-traded Australian coal from major overseas exporters presentlv is about US$40/ton (US$1.5/GJ, or US$63/toe). Free Hungarian border this price is estimated to increase to about US$70/ton (US$2.6/(,J,or US$110/toe). The present Hungarian border price of coal imported from Poland under the CMEA trading arrangements is US$40.0/ton (US$1.4/GJ, or US$60/toe), and of briquettes imported from GDR US$37.0/ton (US$1.9/GJ, or US$81/toe). - 72 -

Table 4.25

1982 Coal Production Cost /1

Ft/t US$/t US$/GJ

Lignite

Matraalj'a 260 6.5 1.0 Veszprem /2 n.a. n.a. n.a.

Brown Coal

Dorog 10,101 25.3 1.3 Tatabanva 1,100 27.5 1.9 Oroszlanv 680 17.0 1.3 Veszprem 640 16.0 1.4 Nograd 1,000 25.0 2.2 Borsod 720 18.1 1.5

Average Brown Coal 780 19.5 1.6

Hard Coal

Mecsek 990 24.8 1.4

Average All Coal 660 16.5 1.5

Source: Mining companies.

/1 Statisticaldata on past production costs were not given to the mission. /2 Included in Veszprem brown coal (28% of Veszprem's production is lignite, 72% brown coal).

H. Past Supply of District Heat

4.45 Hungarv has a long tradition of district heating. The first district heating supplv svstem was built towards the end of the 19th centurv. Following this, several industrialcombined heat and power (CHP) schemes were constructed,especiallv in sugar factories. In the 1950's, districtheating was further expanded and outmoded boiler installationsin manv industrial plants were shut down to be replaced bv CHP plants and MVMT district heating plants. In view of these possibilities,increased attention was paid to combining the production of power and heat fuel savings. CHP plants completed in the 1960's were primarilv designed for industrial steam supplv. In the course of constructionof these CHP stations,municipal district heating plants for supplving purelv residential areas were also built. These district heating networks are almost exclusivelv laid out for hot water. - 73 -

4.46 Because district heating originated in schemes to supply industrial estates with heat, most early heat production stations consisted of back- pressure turbines supplying steam to industry and driving electric power generators. During the Late 1960's and 1970's, MVMT converted some of its old steam turbines to produce heat for distribution as well as power. Whilst this could be achieved at low capital cost, the electric power output of these power stations was substantially reduced. The increased demand for district heat in the 1970's, coup:Led with shortages of finance and low prices for oil and gas resulted in much of the additional heat required being supplied from new boilers. These boilers were usually installed in existing MVMT or industrial power stations and often connected to the existing steam lines in the power station. Almost all these boilers were designed to burn oil or natural gas, often with dual fuel capability.

4.47 Total heat production capability increased at 9.0% p.a. during the period 1970-75 and 7.4% p.a. during 1975-80. In 1981 the installed capacity was 15,536 MWth (Table 4.26). Of this, 10,025 MWth (65%) was designed to produce process steam, mainly for industry, and the remainder was for hot water production, principally for supply to households. There are about 100 district heating systems in 45 cities, towns and villages (see Map IBRD 18105. However, in 71 cities, the number of apartments supplied is less than 2,000, so that most district heating systems are very small. Budapest and five other cities, Debrecen, Pecs, Gyor, Miskolc and Szeged, account for 46% of the gross consumption of district heat. MVMT's heat production capacity amounted to 4,458 MWth in 1982, of which 1,534 MWth (34%) was from boilers and 2,928 MWth (66%) from CHP turbines. Between 1980 and 1982, hot water boiler capacity increased by 13% and steam boiler capacity by 26%, whereas CHP capacity remained almost unchanged, probably because of shortages of finance which led to the cheaper boiler plant being favored.

Table 4.26

Heat Production Capability, 1970-1981 (MWth)

Annual Rate of Increase (% p.a.) 1970 1975 1980 1981 1970-75 1975-80 1980-81

Hot Water 2,192 3,377 4,797 5,511 9.0 7.3 14.9 Steam 4,450 6,856 9,803 10,525 9.0 7.4 2.3

Total 6,642 10,233 14,600 15,536 9.0 7.4 6.4

Source: EGI

4.48. In Budapest there are 25 district heating plants with an installed capacity of more than 2,700 MWth. The 10 largest plants, with an installed - 74 - capacity of 2,638 MWth met an estimated peak demand of 2,126 MWth and produced 24,440 TJ in 1980. This indicates a heat load factor of 36%, which is low. Only 9 of the 25 heat-producing stations in Budapest have CHP plant, and the electrical installed capacity in three of these is less than 5 MW. The power load factor of the remaining six was only 53% in 1980, whereas load factors of up to 90% for urban CHP stations are found in other countries. Furthermore, the maximum power-to-heat ratio was only 0.17 (200 kWh/Gcal). This is a consequence of the low steam temperatures and pressures in these plants, a characteristic of their age, and because of the extensive remodeling of old power stations, e.g., by adding new boilers to produce heat. In order to save investment costs, about 2,130 MWth of boiler capacity, which is considerably cheaper than CHP plant, was added to the heat production capacity in Budapest between 1965 and 1980. Most of the boilers burn gas or oil. Therefore, the major part of heat supplied in Budapest is effectively met from boilers burning oil and gas.

4.49 MVMTproduces about 70% of heat supplied to district heating systems. The proportion of heat produced by heat supply companies has increased from 4% in 1970 to 21% in 1980, probably as a consequence of the expansion in boiler capacity. Heat produced by heat supply companies fell by nearly 16% in 1981, following increases in the prices of fuels and the Government's policies to conserve energy and rationalize fuel use (Table 4.27). Heat production data for the main systems are given in Annex 4.6. Heat production data for the main systems are given in Annex 4.6.

Table 4.27

Heat Production by Institution 1970-81 - == ~~~(.TJ)

Arrnial Rate Share % of Irrrease (%-p.a.) 1970 1975 1980 1981 1970 1975 1980 1981 1970-75 1975-80 1980-81

MVS 31,317 43,195 54,595 57,223 79 73 68 71 6.6 4.8 4.8 Heat Supply camanies 1,490 8,101 17,367 14,624 4 13 21 18 40.3 16.5 -15.8 Others 6,586 8,13 8,942 8,931 17 14 11 11 4.3 1.9 -0.1

Total 39,393 59,427 80,90Y 80,778 100 100 1D 100 8.6 6.4 -0.2

Source: ;I

Fuel Consumed in District Heating Plants

4.50 In 1981, district heating plants accounted for 8% of the gross consumption of primary energy and its equivalents in Hungary. Natural gas is the major fuel used in district heating plants, accounting for 47% of fuel consumption in 1981. Coal accounted for 31% and oil for 19%. Other fuels accounted for 3% and these include geothermal water and refuses A 60 MWth - 75 - heating plant to burn half the refuse in Budapest was partially commissioned in 1983. The Paks nuclear power station will also supply a small quantity of heat to the nearby town. The share of coal in heat supply has not changed significantly since 1970. Consumption of oil increased at around 10% p.a. during 1970-75, but has since declined in favor of natural gas (Table 4.28).

Table 4.28

Consumption of Fuel in District Heating Plants 1970-1981 ('000 Toe)

Amial Share(Z) GrowthRate (% p.a.) Fuel 1970 1975 1980 1981 1970 1975 1980 1981 1970-75 1975-90 1980-81

LightFuel oil 1,450 2,271 2,847 2,612 3 3 3 2 9.4 4.6 -8.3 Heavy Fuel oil 11,625 19,301 24,126 19,020 22 24 21 17 10.7 4.6 -21.2 Natural Gas 23,474 31,062 48,096 50,965 43 38 43 47 5.8 9.1 6.0 Coal 16,04227,152 34,943 33,800 2 2 2 3 3.4 8.4 -3.3 Other 1,372 1,521 2,422 2,756 2 2 2 2 3.4 8.4 13.0

Total 53,963 81,407 112,434 109,153 100 100 100 100 8.6 6.7 -2.9

Source: BEI

4.51 MVMT CHP plants produced heat mainly from coal (40%) and natural gas (38%), heavy fuel oil accounting for most of the remainder. Industrial stations produced heat mainly from coal, heavy fuel oil and natural gas, each of which accounted for about 30% of fuel consumption. Urban heating plants, which mainly consist of boilers with no power generation, consume fuels in the following proportions: natural gas, 62%; heavy fuel oil, 20%; light fuel oil, 10%; coal, 3%; and others, 5%. Overall, district heat is produced mainly from natural gas, 42%; coal, 31% and oil, 24% (Table 4.29).

Table 4.29

Fuel Consumption of District Heating Producers, 1980

Industrial MVMT Stations Urban Plants Total Type of Fuel TJ () TJ (Z) TJ (X) TJ (%X

Solid 30,430 40.5 4,053 28.5 760 3.3 35,243 31.3 Heavy fuel oil 15,418 20.5 4,046 28.5 4,662 20.0 24,126 21.4 Light fuel oil 504 0.7 23 0.2 2,320 10.0 2,847 2.5 Natural gas 28,731 38.3 4,326 30.5 14,509 62.2 47,566 42.3 Other 1,753 12.3 1,059 4.5 2,812 2.5

Total 75,083 100.0 14,201 100.0 23,310 100.0 112,594 100.0

Source: EGI - 76 -

4.52 The economics of using boilers burning gas or oil to supply heat to district heating systems do not appear favorable, except for limited peaking purposes, or to utilize low-grade fuels (e.g., brown coal, refuse), or as a temporary measure during the period when demand grows in a new housing development. The present value of lifetime fuel costs tends to swamp the investment cost of a boiler. Hence it is probably not economic to generate steam for industry in remote boiler plants using oil or gas, since the limited scale economies and savings in spare boiler capacity are offset by heat distribution losses of at least 8% and the high cost of steam distribution pipelines. Similarly, for households, the high costs of distribution networks and distribution losses would tend to eliminate the investment savings from large central heating boilers, compared to individual household boilers. In addition, separate distribution pipelines for natural gas could be required for the district heating alternative, since district heat cannot be used for cooking. There appears to be substantial scope for rationalizing the production of heat in Hungary. As a minimum, this would involve interconnection of local heat distribution networks, the replacement of some boiler plant by CHP installations, and replacement of old CHP turbines by plant with greater thermal efficiency utilizing higher steam temperatures and pressures. The ultimate aim should be to re-structure heat production capacity so as to produce more heat from CHP plants, especially from plants that burn coal. During the summer, it would then be possible to produce a district heat almost entirely from CHP plants. A strategy for restructuring heat production capacity is discussed further in paras. 5.52 to 5.60. - 77 -

V. PRODJECTED CONSUMPTION AND SUPPLY OF POWER, COAL AND DISTRICT HEAT

A. Forecast Consumption of Power, Coal and District Heat

Forecasts of Energy Consumption to 2000

5.01 Government forecasts of the demand for energy for the period 1980-2000 are based on the following assumptions: (a) GDP would increase at about 2% to 3% a year over the next two decades, a rate of increase substantially lower than that experienced in the past 25 years; (b) domestic coal would increasingly displace oil and gas mainly because the domestic reserves of the latter products are insufficient to maintain the present level of production until the end of the century, and because the imminent price increases stemming fromnthe 1976 Bucharest Agreement and uncertainty about the magnitude of supplies priced in roubles after 1985, preclude the viability of importing these products at the present levels without further exacerbating the country's liquidity problems; (c) the relative share of nuclear energy in the generation of heat and electricity would increase; and finally, (d) all reasonable means, including allocative and pricing measures, would be employed to ensure conservation, substitution and utilization of domestic energy resources. These assumptions appear reasonable, although the Government may have underestimated the success of its energy management program. Consumption in 1990 could be about 4% lower if the decline in energy intensity since 1980 were to continue at the same rate. The Government energy projection is based on 2.2% p.a. GDP growth between 1980 and 1990, which is close to the current Bank projection of 2.0% p.a. 1/ Annex 5.1 describes the forecasting methodology.

5.02 Based on these assumptions, gross consumption of energy is forecast by the Government to increase from 31.7 million toe (1,354 PJ) in 1980 to 35.8 million toe (1,530 PJ) in 1990 and 41.3 million toe (1,765 PJ) in 2000, yielding an average annual growth rate of 1.2% for the period 1980-1990 and 1.4% for the period 1990-2000. As summarized in Table 5.1 below, intensity of energy consumption is projected to decrease at an increasing rate, averaging 1.0% a year between 1980 and 1990, and 1.4% a year between 1990 and 2000. The energy coefficient for these two periods would fall slightly from 0.56 during 1980-90 to 0.50 during 1990-2000.

l/ Country Economic Memorandum 1984, "Stabilization, Growth and Structural Adjustment" (Report 5006-HU). - 78 -

Table 5.1

Relationship between Forecasts of Demand for Energy and Real GDP

Gross Domestic Energy Consumption /1 Energy Intensity Year ('000 toe) GDP /2 (toe/million Forints)

1980 31,710 751.0 42.4 1985 33,490 837.3 40.0 1990 35,830 933.5 38.4 2000 41,330 1242.5 33.3

Average Annual Growth Rate (%O)

1980-1990 1.2 2.2 -1.0 1990-2000 1.4 2.9 -1.4

Source: IpM

/1 Biomass and geothermal energy not counted in the official energy balance are included. These amounted to 2,196 thousand toe (93.6 PJ) in 1980 and were estimated by the mission to increase to 2,810 thousand toe (120 PJ) in 1990 and 3,040 thousand toe (130 PJ) in 2000. 12 In billions of 1980 Forints.

5.03 The industrial sector's share of the demand for energy is forecast to decline most rapidly, from 50.5% in 1980 to 48.4% in 1990 and 46.8% in the year 2000, followed by the transport and construction sectors. In contrast, the public and communal sectors' share of the demand for energy is forecast to increase steadily from 8.1% in 1980 to 10.3% in 2000 for the former and from 24.0% to 27.0% for the latter, respectively. These shifts reflect changes in the structure of economic output, improved housing quality and the time needed to adjust household energy prices to their economic cost.

5.04 One of the assumptions of the Government's forecast calls for domestically produced coal to increasingly displace the consumption of oil and gas. The Government's forecast of production and import of primary energy and equivalents was modified by the mission to take account of revised coal, petroleum and nuclear supply projections and is summarized in Table 5.2. This shows a substantial increase in the supply of primary (nuclear) electricity during the period 1983-1990. The supply of coal (production and imports) is expected to increase marginally by only 1.8% between 1983 and 1990 but its share in total energy would decline by about 3%. Small delines in the production of oil and gas are offset by slightly higher imports of these fuels.

5.05 Despite the marginal shift in structure of the supply of coal, oil and natural gas, the supply forecast shows the country's dependence on - 79 -

imported energy increasing from 45% in 1983 to about 47% of gross supply in 1990. However, the production of oil as a percentage of domestic energy supply is expected to decline from 8.2% in 1983 to 6.8% in 1990 and that of gas from 15.9% to 12.1%. This decline in the share of hydrocarbons in domestic production is more than compensated by the increasing share of primary electricity, mai.nly nuclear, which increases from 0.1% in 1980 to 7.9% in 1990. The overall picture after 1983 is therefore one of nuclear electricity substituting for the small decline in oil and natural gas production.

Table 5.2

Forecast supply of Primary Energy and Equivalents, 1980-1990

1980 1983 1985 1990 (Mtoe) (%) (Mtoe) (%) (Mtoe) (%) (Mtoe) (%) ------Actual ------Projected ------Domestic Production: Coal 6.81 20.5 6.58 20.3 6.60 19.3 6.80 18.1 Oil /1 2.65 8.0 2.66 8.2 2.61 7.6 2.57 6.8 Gas 4.99 15.0 5.15 15.9 5.81 17.0 4.55 12.1 Primary Electricity /2 0.03 0.1 0.60 1.9 1.49 4.3 2.95 7.9 Other /3 2.52 7.6 2.86 8.8 2.90 8.5 3.14 8.4

Subtotal 16.99 51.2 17.84 55.1 19.41 56.7 20.01 53.3

Imports. Coal /4 2.13 6.4 1.97 6.1 2.10 6.1 1.90 5.1 Oil 8.93 26.9 7.04 21.7 7.38 21.5 8.64 23.0 Gas 3.14 9.5 3.21 9.9 2.63 7.7 4.24 20.5 Electricity /5 2.00 6.0 2.31 7.1 2.74 8.0 2.74 7.3

Subtotal 16.20 48.8 14.54 44.9 14.85 43.3 17.52 46.7

Gross Supply 33.19 100.0 32.38 100.0 34.26 100.0 37.53 100.0

Export and Stock Change (1.48) (0.80) (0.77) (1.70)

Gross Domestic Consump- tion of Primary Energy and Equivalents 31.71 31.58 33.49 35.83

Source: Mission estimates, IpM, Petroleum Project SAR.

/1 Oil production includes natural gas liquids. /2 Primary electricity consists of hydro (average 0.04 million toe) and nuclear electricity, both expressed in fossil fuel equivalent. /3 Others consist of fuelwood and items not included in the official energy balance, i.e., some biomass and geothermal (see footnote to Table 5.1). /4 Coal imports include coke, briquettes and charcoal. 75 Electricity imports are expressed in fossil fuel equivalent. - 80 -

Forecast Electricity Consumption

5.06 The gross consumption of electricity in Hungary is projected by the Government to increase at 3.0% p.a. until 1985 and then at about 3.5% p.a. until the end of the century (Table 5.3). This forecast seems reasonable in relation to the past relationships between consumption and GDP and projected economic growth. Intensity of electricity use is projected to increase at the same rate of 0.7% p.a. observed during the period 1970-81 (Table 4.10). The elasticity of electricity consumption with respect to GDP would be 1.25 during the period 1982-90 and 1.17 during 1990-2000, which seems plausible in relation to the 1.32 observed in 1970-75 (para. 4.10). However, electricity pricing reforms and other demand management measures might lead to a lower elasticity and intensity. No breakdown of the forecast by economic sector was available to the mission to study this further, but it is likely that it would show an increasing share of households in total consumption and a decline in the share of industry. Sales of electricity by MVMT to households increased by 9.4% in 1982 and 8.5% in 1983, whereas sales to industry increased by 0.1%

Table 5.3

Forecast of Electricity Consumption (GWh)

Gross Electricity Maximum Consumption Electricity Intensity Sold by Demand Year All Hungary (kWh/Ft '000 of GDP) /1 MVMT (MW)

1982 (Actual) 33,540 44.7 27,412 5,110 1985 36,600 0.0 31,200 5,730 1990 44,000 47.1 37,500 6,890 1995 52,500 0.0 44,740 8,150 2000 61,500 49.5 52,420 9,640

Average Growth Rate (% p.a.)

1982-85 3.0 0.7 4.4 3.9 1982-90 3.5 0.7 4.0 3.8 1990-2000 3.4 0.5 3.4 3.4

Source: IpM.

/1 GDP at 1980 prices. and 2.1%, respectively. It is likely that reforms to household energy prices would lead to a significant slowdown in the rate of growth of household consumption. Since households account for about 20% of total MVMT electricity sales this would affect total consumption. Industrial load management (para. - 81 -

6.04) would also lower maximum demand. It is therefore recommended that the Government review its electricity demand forecasts so as to investigate the impact of reducing household electricity price subsidies on total electricity demand, changes to the tariff structure and industrial load management.

Forecast Coal Consumption

5.07 Based on the Government's projections, updated by information collected in the field, the mission forecasts that the consumption of coal will remain practically unchanged between 1982 and 1990. A small increase in coal energy consumption of about 10% in total is expected from all consuming sectors before 1995 (Ta'ble5.4), mainly because of coal fired CHP projects being completed. Thereafter, consumption could increase steeply if major power projects based on lignite (BiikkAbrany)are implemented (para. 5.46).

5.08 Households, including communal consumers, are expected to moderately increase their consumption of coal from the 1982 consumption of 6.0 million tons per year to about '3.5 million tons in 1990. The increase is low because there appears to be consumer resistance to the inconvenient and unpleasant use of low-grade Hungarian coal despite the low price of coal relative to competing fuels (Table 6.3). The estimated increases would depend on the availability of higher quality coal such as local washed coal and smoke-reduced lignite briquettes. Should lignite processing into briquettes and coke prove to be viable, local lignite may replace a portion of the hard coal and imported coal used in households.

5.09 The steel industry has depended and will depend mainly on imported coke and coking coal. Due to technological improvements, coke consumption should decline by about 10% by 1990.

5.10 Coal consumption of other industrial users would be restricted, mainly because the major consumers of process heat are already located near power or heating plants where they receive their supplies directly in the form of steam. TechnologicaL reasons restrict the use of coal other than for boilers. Cement plants would be the single largest other consumer. However, the quantities involved are small and of relatively little significance for the overall coal market. In total, all industrial users other than steel and cement will not increase their consumption of coal.

Projected Consumption of District Heat

5.11 The Government projects the consumption of district heat to increase at 2.8% p.a. during the period 1980-85, from 80.9 PJ (1.90 million toe) in 1980 to 92.8 PJ (2.17 million toe) in 1985. This rate of growth is projected to slow slightly to 2.4, p.a., so that in 1990, the heat supplied to district heating systems would amount to 104.3 PJ (2.44 million toe). This growth is considerably faster than projected for total final energy consumption, which is expected to increase at only 1.2% p.a. during 1980-85 and 1.4% p.a. in the period 1985-90 (para. 5.02). - 82 -

Table 5.4

Present and Estimated Future Coal Consumption /1 (in million tons)

Actual Projected 1982 1985 1990 1995 Power Generation and District Heating

Lignite 7.8 8.1 8.1 10.9 Brown coal 9.7 9.7 9.7 13.3 Hard coal 1.5 1.5 1.5 1.5

Households and Communal

Lignite 0.5 0.5 0.7 0.9 Brown coal 4.1 4.1 4.5 4.5 Hard coal 0.7 0.7 0.6 0.5 Imports 0.7 0.7 0.6 0.5

Steel

Hard coal 0.7 0.7 0.7 0.7 Imports /2 2.4 2.4 2.2 2.1

Cement

Brown coal 0.3 0.3 0.4 0.5 Hard coal 0.1 0.1 0.1 0.1

Other /3

Brown coal 0.6 0.6 0.6 0.6 Imports 0.1 0.1 0.1 0.1

Total Coal Consumption 29.2 29.5 29.8 36.2

of which lignite 8.3 8.6 8.8 11.8 brown coal 14.7 14.7 15.2 18.9 hard coal 3.0 3.0 2.9 2.8 imports 3.2 3.2 2.9 2.7

Consumption (million toe)

Lignite 1.3 1.3 1.4 1.8 Brown Coal 4.3 4.3 4.4 5.5 Hard Coal 1.0 1.0 1.1 0.9 Imports 2.1 2.1 1.9 1.8

8.7 8.7 8.7 10.0

Source: Mission estimates

/1 Consumption is on a primary energy basis. 77 About 63% coke, 37% coking coal. /3 other industries, transport, agriculture. - 83 -

5.12 It is difficult to judge whether the projected consumption of district heat is realist;,cwithout a breakdown of forecast consumption by sector and region. The low prices of district heat to households, compared to other fuels, would suggest that the consumption of households is essentially supply-constrained, i.e., as in the past, growth in demand would come from the connection of new consumers. Unless current pricing policies for district heat are changed, the consumption of heat by households would depend on the rate at which heat distribution networks are extended and the rate of construction of new apart:mentblocks.

B. Future Electricity Supply

Generation Planning Methodology

5.13 Generation planr,ing is carried out by EROTERV under contract to OEGH/IpM. The generation planning methodology has been evolving and EROTERV presently uses a conventional approach of evaluating the present value costs of alternative generation development programs. This simulation analysis leads to the least cost solution of meeting projected demand. The methodology gives basically the same results as the approach used later in this report (Annex 5.3). An important feature of the EROTERV methodology is that the model for simulating power system operation and calculating operating costs is interfaced with a fuel supply model, which takes account of physical constraints on fuel supply and the variation of coal mine production costs with mine output. The model also provides detailed analysis of power plant performance during the commissioning period and of power imports. The methodology is well suited for medium term planning and can also be used for long term planning, although this can prove combersome. EROTERV and IpM are now planning to acquire the IAEA WASP model to enable long term optimization studies to be carried out efficiently.

Programs for Expanding Generation

5.14 The future development of generation in Hungary can be divided into two periods: first, the medium-term period, 1983-90, for which decisions on new generating capacity have already been taken; and second, the long-term period, after 1990, for which the authorities have to resolve strategic issues such as choice of fuel type, total capacity, technology and timing of new generation projects. Developments in the medium term depend on the implementation and perfornance of projects currently under construction. In the longer term projects have two main objectives: to meet the growth demand; and to facilitate structural change in power and heat production by substituting indigenous low-cost fuels, e.g., coal, for expensive imported fuels such as oil, particularly in CHP applications. Scenarios for each of the two periods are discussed below.

Medium-Term Generation Development (1983-1990)

5.15 Generation development in the medium term is dominated by the completion of the Paks nuclear power station, situated on the Danube about 115 km south of Budapest. Four pressurized water nuclear reactors (PWR's) are - 84 - under construction, each with a gross electrical output of 440 MW, based on the Soviet VVER design. The first unit at Paks entered trial operation in December 1982 and operated successfully during 1983, producing about 2,400 GWh, a load factor of 62% which is good for a period that includes trial operation.

5.16 However, the Paks project has suffered from construction delays. The original contract with the USSR was signed in 1966 for an 800-MW station. In 1970 the contract was modified to increase the capacity to the present plan for 1,760 MW. Construction began in 1973 with the intention of commissioning the first unit in 1980. This entered full operation in mid-1983, a delay of almost three years caused by late deliveries by sub-contractors not used to either multinational projects, or unusual projects requiring strict quality control; and the prototype nature of the first Hungarian unit, which led to design modifications during construction. Completion of the remaining three reactors has also been delayed. Present plans call for the remaining three units to enter commercial operation in 1984, 1986 and 1989 (Table 5.5).

Table 5.5

Completion Dates of Paks Nuclear Power Station

Commercial First Trial Operation

Unit 1 Dec 82 June 83 Unit 2 Dec 83 Sept 84 Unit 3 June 86 Dec 86 Unit 4 Dec 88 June 89

Source: OEGH, mission estimates.

5.17 MVNT intends to retire about 100 MW of old plant during the period 1983-90 starting with the oil-fired Matra power station (75 MW) which has no CHP capability. Table 5.6 below shows the estimated capacity balance year by year for 1982-1990. During this period maximum demand on the interconnected system is projected to increase at 3.8% per annum. The Government forecasts imports to be 25% higher in 1985 than in 1982, but not to increase above the 1985 level.

Generation Development After 1990

5.18 The main options which the Government has been considering for meeting the growth in demand in the 1990's are:

(a) a lignite-fired mine-mouth power station at Bukkabrany with an ultimate capacity of 8 x 250 MW which involves a new open-cast lignite mine. The lignite has a low heat content, 6.7 GJ/t (1,600 kcal/kg), and high contents of water (46%), ash (21%) and sulphur (1.1%); - 85 -

Table 5.6

Projected Supply of Electricity 1982-1990 A (MW)

A1erae Rate of (Actual) Increme (X p.a.) 1982 1983 1984 1985 1986 1987 1988 1989 1990 1982-1990

A) Interconnected System

4mdnun DandM /2 5,439 5,650 5,870 6,100 6,330 6,570 6,810 7,070 7,330 3.8

Available Gross Caacity

Nuclear - 410 880 880 1,320 1,320 1,320 1,760 1,760 Stem /3 4,638 4,638 4,638 4,618 4,618 4,618 4,618 4,600 4,600 Gas turbine 202 2)2 202 202 202 202 202 202 202 Hydro 16 _16 16 16 16 16 16 16 16

Total 4,856 5,296 5,736 5,716 6,156 6,156 6,516 6,578 6,578 3.9

Purchasedfrom autoprqducers 184 123 123 123 123 123 123 123 123 -4.9

Imports from abroad 1,428 1,428 1,608 1,788 1,788 1,788 1,788 1,788 1,788 2.9

Total available 6,468 6,8S7 7,467 7,627 8,067 8,067 8,067 8,489 8,489 3.5

Reserve mrgin () /4 19 21 27 25 27 23 19 20 16

B) All IhrEary

Installed Capacity W4Mi/3 5,212 5,652 6,092 6,017 6,457 6,457 6,457 6,872 6,872 3.5 Autcnxkcrer, 461 461 461 461 461 461 461 461 461 -

Total 5,673 6,113 6,553 6,478 6,918 6,918 6,918 7,333 7,333 3.3

Sources: MM, CEM, mission estinates.

/1 Capa:ity in full cesrcial operation to mwet the auzal cimzndnd in December. /2 Maxmn deman figures are nt corrected to nuninal 50 Hz frequency. 7T Asumpd retirements are; 1985 Matra 75 J44 installed capacity, 20 !S7available capacity; 1989 25 W1installed (18 NI available capacity) retired. /4 Reserve mEtrgin defirned as difference betven total available asuply less nxmmiun dea2nd, divided by mnci n did. - 86 -

(b) a steam power station at Bicske burning residual brown coal from coal-washing plants. Coal would be transported to the station by belt conveyor and rail. This station would have an ultimate capacity of either 4 x 250 MW or 6 x 250 MW. One variant envisages a CHP station with a 35-km insulated pipeline to supply heat to Budapest. The brown coal would have a low heat value, 13.4 GJ/t (3,200 kcal/kg), a moisture content of 18% and high ash and sulphur contents of 32% and 3.15% respectively;

(c) a 2 x 1,000-MW extension of the Paks nuclear station. This would be a Soviet VVER PWR with a single 1,000-MW turbogenerator;

(d) a 4 x 300-MW pumped-storage power station on the Danube at Predikaloszek, north of Budapest. 1/

5.19 Other options exist for projects to meet the growth in demand. These are not being considered for the period 1990-2000 for technical, economic and environmental reasons. Such projects include:

(a) a 4 x 250-MW extension to the existing Gagarin lignite-fired power station, which would also involve an expansion of open-cast mining. This project is apparently less economic than developing a new lignite mine and power station at Biikkabrany because of the higher ratio of waste to coal and the lower heat content of the coal, compared to BiikkAbrany;

(b) a further 1,000-MW nuclear reactor at Paks;

(d) the Nagymaros-Gabcikovo hydro scheme on the Danube near the Hungarian-Czechoslovakian border. Two power stations are envisaged: a 8 x 90-MW station at Gabcikovo and a 6 x 27-MW station at Nagymaros. As well as providing power, the project is intended for flood control, improvements to navigation, and the supply of water for irrigation and population centers. Civil works began in the late 1970's but both parties have heretofore concentrated more on flood prevention works than the main hydro scheme. Apparently, the project was postponed because of lower electricity forecasts and financial constraints. Adverse public reaction in Hungary to the environmental consequences of the project has also been cited as a factor in the decision. 2/ Recent reports suggest that the project might be re-activated; and

I/ The pumped storage option would appear to depend on a sufficiently large nuclear program to provide cheap pumping energy during the night. As the WASP model did not show nuclear stations being commissioned this century, pumped storage was not considered an option at present. 2/ See Water Power and Dam Construction, March 1982 and May 1983. - 87 -

(e) a number of other hydro alternatives exist on the Drava River at the border with Yugoslavia. However, the mission understands that Hungary does not wish to finance these schemes and might agree to the Yugoslavs proceeding alone. Another multipurpose hydro project has been studied at Csongrad on the Tisza river in Hungary. Ihis project is apparently not a high priority.

5.20 The second type of generation projects have the objective of substituting coal for oil and gas. The main project being considered is the conversion of the Dunamenti power station. Several technical alternatives have been investigated fcr converting part of the power station to brown coal-firing, which would also maintain the supply of steam from the power station to the oil refinery at SzAzhalombatta. The power station at present burns vacuum residual from the refinery and natural gas. However, when the refinery configuration is changed to include catalytic cracking and is visbreaking, the supply of vacuum residual will be substantially diminished. The mission understands that constructing 2x800-t/h boilers and 2x180-MW turbogenerator units fuelled by brown coal was shown in the Budapest Heating Study to be referred to replacing boilers in the old part of the power station with coal-fired boilers. The new units would provide steam for the oil refinery and hot water to the Budapest district heating system. The boilers would be capable of supplying steam to the existing 250-MW turbines in summer, when one of the heat turbines would be shut down. Finally, there are a number of projects designed to replace old generating plant, to substitute for oil and gas and to meet increases in the district heating demand. These projects include:

(a) a 2 x 48-MW brown coal-fired CHP station which would supply the heat base load of 718 MW in the city of Gyor;

(b) a new 60-MW condensing replacement turbine at an existing power station near Miskolc. This unit would be supplied with steam from existing coal-fired boilers and would supply heat to the city of Miskolc by pipeline;

(d) other CHP projecl:s, Szolnok, Almafuzito, Obuda, Debrecon, NyiregyhAza and Kecskemet wit:h a combined electrical output of almost 100 MW.

Choice of Power Investmenl: Strategy

5.21 The central issue which the Government faces in the power subsector concerns the appropriate strategy for developing these power generation options so as to minimize the cost of the resources used to meet the demands for power and heat. The Government intends to complete economic analysis of the alternatives and take a decision on the next major power investment in mid 1984. Using the WASP III computer program the mission has evaluated power generation investments using preliminary data obtained from IpM and MVMT. The purpose of this study was to determine the least-cost generation program for Hungary based on this data as a contribution to the decision making process. - 88 -

The authorities could modify this least-cost program to take account of more information on investment costs, technical options, system operation and policy constraints to arrive at a specific course of action. Annex 5.3 describes the main assumptions and results obtained from the model.

5.22 Two strategies for generation development were evaluated. The first consists of CHP plant commissioned in 1991 which enables the large coal and nuclear power-only investments to be delayed. The second strategy gives priority to developing power-only plant with no new CHP plant being commissioned. "Optimal" solutions with respect to the data and assumptions of the model are shown in Table 5.7. As well as meeting the growth in electricity demand in the early 1990's, the CHP strategy would lead to a major restructuring of heat producton capacity. A major benefit of the CHP strategy would be to substitute brown coal based CHP heat producton for the production of heat in oil or gas fired boilers. A preliminary economic analysis of the CHP and power-only strategies, which is described in Annex 5.3, indicates that the CHP strategy is probably preferred to the power-only strategy, providing that the benefits of fuel savings in district heating are evaluated at international prices. Nine CHP projects were evaluated as one and it is possible that some of these might not feature in a least cost investment program. Eliminating such projects would increase the apparent advantage of the CHP strategy. Moreover, the timing of each individual project should also be evaluated. It is recommended that the Government complete studies to evaluate the role of each of the CHP projects in least-cost development programs for electric power and heat supply and prepare detailed feasibility studies for those projects in the least-cost programs.

5.23 After the CHP plants are commissioned, the mission concludes that, based on the capital and fuel cost data given to the mission, the BiikkAbrany lignite-fired station would be the least cost power-only investment. For the no CHP strategy the conclusion is the same, except that construction would be advanced by two years. After BUkk&brany is completed the Bicske brown coal fired power station would be preferred to another lignite station (Table 5.7), although this should be reviewed when better cost estimates are available for lignite projects at Visonta and Torony. In particular, preliminary estimates indicate that the marginal costs of brown coal and lignite might be 30% and 35% respectively above the financial costs of coal (see Annex 6.8). This highlights the need for a study to establish the economic cost of coal and lignite that would, inter alia, consider the appropriate foreign exchange costs. It is recommended that the Government complete studies to confirm that the BiikkAbrAny project is the best power-only alternative and carry out detailed feasibility studies to prepare both the lignite mine and power station. If mine construction takes 7 years and the power station is required for 1995, the feasibility studies should be completed by early 1986.

5.24 Role of Nuclear Power: A clear conclusion of the mission's study is that 1,000 MW nuclear units are a low priority at present. A 1,000 MW nuclear unit entered the optimal solution only when its capital cost was cut by 25%. These nuclear units did not enter the solution when coal and lignite capital costs were increased by 20%, or when the prices of brown coal and lignite were raised by 30% and 35% respectively to what would be an approximate magnitude of their marginal costs. Even when its capital cost was cut by 25%, a - 89 -

Table 5.7

Summary Results of Generation Planning Studies

Year CHP Strategy No CHP Strategy

1991 Dunamenti 2x180 MW No Additions Gy-or 2x48 MW North Pest 2x23 MW, 2x46 MW Almasfuzito 14MW,,Szolnok 14 MW C\Obuda46 MW, Debrecen 8.6 MW ,Nyiregyhiza 9.6 MW, Kecskemet 7 MW

1992 No Additions Gas Turbine 1 100 MW

1993 No Additions Bukkabrany 1 250 MW Gas Turbine 2 100 MW

1994 No Additions BUkkabrany 2, 3 2x250 MW

1995 Buikkabrany1 250 MW Biikkabrany4 250 MW Gas Turbine 1 100 MW

1996 BukkabrAny 2 250 MW BukkAbrAny 5 250 MW

1997 BUkkhbrhny 3 250 MW BiikkAbrany6, 7 2x250 MW

1998 BUkkabrany 4, 5 2x 250 MW Bukkabrany 8 250 MW

1999 BUkkAbrany 6 250 MW Bicske 1 250 MW

2000 BtikkAbrany7, 8 2x250 MW Bicske 2, 3 2x250 MW

2001 Gas Turbines 2, 3 2xlO0 MW Gas Turbines 3, 4 2xlO0 MW

2002 Bicske 1 250 MW Bicske 4 250 MW

2003 Bicske 2 250 MW Lignite B 1 250 MW

2004 Bicske 3 250 MW Lignite B 2 250 MW Gas Turbine 5 100 MW

2005 Bicske 4 250 MW Lignite B 3 250 MW

2006 Lignite B 1 250 MW Lignite B 4 250 MW Gas Turbine 4 100 MW

2007 Lignite B 2 250 MW Gas Turbines 6,7 2xlO0 MW

2008 Lignite B 3 250 MW Gas Turbines 8,9 2xlO0 MW

2009 Lignite B 4 250 MW Nuclear 1,000 MW

2010 Gas Turbines 5,6,7 3xlO0 MW Gas Turbines 5,6,7 3xlO0 MW

Source: Annex 5.3. - 90 -

1,000 MW nuclear unit entered the solution only in 2006 after the Biikkabrany and Bicske projects are completed. A 1,000 MW nuclear plant enters the no CHP program in 2009, but this is almost certainly because no further coal options were available to the model. 1/ The conclusion that further 1,000 MW nuclear stations are a low priority was reached despite two assumptions favorable to them, viz:

(a) Hungarian planning studies used a capital cost for 1,000 MW units of US$1,120/kW at 1983 prices, excluding initial fuel, interest during construction, price escalation and taxes and duties and this figure was used in the analysis carried out by the mission. This cost is only 69% of the IAEA base estimate of US$l,620/kW on a comparable basis and below the IAEA lower bound estimate of US$1,235/kW, possibly because of distortions to the relevant exchange rates; and

(b) Planning studies in Hungary, as well as the mission's analysis, have assumed an availability (load factor) of 76% for VVER 1,000-MW stations, which is considerably more than the world average of 59% for PWR's with a capacity greater than 700 MW. Considering that only one VVER 1,000-MW is in operation, it would not appear prudent to assume a load factor substantially above the world PWR experience except on the basis of proven experience over a reasonable number of reactor years.

5.25 The principle reason why the 1,000 MW nuclear option did not feature in the optimal solution was its long construction period and the high 12% discount rate used for project appraisal in Hungary. A construction period of 9 years was assumed by the mission, roughly the same as the IAEA average of 100 months for reactors under construction (Annex 5.2), with some allowance for delay arising from the station being first of its type in Hungary. There are several reasons why the mission believes that it is unlikely that a VVER-1,000 MW station could be commissioned in less than 9 years. Construction of the Paks station has been delayed by almost three years (para. 5.16). Similar delays might arise with further nuclear power stations. According to reports in the Soviet press, production difficulties have arisen at the Atommash plant at Volgodonsk which manufactures components for VVER 1,000-MW nuclear power stations. These problems have attracted the attention of the highest levels of the Soviet Government 2/ and have led to delays in deliveries of components for some of the eight 1,000-MW nuclear power stations under construction. 3/ Moreover, a recent article by the Soviet first deputy minister of power and electrification criticized the lack of standardization in the designs for

1/ In the WASP analysis used to calculate power LRMC's an additional coal-fired station burning imported coal priced at US$65/ton (US$2.39/GJ) was preferred to a nuclear station after the two lignite and Bicske options had been taken. 2/ Pravda, July 16, 1983; Pravda, July 20, 1983. 3/ Sotsialisticheskaya Industriya, October 16, 1982, Sovetskaya Rossiya, October 20, 1983. - 91 -

VVER 1,000 MW stations and problems in quality control and site management. He recognized that Plan targets for completing nuclear power station are not being achieved. 1/ Finally, designs would probably require some adaptation to Hungarian conditions and contractors would take time to become familiar with the new technology, as was the case with Paks 1. At 12% discount rate, the equivalent cost of the nuclear project when the annual capital cost cash flows are compounded to the commissioning date (equivalent to economic "interest during construction") is about 86% higher than the simple sum of the capital cost cash flows. By contrast, the five-year construction period commonly achieved for coal or lignite-fired units results in economic "interest during construction" of only 39% (Annex 5.3, Table 2). These percentages would be lower at lower discount rates. At 12% discount rate nuclear is put at a considerable disadvantage compared to coal or lignite. The sensitivity analysis whereby the nuclear construction time was reduced by 25% to put nuclear in the optimum solution would be equivalent to a construction period of 5 years which has only been achieved by three countries and would be unlikely for the first reactor of its type in Hungary. It is therefore recommended that 1,000 MW nuclear units be given a low priority at present, but that the prices and construction performance of potential vendors be monitored so that nuclear can be re-considered as an option for after the Biikkabranyproject.

5.26 Role of Power 'Imports: The model used the Government projection for net imports of elecitricity to increase from 8,510 GWh (1,312 MW) in 1982 to 10,160 GWh (1,738 MW) in 1985 and then remain constant for the remainder of the century. The minimum level of imports over this period is about 1,100 MW, set by contract into the next century (para 4.28). The maximum in the medium term would be set by the technical capacity of the interconnectors, about 2,500 MW. Allowing for the 400 MW available for emergency import to cover the loss of generating units in Hungary, imports could technically increase to about 2,250 MW, or 312 MW above the level contracted for 1985. However, the low frequency on the OES indicates a shortage of generating capacity among the CMEA countries (para. 4.26), and the production problems apparently affecting the Soviet nuclear program (para. 5.25) suggest that spare capacity for additional imports to Hungary may not be available during, say, the next 10 years. Moreover, it is probably economic to import below the technical limit, in order to enable additional short-term imports to cover for errors in demand forecasting and construction delays, i.e., to allow generation reserves to be shared among the OES partners to minimize these risks. Finally, the mission was informed that the cost of additional imports to Hungary was likely to be similar to the cost of local generation in Hungary, since additional imports would originate from Soviet power stations with similar operating costs to power stations in Hungary. For these reasons, imports above the level contracted for 1985 do not appear to be an option. Information on the savings from a lower level of imports was not available to the mission. However, the savings per kWh are probably below the marginal cost of generation in Hungary and the Government should confirm this when negotiating imports for the period 1990-94.

1/ Sovetskaya Rossiya, October 5, 1983. - 92 -

5.27 Retirement of Old Plant: As described in para. 4.20, there is about 2,000 MW of steam plant that was commissioned before 1970 and will therefore be at least 30 years old by the end of the century. There is no fixed age for power stations beyond which they must be retired. A rational retirement policy would de-commission stations when their anticipated operating costs, including any necessary refurbishment, exceeds the costs of providing their output by bringing forward the least-cost investment program. Retirement decisions for MVMT's old power stations are complicated by the fact that about 20 out of the 25 stations that are candidates for closure have some CHP capability. MVMT's retirement policy is to replace old CHP plant by CHP units of similar capacity and this was the assumption used in the model. However, it might be economic in some cases to increase the ratio of power to heat or vice versa, or even to discontinue both power and heat production at the site. Because of the large amount of plant that needs consideration for retirement, or refurbishment it is recommended that MVMT commission studies to decide the future role of old power stations, taking into account the heat supply requirements. Such a study should be undertaken in conjunction with the formulation of a long-term investment programs for electric power and district heating systems (paras. 5.13 and 5.53).

5.28 Power Turbogenerator Unit Sizes: A unit size of 250 MW is being used for coal and lignite-fired plant in current planning studies. The 250-MW turbine is the maximum size produced by the Hungarian manufacturer (Lang) under the current license from a West European company (BBC). If Hungary were to procure power plant internationally, a larger unit size might be more economic for power production. Since there is worldwide overcapacity among manufacturers of large (500-MW and above) turbo-generators, it is probably not worth Hungary obtaining this manufacturing capability, unless it sees favorable long-term market opportunities in CMEA countries. Labor costs which appear low in Hungary compared to European and developing countries in the region, and the low cost of Hungarian lignite and coal compared to oil, offset the potential economics of scale of large units. Although the Government has reportedly studied the economics of larger units and found them uneconomic it would appear worth re-examining this during the feasibility study for the Bukkabrany project.

5.29 Risk, Uncertainty and Reserve Margins: The CHP projects are justified primarily on the grounds of fuel savings and their timing is consequently insensitive to errors in the electricity demand forecast. With the CHP strategy no power-only plant is required until 1995. Should demand grow faster or slower than expected, there would be ample time to adjust the generation program.

5.30 A conclusion of the WASP studies was that there is a need for peaking plant to be installed during the planning period. This is not surprising considering that the Paks nuclear station under construction and the Biikkabrany and Bicske stations are all base load plants. An assumption in the model was that 400 MW of emergency imports would be available above the contracted imports. Should these emergency imports not - 93 - be available, it is highly likely that additional gas turbine plant would b'e required during the period 1991-95 (Annex 5.3). In the planning studies it has been assumed that peaking plant would consist of gas turbines. Combined cycle plant iS an option we have not considered and CHP variations are a possibility. Although combined cycle plant usually has an operating regime between base load and peaking plant, this option might change the number of gas turbines and delay coal investment. It is recommended that the economics of combined cycle plant be evaluated, particularly if natural gas is available at a cost to the national economy below that of gas oil.

5.31 An additional finding of the model was that the present system reliability standard oE 50 hours/a of load shedding may be too high in relation to the IpM estimate of the cost of unserved energy of US$l.5/kWh. The model selected an optimal loss of coal probability of about 1.09% (95 hours/a). However, as there is already significant load shedding due to the low frequency of the OES system, unserved energy may represent disconnections rather t:han load shedding through frequency and voltage reduction. Nevertheless, the Government should re-appraise both the estimate of the cost of outages and the system reliability standard.

Supply Projections

5.32 Projections of power generating capacity are shown in Table 5.8 and net generation and fuel consumption in Table 5.9. This scenario indicates a slow transformation of the public power system towards nuclear generation in the late 1980's, brown coal based CHP production after 1991 and lignite up to the end of the century. Gas and oil plant would be used more intensively for a period after Paks is completed and before the first units of the Bukkabrany lignite station are commissioned. After 1995 gas and oil based generation is likely to decline to around 21% of total generation in 2000, cormpared to about 25% of total generation in 1990, after which its output remains constant and its share declines. The completion of nuclear, coal and lignite projects will gradually restructure electricity production. As Paks comes on stream oil and gas consumption would fall from 3.8 miLlion toe in 1982 to 2.4 million in 1985 before increasing again to 3.4 million toe in 1995. After commissioning of the Bukkabrany lignite units has begun, oil and gas consumption would gradually decline. Oil and gas are therefore likely to remain significant fuels for power generation for the next 10 years, but their consumption is likely to remain below the levels of the early 1980's. Reserve margins are projected to be low at around 13% in the mid 1990's, mainly because high reliability imports are projected to amount to more than 20% of available capacity.

Transmission Development

5.33 Table 5.10 shows the expansion of the transmission system until the end of the century. The main 400-kV transmission system is projected to increase at a faster rate than maximum demand, but this may be due to the connection of new power stations to load centers. The 120-kV primary distribution system is projected to grow at a slower rate than maximum demand. However, the capacity of local distribution systems could increase - 94 -

Table 5.8

Lorg-Tenn Generation, Pograe

Macimun Demand 1990 1991 1992 1993 199 1995 1996 1997 1998 1999 200)

Available Net Capaity

Nu.lear 1,620 1,620 1,620 1,620 1,620 1,620 1,620 1,620 1,620 1,620 1,620

Steam (oil/gas) 2,447 2,447 2,447 2,447 2,447 2,447 2,447 2,447 2,447 2,447 2,447

Stean (lignite) 776 776 776 776 776 1,007 1,238 1,469 1,931 2,162 2,624

Stean (brown coal) 723 723 723 723 723 723 723 723 723 723 723

CQP 451 1,043 1,043 1,043 1,043 1,043 1,043 1,043 1,043 1,043 1,043 Gas turbirs & eirger y inports 590 590 590 590 590 690 690 690 690 690 690

Hydro 16 16 16 16 16 16 16 16 16 16 16

Inports 1,788 1,788 1,788 1,788 1,788 1,788 1,788 1,788 1,788 1,788 1,788

Total Available 8,352 9,003 9,003 9,003 9,003 9,334 9,565 9,796 10,258 10,489 10,951

Reserve margin (%) 21 26 22 17 13 13 13 12 13 12 14

Loss of Load Probability (%) 0.152 0.019 0.067 0.224 0.655 0.698 0.904 1.165 0.889 1.184 0.958

Source: Amex 5.3

I - 95 -

Table 5.9

Projected Generation ari Fuel Consuption, WM 1985-2005

% Share 1985 1990 1995 2000 2005 1985 1990 1995 2000 2005

Net Gernration (GWh)

Nuclear 5,111 10,223 10,223 10,223 10,223 15 25 21 18 16 Hydro 130 130 130 13D 130 - - - - - Lignite and black coal steam 5,205 5,191 6,764 17,583 17,667 15 12 14 30 28 Brown coal stean 2,615 2,631 3,223 2,818 9,363 8 6 6 5 15 Natural gas/oil stean 9,692 11,558 14,030 12,113 11,519 28 27 28 21 18 Gas turbines /1 - 16 84 86 139 - - - - - CHP 1,702 1,702 5,012 5,012 5,012 5 4 10 9 8 Imports 10,160 10,160 10,160 10,160 10,160 29 24 20 17 16

Total 34,615 41,609 49,624 58,124 64,214 100 10) 100 100 100

Unserved energy - 0.9 6.4 9.4 10.5 0.0000 0.0022 0.0129 0.0162 0.0164

Fuel Consupticn (toe million)

Lignite 1.24 1.23 1.67 4.65 4.68 20 18 18 40 35 Bnrn coal 2.16 2.17 3.74 3.57 5.49 34 32 40 30 41 Black coal 0.53 0.52 0.53 0.52 0.51 8 8 6 4 4 Natural gas/fuel oil 2.39 2.79 3.39 2.93 2.80 38 42 36 25 21 Gas oil - - 0.04 0.06 0.06 - - - - -

Total 6.32 6.71 9.37 11.73 13.54 100 100 100 100 100

Fuel Cnmpticn (ton million)

Lignite 8.1 8.1 10.9 29.9 30.1 Brown coal 7.7 7.7 13.3 12.7 19.5 Black coal 1.5 1.5 1.5 1.4 1.5 Fuel oil equivalent /2 2.5 2.9 3.6 3.1 3.0 Gas oil - - - 0.1 0.1

Source: Mission estimates.

/1 Inrcludes enargem2y inports.

/2 Includes natural gas. - 96 - because of the greater load carrying capability of a 120-kV system compared to lower voltage levels. The distribution investment program should be reviewed as part of an investigation into system losses (para. 4.38), since loss reduction at the MV and LV voltage levels could result in substantial savings in fuel and generation and transmission investment

Table 5.10

Transmission Development, 1982-2000

Rate of Increase (% p.a.) 1982 1990 2000 1982-90 1990-2000

Trananission lines 750 kV 268 268 268 - (km.) 400 kV 1,065 1,620 2,600 5.4 4.8 220 kV 1,400 1,270 1,270 -1.2 - 120 kV 6,10 6,900 8,700 1.6 2.3

Total 8,833 10,058 12,838 1.6 2.5

Transfomers 750/400 kV 1,100 MvA 2 2 2 - (No.) 400/220 kV 500 MVA 2 2 2 - - 400/120 kV 250 MVA 12 21 39 7.2 6.4 220/120 kV 160 MVA 29 25 27 -1.8 0.8

Substations 750/400 kV 1 1 1 (No.) EHV/HV 27 29 37 -1.8 2.5 120 kV/MV 225 270 350 2.3 2.6

Maxirn= Demand (MW) 5,439 7,330 10,250 3.8 3.4

Source: MVMT - 97 -

C. Future Coal Supply

DevelopmentStrategy

5.34 The Government'scoal development strategy forms part of its energy policy aims for replacing oil and gas consumptionby coal. After the decline of the coal industry during the late 1960's and early 1970's, long-term plans now call for a stabilizationand even modest increase in the coal production. This reversal in policy was brought about by the increasingprices of imported hydrocarbonfuels. The main goals for coal subsectorinvestment are to: (a) mechanize and modernize existing mines; (b) prepare projects sufficiently in advance of the exploitationof new coal reserves; (c) develop a few new modern mines not only to replace either depleting or uneconomic old mines, but also to contributeto a modest expansion of production; (d) improve existing coal-washingand briquetting facilities for better quality coal products and install new coal-washingcapacity to cope with the decreasingquality of run-off-minecoal due to mechanization;(e) expand the supply of better quality coal products from domestic resources to households and industry;and (f) expand the use of low-qualitycoal to industry and households through the introduction of improved combustion technology.

5.35 To achieve the goals of the coal developmentstrategy, the Government establishedand has started to implement two major developmentprograms, the Eocene 1/ and Lias 2/ programs. In addition,most coal-miningcompanies have also started their own investmentswith the same objectives. The Eocene program was started in 1976 and aims at arresting the decline of production in the major West Hungarian brown coal fields. The Dorog, Vezprem, Nograd and Borsod mining companies are undertaking,with Government support, their own investmentswith the samaeobjective. Estimated costs of the Government- sponsoredEocene program are about US$40O million (US$250million of which have already been spent) and in addition, the companies' investmentamounts to TJS$190 million.

5.36 The investmentsstill to be completed for brown coal represent an additionalmining capacity of 6.8 million tons per year from 1982 until the end of this decade. Average capital costs in financial terms are US$67 per ton per year. This is Lower than for a greenfieldproject outside Hungary, and reflects both the excistenceof infrastructureand the low level of prices for equipment and labor.. Only a portion of the 6.8 million tons capacity will be a net addition since a major part will be needed to replace depleting old mines. No detailed figureswere however given on the rate of depletion of old mines and this should be studied further before any new brown coal mine investmentsare decided. The mission was told that implementationof the investmentswas in general on schedule and within estimated costs. All projects should be compLeted before 1990.

5.37 The Government"sLias program was started only in 1982 and was originallyexpected to 'Last10 years. It aims at maintaining and slightly

1/ Named after the Eocene geological formation which carries the brown coal seams of the areas west of Budapest (Dorog,Tatabanya, Oroszlany). 2/ Named after the Lias geological formation which carries the hard coal seams in South Hungary (Mecsek Hills near Pecs). - 98 - expanding the production from the difficult hard coal mines of the Mecsek company. Present production of about 3 million tons per year would be increased by about 0.4 million tons. The Government sees the maintenance and slight increase of the local supply of coking coal to the steel industry as a major justification of the Lias program. Total costs are about US$580 million which would have to be augmented by a further US$180 million investment by the company. The Lias program would raise the cost of hard coal to about US$2.8/GJ assuming that the productive life of the investment program would be 30 years. The coking coal can only be recovered to about 25% from the raw coal and its quality is relatively low. Traded coking coal of good quality in Western markets has a price premium of only 10%-15% above steam coal. An imported mix of 75% steam coal and 25% coking coal would not exceed a price of about US$2.7/GJ. The mission is therefore of the opinion that the economic viability of the Lias program in its present form is very doubtful. In addition, the Lias hard coal program has slipped behind schedule and, in its original form, cannot be completed by 1992 as previously planned. The Government and the Mecsek colliery have now recognized the need for an economically justified Lias program and have therefore embarked on a major cost reduction program. It is reconmnendedthat this cost reduction program should consider the areas of new mine construction, transport of coal, and modification of beneficiation plants, as well as alternative sources for coke and coking coal, and that its planning and implementation should be accelerated.

5.38 A summary overview of the present investment program for major projects is presented in Table 5.11.

Table 5.11

Present Inestnt Program

Cac:ity already Estimated installed Capacity /2 Capital Ilplaentation by end 1982 Expendittures Addition Cost Start Full milliam irrurred up Million Ton Us$ GCostnxt. Prod. tons to end 1982 Per Year Million Date Date per year _US$ million

BrownCoal

(a) EOCEw progran - Tatabanya 3.1 277 Late 1970s 1988 0.6 148 - Oroszlarny 2.4 123 1977 1988 1.0 102

(b) Caipanies' progrm - Dorng 1.0 80 1982 1988 - 10 - Veszpren 0.2 45 1979 1985 - 15 - Nograd 0.7 18 1982 n.a. - n.a. - Borsod 1.0 20 1977 1985 - n.a.

Total Brown Coal 8.4 563 1977 1988 1.6 approx. 190

Hard Coal

LIAS program - Mezsek 0.4 /3 580 1982 1992 - n.a. inor

Sources: Coal Companies, C&A2, KEFI.

/1 O0-szlhrb Go. expects no increase in production uritil 1990 and tbereafter despite irnrease fron new Eucene mine. Tatab&ya, the otber major Eocene beneficiary, stated that reserves in old mines are critically low and new Eccene prduction would be urgently needed for replacement. /2 &r-of-mine coal, real increase will be reduced due to d4leted mines, rm figures on depletion available. /3 In additin, the existizr pmducztionlevel of 3.0 million tao per year will be isirtained. - 99 -

5.39 Possible additional future projects which would supply coal in the 1990's were indicated to the mission by the mining companies, KBFI and the Ministry of Industry. Hcwever, the Government has not yet decided which of these projects should be implemented. They may be grouped into three categories as shown in Table 5.12 below.

Table 5.12

Possible Additional Coal Investment Options

Capacity Addition (million tons Mine/Project Company per year)

Investments to maintain or expand production of existing mines

Lignite Ihorez Matraalja O /1 - 10.0 Brown Coal Borokas Dorog 1.0 Kerekdomb Dorog 2.0 Feketevolgy Borsod n.a. Ljukob&nya Borsod n.a.

Investments for new mines

Lignite Biikkabrgny (still to be formed) 10.0 /2 - 21.0 Torony (still to be formed) 20.0 Brown Coal Many II Tatabanya 3.0 Bokod II Oroszlany n.a. Aijka II Veszprem 3.0 Mizserfa II Nograd 0.7 Dubicanji Borsod 2.2 Hard Coal Maza South (still to be formed) 4.0 - 7.5

Investments for coal-processing plants

Lignite briquetting, Matraalja 0.5 Brown coal briquetting, Dorog 0.3 Brown coal coking, Tatabanya 0.3 Coking coal flotation II, Mecsek 0.2

Sources: Coal Companies, OEGH, KBFI.

/1 Option without expansion, just maintaining present production. /2 Likely option for the mid-1990's

5.40 Capital cost as well as production cost data prepared by KBFI for some of the above projects were given verbally to the mission by different institutions. There are inconsistencies when comparing these cost data among - 100 - each other and with data from existing mines. The preparation status of all these projects is not fully known to the mission. Since no feasibility studies were released to the mission there remains a doubt that some of the projects may not be sufficiently prepared for implementation.

5.41 In view of the limited market prospects and the projects which are already being implemented, the output from all these additional projects is clearly excessive, and most of the projects probably require further preparation and therefore cannot be candidates for early implementation. However, some projects would appear to have economic priority, e.g., maintaining production from the Thorez open-pit lignite mine, and from existing mines at Borsod. Without information on the depletion of existing mines it is not possible to estimate the timing of these projects.

5.42 In view of the limited demand, the number of brown coal projects being considered for implementation appears too large. A priority ranking of these projects as well as a better definition of the market for brown coal appear necessary. The depletion rate of existing mines would, to a great extent, determine the timing of new mine projects and partly also their priority ranking. The economics of replacing a portion of the household brown coal supplies by briquettes and coke manufactured from low-cost open-pit mined lignite have not yet been determined. Therefore, it is recommended that: (a) the depletion rates of existing brown coal mines be determined; (b) the economics of briquette and coke manufacture from open-pit mined lignite be investigated through tests and studies; (c) the economic cost of brown coal production from the various possible projects be determined; and (d) a least-cost brown coal development program be established.

5.43 Information received from the Ministry of Industry indicated that the Bicske brown coal option was initially preferred to Biikkabrany lignite for power generation. An advantage of the Bicske (brown coal) option for power generation compared to BiikkAbrany lignite was that this project could supply district heat to Budapest, in addition to the possibility of recovering a coal fraction suitable for households from the raw coal before it is sent to the power plant. However, an evaluation of costs obtained by the mission indicate that the LRMC of coal from the BukkAbrany pit is only UStl.4/GJ (US$34/toe), compared to about US$2.0/GJ (US$73/toe) for brown coal (paras. 6.13-6.14). This difference in the cost of coal would tend to favor the lignite option, especially as the Bicske power station does not appear to be the least-cost means of supplying heat to Budapest. Another reason put forward for the Bicske project has been that without the project the existing mining tradition and the current employment opportunity in the Tatabanya area would be lost, and in the medium and long term it would lead to a further decline of mining activities in the area. However, even without the Bicske project, coal production in the Tatabanya area would remain at the present or an even slightly higher level into at least the mid-1990's (Table 5.13). It is therefore recommended that the option of constructing a power plant at Bicske be given up in favor of constructing a lignite power plant at Biikkabrany, and/or a brown coal CHP plant at Dunamenti. It is further recommended that the feasibility of the BUkk&brany mine, in particular the phasing of bringing it into production, be evaluated in detail. - 101 -

5.44 In order to define the future investment program, the mission recommends developing a sl:rategy for each of the three coal types based on economic and technical considerations. The existing project ideas should then be reviewed for their conformity with this strategy. Several reviews of sectorial issues as well as studies of specific, most promising projects will be necessary. The mission's views on the development of the three coal subsectors are as follows,

- Lignite: large reserves, low production cost and limited other uses make this resource a prime candidate for large-scale, mine-mouth based power generation projects;

- Brown Coal: more difficult mining conditions, higher production cost and limited reserves which are mineable at lower cost restrict the development of this resource. Due to the low quality of the coal, any significant expansion of the household and general industrial markets cannot be expected. Therefore, the continuation of the present policy, t:omodernize existing mines and develop new mines for replacement of depleting mines and for some expansion, if needed, appears to be the best strategy;

- Hard Coal: difficult mining conditions, which allow mechanization only at a high cost and with relatively low production and productivity, are a serious constraint for further development of this resource. The first phase of the coal washing plant included in the Lias program is justified economically on the basis of the recovery of a coking coal fraction from this coal. However, before further major investments are made for the development of hard coal, imports of coke and coking coal as well as limited semi-coke production from lower-cost Hungarian coal should be considered as alternatives. Semi-coke from brown coal or lignite may be suitable for replacing coke in the sintering process of iron ore. Fine coke from brown coal or lignite may also be suitable for direct injection into the blast furnace.

5.45 Therefore, the mission proposes a development strategy which would basically consist of: (a) expansion of lignite mining for power generation and limited non-power use of lignite; (b) modest, near zero, expansion of brown coal; and (c) gradual reduction in hard coal mining.

Projected Coal Supply

5.46 Based on the proposed strategy, the mission has developed a forecast of coal supply as outlined below and illustrated in Table 5.13. - 102 -

Table 5.13

Future Coal Supply, 1982-1995

Actual Projected 1982 1985 1990 1995

Production (million tons)

Lignite Matraalja (Thorez) 7.3 7.6 7.8 8.0 Bukkabrany - - - 3.0 Veszprem 1.0 1.0 1.0 0.8 Total Lignite 8.3 8.6 8.8 11.8

Brown Coal Dorog 0.5 0.5 1.0 1.0 Tatabanya 2.3 2.3 2.3 6.0 Oroszlany 3.1 3.1 3.3 3.3 Vezprem 2.6 2.6 2.6 2.6 Nograd 1.0 1.0 0.8 0.8 Borsod 5.2 5.2 5.2 5.2 Total Brown Coal 14.7 14.7 /1 15.2 18.9

Hard Coal Mecsek 3.0 3.0 2.9 /2 2.8 /2 Total Production 26.0 2 -67 36.7 -

Imports (million tons) Coking coal 1.5 1.5 1.4 1.4 Coke 1.0 1.0 0.9 0.7 Briquettes 0.7 0.7 0.6 0.6 Total Imports 3.2 3.2 2.9 2.7

Total Supply 29.2 29.5 29.8 36.2

Total Supply (million toe) Production - Lignite 1.3 1.3 1.4 1.8 - Brown Coal 4.3 4.3 4.4 5.5 - Hard Coal 1.0 1.0 1.0 0.9 - Total 6.6 6.6 6.8 8.2

Imports - Coking coal 0.9 0.9 0.8 0.8 - Coke 0.7 0.7 0.7 0.6 - Briquettes 0.5 0.5 0.4 0.4 - Total 2.1 2.1 1.9 1.8

Total Supply 8.7 8.7 8.7 10.0

Source: Mission estimates.

/1 Any increase in production from new mines would be offset by reduction from depleting mines. /2 Assumes modified Lias program. Without any investment, the decline in production would be steeper. - 103 -

5.47 Lignite production would increase slowly due to better utilization of the Gagarin power plant and possibly some manufacture of briquettes and coke from open-pit mined lignite. A moderate expansion of the Thorez open pit, which in any case has to install some additional equipment due to increasing overburden, would be reqiired. It is assumed that the Biikkabrany lignite-fired power station would be the least-cost means of meeting the additional demand for power in the second half of the 1990's, although this would need to be confirmed by detailed economic studies (para. 5.23). This lignite mine would account for nearly half of the projected increase in coal supply (on a weight basi,).

5.48 Brown coal production would be expected to rise in the early 1990's if power and heat plants are converted to coal. In that case, a revised version of the already long-prepared Many II project (Tatabanya company) could be implemented. This mine would be relatively close to the major new coal consumer after conversion (Dunamenti power plant). The Bokod II project (oroszlgny) is an alternative which should be evaluated. In any case, before deciding on a new project, it would be necessary to clearly identify the depletion rate of older mines since this would determine the net capacity addition which could be achieved from projects under construction. 1/

5.49 Hard coal production is estimated to decline due to the depletion of existing mines and the high cost of replacing their production. It is assumed that a modified Lias program will slow the decline of production, so that in the mid-1990's, the production will still be near the present level. The modified Lias program would only contain investments (mostly for underground development) which are necessary to prevent a rapid decline in the production and would avoid a steep increase in production cost.

D. Future Supply of District Heat

Priorities for District Heat Supply

5.50 The Government recognizes that much of the district heat production capacity is no longer economic at present fuel prices. It has prepared a number of projects to, first, increase the proportion of heat produced from CHP plant and second, to substitute coal for oil and gas in heat production. These projects are located in the cities of Budapest, Almasfuizito,Debrecen, Gyor, Kecskemet, Miskolc/Borsod, Nyiregyhaza, Sopron and Szolnok.

Supply of Heat to Budapest

5.51 A major study of district heating in Budapest was competently carried out by EGI and completed in 1983. The study concluded that the most economic option for heat supply was to supply Budapest via a 25-km pipeline, from two new coal-fired CHP turbines at the Dunamenti power station. The main

l/ Lencsehegy II (Dorog Co.), Nagyegyhaza and Many I (Tatabanya Co.), Markushegy (Oroszlany Co.), Dudar/Balinka (Vezprem Co.), Kanyas (Nograd Co.), Putnok (Borsod Co.). - 104 - alternative to Dunamenti was some CHP capability at the proposed 1,000-MW Bicske power station, which would require a 35-km pipeline to Budapest. In addition, a new CHP station in North Pest (138 MW) would supply adjacent industrial areas. These projects would be completed in the early 1990's and represent the major investments in heat supply in Budapest.

5.52 Projects for restructuring district heat supply in Gyor, Miskolc, Szolnok, Almasfuzito, Obuda, Debrecen, Nyiregyhaza and Kecskemet have been identified and are in various stages of preparation. Almost all of these projects involve heat from coal-fired CHP stations substituting for heat produced in gas or oil-fired boiler stations. These projects are described in Annex 5.4 and summarized in Table 5.14 below.

Table 5.14

Proposed Heat Supply Projects /1

Power Peak Heat Heat Fuel Con- Investment Capacity Demand Production sumption Cost Location (MW) (MW) (PJ/a) (PJ/a) (US$ million /2

Dunamenti 360 3,117 16.6 34.0 478 Gybr 96 718 4.4 7.6 153 North Pest 138 1,373 8.2 13.9 1,963 Miskolc 60 383 3.0 2.7 61 Szolnok 14 194 1.7 2.5 43 Almasfuzito 14 98 2.3 2.5 18 Obuda 46 363 1.9 3.2 30 Sopron - 134 0.7 0.8 11 Debrecen 9 397 - 3 Nyiregyhaza 10 271 - - 2 Kecskemet 7 150 1.7 1.7 21

Source: EGI (see Annex 5.4).

/1 Some of these projects are rehabilitations or replacements at existing stations. Capacity and fuel consumption figures are the incremental quantities attributable to the project. /2 Costs are in January 1983 prices, converted at US$1.00 = Ft 40.

Issues in Future Heat Supply

5.53 Investment Priorities: Although projects have been prepared to rationalize district heat supply in nine cities (para 5.52), to the mission's knowledge these have not been arranged in priority in a long-term investment program. This would identify the timing of these projects as part of the least-cost development of individual heating systems, as well as for the heating subsector as a whole. Such a program could be used for allocating scarce financial resources to the sector and investigating the interaction - 105 - between district heating and other subsectors, e.g., electric power. It would also serve as the basis for calculating the LRMC of heat supply to be used for economic pricing. It is therefore recommended that IpM commission a study to prepare a least-cost development program for the district heating subsector.

5.54 Construction Period: The investment cash flows for the Dunamenti conversion project cover the period 1985-94, implying that the station would not enter full operation until 1995. A 10-year construction program for a 2x180-MW addition to a power station is, in our view, too long and it is recommended that ways tc achieve fuel savings earlier by speeding up construction be investigated. A present value saving at 12% discount rate of Ft 3,690 million (US$92 million) would result if the construction period were 5 years rather than 10 years and if power benefits were valued conservatively at oil/gas fuel replaced in power generation, i.e., excluding the benefits of the MW produced by the station. If there are technical reasons why the construction time of the large CHP projects cannot be shortened, then a number of smaller schemes may be more economic than a few large projects. It is therefore recommended that (a) a technical re-evaluation of the design of the Dunamenti project be carried out to see whether the construction period could be shortened; and (b) in future studies, discounted cash flow analysis should be used to evaluate whether small projects with short lead times are preferable to large scale projects.

5.55 We support the Government's view that priority should be given to increasing the proportion of heat supplied from CHP stations and substituting lower cost fuels, i.e., coal, for high cost fuels, i.e., oil and natural gas. However, this is unlikely to be achieved quickly, because of the long lead times for major rationalization projects. Economic analysis that takes the phasing of projects into account, i.e., discounted cash flow analysis, might suggest that priority be given to projects that yield quick returns. For instance, interconnecting local heat networks might enable fuel savings to be achieved through the more intensive use of low production cost plant. Since it appears inevitable that natural gas and oil will continue to supply the greater part of district heat until the end of the decade at least, ways to use these fuels more efficiently should be explored. Distribution losses in heat networks are unknown, although an investigation using infra-red photography is being carried out. Since the cost of reducing losses is probably small, it would appear worthwhile to investigate distribution losses intensively and take steps to eliminate them. It is therefore recommended that quick studies be carried out to establish the potential for short- to medium-term savings before major heat supply projects can be implemented.

5.56 Natural Gas as a Substitute for District Heat. Medium-term measures such as conversion of gas turbines to CHP, interconnection of local district heat networks and loss reductions are essentially palliatives. Since no major restructuring of heating supply is likely before the end of this decade, the policy for supplying district heat to new consumers should be reviewed. Because supply to some ad[ditional district heating consumers is likely to come from central gas-fired boilers, the issue is whether it would be more economic if these potential consumers were supplied with natural gas directly, thus avoiding several years of heat distribution losses of at least 8% of gross - 106 -

supply, or obtained their heat from other sources, such as briquettes for space and water heating. Given the technical and environmental constraints to expanding coal-fired CHP, the existence of gas distribution networks for town gas and the additional use of gas for cooking, it would appear worthwhile to consider greater use of natural gas in other residential markets, especially to meet additional energy demand up to the early 1990's. It is therefore recommended that the policy for connecting new consumers be reviewed as part of the studies of short- to medium-term heat supply (para. 5.55), and that the ultimate size of the market for district heat be critically reviewed as part of the study to prepare a long-term development program (para. 5.53) and the gas utilization study, included in the Petroleum Project.

5.57 Use of Gas in CHP. Given that natural gas will continue to be a significant fuel in power generation for at least the next decade, the issue arises as to the optimum use of this premium fuel. The possibility would exist of supplying natural gas to MVMT gas turbines and retrofitting heat recovery boilers. The mission was informed that there were restrictions on installing high pressure gas turbines in urban areas, although other countries do this without lowering public safety. Furthermore, combined cycle gas turbine plants for CHP are now a proven technology and offer thermal efficiencies of around 70%. Such plants could be located in urban areas and would not cause air pollution, since they burn natural gas. Combined cycle plant has low investment costs and would avoid the costs of long-distance heat pipelines. Providing the economic cost of natural gas is not expected to exceed thermal parity with fuel oil, these plants would appear to offer an economic alternative to supplying heat to existing urban networks. However, such plants would require imported gas turbine and electronics technology to be blended with Hungarian experience in heating turbines, controls and instrumentation. Combined cycle CHP appears to offer more efficient use of gas in power generation and rationalization of district heat production capacity. It would therefore appear to warrant more detailed investigation. It is recommended, therefore, that consideration be given to the use of existing or new gas turbines for heat production, particularly in combined cycle with a steam turbine for electricity production when a least-cost development program is prepared.

5.58 Nuclear Heat Supply Low temperature nuclear reactors for base load heat supply are currently under consideration. However, only one heating nuclear reactor has been built. This plant is in the Soviet Union, but a Swedish-Finnish consortium and a French company also offer heat reactors. The technology is therefore still experimental and estimates of its costs are consequently uncertain. It is a technology which would appear to have a limited market and which Hungary could only participate in a minor capacity. It would probably take about 10 years to develop a heating reactor in Hungary and because of the prototype nature of such a plant there would be risks of delays and cost overruns. If a supplier were prepared to sell a heating reactor to Hungary at a favorable price to demonstrate its technology worldwide then this might be an offer worth accepting. However, in our view it would be risky to rely on nuclear technology for the rationalization of district heat supply. - 107 -

VI. DEMANDMANAGEMENT AND PRICING

A. Demand Management

Energy Management Program

6.01 The Energy Management Program, started in 1981 is a consistent set of policies for the management of energy demand. The program, which is described in Annex 6.1, consists of (a) the economic pricing of energy to enterprises; (b) regulation of the energy consumption of enterprises; (c) priority finance for energy rationalization; and (d) a set of technical measures and publicity to encourage energy conservation. The program appears to be successful. There has been a sustained decline in energy intensity since 1981, which together with the slowdown in GDP growth and milder winters, led to a fall of about 2% in the gross domestic consumption of commercial energy in 1983 and stagnation in energy consumption since 1980 (para. 4.06). These impressive savings have been made t:hrough retrofitting existing plant and better operating procedures. Even greater energy savings would probably have been achieved had the investment constraints necessary for economic stabilization not slowed the modernization and restructing of industry.

Electricity Demand Management

6.02 Electricity demand management is achieved through system of permits for energy consumption and the remote control of consumers loads (Annex 6.1). Remote control has been carried out by audio frequency injection of control signals on distribution networks to control household loads, mainly in Gybr. However, weaknesses in the distribution system have retarded the adoption of the system.

6.03 Transferring loads off-peak leads to future savings in generation and transmission investment, although local reinforcement of the distribution system may be necessary and in addition, further distribution investment may be required if distribution peaks shift because of off-peak loads. A major benefit from night storage devices is achieved in countries where the marginal energy cost is high during the peak, e.g., when gas turbines are used, and low at night, e.g., when there is surplus run-of-river hydro or nuclear capacity. In these countries, substantial fuel savings are achieved when loads are shifted off-peak. This is not the case at present in Hungary. Incremental changes to both peak and off-peak load are met by oil and gas-fired plant. The marginal fuel cost is essentially the same at all times of the day and year (para. 6.43). Fuel savings from night storage heating are therefore negligible. Indeed, night storage space heating could actually lead to a greater fuel cost to the economy if oil or gas supplied in the form of electricity at a thermal efficiency of around 34% were being substituted for direct coal heating. Moreover, given the hourly pattern of imports, which follow the daily variation in demand, the scope for generating more electricity at night is limited. If the Hungarian power stations were to operate at constant load all day, the amount of energy that would have to be transferred from the morning and evening peaks to other times would amount to about only 25% of daily consumption. Therefore, electricity demand management - 108 - in Hungary would need to be justified mainly on the savings in future generation and transmission investment, after deducting the additional costs of local distribution. Moreover, other alternatives such as natural gas, district heating, coal or even oil may provide space and water heating at lower economic cost.

6.04 MVMT does not have contracts for interruptible supply with large industries, although the existing tariff structure provides good incentives for avoiding consumption during peak periods. Experience in other countries has shown that a number of industries can accept shedding some loads for small, infrequent periods when the power system is under stress. This enables the utility to reduce load at the most appropriate times and may have a smaller impact on the production of large industries than the comparatively blunt instrument of time-of-day or maximum demand tariffs. Furthermore, autoproducers cooperating with MVNT are paid under a simple tariff which probably does not give them sufficient incentive to control their own consumption and export to MVMT. The present tariff for purchases from autoproducers does not provide them with an incentive to maximize exports when the system is under stress. Despite technical constraints on the operation of industrial CHP plant, it appears that some savings could be made by providing more flexible arrangements for supply to large industries and for purchases from autoproducers. Experience in industrialized countries has shown large savings from load management of industrial consumers. In view of the potential benefits of industrial load management and the uncertain economics of residential load management, it is recommended that MVMT commission a study that would evaluate the options from a technical and economic viewpoint and recommend a program of action to implement a load management program.

B. Historical Overview of Coal and Electricity Prices

Coal Prices

6.05 There are two groups of coal prices, both set by the Government: (a) producer prices which are to be paid for all coal to the producers, either by direct consumers or by the state-owned coal trading company (TUZEP) which sells and distributes coal to smaller, mainly household customers; and (b) consumer prices for households and institutions (schools, hospitals, etc.) only, paid to the coal trading company. Consumer prices are much lower than producer prices and the deficit is covered by Government subsidies allocated from the budget to the coal trading company.

6.06 Between 1973 and 1977 the producer price of lignite (M&traalja Co.) increased at an average rate of 8.4% p.a. and brown coal (Tatabanya Co.) at a rate of 3.0% p.a., compared to an average rate of increase in industrial prices of 4.9% p.a. However, during the period 1977 to 1982, the prices of both lignite and brown coal increased at an average rate close to 20% p.a., or about 12% p.a. in real terms. An illustrative comparison of producer prices of Hungarian brown coal with the hypothetical cost of coal imported to the Hungarian border from the major overseas coal exporting countries is presented in Table 6.1. The Hungarian prices are weighted averages of the lower priced fine coal supplied to power stations (2 thirds of coal supplies at USt1.5/GJ) and the higher priced coarse coal supplied to other consumers (1 third of coal supplies at US$2.2/GJ). - 109 -

Table 6.1

Development of Producer Coal Prices

1975 1977 1979 1981 1983

Hungarian Brown Coal (3,200 kcal/kg) US$/t 5.6 6.9 7.7 16.5 23.6 US$/GJ 0.4 0.5 0.6 1.3 1.7

Imported Coal /1 (6,500 kcal/kg)US$/t n.a 26.0 60.0 80.0 70.0 US$/GJ n.a 2.2 2.2 2.9 2.6

Ratio Hungarian/West European import price, same heat. basis, % 23 27 45 65

/1 Notional imports from overseas, including rail freight, free Hungarian border.

6.07 By contrast, consumer prices of brown coal and briquettes increased only at the rate of 1.1% p.a. and 1.4% p.a. respectively during the period 1970 to 1979, falling by 24% and 23%, respectively, in real terms (Table 6.2). The price of coal to households is subsidized for social and political reasons and today is typically only 30-40% of the price to producers.

Table 6.2

Consumer Prices of Coal (Ft/t)

Brown Briquette Retail Price Years Coal (Dorog) Coke Index

1960 220 515 778 - 1970 263 510 970 100.0 1975 311 520 1,180 115.8 1979 291 576 1,280 145.9 1980 357 650 1,510 159.3 1983 (estimated) 580 770 2,084 193.0

Average Annual Rate of Increase (% p.a.)

1970-79 1.1 1.4 3.1 4.3 1979-83 18.8 7.5 13.0 7.2

Source: KSH, "Statisztikai Evkbnyv 1980", Sz&nforgalmi Iroda. - 110 -

6.08 A comparison of coal prices with other energy prices is made in Table 6.3. On a heat value basis, coal represents by far the lowest-priced energy option for both the industrial as well as the domestic consumers in Hungary. Particularly, the incentive to switch from heating oil to coal is large with respect to household prices. The subsidization of the consumer coal prices represents an annual cost to the Government in the order of US$100 million.

Table 6.3

Producer and Household Prices for Selected Energy Sources (Adjusted for End-Use Efficiencies)

Producer Price Consumer Price Percent Percent Energy Source US$/GJ (Coal=100%) US$/GJ (Coal=100%)

Domestic coal 2.27 /1 100 0.72 100 Natural gas 5.43 209 1.69 206 Heating oil 5.88 227 2.95 360 Electricity during: Night - - 2.78 277 Day - 5.15 512

Source: Sz&nforgalmi Iroda.

/1 Price for briquettes.

Electricity Tariffs

6.09 The sharp increases in coal prices were reflected in the prices of electricity. Between 1970 and 1977, the average price of electricity sold by MVNT increased at 2.1% p.a. During the period 1977-82 the rate of increase climbed to 13.4% p.a. (Table 6.4). This acceleration in the rate of increase was a result of a policy to increase the producer prices of electricity. During the period 1970-77, the average price of electricity paid by a typical industrial consumer increased at 2.6% p.a., in current prices, climbing to 17.2% p.a. during the period 1977-82. However, the price of electricity to households was held down for social and political reasons. The average price paid by households actually declined in nominal terms during the period 1970-77 and despite an increase of almost 30% in 1980, the nominal price in 1982 was only 10% above its 1970 level. In real terms the price of electricity to all classes of consumer fell between 1970 and 1977. However, after 1977 the real price of electricity sold to industry increased by more than 9% p.a., whereas the price to households fell by nearly 2% p.a. in real terms. Despite the lower costs of supply to medium-voltage (MV) consumers, the tariff for MV consumers was about 46% higher than the average price of electricity sold to households in 1982. - ill -

Table 6.4

Prices of Electricity and Fuels Used in Electricity Generation (Current Prices)

Prices of Ftels Electricity P2ices Industrial Retail Used in Electricity Generation All House- Price Price Brown Natural Heavy Year Corsoumrs 11 Inistry 12 holds /3 Irt A4 Ire Lignite /5 Coal /6 Gas Oil 7 Ft/kih-- (J?t/t) (Ft/t) (yt/.P) 6FT7t)

1970 0.69 0.55 0.91 100.0 100.0 1971 0.69 0.55 0.89 101.3 101.7 1972 0.69 0.55 0.87 103.4 194.9 1973 0.69 0.55 0.85 105.5 108.6 81 381 677 700 1974 0.69 0.55 0.83 106.8 110.9 83 473 677 70) 1975 0.69 0.55 0.81 118.2 115.8 87 401 935 1000 1976 0.80 0.66 0.8D 126.0 121.9 112 469 1190 1300 1977 0.80 0.66 0.78 127.8 126.8 112 429 1181 130 1978 0.92 0.78 0.75 133.6 133.0 112 438 1173 1300 1979 0.94 0.78 0.79 135.3 145.9 115 442 1164 1300 1980 1.20 1.09 1.03 161.5 159.3 212 743 1974 2800 1981 1.34 1.27 1.02 173.0 167.3 252 922 2520 4110 1982 1.50 1.46 1.00 182.1 178.3 283 1046 3023 5160

Average Amnual Rate of Increast (Z p.a.)

1970-77 2.1 2.6 -2.2 3.6 3.5 8.4 /8 3.0 /8 14.9 /8 16.7 /8 1977-82 13.4 17.2 5.1 7.3 7.1 20.4 19.5 20.7 31.7

Suroes: WMI; Statisztikai EvWk6yv 1981 (Statistical Yearbmok 1981), Magyar Statisztikai ZsebV6ryv (Statistical Pocletbcok, 1982).

/1 Average price/16&, MVM. 72 Average price for a MVconumer with followirg load characteristics: load factor 6CZ, peak coirridence factor 80Z, day/night energy 80Z/20%; weighted by the number of days per year the tariff was effective. /3 Average price for NW sales to househblds. 7T Price index of total sales for socialist industry. /5 Sellirg price Mkraalja Compary (Visonta). T6 Selling price Tatabrya Ccxpany. /7 Vacuum residue (GLron) for pner stations. /8 Rates of increase for fuel prices are for 1973-77. - 112 -

6.10 Between 1973 and 1982, the prices of fuels used in power generation increased substantially in real terms, ranging from a two-fold increase for lignite to a four-fold increase for heavy fuel oil. During the same period, the average level of electricity prices increased in real terms by 26%. Fuel accounts for about 43% of MVMT's operating costs. Without increases in productivity, arising mainly from increasing the size of generating units and switching to lower cost fuels such as natural gas and coal, plus growing cheap imports of power from the Soviet Union, there would have been a substantial deterioration in the financial viability of MVMT.

C. Institutional Responsibility and Basis for Energy Pricing

Institutional Responsibility

6.11 The National Board for Materials and Prices (NBMP) is responsible for setting the prices of all forms of energy. Prices, especially those applicable to households, are arrived at through consultation with the Government, NPO, trade unions and other interested parties, including the energy producers and distributors. Energy price increases are usually triggered by an increase in the international price of oil. All domestic energy prices are increased at roughly the same time. Natural gas price levels are set in relation to the international price of oil. The financial situation of energy sector enterprises is not taken into account when NBMP sets prices. After consulting with NPO, NBMP makes recommendations on the levels of energy price to the Council of Ministers for approval. Household energy prices are set to reflect social considerations and, along with other consumer prices, are used as an instrument of macroeconomic policy.

6.12 Electricity tariffs usually are raised in response to increases in fuel prices and only higher fuel costs have been allowed to be recovered in higher tariffs. Increases in other costs, such as labor, must be met out of higher productivity, although the Ministry of Finance may alter the tax rates applicable to MVMT to offset rises in non-fuel costs. MVMT receives a revenue target from NBMP and designs tariffs to generate this income. In addition, NBMP sets targets for the price of electricity to households which it arrives at in a process of consultation with the Government and others. Tariffs for consumers other than households are designed by MVMT to reflect the accounting cost of service, taking into consideration the costs of metering. In setting tariffs for each consumer group, MVMT makes use of load research carried out by AEEF.

D. Pricing of Coal

Cost Trends for Future Coal Production

6.13 Open-pit mined lignite. Present production cost of the Thorez mine is US$6.5/t, equivalent to US$1.0/GJ. The ratio of overburden to coal is slowly increasing and it will be necessary to install additional equipment. - 113 -

Studies made by the Matraalja Company and KBFI show that this would cause a moderate increase to about US$1.1/t. 1/ The new Bukkabrany mine would operate with a more favorable coal/overburden ratio. On this account alone, production cost, compared to Thorez, would drop to US$5.5/t. Furthermore, the heating value of the coal is higher, and cost per heat unit would further drop to US$0.8/GJ. These costs include accounting depreciation assets valued at historic cost. To better reflect the economic cost of capital invested, a capital recovery factor has been applied to an updated capital investment estimate (Annex 6.2). With such a correction, the production cost of lignite would become US$1.4/GJ, a figure which is indicative of the long-run marginal cost.

6.14 Brown coal production costs range from UStU7.0/t (Oroszlany Co.) to US$27.5/t (Tatab&nya Co.). On the basis of heat units, the cost ranges from US$l.3/GJ (Oroszl&ny Co.) to US$2.2/GJ (Nograd Co.). Eocene brown coal costs from new mines in the Tatabanya area have been estimated by KBFI at US$19.8/t or US$1.4/GJ (Many II project). However, more than for lignite, there remains a considerable risk that. actual production costs may be higher, due to the danger of rock bursts and high water inflows. The long-run marginal cost of brown coal, based on a similar capital cost correction as for lignite, would be US$2.0/GJ.

6.15 Production cost of hard coal presently is USt24.8/t or UStl.4/GJ. Due to the age of the mines, depreciation presently only accounts for 8% of the production cost. In. order to avoid a rapid decline production level, major investments, like sinking new shafts, will have to be made. Furthermore, some mechanization will have to be introduced to improve working conditions and safety, which, due to the difficult geological conditions, may result in cost increases rather than decreases. The mission estimates that in the future the production cost may be in the order of US$35-50/t or US$2.0-2.8/GJ, if a fast decline of the present production level is to be avoided. A more reliable cost estimate would only be available after re-assessment and modification of the Lias program. Because difficult geological conditions preclude the opening of efficient new mechanized mines present production costs give little indication of the costs of hard coal from new mines. Consequently, no attempt has been made to estimate long-run marginal cost in the same manner as for brown coal and lignite.

6.16 The expected development of production costs under the assumed production scenario (para. 5.63 to 5.65) is shown in Table 6.5. It should be noted that if major expansions for brown and hard coal were to be started, then production cost would increase more steeply.

l/ This and following cost data are in 1982 terms. - 114 -

Table 6.5

Estimated Development of Coal Production Cost (In constant 1982 US$/GJ)

Average Production Cost Long-Run 1982 1985 1990 1995 Marginal Actual Estimated Estimated Estimated Cost

Lignite

Matraalja 1.0 1.0 1.1 1.1 n.a BukkAbrany - - - 0.8 1.4. Veszprem /1 n.a. n.a. n.a. n.a. n.a.

Brown Coal

Dorog 1.3 1.3 1.4 1.4 n.a Tatabanya 1.9 1.9 1.8 1.8 2.0 Oroszlany 1.3 1.3 1.4 1.5 n.a Veszprem 1.4 1.4 1.5 1.5 n.a Nograd 2.2 2.2 2.2 2.1 n.a Borsod 1.5 1.5 1.6 1.7 n.a

Total Brown Coal 1.6 1.6 1.7 1.7

Hard Coal

Mecsek /2 1.4 1.4 1.6 1.7 n.a

Source: Mission estimates.

/1 Included in Veszprem brown coal. /2 Reduced Lias program assumed.

6.17 The above cost figures represent the mission's estimate based on the information collected. Although the mission feels that the main trends as outlined above would not change, a more detailed analysis of the long-run marginal cost of all future producers of lignite, brown coal and hard coal would be required for the longer-term pricing of coal.

Coal Pricing Principles

6.18 Coal prices are set by NBMP in relation to the prices of coal traded in Western Europe. Some judgement is used to calculate coal prices since Hungarian coals are generally of much lower quality than internationally traded coal. Moreover, the pricing principle is applied flexible to avoid widespread financial losses in a particular year when the international coal - 115 - market is soft. In rare instances, coal prices have been reduced when this is ihdicated by international prices, e.g. coke in late 1983.

6.19 The level of coal prices determines, at least at the margin, the market for coal. This in turn influences the level of production required and the amount of investment required to maintain or expand production. Furthermore, the level of prices influences the profitability of the mining enterprises and hence the funds available for investment. Given the greater decentralization of the coal industry since 1980, the level of coal prices now influence the economic efficiency of the industry to a greater extent. In order to balance coal demand and coal supply at an economic level it is necessary that coal shou;Ld be priced at its economic cost. The financial self-interest of the mining companies would be brought into line with the national interest and they would be encouraged to implement projects that were economically viable.

6.20 For coals and coal products where changes in local demand are met by changes in the level of imports, e.g., hard coal, coke and briquettes, the economic cost is the c.i.f. cost of imports, expressed in convertible currency. I/

6.21 For other coals such as lignite and brown coal, it is not economic at present for Hungary to either export or import them or their coal substitutes. In such cases coal should be priced at the long-run marginal cost (LRMC) of the highest cost mine. Because of the lumpiness of mining investmen., the long-run average incremental cost (LRAIC) is sometimes used as a proxy for strict LRMC. 2/ Because of the progressively more difficult geological conditions that will be faced in brown coal mining, the LRMC of brown coal would be expected to rise. Providing the cost of imported coal does not increase at a faster rate, which seems unlikely, the economic cost of brown coal would eventually reach the c.i.f. price of imported coal, at which time it would only be economic to expand production if the price of imported coal increased above the LRMC of coal mined in Hungary. From this time the price of brown coal should equal the c.i.f price of imports.

6.22 In 1983 the domestic producer price for brown coal, Hungary's major coal category, was about IJSt1.7/GJ, compared to the long-run marginal cost of

1/ Imports where the quantity traded is fixed under CMEA trading arrangement present special probl,ems,since additional supplies under these arrangements may not be available and the average, or contract, price may not reflect the cost of additional supplies. The approach to dealing with this is to pose the question: if there were a sustained increase in the demand for a type of coal, say, 250,000 tons, where would the supply come from, and what would be the cost in terms of convertible currency? If domestic production represents the marginal supply, then the economic cost of the coal would be calculated using the same principles as for non-traded coals (para. 6.33). 2/ Both LEMC and LRAIC are based on forward-looking estimates of economic costs. LRAIC is defined as the present value of incremental future investment and operating costs, divided by the present value of incremental output. - 116 - about US$2.0/GJ and a border price of US$2.6/GJ for hypothetical imports of steam coal through Western Europe. There is therefore scope for increases of brown coal prices to improve the financial situaton of the coal mining companies and to provide for more appropriate self-financing for necessary investments (paras. 7.10 to 7.12). The price of lignite in 1983 was about US$1.1/GJ compared to a LRMC of about US$1.4/GJ. Since lignite is a non-tradeable commodity it should be priced at its LRMC.

6.23 The Government has wished to avoid basing coal prices on domestic production costs, whether they be average or marginal costs. It believes, with some justification, that a cost-plus approach to pricing would give the mining companies insufficient incentive to minimize their production costs. However, in order to maintain operational efficiency there is a case for periodically, say every five years, calculating the C and at the same time auditing the efficiency of the mining enterprises. Price changes in intervening years could be set in relation to world prices, as at present. This is pricing policy which the Government is considering for the future.

6.24 The present producer price is too low to mobilize sufficient financial resources to enable a reasonable level of self-financing for the completion of on-going and proposed projects. Raising prices to the level of LRMC would require an increase of about 18% for brown coal and up to 36% for lignite. The financial implications of LRMC pricing should be evaluated to determine whether it would ensure sufficient self-financing of investment. Moreover, the removal of coal subsidies would have a favorable impact on the Government budget in the order of US$100 million.

6.25 It is recommended that the Government establish a program for a gradual reduction of the economic subsidies for household and commercial consumers. It is further recommended that the appropriate longer-term coal prices be set in relation to the future economic cost of production of lignite, brown coal and hard coal based on the recommended studies for the Bukkabrany lignite mine, the brown coal mining projects and the reduced Lias hard coal program.

E. Electricity Tariffs

Prevailing Tariffs

6.26 MVNT offers the following five types of tariffs:

(a) demand tariffs having charges for basic and peak coincident contracted maximum demand (kW), as well as energy (kWh) during two or three times of use (peak, day, night). Different tariffs exist for each voltage level;

(b) general tariffs having fixed charges depending on the range of potential demand (kVA) and uniform kWh rates that differ between day and night;

(d) two tariffs for streetlighting, having a maximum demand charge and a uniform rate for kWh consumed at all times; and

(e) residential tariffs consisting of a flat kWh rate that differs for Budapest, large cities, towns and villages. There is also a night kWh rate for consumers with loads that can be switched to operate off-peak.

These tariffs are shown in detail in Annex 6.2.

6.27 Residential tariffs have changed only once since 1970, when they were increased by more than 30% in 1979. Current tariffs are shown in Table 6.6.

Table 6.6

Residential Tariffs (effective July 23, 1979)

Ft/kWh USc/kWh

Budapest 0.75 1.9 Large towns 1.20 3.0 Towns 1.55 3.9 Villages 1.95 4.9 Night rate (al].areas) 0.40 1.0

Source: MVMT

The regional differences in residential tariffs were intended to reflect differences in the cost of supply, but the differences are now said to be greater than those justified on costs alone.

Principles of Electricity Pricing

6.28 The level of existing tariffs can be compared to the economic cost of electricity. The economic cost of electricity is widely accepted to be the long-run marginal cost (LRMC) of supply, with all inputs used in the production and distribution of electricity also being valued at their economic cost. The economics literature shows that a power utility pursuing the sole objective of economic efficiency, i.e., maximizing social welfare 1/, should set the price of electricity equal to its LRMC. However, in practice departures from this rule may be justified, e.g., when other

1/ Defined as consumers willingness to pay less the social costs of supply and outages. See Munasinghe & Warford, Electricity Pricing: Theory and Case Studies, Johns Holpkins (1982) for a description of marginal cost pricing applied to elec-tricity. - 118 -

fuels are not priced at their economic cost, to meet financial objectives and on grounds of equity. Nevertheless, LRMC serves as a useful benchmark against which to review existing tariffs.

6.29 LRMC has two components. The first is the capacity cost which, in principle, is the cost of bringing forward (or delaying) future generation, transmission and distribution investment to meet a sustained increase (decrease) in demand (kW). The second component is the cost of producing an extra kWh at a particular time of the day or year, which is mainly the fuel consumed in generation, adjusted for transmission and distribution losses. Marginal capacity costs may be divided into three categories: (a) generation; (b) transmission; and (c) distribution. The marginal capacity costs of generation capacity were estimated using the WASP computer program to evaluate the additional costs of advancing the Base Case operation investment program to meet a sustained 200 MW increment in maximum demand (Annex 6.3). This increment is equivalent to about one year's growth in demand and the marginal costs were evaluated over the typical 20-year life of electricity using plant and appliances. The calculation of LRMC of generation was made on the basis of power stations planned for 1995 being advanced since plant under construction (Paks) is a sunk cost and the CHP projects are timed to achieve fuel savings in district heating. Power LRMC's may therefore increase over time and this should be investigated in a LRMC pricing study. The long-run average incremental cost (LRAIC) is often taken as a proxy for the LRMC of transmission and distribution. The transmission LRAIC was calculated using highly aggregated data for three years (Annex 6.3). Detailed information on planned distribution investment and projected demand by voltage level was not available, so that a simplified approach had to be adopted. Table 6.7 shows the estimated marginal capacity costs at each voltage level, adjusted for peak losses.

Table 6.7

Marginal Capacity Costs by Voltage Level (US$/kW/a, 1983 prices)

Item Voltage Peak Genera- Trans- Distribution Level Losses (%) tion mission M LV Total

Net generation - 74.1 - - - 74.1 Transmission 7.3 79.9 14.1 - - 94.0 MV 4.7 83.9 14.8 7.0 - 105.7 LV 12.3 95.6 16.9 8.0 16.1 136.6

Source: Mission estimates (Annex 8.2), MVMT.

Marginal Energy Costs

6.30 Marginal energy costs are the additional costs of fuel and other items whose consumption varies with power station use, e.g., lubricants, - 119 -

filters, chemicals, etc., incurred in producing an extra kWh. Such costs vary from hour to hour, depending on system operation. Marginal fuel costs are used to optimize system operation at the National Dispatch Centre. Based on the current mode of system operation and daily load curves, and taking into account the commissioning of Units 1 & 2 at the Paks nuclear station, it appears that incremental kWhs will continue to be supplied from oil and gas-fired power stations during 1983-84. Imports of electricity are effectively fixed by contract, so that an extra kWh at a particular time would normally be generated in Hungary.

6.31 Marginal energy costs should be calculated using the economic cost of fuel. It is assumed that: heavy fuel oil will continue to be exported at the margin at an economic cost of US$150/t (USt3.70/GJ). 1/ The power stations operating at the margin burn both natural gas and fuel oil. Gas supplies to Hungary are fixed in the medium term for contractual and technical reasons. For the next few years therefore, the opportunity cost of natural gas will be fuel oil consumed in power generation, since a marginal change in gas supply would result in a corresponding change in MVMT fuel oil consumption. In the longer term it appears that additional gas supplies would be available at a price, in equivalent convertible currency, about equal to thermal parity with fuel oil. This reportedly is the price at which the Soviet Union exports gas to Western Europe. The economic cost of natural gas for power generation was therefore taken to be US$3.70/GJ (US$158/toe).

6.32 The dual oil/natural gas-fired Tisza (4x215 MW) and Dunamenti (6x215 MW) power stations would operate at the margin at all times of the day and year. Steam stations in Hungary are not shut down during the low load period at night, so that the marginal system cost is the incremental fuel cost of these units, i.e., US$31.2/MWh for Dunamenti and US$32.5/MWh for Tisza. Marginal fuel costs are shown in Table 6.9 after rounding the incremental costs to US$32/MWh and adjusting for losses in transmission and distribution.

Table 6.8

Marginal Fuel Costs (USc/kWh 1983 Prices)

Voltage Level Losses % Marginal Cost

Transmission 3.5 3.3 Sub-transmission 1.4 3.4 MV 2.9 3.5 LV 6.7 3.7

Source; Mission estimates,

1/ When the catalytic cracker is fully operational, Hungary may cease to be a net exporter of fuel oil. In this case, the economic cost of oil and gas would rise to the f.o.b. export price, which was about US$160/ton in 1983. - 120 -

Comparison of Tariffs to LRMC

6.33 A comparison of tariff levels to LRMC is shown in Annex 6.4 and summarized in Table 6.9. On average, tariffs are about 70% of LRMC. However, there is considerable cross-subsidization among different types of consumers. Industry and other enterprises pay tariffs that are between 76% and 96% of LRMC. Households are subsidized as a deliberate policy so that tariffs in Budapest are only about 27% of LRMC and households in villages pay tariffs about 71% of LRMC, although more precise data on distribution LRMC's might narrow the difference between Budapest and elsewhere. The night rate to households is only 27% of the cost of fuel used in the production of a marginal kWh at night, adjusted for losses. Tariffs for rail traction are about 64% of LRMC and diverge from LRMC more than other producer prices.

Table 6.9

Comparison of Tariff Levels to LRMC, 1983 (USc/kWh 1983 Prices)

Proportion of Average Tariff as Tariff Electricity Consumption Tariff LRMC % of LRMC

Power Tariffs - Basic network 0.2665 3.40 4.5 76 - Sub-transmission 0.0441 3.56 4.7 76 - MV tariff I 0.1705 4.03 4.8 84 - MV tariff II 0.0072 5.19 5.6 93 - LV tariff I 0.1150 5.55 5.9 94 - LV tariff II 0.0444 5.56 5.8 96

Traction - Rail 0.0288 3.13 4.9 64 - Tram 0.0130 3.80 5.3 72

General tariff 0.0713 7.37 8.7 110

Public lighting 0.0192 7.83 7.1 110

Residential 0.2200 2.50 6.9 /I 36 - Budapest 1.88 6.9 27 - Large towns 3.00 6.9 43 - Towns 3.88 6.9 56 - Villages 4.88 6.9 71 - Night Rate 1.00 3.7 27

Weighted average 1.0000 3.89 5.5 70

Source: Mission estimates (Annexes 8.2, 8.3 and 8.4).

/1 Insufficient data were available to estimate residential LRMC's by region. - 121 -

6.34 The differences between electricity tariffs and LRMC have implications for resource mobilization and economic efficiency. Shortage of local currency finance is a constraint to power subsector investment, particularly in areas such as the replacement of old power stations, improvements to power station performance and the reinforcement of distribution. Moreover, at the macroeconomic level, shortages of local finance are one of the factors which are at present leading to low rates of investment. Pricing electricity and other fuels at their economic cost would generate extra funds for financing subsector investment and would either directly or indirectly contribute to the State budget, although there would be losses in economic efficiency if prices exceeded LRMC. Setting tariffs at their economic cost would encourage enterprises to economize on electricity and make the correct choices at the margin in substituting capital and other inputs for electricity. 1/ This would reinforce the program of energy rationalization and conservation which the Government is implementing, by bringing the financial self-interest of the enterprise more in line with national priorities. In view of the importance that the Government places on the rational use of energy and the need to mobilize resources for financing improvements in efficiency and the expansion of the subsector, there is a need to bring electricity tariffs more in line with LRMC.

Electricity Tariff Structure

6.35 Industrial tariffs which apply to 65% of electricity sold by MVMT have a structure which enables a good representation to be given of LRMC. At present the marginal cost of energy does not differ by time of day or season (para. 6.37). Therefore, differentiation in price between kWhs at different times of the day may not be necessary. However, towards the end of the 1980's when nuclear capacity will amount to 27% of installed capacity, it may be necessary to reduce the output of coal-fired power stations at night and even to two-shift oil and gas-fired stations. This would result in a night/day differential in marginal fuel costs which the present metering arrangements could then reflect. In addition, there is some theoretical justification in charging some capacity costs in off-peak periods. For these reasons, the existing metering arrangements should be retained.

6.36 The outstanding characteristic of power tariffs in relation to LRMC is that the kWh charges are close to, or exceed, the marginal energy cost, whereas demand charges are substantially below the LRMC of capacity. Between 1973 and 1980 demand charges remained constant, increasing by about 18% in 1980 and 23% in 1982, or about 45% overall. During the same period, the general level of industrial prices increased by 73% so that real demand charges fell, even though the average price of electricity paid by industry increased by 65% in real l:erms. The irregular increases in demand charges were partly a result of the Government's wish to pass on fuel price increases and to minimize the increases in electricity prices. However, the procedure of MVMT to calculate capacity charges on the basis of average accounting costs

1/ Providing that other prices are themselves not severely distorted. Distortion in the prices of substitutes and complements of electricity should be considered in a LRMC pricing study. - 122 - was also a contributing factor, since there were no major additions to fixed assets during the second half of the 1970's.

6.37 Traction tariffs have the greatest difference between price and LRMC of all except residential the producer prices of electricity. They are the only MV tariffs with a simple flat kWh rate. A two or three rate kWh tariff would give a better representation of LRMC at negligible metering cost in relation to the costs of supply.

6.38 General tariffs have two kWh rates and a fixed charge based on estimated demand. Such a fixed charge could be justified if it reflects the sunk costs of connecting typical consumers to the network that do not change in relation to incremental changes in demand. However, assessing demands is cumbersome to administer and it might be preferable to charge these consumers directly for the costs of connecting them, or include distribution capacity charges in day/peak kWh rates.

6.39 Residential tariffs are the only tariffs differentiated by region. Data were not available to check whether these tariff differences are justified on cost grounds, but our impression is that the differences are too great for this. Since distribution is organized by regional companies, it should be possible to calculate LRMC's by region for residential and other consumers. If the differences are small then a uniform national tariff could apply. If the Government wished the distribution companies to be autonomous, then it would follow that they would require greater freedom to set prices to reflect their own costs, in which case regional differences would remain.

6.40 In view of the differences between tariff levels and LRMC (para. 6.33) and the varying degrees of inconsistency between the tariff structure and the structure of LRMC (paras. 6.35-6.39), it is recommended that MVMT commission a study that would use investment and operations planning models to produce accurate estimates of LRMC and design tariffs that would give a good representation of LRMC, taking existing metering and the costs of alternative metering into account. Furthermore, it is recommended that MVMT, in consultation with NBMP and other relevant institutions, arrive at a program for implementing these tariffs for producers over a period of, say, three years.

F. Pricing of District Heat

Existing Prices

6.41 Prices of district heat differ for each city. As for other fuels, there are separate prices for producers and households. Producer prices are intended to be based on the economic cost of producing and distributing heat. Household prices are deliberately set lower as part of the Government's social policies. Typical producer prices of heat supplied from MVMT power stations are shown below in Table 6.10. - 123 -

Table 6.10

Producer Prices for Heat Supplied by MVMT

Date Effective Aug. 2, 1982 Jan. 1, 1982 (Current)

Dunament i

Industrial Steam Ft/GJ 128 135 IJS$/GJ 3.66 3.38 lJS$/toe 156 144

Town Heating Ft/GJ 128 140 (Bulk supply to IJS$/GJ 3.66 3.50 distributor) IJS$/toe 156 149

Gyor (1983)

Ft 390 (US$9.75) per annum per kilowatt of contracted heat demand, plus

Ft 185/GJ (US$4.63/'GJ, US$197/toe) for heat supplied.

Source: MVM1T

Note: Exchange rates: 1982, US$1.00 = Ft 35 1983, US$1.00 = Ft 40.

6.42 Heat supplied to households is rarely metered. Customers usually pay a fixed charge, or a charge based on the size of the dwelling. In 1983, prices in Budapest were:

Space Heating - Ft 23.4 (US$0.59) per m3 per annum of dwelling volume.

Hot water - Ft 10.20 (US$0.26) per m3 per month of hot water, the consumption of hot water being estimated from the floor area of the dwelling.

For a typical dwelling of 52m2 , or 130m3 , which would consume about 41.6 GJ/a for space heat and 1.9 GJ/month of hot water, the average prices roughly would be:

Space Heating - 3.1 Ft/GJ (US$1.83/GJ) or US$78/toe

Hot Water - 48.7 Ft/GJ (US$1.22/GJ) or US$52/toe - 124 -

Level of District Heat Tariffs

6.43 The principle of heat pricing is the same as for other fuels, namely heat should be priced at its economic cost. As for electricity, the economic cost of heat is the LRMC of supply. A preliminary calculation of the economic cost of district heat has been made by the mission and is based on partial data for future heat supply in Budapest. It would need revising when indicative investment programs for district heat systems are available. The calculations of LRMC of heat is further complicated by the present imbalance between boiler and CHP plant in heat production capacity. Estimates of economic cost of district heat delivered to the consumer in constant 1983 prices are described in Annex 6.5 and summarized in Table 6.11. The figures show how the marginal fuel cost might change if a better balance between CHP base load plant and peaking boiler heating plant were achieved in the 1990's and the marginal value of CHP electricity were to fall if lignite and coal plants were commissioned in the period 1995-2010. Assuming that existing boilers would continue to be used for winter peaking and that CHP plant would operate at the margin during summer, the marginal fuel costs in winter and summer would be the costs of producing heat in boilers and CHP plant respectively.

Table 6.11

LRMC of District Heat (constant 1983 prices)

Hot Water Steam

LRMC of production & distribution capacity (US$/kW/a) 44.9 34.1 Marginal fuel cost, boilers (USt/GJ) 4.7 4.7 Marginal fuel cost, CHP plant (1991) (US$/GJ) 0.4 1.3 (1991-2010) (USt/GJ) 1.6 2.0

Source: Mission estimates (Annex 8.5).

6.44 A comparison between the economic cost of heat, expressed as a total cost/GJ and the prevailing tariffs is shown in Table 6.13. The table shows that the prevailing level of district heating tariffs is in the order of 46-74% of economic cost for industries and 14%-22% of economic cost of households. The household prices of hot water do not cover the marginal fuel cost. The differences between price and economic cost should narrow in the future if CHP plant replaces oil/gas-fired boilers in producing heat at the margin at some times of the year. The rough calculation shown in Table 6.12 would indicate that household prices would be in the order of 16%-25% of LRMC in the mid-1991's and industrial steam prices about 57%-92% of LRMC. In view of the need to improve these estimates of LRMC and to calculate them for all the major heat supply systems, as well as the requirement to establish a correct pricing strategy for the transition from unbalanced heat production capacity to when there is a better balance between CHP and boiler capacity, it is recommended that the Government carry out a district heating pricing study for Hungary and gradually raise heat tariff levels towards LRMC. - 125 -

Table 6.12

Comparison of Heat Tariffs to LRMC (US$/GJ, constant 1983 Prices)

Hot Water Steam

(a) 1983 System

LRMC of production and distribution capacity(US$/GJ) 4.1 4.7 Marginal fuel cost 1983 4.7 4.7

Total LRMC 1983 8.8 7.4

(b) 1991 System

LRMC of production and distribution capacity 4.1 2.7 Marginal fuel cost 3.6 3.3

Total LRMC 7.7 6.0

Tariff as % of LRMC, 1983 system 14%-22% 46%-74% 1991 system 16%-25% 57%-92%

Source: Mission estimates.

/1 Tariff for water heating, Budapest. 72 Tariff for household space heating, Budapest. /3 Bulk steam tariff, Dunamenti. /4 Steam tariff average price for a load factor of 35%, Gyor.

Structure of Heat Tariffs

6.45 As existing household heat tariffs are related to dwelling floor area the marginal price of heat is zero. Consumers therefore, have no incentive to conserve energy, e.g., by turning the level of heating down when the dwelling is unoccupied, keeping windows airtight, repairing dripping hot water taps, etc. Experience in other countries has shown significant reductions in consumption when district heating connections are metered. Indeed, judging by the different heating consumption levels between households using natural gas, which is metered, and district heat in Hungary, the reduction in consumption would be about 30%. The typical saving of about 12 GJ/a of delivered heat (0.3 toe) would, if achieved by all household district heat consumers, lead to a total saving of aboul: 7 PJ/a (170 thousand toe/a) or about 0.5% of the national gross consumption of energy. In addition, there would be savings through delaying investment in heat supply capacity because of the lower - 126 - demand. The issue is whether these potential savings are greater than the costs of metering, meter reading and billing. A preliminary analysis indicates that the savings in the first two years are likely to exceed the cost of metering. With a net saving of US$19 per annum per consumer, the total annual national saving would be as high as US$3.3 million (Annex 6.6). The Government is aware of the potential economic loss from existing heat tariffs. Recently, it has decided to meter the supply of hot water to new apartments and to meter heat for space heating communally in new apartment blocks, with automatic controls to prevent overheating. However, financial shortages are preventing the metering of heat in existing dwellings. Investment in demand management measures such as heat metering probably cost less than investments to meet the heat consumption saved. It is recommended that the Government review its heat metering policies and if economically justified, initiate a program of retrofitting heat meters in existing apartments, so as to achieve immediate savings in oil and gas consumption. Such a review should also consider the economics of direct automatic controls on space heating as both substitutes and complements of heat meters (political constraints on the level of heat tariffs are a short-term argument in favor of direct controls), as well as the joint metering of district heat for both space heating and domestic hot water.

G. Household Prices of Power, Coal and District Heat

Background

6.46 As mentioned earlier, the prices to households of electricity, coal and district heat are substantially below economic cost. Household electricity prices are about 36% of LRMC, coal prices about 31% (brown coal, excluding delivery costs) and district heat prices about 16%-25% of LRMC. Smaller distortions exist for heating oil and LPG used by households. Home heating oil costs US$l3l/ton, or 50% of the border price of about US$261/ton. 1/ LPG costs households US$102/ton, or 42% of the border price of about US$245/ton. The household price of natural gas is about US$1.74/GJ, or 47% of an economic cost of about US$3.70/GJ (excluding distribution costs). On the other hand, gasoline is priced at US$572-667/ton to all users, roughly twice the international price of USt3OO/ton or less.

6.47 Whereas it might be possible in theory to offset the potential loss in economic efficiency arising from the differences between electricity prices and LRMC for enterprises through the demand management program, this is much harder to achieve for households. The number of dwellings is very large (about 3.5 million) and it is difficult for any Government to allocate fuel consumption for this number of homes. Some management of residential demand could be achieved by regulating the performance of appliances or through the specification of standards for public housing. However, such measures have little effect on how households operate their appliances. Moreover, the choice of energy using equipment and level of thermal insulation is more difficult to regulate in the private housing sector, where householders in

l/ The domestic price for heating oil was increased by 19% in January 1984 to the level shown. Previously it was US $110/ton. - 127 -

Hungary engage in a high degree of "do-it-yourself" construction, repair and maintenance. The present pricing policies for domestic energy are in direct conflict with the policies for energy conservation and rationalization. The Government is aware of this and has the long-term aim of raising household energy prices to their economic cost.

6.48 There appears significant potential for energy saving in the household sector. Energy consumption per m2 of dwelling area is no lower than in Western Europe (Table 6.13). The specific household heat consumption in Hungary is relatively high considering: (a) the difference in household incomes between Hungary and the other countries shown in Table 6.13; and (b) the high proportion of apartments in the Hungarian housing stock, which have lower heat requirements. Econometric analysis of Hungarian data has shown price elasticities for household energy ranging from -0.4 to -1.1, depending on the income category, which indicate that the response to energy price reforms would be significant. 1/ Furthermore, experience elsewhere confirms that households respond to price signals and reduce energy waste. In Denmark, specific energy consumption by households was reduced by 30% between 1972 and 1980, mainly by increases in the price of heating oil and district heat (Table 6.13). 2/

Table 6.13

Residential Energy Consumption Per m2 of Dwelling Area

Residential Specific No. of Average Energy Energy Dwellings Size Consumption Consumption (Million) (m2 ) (Mtoe) (kgoe/m2 )

Hungary (80) 3.544 59 5.17 24.7 Austria (80) 3.038 76.5 5.94 25.6 Belgium (80) 3.811 104.7 9.80 24.6 France (78) 18.641 77.1 37.38 26.0 Germany (FRG) (81) 25.748 82 47.55 22.5 Denmark (72) 1.860 101 5.41 28.8 Denmark (80) 2.106 107 4.52 20.1

Source: National Statistics, OECD/IEA, UN Economic Commission for Europe, Schipper, op.cit.

Note: Consumption of gasoline is excluded.

1/ Gy. Szakolczai et al. "Classical Models of Consumption Analysis in the Service of Pricing Consumers' Goods in Hungary" Acta Oeconomica Vol. 22 (1-2), pp 87-112 (1979). 2/ L. Schipper, "Residential Energy Use and Conservation in Denmark 1965-1980", Energy Policy Vol. II (4), pp 313-323 (December 1983). - 128 -

Energy Expenditure and Household Income

6.49 The differences between household energy prices and economic cost have been allowed for reasons of equity and macroeconomic policy. However, since the cost of energy to the national economy is ultimately borne by the population, the fact that energy prices are below economic cost does not mean that the overall cost of energy to households is low. Households might pay for their energy indirectly, say, through incomes being lower than they would be if household energy prices were set at their economic cost. In the view of the mission, this ultimate cost of energy to households would be lower if prices were set at economic cost and a more economically efficient consumption eventuated, such as through the elimination of energy waste.

6.50 As Table 6.14 shows, the proportion of income spent by different occupational groups on energy in 1981 ranged from only 3.4% to 6.2% and for electricity from 1.2% to 1.7%, with the higher percentages being for economically inactive households whose main source of income is from the state in the form of pensions and allowances. Moreover, the proportion of household income spent on energy in Hungary is not high compared to the 6-10% spent in West European countries. However, recent energy price increases have probably increased the percentage of income spent on energy above these amounts.

Table 6.14

Per Capita Energy Expenditure as a Percentage of Per Capita Gross Income, 1981

Household Type Electricity (%) Total Energy (%)

Blue collar workers 1.4 4.1 Cooperative farmers & peasants 1.3 3.7 Two-income households 1.2 3.4 White collar workers 1.4 4.1 Economically inactive 1.7 6.2

Source: Annex 8.6.

Not surprisingly, the proportion of income spent on energy and electricity is higher for low-income households as Annex 6.7 shows. Expenditure on electricity ranges from 2.4% of gross increase for the lower income economically inactive to 1.1% for two income households in the highest income bracket. Energy expenditure ranges from 8.9% to 3.0% respectively. Increasing residential electricity tariffs to the level of LRMC would result in expenditure on electricity for blue collar workers rising from 1.4% to over 5% of gross household income, if the previous level of consumption were maintained. To avoid distortions in the choice of fuels it would be necessary to adjust the prices of other household fuels if the differences between electricity prices and LRMC were reduced. Assuming that prices to households are about one third of economic cost for all fuels on average (para. 6.46) and - 129 - if consumption did not decrease, expenditure on energy for blue collar workers would rise from 4.1% to about 12% of gross income. This proportion would be over the upper limit of about 10% observed in European countries. In practice, increases of this magnitude would encourage conservation and the elimination of waste, resulting in energy expenditure being a lower proportion of income.

Household Energy Pricing Policies

6.51 The Government is aware of the potential inefficiency of subsidized consumer energy prices and plans to gradually eliminate them. However, consumer price subsidies are sensitive politically and their hasty removal could lead to political pressures that would slow the pace of economic reform in general. Nevertheless, the mission believes that the Government should re-examine its program of energy price reforms to determine whether it could be speeded up. Well designed price increases could mitigate the adverse effect of increased prices on low-income households. First, the Government could raise the incomes of these households to compensate, e.g., by higher pension payments that could be financed out of the extra tax revenue that would be generated by the energy suppliers. Second, for electricity, natural gas and district heat, lifeline tariffs could be re-introduced, having a low price for the first tranche of consumption and a higher price for the remainder. The lifeline tariff has an additional advantage in that the second price can be near, but probably not greater than, LRMC, so that an economically efficient price is given for incremental consumption. However, some loss of economic efficiency might result from the lifeline tariff, particularly if some households take decisions on the basis of average costs, but this could be offset by suitable publicity. In a country with efficient public administration amd well developed means for transfer payments to households, the first option would be preferred.

6.52 In view of the significant differences between household energy prices and their economic costs and the need for energy prices to reinforce the Government's energy rationalization program, it is recommended that the Government review its program for raising consumer energy prices to determine whether it could be speeded up, especially by directly compensating low-income households, e.g., preferably by increases to existing transfer payments such as pensions, or alternatively by having higher prices for electricity, heat and gas above a certain level of consumption. - 130 -

VII. INVESTMENT

Overview of Past and Planned Investment

7.01 The distribution of energy sector investment among the subsectors has shifted, reflecting changes in energy policy. Coal subsector investment in the 1981-1985 Five-Year Plan accounts for 16.7% of total energy sector investment, compared to 10.5% in the 1971-1975 Plan, a consequence of the Government's decision to revise the decline of the coal industry. Power subsector investment increased from about 40% of energy sector investment in the 1971-1975 Plan to about 44% in the 1976-1980 and 1981-1985 Plans, mainly because of the Paks nuclear power station. The re-orientation of energy policy towards demand management caused the dramatic shift in the energy conservation investment which increased from less than 2% of sector investment in 1971-1975 to over 10% in 1981-1985.

7.02 Energy sector investment is planned to account for 16.5% of total national investment during 1981-1985, and this share has risen steadily from 11.3% during the period 1971-1985, because of the priority given to arresting the decline of the coal industry, energy conservation and the completion of the Paks nuclear station. Power subsector investment during the 1981-1985 Plan is projected to comprise 7.2% of national investment.

7.03 Power subsector investment is dominated by the Paks nuclear station which will account for 73% of power subsector investment in 1984. Target group investment consists of projects deemed to have national importance where investment decisions are taken by the Government. Such investment amounts to about 17% of power subsector investment and comprises primary transmission facilities. Enterprise initiated investment in the power subsector consists mainly of small CHP units and replacement investment. - 131 -

Table 7.1

Past and Planned Investment (Ft million, current prices)

Actual Planned 1971-1975 1976-1980 1981-1985

Coal Subsector 7,863 17,292 28,169 - State investment 1,433 6,151 12,056 - Enterprise investment 6,430 11,141 16,113

Power Subsector 29,892 57,639 73,897 - State investment 15,321 32,986 50,362 - Enterprise investmenl: 141,517 9,977 12,388 - Target group investment - 14,455 12,388

Oil and Gas Subsector /1 32,674 44,526 43,916 Energy Conservation 1,434 5,354 17,058 Other 2,676 4,508 5,202

Total Energy Sector 74,539 129,319 168,242 - State 31,748 50,259 66,173 - Enterprise 36,720 52,075 70,318 - Target group 4,750 26,764 31,483

Gross National Investment 661,139 916,363 1,020,000

Source; NPO, KSH

/1 Oil and gas subsector investment data exclude exploration, field development and technical development. Adding these items would increase investment to Ft 59,700 million in 1976-80 and Ft 61,700 million in 1981-85 (see Petroleum Project SAR for details of petroleum subsector investment).

7.04 Table 7.1 also gives an indication of how the pattern of investment decision making has changed. Enterprise initiated investment has declined in both the coal and power subsectors, for the coal subsector, enterprise investment fell from 82% in the 1971-1975 5-Year Plan to 58% in the 1981-1985 Plan, despite the dissolution of the coal trust in 1980 and moves towards greater enterprise autonomy. This was a consequence of the large investments required to modernize the industry exceeding the financial capabilities of the mining companies. Similarly, for the power subsector enterprise investment declined from 49% to 17%, mainly because of the very large investment in the Paks nuclear station. There is a dilemma between the policies towards greater enterprise autonomy and the Government's desire to maintain strict control over large energy sector investments at a time of severe investment restraint. However, the self-financing of the enterprises could be improved with the pricing reforms recommended in Chapter VI which would also assist in signalling the economic level of investment to the mining companies. - 132 -

Future Power Sector Investment

7.05 Assuming that the Government adopts a power generation strategy involving CHP plant, followed by the Bukkabrany lignite station, projected investment would very roughly amount to that shown in Table 7.2:

Table 7.2

Power Subsector Investment 1986-1995 (Ft billion, current prices)

1986-1990 1990-1995

Generation

- Paks 4 1.0 - CHP projects 53.7 - Biikkabrany - 65.0 - Gas turbine - 3.2 - Rehabilitation 10.0 20.0

Transmission 5.0 10.0 Distribution 10.0 10.0 Other 1.3 1.8

Total 81.0 110.0

Total (1983 prices) 58.0 55.0

Source: Mission estimates.

These figures indicate that the level of power subsector investment could fall by about 20% in real terms from about Ft 74 billion in the current 1981-1985 Plan to Ft 58 billion during 1986-1990. This would be a consequence of the completion of the Paks station which would obviate the need for further capacity additions until the early 1990's. Power subsector investment would then fall from the current level of about 7% of national investment to 5% during the period 1986-1990.

Future Coal Subsector Investment and Funding

7.06 Most ongoing coal investment (para. 5.40 and Annex 7.1) will be completed after 1985. About Ft 10 billion are needed for the brown coal projects. If the Lias program were implemented in its original form, another Ft 30 billion would be required, making a total of Ft 40 billion for the period 1986-1995. If the CHP projects are implemented, additional brown coal mining capacity, particularly in the Tatabanya area, will have to be created. This may require investments in the order of Ft 17.0 billion. For the Bukkabrany project, which would follow the CHP projects, an additional investment of about Ft 25.0 billion for the lignite mine would have to be added (Table 7.3). - 133 -

Table 7.3

Coal Subsector Investment, 1986-1995 (Ft billion, current prices)

Mine 1986-1990 1990-1995

Completion of ongoing investments 32.0 8.0 New brown coal mines for ("HP projects 15.0 2.0 Bukk&brany lignite mine 2.0 23.0 Continued modernization of existing mines 3.0 20.0

Total 52.0 53.0

Total (1983 prices) 37.0 27.0

/1 Including Ft 30 billion for LIAS program in its present form.

7.07 Although no complete and detailed financial statements of the mining companies were given to the mission, it appears already possible to draw at this stage some preliminary conclusions as to the funding needs and the resource mobilization of the coal industry.

7.08 The mining companies face relatively high tax rates: a community tax of 15% of profits and a general tax of 45% of profits. In addition, 40% of their depreciation has to be transferred to the Government. Furthermore, the companies are obliged to keep several funds which comprise in particular compulsory reserves of 20% of profits after tax, a development fund and other funds.

7.09 The Government has also implemented a system with the intention that no mining company shows losses in its financial statements. This is achieved by compulsory transfers from each profit-making company to non-profit-making companies. Most companies have normally a low debt to equity ratio (less than 20/80) and a high current ratio (well above 2.0).

7.10 Financing of coal investments traditionally has been carried by the State Development Bank (SDB) in form of grants and loans. 1/ Since the break-up of the coal trust, companies increasingly use loainsfrom the National Bank of Hungary (NBH). The terms for SDB loans are 13% fixed interest rates and for NBH loans, 14%. For SDB loans, repayments can be deducted from the depreciation before the 40% share to the Government is paid, but not for NBH loans. The mission was inEormed that funding contribution by the companies in the order of 15% would presently be a guideline for new investments. However,

1/ The mission was not informed about the relative share of grants and loans. - 134 - some companies may not be able to contribute this share without receiving grants. 1/

7.11 Funding of investments presently, and probably more so in the future, is imbalanced and, from a macroeconomical view, requires transfers of financial resources from non-coal sectors. Due to the low level of profits (US$23.5 million for the industry as a whole in 1982), taxes are also low in absolute terms. According to information collected from the mining companies, the total resource generation (net profits, taxes and depreciation) of the industry over the next three years (1983-85), will be an average US$68.7 million p.a., whereas investments for replacement and committed projects over the same period appear to be in the order of US$100-200 million p.a. Investment would more than double, if the LIAS program in its original form and new brown coal and lignite mines for power projects were added.

7.12 To balance the resource mobilization of the industry and its funding requirements, a producer price increase of about 10% above 1983 levels would be needed to cover funding for the ongoing investments. If the Lias program in its original form were added as well as new brown coal mines for CHP plants and the Biikk&br&ny lignite mine and if the financing of these projects were to be covered 40% by the coal mining industry a further price increase of about 10%-15% would be required.

September 1984

1/ The mission learned for instance that the Oroszl&ny company so far has only contributed Ft 80 million for the Eocene program, representing 2% of the amount spent so far (Ft 4,100 million). HUNGARY POWERAND COALSUBSECTOR REVEW PowerSubsector Organization

MINISTRYOF INDUSTRY

I NATIONAL ENERGY

HUNGARLAN ELECTRIC POWERTRUST (MC MT) . I POWER& HEATPRODUCTION ENTERPRISES TRANSMISSION& DISTRIBUTION ENTERPRISES INVESIMENT,CONSTRUCTION & INSTALLATION ENTERPRISES

- AJKATHERMAL POWER STATION CO. - OVIT(NATIONAL TRANSMISSION CO.) - ERBE(POWER STATION INVESTMENT CO.) - BORSODTHERMAL POWER STATION CO. - ELMU(BUDAPEST ELECTRICITY DISTRIBUTION CO.) - VERTESZ(POWER STATION STJDY & ERECTIONCO.) - BUDAPESTTHERMAL POWER STATION CO. EDASZ(NORTH-WEST HUNGARY ELECTRICITY DISTRIBUllON CO.) - VITEV(ELECTRIC ENERGY INDUSTRY CML ENERGINEERING - DUNAMENTITHERMAL POWER STATION CO. EMASZ(NORTH HUNGARY ELECTRICITY DISTRIBUTION CO.) & MAINTENANCECO.) - GAGARINTHERMAL POWER STATION CO. DEDASZ(SOUTH-EAST HUNGARY ELECTRICITY DISTRIBUTION CO.) - 7THM40EMBER THERMAL POWER STATIlON CO. DEMASZ(SOUTH HUNGARY ELECTRICITY DISTRIBUIION CO.) - OROSZLAMYTHERMAL POWER STATION CO. TfTASZ(EAST HUNGARY ELECTRICITY DISTRIBUTION CO.) PAKSNUCLEAR POWER STATION CO. PECSTHERMAL POWER STATION CO. TATABANYATHERMAL POWER STATION CO. TISZATHERMAL POWER STATION CO. POWERSTATION MAINTENANCE CO. (EROKAR)

Wodc Bank-25274 x1 HUNGARY POWERAND COAL SUBSECTORREVIEW Orgonhzatlonof Hungarlan Electic Power TWs (MVMT)

| D.Co- G 9M7. D W F V

I~~~~~~~~~~~-

To~~~~~~~~~~~~~~~-

WAoliBa*-252f2

I C - 137 - ANNEX 2.3

HLNUA

POUERAND COAL SUBSBCTO1 REVIEW

Electric PowerSubsector Marpower1975-1985

Actual Forecast 1975 1980 1982 1985 Category Number % Numer % Ntmber % Number %

Workers Skilled 16,747 41.8 17,169 44.2 17,276 45.3 18,000 45.6 Inel.Technicians 2,485 14.8 2,774 7.1 2,849 7.5 3,050 7.7 Semi-skilled 9,213 23.0 8,712 22.5 8,472 22.2 8,690 22.0 Unskilled 3,473 8.7 2,404 6.2 1,938 5.1 2,000 5.0

TotalWorkers 29,433 73.5 28,285 72.9 27,686 72.6 28,690 72.6

Engineering andAdministrative Univetsitygraduates Ergineers 1,206 3.0 1,424 3.6 1,346 3.5 1,480 3.8 Others 293 0.7 204 0.5 351 0.9 360 0.9

Subtotal 1,499 3.7 1,628 4.1 1,697 4.4 1,840 4.7

High schoolgraduates Technical 591 1.5 809 2.1 9!i9 2.5 1,005 2.5 Others 145 0.4 303 0.8 329 0.9 335 0.8

Subtotal 736 1.9 1,112 2.9 1,278 3.4 1,340 3.3

Technicians 2,895 7.2 2,747 7.1 2,612 6.8 2,750 7.0 Others 5,457 13.7 5,043 13.0 4,862 12.8 4,880 12.4

Total Ergineering & Administrative 10,587 26.5 10,530 27.1 10,449 27.4 10,810 27.4

GRANDTCTAL 40,020 100.0 38,815 100.0 38,135 100.3 39,500 100.0

Source:MUTh

February1984 (1808P) - 138 - ANNEX 2.4 Page 1 of 3

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

Wages and Salaries, Electric Power Subsector

1. Official Scales

Salary Scale Category Forints/Month

Engineering and Administrative, Grade A

Director of Enterprise 10,200-15,600 Deputy Director 8,880-14,400 Manager (Technical, Materials, Finance/Accounts) I 6,500-10,000 II 5,400-9,000 Production Chief I 5,500-8,500 II 4,800-8,000 III 4,500-7,500 IV 4,000-7,000 V 3,400-6,000

Administrative, Grade C /1 (Technical, Finance/Accounts, Supplies)

1. 0-3 years of service I 1,350-2,500 II 1,700-3,000 III 2,150-3,700 IV 2,600-4,500

2. 3-8 " I 1,700-3,000 II 2,150-3,700 III 2,600-4,500 IV 3,100-5,100

3. 8-15 " " I 2,150-3,700 II 2,600-4,500 III 3,100-5,100 IV 3,700-6,000

4. 15-20 " " " I 2,600-4,500 II 3,100-5,100 III 3,700-6,000 IV 4,200-7,000

/1 Categories I and II of administrative staff Grade C have primary schooling only, Category III secondary school and Category IV high school. - 139 - ANNEX 2.4 Page 2 of 3

5. Over 20 years' sertrice I 3,100-5,100 II 3,700-6,000 III 4,200-7,000 IV 4,900-8,000 6. Senior advisers III 4,900-8,000 IV 5,900-9,500

Administrative,Grade D

1. 0-5 years' service 1,350-2,800 2. 5-10 " " 1,700-3,300 3. 10-15 " " 2,150-3,700 4. 15-20 " " 2,600-4,500 5. Over 20 " 3,100-5,100 Workers

Unskilled

Category 91 1$350-2,480 92 1,720-2,860 93 2,000-3,630 71 1,720-2,860 72 2,000-3,630 73 2,390-4,300 61 (Operators) 2,000-3,630

Semi-Skilled

Category 62 2,390-4,300 it 63 2,960-5,060 if 51 ) 2,000-3,630 it 52 ) (Maintenance) 2,390-4,300 it 53 ) 2,960-5,060 Skilled

Category 41 2,390-4,300 42 2,960-5,060 43 3,530-5,830 31 2,960-5,060 32 3,530-5,830 "' 33 3,920-6,680 21 3,530-5,830 22 3,920-6,680 23 4,200-6,970

HighlySkilled - Category 11 5,000-8,100 - 140 - ANNEX 2.4 Page 3 of 3

2. Actual Salaries and Wages /1 - Dunamenti Power Station

Number in Forints/Month Category Category Lowest Highest

Engineers

University graduates 30 3,600 12,700 /2 Works engineers (high school) 16 3,950 6,700 Works engineers (workers) 4 3,550 4,630

Technicians 205 3,550 6,170

Secondary school ill 2,740 5,300

Workers

Skilled 578 3,100 5,820 Semi-Skilled 227 2,300 4,420 Unskilled 62 1,900 2,900

TOTAL 1,233 1,900 12,700

Source: Dunamenti Power StationEnterprise.

/1 At April 30, 1983. 72 This is the salary of the director of the enterprise.

February 1984 (1808P) -141 -ANNEX 2 .5

HUNGARY Organizct on of Trtabanyod Coal Mining Comnpany

*~~~~~~~~~~~~~~~~~~~~~~~~ .. -I O

I I - hh.1d

H~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~-I <_ q "

l l r

2 ht,l l 4tt|qD Pta |

l l _ l Ll l~~~~P.W

H dLE___E5ttq {Es~~~~~~~~~~~~~~~~~~~~~o, I H 8I - 142 - ANNEX 2.6 Page 1 of 2

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

Tatabanya Coal Mining Company

1. Employment, May 1983

No. of Persons

High level managers /1 4 0.5 Managers 57 - Production Supervisors 598 4.7 Advisers 42 0.3 Administrative Staff 1,147 9.0 Office workers 353 2.8

Total of Non-Manual Employees 2,201 17.3

Unskilled workers 957 7.5 Semi-skilled workers performing simple job 2,169 24.9 Semi-skilled workers performing complex job 1,011 Skilled workers performing simple job 1,255 50.4 Skilled workers 5,183 Total of manual workers 10,575 82.7

Total of Employees 12,776 100.0

NOTE: About 5,100 of the employees are engaged in non-mining activities (manufacture of long wall power supports, house-building, etc.).

/1 Including General Manager and Deputy General Manager.

February 1984 (1808P) - 143 - ANNEX 2.6 Page 2 oT 2

2. Salaries of Non-Manual Workers, 1982 (Forints/Month)

Category Lowest Highest Average

High level managers I 9,600 12,375 10,600 Managers I /2 6,700 9,100 8,274 Managers II 73 4,800 8,000 6,680 Production supervisors [ /4 6,000 10,200 7,764 " II /4 5,000 7,300 6,181 iii 7T 4,500 6,900 5,877 iv 76 4,000 6,100 4,983 V /7 3,400 5,200 4,290 Advisers IV 5,950 8,100 6,996 " III 4,900 7,200 6,078 Administrative IV /8 2,600 7,800 4,703 " III /8 2,500 7,000 5,616 "II /9 2,150 6,600 4,158 "I 2,300 4,950 4,295 Office Workers 5. /10 3,100 4,250 3,527 4. 2,800 3,900 3,222 3. 2,400 3,650 3,034 2. 2,250 3,300 2,670 1. 1,950 2,600 2,290

Source: Tatabanya Coal Mining Company.

/1 General Manager, Assistant General Manager /2 Head of Department, Assistant Head of Department T7 Division Chief /4 Manager of Factory Units, Operating Manager /5 Works Manager with high qualification 76 Works Manager with intermediate qualification 77 Works Manager in training 7 High qualification /9 Intermediate qualification 7iO Years experience

5th category: over 20 years 4th category: 15 to 20 years 3rd category: 10 to 15 years 2nd category: 5 to 10 years 1st category: 0 to 5 years

February 1984 (1808P) - 144 - ANNEX 2.7 Page 1of 11

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

Main Provisions of Public Law IV of 1962 Concerning the Development, Transmission and Distribution of Electric Power, Decree 40/1962

Notes: 1. The provisions quoted are numbered consecutively for convenience of reference, but the numbers do.not correspond to those in the law.

2. "Minister of Heavy Industries" in the law should now be read as "Minister of Industry", since the Ministry of Heavy Industry was abolished in 1981 and replaced by the Ministry of Industry, which is now responsible for electric power.

1. Scope

The law concerning the generation, transmission and distribution of electricity:

(a) express the fundamental principle -- in view of the change in social and economic conditions -- that electric power stations many constitute socialist property only and that electric power stations to supply consumers may be owned by the state only;

(b) establishes the obligation of electric power stations to supply electric power requirements continuously and to cooperate in the most economical utilization of the capacities of stations;

(c) assures the ability of the operator of an electric power station to acquire the right to establish installations and place conduits on real estate owned by others and regulates the mode of exercising such rights;

(d) prescribes the establishment of safety zones, which -- with due consideration for the interaction with the environment -- will more effectively ensure the operation of the power station and the safety of life and property;

(e) regulates the administrative and technical supervision of power stations and consumer installations and the professional qualifications of the workers in electric power stations;

(f) regulates in harmony with the principles of advanced energy management the utilization of electric power and power station capacities; - 145 - ANNEX 2.7 Page 2 ot ll

(g) specifies -- uniformly on the national level -- the legal relationship between the power stations and consumers; and

(h) regulates the problems of compensation arising from the effects of the establishment and operation of power stations on the property of others.

2. Exceptions

The following electric installations do not fall within the scope of this law:

(a) installations for the generation, transformation, switching or storage of electric energy built into vehicles (locomotives, aircraft, road vehicles, etc.);

(b) the working contact wires of railroad and other electric traction vehicles and the transformer and switching installations serving the direct supply of such wires;

(d) operating power stations having capacities not in excess of 1000 kilowatts and operating separately from public power stations, serving exclusively the utilization of water by agriculture (irrigation) or protection against water damage or as an operational reserve;

(e) operating power stations of government or cooperative agencies having capacities not in excess of 200 kilowatts and operating separately from public power stations;

(f) electric power generating installations having a capacity not in excess of 5 kilowatts; and

(g) wired or wireless communication (telephone, telegraph, signalling, remote operating, remote measuring) facilities.

3. Ownership of Power 5tations

Power Stations and the electric power generated and transmitted therein -- if not exempted by the Council of Ministers -- are owned by society; public stations may be owned by the state only.

4. Establishment and Operation of Power Stations

(a) Permits for the construction of power stations (land use, construction, startup, etc.) require the approval of technical authorities to be obtained in the manner specified by the Minister for Heavy Industries. - 146 - ANNEX 2.7 Page 3 of 11

(b) In the technical design, construction, startup, modification or expansion of electric power stations, Hungarian standards and safety and health rules shall be followed.

(c) Technical conditions of governing the construction, modification, expansion -- including the preparation of technical designs and calculations -- and the startup of power stations are specified in keeping with (b) by the Minister of Heavy Industries.

(d) In the case of in-plant power stations operated by mining enterprises the conditions set forth in (c) shall be specified in agreement with the chairman of the National Chief Inspectorate for Mining Technology.

(e) Conditions relating to the crossing and approaching of roads, railroads, transportation and communication installations, and the cooperation of the agencies involved, shall be regulated by the Minister for Heavy Industries together with the Minister of Transportation and Posts.

(f) Establishments belonging to power stations -- having regard to the interests of the national economy -- shall be placed in general so that they will not interfere with the functional use and development of installations serving other purposes.

(g) In locating such establishments, compliance with regulations for the protection of forests, agricultural lands, monuments and the environment, and with the provisions of water statutes shall be assured, together with the reduction of the contamination of the atmosphere to the lowest technically and economically possible level.

(h) The operator of an electric power station shall prepare a trace drawing containing the designation of the location of the trace establishment, continuously update it, maintain records of technical data and provide information concerning them upon request to the agencies involved and the owner and user of the land.

(i) Rules relating to the contents of the trace drawing and the mode of record keeping shall be promulgated by the Minister for Heavy industries.

(j) In establishing electric power stations the requirements of energy management shall be considered in the selection of energy source, the plant location, the determination of the capacity of units and of steam characteristics, the expansion of electric power systems and the reduction of network losses.

(k) The operator of the electric power station shall generate the electric power in the authorized model, periods and voltage and supply said power continuously. - 147 - ANNEX 2.7 Page 4 of 11

(1) The operator of public power stations shall be responsible for

(i) supplying the electric power requirements of consumers within the safe capacity of the power station in keeping with contracts;

(ii) announcing predictable interruptions to the consumers ahead of time;

(iii) eliminating power failures and restricting interruptions to the shortest possible time.

5. Autoproducers

(a) "In-plant" power stations (electric works) may be established outside the public power system if

(i) the plant serves as a reserve in the event of interruptions in the supply of electric energy by a public power stations;

(ii) the plant is able to supply its in-plant electric power needs, together with the thermal energy requirements, in a manner that is more economical than service by a public station; or

(iii) waste energy is available in the plant.

(b) the existence of the conditions set forth in (a) may be verified by the Minister for Heavy Industries.

(c) The Minister for Heavy Industries -- if the appropriate technical and economic conditions exist -- may order in agreement with the pertinent ministers (heads of national agencies):

(i) the establishment in plants requiring steam power of back pressure steam extraction power stations;

(ii) the establishment of in-plant power stations utilizing waste energy; or

(iii) the conversion, shutdown or elimination of in-plant power stations operating uneconomically.

(d) In-plant power stations must be constructed so that their connection to public power stations is technically possible. Exemptions may be permitted by the Minister for Heavy Industries.

(e) The operator of an in-plant power station may supply to his own plant only the electric capacity or energy determined in regulations concerning the distribution and consumption of electric power. - 148 - ANNEX 2.7 -age5 ot 11

6. Prices and Investment

(a) Separate statutes shall regulate the fees assessed for connection with public power stations and further services.

(b) In the electrification and the expansion of the grids of in-town and outlying areas, in addition to the government investment funds, contributions by council development funds and voluntary consumer contributions may be further utilized. The conditions of such contributions and the rules of the determination of ownership in relation to the distribution network established in this manner, shall be determined by the Ministry for Heavy Industries, together with the Minister of Finance and the chairman of the National Planning Office.

(c) Funds for the establishment of public lighting systems shall be provided by the executive committees of the county (capital city, city councils).

7. Supply Restrictions and Interruptions

(a) In the interests of the national economy or of national defense -- in case of a temporary power shortage -- the Minister for Heavy Industries is authorized to restrict or interrupt the consumption of electric power.

(b) No compensation shall be due for damage incurred as the result of such measures.

(c) Restrictions or interruptions may extend to all of the country, partial areas, consumers or types of consumption. Relevant rules shall be determined by the Minister for Heavy Industries by decree.

(d) If the restriction affects individual areas, the sequence shall be determined by the Minister for Heavy Industries following consultations with the specialized agency administering energy matters of the executive committee or the city or county councils involved.

8. Coordinated Operation and Planning of Power System

(a) In the interest of the rational utilization of energy reserves and the appropriate use of electric power stations public power stations and designated in-plant stations (autoproducers) shall be operated in a coordinated electric energy system.

(b) The cooperation of electric power stations -- including cooperation with foreign electric energy systems based on international treaties -- shall be directed by the Minister for Heavy Industries in keeping with the principles formulated by the Council of Ministers. - 149 - ANNEX 2.7 Page 6 of 11

(c) The Minister for Heavy Industries shall designate after consultation with the minister supervising the in-plant power stations concerned (head of national agency), the in-plant stations participating in the coordinated system.

(d) The annual plan of the capacity of the coordinated electric power system that may be safely utilized -- including the capacities available from foreign countries -- shall be determined by the Minister for Heavy Industries in agreement with the ministers (heads of national agencies) supervising the designated in-plant power stations and approved by the chairman of the National Planning Office.

(e) Plans for the development of the electric power industry and the plans for the importation of foreign electric power shall be determined in the annual plan of the national economy.

(f) The effective ancd idle loads (daily generating schedules) shall be determined by the Minister for Heavy Industries. In his determination, the Minister shall take into consideration, the requirements of safe operation and rational energy management, the utilization of "in-plant" waste energy and the supply of thermal energy.

(g) The conditions for the connection of energy-generating or energy-recuperating installation with public power stations shall be determined by the Minister for Heavy Industries.

(h) The Minister for Heavy Industries is authorized to have the causes of failures in power plants investigated and to require the plants to eliminate such failures.

9. Land Use Rights

(a) Transformer and connecting installations belonging to power plants owned by the state may be built and maintained in or on part of real estate (land or building) owned by others on the basis of use rights.

(b) Use rights are created in the case of real estate owned by the state by agreement with the agency managing it and in the case of others by agreement with the owner (operator).

(c) Use rights are granted in the absence of permission or agreement upon request by the operator of the power plant -- if there are no other statutory provisions -- by the special agency in charge of administration of the executive committee of the pertinent city or Budapest district councils, and in communities the county office, and in cities under county jurisdiction by the district office. - 150 - ANNEX 2.7 Page 7 ot 11

(d) Use rights may be granted only if their application does not exclude or significantly interfere with the intended functional use of the real estate (land or building).

(e) If pursuant to (d), it is not possible to establish use rights on real estate not owned by the state, the operator of the power plant may request expropriation of the real estate.

(f) The operator of a power plant is authorized to operate, maintain, repair and replace transformer and switching equipment placed on the basis of use rights.

(g) The operator of the electric power plant shall pay compensation to the owner (user, operator) of the real property in return for the exercise of the use right.

(h) The conditions of use rights and the compensation to be paid shall be determined by the Minister for Heavy Industries in agreement with the Minister of Finance, the Minister of Justice, the Minister for Construction and Community Development, the Minister for Transportation and Posts, the Minister for Agriculture and Food and with respect to mine properties with the chairman of the National Chief Inspectorate for Mining Technology.

(i) If there is disagreement between the parties in relation to the extent of compensation the matter shall be decided by the courts.

10. Rights-of-Way for Transmission Lines

(a) The Minister for Heavy Industries is authorized to grant rights-of-way for the placement and operation of lines and the supporting structures thereof on real property owned by third parties to electric power stations owned by the state.

(b) Rights-of-way may be granted on real estate where the application of the rights does not interfere significantly with the intended functional use of the property

(d) Rules concerning the granting of rights-of-way for transmission lines shall be established by the Minister for Heavy Industries in consultation with interested ministers (heads of national agencies).

(e) The operator of the electric power station, on the basis of a rights-of-way, may - 151 - ANNEX 2.7 Page 9 of 11

(i) place above-ground and underground lines, distributor, switch gear and operating telecommunication lines on the real estate;

(ii) establish support structures, transformer and switch gear equipment on said support structures, pipelines for the operation of the power station and channels for the same purpose;

(iii) cross installations of railroads and the postal service, roads, rivers, streams, lakes and canals;

(iv) operate, maintain, repair, replace, expand or remove equipment placed pursuant to the above.

(f) Rules concerning the placement of lines along rivers, streams, lakes or canals and tihe under-water crossing of such features, together with the relocation and removal of such lines, shall be established by the Minister for Heavy Industries in consultation with the chairman of the National Water Office.

11. Management of Electric Supply

(a) Guidelines and objectives for the management of electric energy supplies and generating capacity,together with the organization responsible for electricity supply, are determined by the Council of Ministers in keeping with the requirements of general energy management.

(b) The utilization of electric power by industry, transportation and agriculture and the demands on effective and reserve generating capacity must satisfy the requirements of advanced management.

(c) The Minister for Heavy Industries, in consultation with the chairman of the National Planning Office, is authorized to issue general technical and management regulations controlling the distribution and consumption of electric power in accordance with the guidelines and objectives determined under (a).

(d) In the interest of the national management of electric power supplies, the Minister for Heavy Industries is authorized to control the manufacture within the country of large consuming installations and the import for domestic use of such installations.

(e) Large consuming installations and the conditions for licensing them shall be defined by the Minister for Heavy Industries in consultation with interested ministers (head of national agencies).

(f) Autoproducers operating in-plant power stations are required to transfer any electric power generated by them in excess of their own needs to the operator of the public power stations. - 152 - ANNEX 2.7 Page 9 of 11

(g) The Minister for Heavy Industries is authorized in certain cases to permit the use of electric power generated by in-plant stations by others or its supply to enterprises belonging to the same ministry (national agency).

(h) Consumers are required to report their demands for electric energy or capacity to the operator of the public power stations in accordance with rules established by the Minister for Heavy Industries.

12. Supplier/Consumer Relationship

(a) Electric power to consumers may be supplied only by public power stations. The in-plant use of electric power by the operator of an electric power station is not considered to be the supply of power to a consumer.

(b) The supply and consumption of electric power is based on a contract.

(c) The supply of electric power to a consumer may be denied by the operator of the electric power station for technical or economic reasons only.

(d) General conditions of the supply and consumption of electric power are defined in a separate statute.

(e) The conditions of the supply of electric power for public lighting are determined by the Minister for Heavy Industries in consultation with the Minister of the Interior and the Minister for Transportation and Posts.

(f) The operation of an installation using electric power (consumer installation) shall not endanger the safety of life and health, the operation of the electric power plant, the supply of power to other consumers and the safety of property. Consumer installations shall be established and maintained in keeping with specified standards and safety rules.

(g) The operator of an electric power plant shall be authorized to interrupt temporarily the supply of electric power to a consumer in the case of consumption not in accordance with the general conditions of the supply of electric power or harmful to the interests of the orderly management of electric power generation (hereinafter: irregular consumption).

(h) In cases of irregular consumption the application of increased fee schedules may be ordered, as determined by the Minister for Heavy Industries in consultation with the president of the National Material and Price Office. - 153 - ANNEX 2.7 Page 10 of 11

(i) Consumers shall be compensated for alterations of consumer installations made necessary by changes in the type of current, nominal voltage or the number of cycles. The conditions of such compensation shall be determined by the Minister for Heavy Industries in consultation with the Minister of Finance and the president of the National Material and Price Office.

13. Supervision and Control

(a) The highest authority supervising public electric power stations is 'the Minister for Heavy Industries.

(b) In-plant power stations of autoproducers are supervised at the highest level by the minister (head of national agency) having jurisdiction over the operator and technical supervision is provided by the Minister for Heavy Industries.

(c) The operators of power plants and consumers are required to provide all information and data necessary for the planning of the generation, transmission and consumption of electric power and the exercise of ministerial supervision and control.

14. Qualifications of Technical Personnel

(a) Technical functions in power plants may be performed only by persons who possess the necessary training and experience required by the decree of the Minister for Heavy Industries in consultation with the Minister of Labor and interested other ministers (heads of national agencies).

(b) The professional training and continuing education of technical employees working in electric power plants and the consumer networks is the responsibility of sector ministers in keeping with the instructions issued by the Minister for Heavy Industries in consultation with the Minister of Labor.

15. Electricity Imports and Exports

(a) Imports of electric power into this country and exports to other countries are permitted by the Council of Ministers.

(b) The granting of such permits is to be interpreted as the determination of the quantities of electric power to be imported, transmitted or exported within the plans of the national economy. For export permits the rules of relevant statutes are valid.

(c) Enterprises authorized to effect activities in connection with the importation, transmission and exportation are designated by the Minister for Foreign Trade in consultation with the Minister for Heavy Industries., - 154 - ANNEX 2.7 Page 11 of 11

16. Penalties for Theft of Electricity

According to the Hungarian Criminal Code, crimes against property include the theft of electricity (e.g., illegal connections to the public supply network, meter tampering). Law/Decree 19/1962 provides that:

"the amount of the damage, if the quantity of power cannot be determined, shall be calculated by assuming a consumption by the perpetrator of an amount of power corresponding to a use of energy of 1,500 hours for every installation in operation at the time of discovery of the theft. The use of 1,500 hours per year is valid only if it cannot be proved that the theft of energy extended over a longer or shorter period of time. In the case of a longer period, the annual use of 1,500 hours is extended proportionally, and reduced in the case of shorter periods, and accordingly the quantity and value of the energy stolen may be more or less than 1,500 hours.

February 1984 (1808P) - 155 - ANNEX 2.8 Page 1Tof 9

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

Main Provisions of Act VI of 1977 on State Enterprises and Decree No. 4/1978 of the Council of Ministers on its Enforcement

CHAPTER I: INTRODUCTORY PROVISIONS

Section

2(1) The state enterprise is the economic-organizational unit of society. The assets of the enterprise are in state ownership.

2(2) The function of the enterprise, with efficacious, economical and profitablie activities pursued within the scope of its operations according to plan, (is to) advance the accomplishment of the targets set in the national economic plans.

2(4) The enterprise operates on the basis of the combination of central management and enterprise independence.

2(5) The enterprise is a legal person.

3(2) In the operation of the enterprises the state guarantees the observance of the interests of society and the achievement of the target:s defined by the national economic plans mainly by way of a system of economic regulators and prescriptions of the authorities concerned.

3(3) The enterprise operates under the responsible management of the director.

3(4) The community of the workers of the enterprise takes part directly and also through its representation in the management and supervision of the enterprise.

CHAPTER II: ESTABLISHMENT OF THE ENTERPRISE

7(1) An enterprise may be established by a minister, the principal officer of an organ of nationwide competence and a local council (the founding organ).

8(1) For the establishment of an enterprise, the preliminary agreement of the Minister of Finance shall be required. - 156 - ANNEX 2.8 Page 2 of 9

9 If the minister or the principal officer of an organ of nationwide competence establishes the enterprise, he shall consult the competent local council (in the area concerned).

CHAPTER III: ORGANIZATION OF THE ENTERPRISE

Management

12(1) The head of the enterprise shall be the director who exercises his rights and performs his duties by the State's authority. 12(3) The function of the director shall be in particular

(a) the discharge of the economic functions (of the enterprise) and for the accomplishment of these

-the determination of the plans of the enterprise;

- the efficient exploitation and augmentation of the material and intellectual resources of the enterprise;

- the determination of the pattern of products and services and their reasonable modernization;

- the safeguarding of social property;

- the determination of the business and price policy of the enterprise, the making of contracts and the guarantee of contractual discipline;

- the organization of the control, information and accounting system;

- the establishment of the balance sheet of the enterprise;

(b) the accomplishment of the social functions of the enterprise in the sphere of employment, in accordance with the Labor Code, the continuous improvement of the conditions of work and the organization of socialist emulation.

13(1) The director of the enterprise shall establish its organizational and operating statutes.

13(4) The founding organ shall issue directives as to the content of the organizational and operating statutes.

14(1) The director shall manage the enterprise in cooperation with the deputy director(s).

14(2) The deputy director shall discharge his functions as directed by the director. ANNEX 2.8 - 157 - Page 3 of 9

15(2) The director and his deputy shall be appointed ans discharged by the founding organ after consulting the trade union concerned. 1/

18(1) If the founding organ suspends the director because under his management the activities of the enterprise damage the interests of the state or gravely endanger the fulfillment of the targets of the national economy, the founding organ may appoint a ministerial commissioner for the enterprise for not more than six months.

Participation of Workers in Management

19(2) The director, deputy director and other executives of the enterprise shall be bound to cooperate with the enterprise organs of the trade union and the Communist Youth League; they shall provide for adequate conditions of factory democracy.

20(2) & (3) The workers of the enterprise shall participate in the management and supervision of the enterprise, and exercise decision-making rights, within the scope defined by law and the organizational and operating statutes of the enterprise.

20(4) The workers of the enterprise shall give their opinion on the plans of the enterprise, cooperate in the evaluation of their implementation and in this connection give their opinion on the annual activities of the director and deputy director.

(20(5) The director shall render account of the discharge of his functions to the community of the workers of the enterprise.

21(1) The forums of factory democracy, their competence and rules of operation shall be defined in the organizational and operating statutes of the enterprise.

21(2) The director shall consider the opinion of the trade union concerned and the Communist Youth League organs in formulating the organizational and operating statutes.

21(3) The Council of Ministers and the Presidium of the National Council of Trade Unions shall, within the scope defined by separate enactments of law in conjunction with the Central Committee of the Communist Youth League, jointly define the practice of detailed organizational and operating principles of factory democracy.

1/ Since January 1, 1983 directors have been given the right to appoint their deputy directors. - 158 - ANNEX 2.8 Page 4 of 9

CHAPTER IV: MANAGEMENT OF THE ENTERPRISE

Rights and Obligations Associated with Management

22(3) The enterprise shall be granted definite rights in agreement with its independent management and responsibility; in particular, in the sphere of investment, technological development, exploitation of the intellectual and material resources, labor force, pricing, sales and procurement, organization, including plant and work organization, and in financial, commercial, cooperative and monetary arrangements.

23 The enterprise shall be obliged to draw up a plan which shall be in harmony with the targets set in the plans of the national economy and take into account also the interests of the community of the workers of the enterprise.

24(1) In accordance with separate enactments of law, the enterprise shall be obliged to keep records of its assets and business operations, to prepare a balance sheet and profit and loss accounts, and meet its obligation of accounting and rendering account.

24(2) The enterprise shall define the full scope of its activities and system of internal control in its organizational and operating statutes.

24(3) A separate law shall define the organization and functions of internal control.

Scope of Activity of the Enterprise

25(2) The scope of activity shall be defined by the founding organ. The enterprise may terminate or restrict the activity only by the previous consent of the founding organ and the sectoral ministers concerned.

26(2) The enterprise shall be free to pursue supplementary activities required for the economic performance of its scope of activity. It must notify the founding organ of such activities undertaken for others against payment. The sectoral minister responsible may make pursuit of the supplementary activity dependent on conditions or a separate license.

Assets of the Enterprise

27(1) The founding organ shall, at the establishment of the enterprise, provide it with fixed and working assets to the extent that in the first 12 months of its operation it will not need medium- or long-term bank credits. - 159 - ANNEX 2.8 Page J of 9

27(3) The enterprise shall be liable for its obligations with its assets.

27(4) The enterprise may accumulate funds in he manner defined by separate enactments of law.

28(l)-(3) The founding organ may not withdraw assets from the enterprise except

(a) in the event of modification in the scope of activity of the enterprise;

(b) for a substantial change (modernization) of the production pattern and the improvement of the supply to the population of consumer utility goods or services, in which case the founding organ may redistribute some means of production of the ernterprise to another enterprise; and

Association.

29 In conformity with the provisions of the relevant laws, enterprises may establish, or take part in, economic companies and associations.

CHAPTER V: STATE MANAGEMENTOF THE ENTERPRISE

Supervision and Control

31(l)-(3) Supervision of the enterprise shall be by the founding organ, which will:

(a) organize and supervise the enforcement of government decisions;

(b) evaluate and supervise the activities of the enterprise;

(d) proceed in agreement with the Minister of Foreign Trade. when appraising enterprise foreign trade activities.

32 The supervising minister (or principal officer) must consult the local counc:ilconcerned with regard to measures affecting local employment or supply. - 160 - ANNEX 2.8 Page 6 of 9

34(l)-(4) The founding organ may instruct an enterprise to undertake a specific activity

(a) if required for the performance of a task of national defense, or to meet obligations under an international contract; or

(b) in the interest of a substantial change (modernization) of the production pattern to improve the supply of consumer utility goods or services to the population.

The Council of Ministers may issue similar instructions in other cases. At the request of the enterprise, the founding organ shall provide for the elimination of any financial costs to the enterprise of fulfilling any such instruction.

36 The founding organ may institute a board of control for the supervision of an enterprise. The operation of this board cannot restrict the rights and duties of the enterprise director.

Sectoral Management and Supervision

37(1) The ministers responsible for the sectors of the economy shall provide the sectoral management and supervision, and shall

- make sectoral recommendations as necessary for the implementation of economic policy decisions;

- participate in setting the targets of sectoral development;

- cooperate in the coordination of sectoral tasks serving the expansion of the international division of labor; and

- promote and supervise the enforcement of the requirements of the national economy in the activities of enterprises assigned to the sector.

38(3) The sectoral minister may, with the principal officer of the founding organ in charge of supervision, instruct the enterprise to pursue a specific activity.

Supervision of Enterprise Operation Resulting in Loss

40(1) The director of the enterprise must notify the founding organ in writing if the enterprise has operated with a loss or, as a result, has lost its reserve fund. - 161 - ANNEX 2.8 Page I of 9

40(2) Following such a report, the founding organ shall, if the profitable operation of the enterprise cannot otherwise be guaranteed, decree the supervision of the operations of the enterprise (procedure of rehabilitation), after notifying the sectoral trade union concerned. The enterprise may also initiate this procedure.

40(3) The founding organ must decree a procedure of rehabilitation if this is proposed by the Minister of Finance, the President of the Central Peoples' Control Commission, or the competent banking association.

41(2) The committee of rehabilitation shall submit recommendations for the profitable operation of the enterprise to the founding organ, after obtaining the opinion of the sectoral trade union concerned. If profitable operation cannot be achieved, the committee shall submit proposals for the winding up of the enterprise.

CHAPTER VI: WINDING UP OF THE ENTERPRISE

42(1)- The founding organ may wind up the enterprise if

(a) the national economy shall have no need for the activities of the enterprise; (b) the profitable operation of the enterprise cannot be guaranteed; or

42(2) The winding up may take place by reorganization (contraction, merger, division), or by liquidation. In winding up the enterprise, the founding organ must provide for the appropriate redistribution of the labor force, taking account of the needs of the nat:ional economy and the interests of the workers.

CHAPTER VII: PUBLIC UTILITY ENTERPRISES 1/

45(2) The scope of the enterprises for public utilities shall be defined by the Council of Ministers.

1/ Public electricity and gas supply fall within this category. (THIS IS INCOMPLETE). ANNEX 2.8 -162 - Page 8 of 9

46(1) In the case of public utility enterprises, the founding organ may prescribe the obligation to provide services. The limitations on the founding organ's right to withdraw enterprise assets and issue instructions (Section 28) do not apply in the case of public utility enterprise.

46(2) The medium-range development plan of public utility enterprises is subject to the approval of the founding organ, and also, in the case of utilities of major importance, of the sectoral minister concerned.

CHAPTER VIII: TRUSTS

47(l)-(2) Subject to the consent of the Council of Ministers, the founding organ may establish a trust for the promotion of the profitable operation and development of several enterprises under its supervision, by consolidation of the management of the enterprises. The trust operates on the model of an enterprise. The trust and the enterprise's operating under its management shall be legal persons.

48(l)-(4) The head of the trust shall be the general manager, appointed by the founding organ and assisted by one or more deputy general managers also appointed by the founding organ. 1/ The general manager appoints and discharges the director and deputy director(s) of the enterprises. The trust's board of directors comprises the directors of the enterprises. The resolution setting up the trust must specify the decision-making and consultative rights of the board of directors.

49(l)-(2) The trust may instruct a member enterprise to undertake a specific activity, or issue guiding principles for carrying on its business, and may redistribute its assets in the interest of the national economy, subject to any limitations or conditions to the exercise of this power in the resolution establishing the trust.

50(l)-(2) The trust shall be liable for the performance by its enterprises of their obligations in respect of the state budget. The trust is also responsible for settling the losses of any enterprise operating permanently at a loss, or losing its reserve fund.

1/ Since January 1, 1983, the general manager has the right to appoint the deputy general manager(s). - 163 - ANNEX 2.8 Page 9 of 9

51(l)-(3) The trust must develop and institute an internal system of management, accounting and incentives which shall guarantee the required independence of the enterprises in their business activities and investments, and the interest of each enterprise in its own efficiency, and share in the results of the trust proportionate to its own activities.

52 The rules for enterprises shall apply to trusts and trust enterprises.

February 1984 (1808P) - 164 - ANNEX 3 Page 1 of 4

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

Coal Reserves

Lignite

1. Lignite of Pliocene (Upper Tertiary) age is the geologically youngest and most widely distributed coal in Hungary. The largest reserves are at Visonta, south of Matra mountains, about 100 km east of Budapest, and at BUkkabrany, south of the Buk mountains, about 180 km east of Budapest. Another Pliocene deposit is at Torony near Szombathely in West Hungary at the Austrian border. In West Hungary there is also some geologically older lignite of upper Miocene (Upper Tertiary) age at Varpalota, about 20 km north of the Balaton lake. Total lignite reserves amount to about 1.4 billion tons 1/ (Table 1).

Table 1

Lignite Reserves

Mining Areas Under Outside Existing Exploitation Mining Areas Mining Company (million tons) (million tons)

Visonta /1 98 260 BUkk&brany - 594 Torony project - 431 Varpalota /2 41 -

Total 139 1,285

/1 Mined by Matraalja Company (Thorez open-pit mine). /2 Mined by Veszprem Company (Varpalota underground mine).

2. Reserves at Visonta amount to 360 million tons. The average heating value is about 1,600 kcal/kg. The seams are relatively thick, flat, geologically not so disturbed and are close to surface, allowing large scale open-pit mining.

1/ Proven reserves for well determined mining projects only. Probable mineable reserves are 3 times as high. - 165 - ANNEX 3 Page 2 of 4

3. Reserves at BUkk&ibrany amount to 590 million tons. The average heating value is about 1,700 kcal/kg, slightly higher than at Visonta. Also the ratio for waste to coal is more favorable at Biikkabrany (4.6 bm3 /t as compared to 6.8 bm3 /t presently mined at Visonta). Depostion of seams and other mining characteristics are similar to Visonta-

4. Reserves at Torory amount to 430 million tons. The average heating value is about the same as at Biikkabrhny (1,700-1,800 kcal/kg). However, the ratio of waste to coal is 8.2 bm3 /t, higher than at Visonta or BiukkAbrany. Also the deposition of seams and their thickness are less favorable for mining.

5. Reserves of Miocene lignite at Varpalota are about 40 million tons. The average heating value of 2,400 kcal/kg is higher than for Pliocene lignite. However, due to the larger depth underground mining has to be applied with some problems of gas and water.

Brown Coal

6. Hungarian brown coal is either of lower Miocene (tertiary), upper Cretaceous or Eocene (lower Jurassic) age. The Miocene brown coal occurs in North Hungary in the Borsod region, northwest of Miskolc, about 220 km northeast of Budapest, and in the Nograd region, near Salgatarjan, about 120 km northeast of Budapest. Cretaceous brown coal is only known in West Hungary at Aijka, about 30 km west of the Balaton lake. Eocene brown coal occurs in several smaller basins about 50 km west of Budapest at Dorog, Tatabanya, Oroszlany and Dudar/Balinka. The total brown coal reserves amount to 890 million tons. Practically all brown coal occurs at a depth (100-800 m) where only underground mining is feasible. All brown coal reserves are allocated to the 6 companies which maintain mining operations in the different brown coal basins (Table 2). - 166 - ANNEX 3 Page f 4

Table 2

Brown Coal Reserves

Mining Areas Under Outside Existing Exploitation Mining Areas Mining Company (million tons) (million tons)

Borsod /1 78 186 Nograd /1 16 26 Veszprem /2 57 19 Dorog /3 21 /4 98 Tatabany /3 164 /4 128 Oroszlany /3 79 19

Total 415 476

/1 Miocene coal. /2 Cretaceous and Eocene coal. 73 Eocene coal. /4 Includes new mines of Eocene program still under construction (Dorog Co.: Lencsehegy mine, Tatabanya Co.: Many mine).

7. Reserves at Borsod amount to 260 million tons. The average heating value is about 2,800 kcal/kg. The seams in some places reach 6 m thickness, but generally are about 2 m thick and often only 1.5 m. Mining conditions are moderately difficult. The coal is harder than the surrounding rock and galleries are exposed to considerable rock pressure.

8. Reserves at Nograd amount to 40 million tons. The average heating value is 2,700 kcal/kg. Seams are relatively thin (about 1.5 m) and disturbed.

9. Reserves of Cretaceous coal (at Aijka) amount to 40 million tons. The average heating value is 2,700 kcal/kg. While both, reserves and heating value, are the same as at Nograd, mining conditions are more favorable. There are two seams with a thickness of about 6 m each.

10. Reserves of Eocene coal are the most important among brown coal and amount to 540 million tons and are distributed from north to south as follows: Dorog 120, Tatabanya 290, Oroszlany 90 and Dudar/Balinka 40 million tons. The heating value is decreasing from north to south: from a high 4,300 kcal/kg at Dorog to a low 3,000 kcal/kg at Dudar/Balinka. In general, also the seam thickness decreases from north to south: whereas at Dorog seam thickness can reach up to 15 m, seam thickness at Dudar/Balinka is about 2 m. Generally there are two seams: a thinner (about 2 m) upper seam with a higher - 167 - ANNEX 3 4ofoPage 4 calorific value (4,000 - 4,500 kcal/kg) and a thicker (mostly 2-9 m) lower seam with a lower calorific value (3,000 kcal/kg). The mines, in particular in the northern area (Tatabanya and Dorog) are exposed to danger of Karst water. The immediate footwall of the lower coal consosts of limestone which is fractured and carries a large amount of fresh water. There is also danger of rockburst, caused by a thick, non-caving layer of hard limestone above the lower seam.

Hard Coal

11. Hard coal of Lias (Jurassic) age occurs only in South Hungary. There are two deposits: one al: the eastern slope of the Mecsek mountains, at Komlo and Pecs and the other about 15 km further northeast at Maza. The combined reserves of these two areas are 510 million tons (Table 3).

Table 3

Hard Coal Reserves

Mining Areas Under Outside Existing Exploitation Mining Areas (million tons) (million tons)

Mecsek 178 96 Maza South Project - 236

178 332

The average heating value is 4,200 kcal/kg, the ash content 37% and the sulphur content 2.5%. The coal is weakly coking and after beneficiation a fraction can be used for blending with higher quality imported coal.

12. Reserves at Komlo/Pecs (Mecsek) are 178 million tons with a heating value of 4,100 kcal/kg. Mining conditions are the most difficult encountered in the country. There are 9 mineable seams with thicknesses ranging from 0.8 to 10 m, 60% being thicker than 3.5 m. The seams are steeply dipping, mostly at 30-40 . The area is highly faulted and disturbed with intrusions of igneous rock. The coal is friable, dusty and gassy.

March 1984 (1808P) - 168 - ANNEX 4.1 Page 1 of 4

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

Consumption of Fuels by Sector

1. Power and Heat. The displacement of coal by oil and gas during the period 1970 to 1981 occurred in all sectors except mining, public works, trade and commerce and construction. As shown in Table 1, because of the substitution of oil and gas for coal in boiler plants and for industrial process heat, and because of the commissioning of an oil and gas fired power stations with 2,150 MW capacity at Dunamenti and Tisza, the share of coal in the generation of heat and electricity declined by 23 percentage points, from 63.7% in 1970 to 40.7% in 1981. Concomitantly, the share of both oil and gas increased, from 21.5% in 1970 to 28.4% in 1975 oil and from 14.4% to 22.9% for gas, respectively. Over the next 6 years, however, the share of oil declined, mainly due to supply constraints, dropping to 20.8% in 1981, but that of natural gas increased steadily, reaching 38.0% in 1981.

Table 1

Relative Shares of Coal, Oil and Gas Consumed by the Power Sub Sector, 1970-1981

1970 1975 1980 1981 TJ % Ti % TJ % TJ %

Coal 214,696 63.7 201,698 48.2 201,407 41.3 199,537 40.7 Oil 72,406 21.5 119,123 28.4 107,711 22.1 101,748 20.8 Gas 48,655 14.4 95,997 22.9 177,166 36.3 186,302 38.0 Other 1,277 0.4 2,077 0.5 1,457 0.3 2,167 0.5

Total 337,035 100.0 418,890 100.0 487,741 100.0 489,754 100.0

Source: AEEF/OEGH ibid.

2. Transport. Expansion of road transport, and the switch to diesel oil in railroads were the principal reasons for the decline in the share of coal consumed by the transport sector. Table 2 shows that the share of coal declined from 53.2% in 1970 to 8% in 1981, and that of oil increased correspondingly from 41.0% to 73.0%, respectively. During this same period, - 169 - ANNEX 4.1 Page 2 of 4 due to the expansion of railroad service in rural areas, the share of electricity consumed by the transport sector also doubled, increasing from 3.6% in 1970 to 7.9% in 1981.

Table 2

Changes in Energy Consumption by Type of Fuel in the TlL1sport Sector, 1971-1981

1970 1975 1980 1981 Ti % Ti % TJ % TJ %

Coal 38,372 (53.2) 19,794 (29.8) 6,854 (10.5) 5,092 (8.1) Oil 29,675 (41.1) 38,074 (57.3) 45,969 (70.3) 45,563 (72.7) Gas 75 (0.1) 444 (0.7) 2,638 (4.0) 2,494 (3.9) Electricity 2,616 (3.6) 4,019 (6.1) 4,846 (7.4) 4,979 (7.9) Heat 1,206 (1.7) 4,082 (6.1) 4,995 (7.6) 4,900 (8.6) Other 192 (0.3) 71 (0.1) 46 (0.1) 35 (0.1)

Total 72,136 100.0 66,484 100.0 65,348 100.0 63,063

Source; AEEF/OEGH ibid.

3. Industry. Construction of new petrochemical plants such as the one at the Tisza Chemical Combinat and at Pet, and the substitution of oil for coal in the Beremend Cement Works account for most of the changy in the structure of the fuels consumed by the industrial sector. As .Ihown in Table 3, the share of coal consumed by the industrial sector/declined from 25.7% in 1970 to 15.9% in 1981 while that of oil and gas increased between 1970 and 1980, from 11.6% to 18.5% and from 22.3% to 25.7%, respectively. Over the next year, however, the share of oil dropped to'17.4%, but that of natural gas continued to increase, reaching 26.0% in 1981. - 170 - ANNEX 4.1 Page 3 of 4

Table 3

Changes in the Relative Shares of Fuel Consumed by the Industrial Sector, 1970-1981

1970 1975 1980 1981 TJ % TJ TJ % TJ %

Coal 73,909 (25.7) 71,489 (20.3) 63,849 (15.8) 61,845 (15.9) Oil 33,606 (11.7) 58,992 (16.7) 74,413 (18.5) 67,617 (17.4) Gas 64,295 (22.3) 81,957 (23.3) 103,653 (25.7) 100,982 (26.0) Electricity 28,375 (9.9) 35,418 (10.0) 41,722 (10.4) 41,705 (10.8) Heat 86,419 (30.0) 103,746 (29.4) 118,269 (29.4) 115,168 (29.7) Other 988 (0.3) 699 (0.2) 883 (0.2) 630 (0.2)

Total 287,592 100.0 352,301 100.0 402,739 100.0 387,587

Source: AEEF/OEGH ibid

4. Household/Communal. The changes in the structure of the fuels consumed by the household/ commercial sector, summarized in Table 4 below show that, with the exception of coal, the share of which dropped from 58.4% in 1970 to 28.9% in 1981, the shares of all other energy products increased during this period. The shares of oil and gas, and electricity doubled between 1970 and 1981, increasing from 16.4% to 34.1%, from 5.7% to 11.3% and from 4.4% to 8.5%, respectively. Likewise, the share of heat also increased from 8.6% in 1970 to 13.4% in 1981.

Table 4

Changes in the Relative Shares of Fuels Consumed by the Household/Communal Sector, 1970-1981

1970 1975 1980 1981 Ti % Ti % TJ % TJ

Coal 129,899 (58.4) 93,821 (36.6) 98,280 (30.7) 93,622 (28.9) Oil 36,424 (16.4) 80,752 (31.5) 108,627 (33.9) 110,200 (34.1) Gas 12,766 (5.7) 23,360 (9.1) 35,362 (11.0) 36,408 (11.3) Electricity 9,861 (4.4) 17,217 (6.7) 24,977 (7.8) 27,376 (8.5) Heat 19,230 (8.6) 28,470 (11.1) 41,805 (13.1) 43,314 (13.4) Other 14,275 (6.4) 12,677 (4.9) 11,125 (3.5) 12,053 (3.7)

Total 222,455 100.0 256,297 100.0 320,176 100.0 322,973 100.0

Source: AEEF/OEGH ibid. - 171 - ANNEX 4.1 Page 4 of 4

5. Agriculture. As summarized in Table 11, the changes in the structure of fuels consumed by the agricultural sector during the period 1970-1981 were not unlike those in the other sectors. The one notable difference was that the share of coal consumed by the agricultural sector, instead of declining over the entire 11-year period, as was the case in all other sectors, increased from 0.7% in 1980 to 2.6% in 1981. This shift can be attributed to the substitution of coal for oil, whose allocations to this sector were substantially reduced by the authorities since 1979 in an attempt to rationalize the consumption of imported energy. Due to these allocative restrictions the share of oil consumed by the agricultural sector declined, but as of 1981 it still accounted for over 77.6% of the energy consumed. The corresponding figure for 1970 was 82.4%. Regarding natural gas and electricity, their shares increased steadily during this 11-year period, from 0.9% to 4.0% for the former and from 7.6% to 9.7% for the latter, respectively.

Table 5

Changes in the Relative Shares of Fuels Consumed by the Agricultural Sector, 1970-1981

1970 1975 1980 1981 T J % T J % TJ % T J %

Coal 1,114 (2.8) 1,051 (1.6) 510 (0.7) 2,030 (2.6) Oil 32,687 (82.4) 55,245 (84.1) 60,730 (79.7) 59,348 (77.6) Gas 360 (0.9) 946 (1.4) 2,825 (3.7) 3,115 (4.1) Electricity 3,034 (7.6) 5,513 (8.4) 7,146 (9.4) 7,432 (9.7) Heat 1,733 (4.4) 2,215 (3.4) 4,049 (5.3) 3,648 (4.8) Other 749 (0.2) 691 (0.1) 901 (1.2) 933 (1.2)

Total 39,677 100.0 65,661 100.0 76,151 100.0 76,506 100.0

Source: AEEF/OEGH ibid.

February 1984 (1808P) - 172 - A 4.2 Page 1 of 4

POIERAND CQ%L SUB 9D LEVIEW

Consumption of Coal and Coal Products

Table 1: Primary Coal Consuwption by End -use, 1970-1981

1970 1975 1980 1981 T % TJ % TJ % TJ

CONVERSICN

Briquetting /1 Hard coal 7,400 1.7 3,693 1.1 5,991 1.8 5,642 1.7 Brawn coal 17,074 3.9 13,594 3.9 13,9( 4.2 14 4.5

Subtotal 24,474 5.6 17,287 5.0 19,891 6.0 20,227 6.2

Lignite Drying Lignite 6,104 1.4 3,709 1.1 3,484 1.1 3,442 1.0

Coking coal 43,134 9.9 37,402 10.7 36,413 11.0 35,775 11.0

Electricity/Heat Bron coal 202,652 46.6 150,102 42.9 137,805 41.6 135,484 41.8 Lignite - - 41,758 11.9 53,465 16.2 52,970 16.3

Subtotal 202,652 46.6 191,860 54.8 191,270 57.8 188,454 58.1

Conversion Total 276,364 /2 63.5 250,258 71.6 251,058 75.9 247,734 76.3

Hard coal 7,400 1.7 3,693 1.1 5,991 1.8 5,642 1.7 Bron coal 225,830 51.9 163,696 46.8 151,705 45.9 150,069 46.3 Lignite - - 45,467 13.0 56,949 17.2 56,412 17.3 Coking Coal 43,134 9.9 37,402 10.7 36,413 11.0 35,775 11.0

DIRSCTC(NSJMPT(ll Hard coal 56,497 13.0 47,637 13.6 40,604 12.3 40,866 12.7 Brown coal 79,124 18.2 39,549 11.3 30,220 9.1 28,928 8.9 Lignite - - 2,296 0.7 1,516 0.5 - - Coking Coal 23,235 5.3 10,000 2.8 7,410 2.2 6,576 2.1

Subtotal 158,856 36.5 99,482 28.4 79,750 24.1 76,370 23.7

TOTAL 435,220 100.0 349,740 100.0 330,808 100.0 324,104 100.0

Socwce: AEEF/CEGIibid.

/1 Consuption of dried lignite, uiJich amounted to 2,496 TJ in 1982, is excluded. /2 Consumptionof brain coal (2,390 TJ) in gas wurks in 1970 is excluded frcn the total.

February 1984 (1808P) - 173 - ANNE 4.2 Ya =ot 4

PcWR ANDC(AL SJBSECIM REVIEW

Consunption of Coal an Coal Products

Table 2: Coal Consumption by Sector, 1970-1981

TJ 1970 Ti 1975 TI 1980 TI 1981 1970-75 1975-80 1980-81 1975-81

Agriculture 691 0.16 300 0.23 214 0.06 1,379 0.42 3.0 -23.2 44.4 6.5 Miring 1,457 0.33 725 0.21 582 0.18 484 0.15 -13.0 -4.3 -16.8 -9.5 Intiustry of wkich: 26,761 6.15 22,429 6.41 15,729 4.75 14,949 4.61 -3.5 -6.9 -5.0 -5.2

Food products i 1,775 0.41 829 0.23 385 0.12 333 0.10 Metallurgy 2,202 0.51 4,036 1.15 3,982 1.20 3,791 1.17 Machinery 816 0.19 276 0.C8 267 0.O8 233 0.07 Building Materials 20,570 4.73 16,580 4.74 10,890 3.29 10,320 3.18 Chemicals 582 0.13 172 0.05 108 0.03 73 0.02 other 816 0.19 536 0.15 97 0.03 199 0.06

Construction 1,260 0.29 414 0.12 318 0.10 188 0.06 -20.0 -5.1 -40.9 -15.9 Transport & Ccumnications 34,135 7.84 18,028 5.16 6,281 1.90 4,666 1.44 -12.0 -19.0 -25.7 16.5 Public Works 327 .07 17 - 4 - 2 - Traie & Camerce 8 - 4 - - - - - Household/Camercial 91,807 21.10 57,057 16.3 56,622 17.12 54,538 16.8 -9.1 -0.15 -3.7 -4.6 Power & Heat 202,652 46.57 191,860 54.86 191,270 57.82 188,454 58.15 -1.1 -0.1 -1.5 -0.7 Other 76,102 17.49 58,397 16.70 59,788 18.07 59,444 18.34

TOrAL 435,193 10D.00 349,717 10D.03 330,808 10.03 324,104 10D.0D

Source: AEEF/CE.H ibid

February 1984 (1808P) - 174 - ANNE4.2 Page 3of 4

HUNGM

PCaER ANDCQCL aMBSB=R REVEW

ConsLnpticn of Coal ard Coal Products

Table 3: Cooauixtion of Briquettes by Sector, 1970-1981

1970 1975 1980 1981 Rates of Grwth(%) TJs % 'IJs Z TJs % TJs % 1970-75 1975-80 1980-81 1970-81

Agriculture 184 0.50 96 0.30 167 0.40 368 1.00 -12.2 11.7 220.0 6.5 Minig 17 0.G4 25 0.10 55 0.10 52 0.10 8.0 17.1 -5.4 10.7 Industry 809 2.00 260 l.OD 293 1.00 277 1.00 -20.3 2.4 -5.5 -9.3 Construction 629 2.0D 243 1.00 184 0.50 149 0.40 -17.3 -5.4 -19.0 -12.3 Transport & Camunication 3,889 10.0 1,603 5.00 364 1.00 302 100 -16.3 -25.7 -17.0 -20.7 Public Wors 17 G.04 4 - 4 - 1 - - - - - Trade & Camerce 4 - 4 - - - 3 - - - - - Household/Caorercial 31,418 82.0 28,993 88.00 34,780 94.00 34,205 94.00 -1.6 3.7 -1.7 0.8 Electricity & Heat 1,356 4.0 1,143 3.00 1,315 4.00 915 3.00 3.4 2.8 -30.4 3.5

TOtMl 38,470 100.0 32,99 100.0 37,162 100.O 36,372 100.00 -0.9 0.4 -0.8 -0.3

February 1984 (1808P) - 175 - ANNEX4.2 Page4t 4

P(%ERAND C(AL SOBSECOREVIEW

Consunption of Coal and Coal Products

Table 4: Consumption of Ccke by Sector, 1970-1981

1970 1975 1980 1981 Rate of Growth (%) TJ % TJ % TJ % TJ % 1970-75 1975-80 1980-81 19170-B

Agriculture 222 0.5 155 0.3 129 .3 183 0.7 -6.9 -3.6 219.4 2.2 Mining 71 0.2 29 0.1 9 - 13 0.03 - - - - Irdustry 33,236 79.4 35,199 78.7 34,868 81.5 33,683 84.2 1.2 -0.2 -3.4 0.1 of which Metallurgy 29,451 70.4 32,273 72.2 81,963 74.7 30,878 77.2 1.8 -0.2 -3.4 0.4 Other 3,785 9.0 2,926 6.5 2,905 6.8 2,805 7.0 -5.0 -0.1 -3.4 -2.7 Construction 360 0.9 213 0.5 138 0.3 103 0.3 -10.0 -8.3 -25.4 -10.8 Trmsport/CaTmnicatixn 109 0.3 121 0.3 L34 0.3 89 0.2 2.1 2.1 -33.6 -1.8 Public Works 33 0.1 17 0.04 12 0.03 16 0.04 -12.4 -6.7 33.0 -6.4 Trade/Cacnerce 4 ------Household/Cdmrcial 5,376 12.8 7,015 15.7 6,380 14.9 4,482 11.2 5.5 -1.9 -29.7 -1.6 Electricity/Heat 2,315 5.5 1,666 3.7 1,102 2.6 1,332 3.3 -6.4 -7.9 20.9 -4.9 Other 79 0.2 ------Exports 28 0.1 289 0.6

TQrAL 41,833 100.0 44,714 100.0 42,772 10.0 40,001 100.0 1.3 -0.9 -6.5 -0.4

Source: AEEF/CI ibid

February 1984 (1808P) - 176 - ANX 4.3 Pii f=ot 6

PAORAD COALSM B R IID

Eltricitry Ge-eratirg Cpcity

Table 1: Balame of C~acity ad De , Intezmoctad Syatm 1OMWGenrted)

Inatalled Capacity Available Cwacity /1 Reserve Auto- Autor- sub ISmx /2 YArgin Crpwity Availability (Z) Year mm Total mv Tcal I rt /3 Total Dent () mm Total (D Xi ~~(3) T4)~- 2>F3 77 (6) T73R-55;Z67 a T9(7?-77710)-757 7151)= (/10712W(57/ 2) 1~ 7U= (/4) 1950 559 116 675 515 105 620- - 620 486 28 92 92 1955 911 185 1,096 818 219 1,037 45 1,082 885 22 9D 95 1956 947 195 1,142 875 178 1,053 100 1,153 895 29 92 92 1957 1,022 186 1,208 948 171 1,119 60 1,179 984 20 93 93 1958 1,111 185 1,296 1,039 177 1,216 68 1,284 1,085 18 94 94 1959 1,160 194 1,354 1,113 166 1,279 n 1,35D 1,197 13 96 94 1960 1,251 197 1,448 1,148 225 1,373 109 1,482 1,293 15 92 95 1961 1,382 210 1,592 1,234 205 1,439 95 1,534 1,421 8 89 90 1962 1,494 217 1,711 1,310 179 1,489 145 1,634 1,557 5 88 87 1963 1,588 212 1,8D0 1,496 154 1,65D 227 1,877 1,705 10 94 92 1964 1,678 229 1,907 1,532 198 1,730 220 1,950 1,851 5 91 91 1965 1,8D8 229 2,037 1,610 19D 1,8M0 249 2,049 1,993 3 89 88 1966 1,956 243 2,199 1,757 170 1,927 311 2,238 2,168 3 90 88 1967 2,183 238 2,421 1,661 148 1,809 449 2,258 2,325 -3 76 75 1968 2,340 245 2,585 2,L38 217 2,355 352 2,707 2,504 8 91 91 1969 2,417 233 2,650 2,131 210 2,341 555 2,896 2,719 7 88 88 1970 2,692 228 2,92D 2,292 152 2,444 559 3,003 2,983 1 85 84 1971 2,820 238 3,658 2,486 157 2,643 744 3,387 3,221 5 88 86 1972 2,974 225 3,199 2,588 154 2,747 780 3,522 3,486 1 87 86 1973 3,182 184 3,366 2,983 165 3,148 766 3,914 3,784 3 94 94 1974 3,699 199 3,896 3,32D 18D 3,500 776 4,276 4,018 6 90 90 1975 4,006 222 4,228 3,980 1E8 4,168 603 4,771 4,185 14 99 99 1976 4,419 224 4,643 4,189 141 4,330 526 4,856 4,407 10 95 93 1977 4,657 249 4,906 4,585 199 4,784 707 5,491 4,722 16 98 98 1978 5,252 238 5,490 5,173 233 5,406 658 6,064 5,034 20 98 98 1979 5,162 238 5,400 4,872 233 5,105 978 6,083 4,718 29 94 95 1980 5,222 188 5,410 5,062 183 5,245 l,1 6,467 5,107 27 97 97 1981 5,197 196 5,393 4,990 191 5,181 1,232 6,413 5,173 A4 96 96 l982 5,212 212 5,424 5,165 184 5,349 1,312 6,661 5,439 22 99 99

Sare;: HM,'9eultats Tehmiques P nwiairea,1982W'

/1 Available cvacity is mutimn gemted (goe) tput ftm all paer staticuu nrmirg in 1 qeratimn after allowir4 for cwtamt or taqo?ary losam in capacity. /2 Mlun dmxas in Daceer are tbhe actually recorded, vidut e ajustnt for diffexeas bebmt actual frequincy w rmnal (imz)

/3 Imported MWfigurea shimn a averaes for all didng day in Decber.

Much 1984 (L808P) - 177 - ANNK4.3 Pag=e.2o 6

HUW-AK

PO()ERAlD CCPL SJBECIMRREVIEW

Electricity Generatirg Capacity

Table 2: Details of Power Generatirg Plant, Decemier 1982

Unit Sizes Installed Plait Fuel Camiissionirg Station (NW) CapacityLNW) Capability (0) Type Type /1 Year

MrT Dunrasti I 2x20,50,40,3x150 580.0 454.3 Steam, CHP VR,l:,,MD 1966-68 Durmrenti II 6x215 1,290.0 1,290.0 Steam VR,JU,IM) 1973-76 Gagarin 2x100,3x2C0 800.0 770.0 Steam LIG,EC 1970-73 Tiszai 4x215 860.0 860.0 Steam VR,NG,IA) 1977-78 Tiszapalkon 4x50,18,15,7 235.0 217.2 Steam, CAP 3,IC 1957-59 oroszlany 4x50 200.0 2D0.0 Steam 1962-63 Barhida 100 100.0 91.0 Stean 1968 Pecs 3x30,2x50,18 208.5 190.7 Steam, CAP HC 1960-62,1965-66 Borsod 4x30,21,12,10,4,5 171.4 152.7 Stean, CHP BC 1955-57 Ajka 3x30,14,12,10 126.6 122.0 Steam, GAP BC 1960-62 Naoveier 7 6x20 100.0 100.0 Steam 8: 1951-55 Matra 75.0 20.0 Steam LTIO 1950-53 Kelenfold (Bp) 19,2x15,2x6,5 66.0 53.2 Steam, GAP j,LFE) 1963-71 TatabarWa 32.2 25.3 Steam, CGP B 1951-52 Dorog 2.5 2.4 Steam, CHP BC,LFO 1940 Salgotarjan 2.5 1.6 Steam, GAP LED 1966 Kmnlo 9.9 5.4 Steam, CHP BC,IO 1950 Kctarrya (Bp) 2x10.3,1.3 21.9 21.5 Steam, CHP 11,LFO 1964 Kispest (Bp) 2x12 24.0 23.7 Steam, GAP iE,L 1962-63 Ujpest (Bp) 4.3,3.8,1-5 9.6 8.0 Steam, CHP TI,LED 1964 Angyafold 9.7 9.7 Stea-, (H' Il) 1963 Gyor I 8.0 3.7 Steam, CHP BC,D" Gyor II 8.0 1.6 Steam BC Soprn 8.5 4.6 Steam, CGP BC, LFO Szekesfeher 1.2 0.6 Steam, CGP LO" Szeged 1.4 0.9 Steam, CHP NGBC Debrecen L5 1.4 Steam, CHP WC,LFO Nyireghaza 8.5 6.0 Steam, CHP N,ILFO Kelenfold 32 32.0 32.0 Gas Turbine 0) 1972 November 7 2x85 170.0 170.0 Gas Turbine GO 1974-75 Tiszalok 11.4 3.2 Hydzo - " Kiskore 28.0 6.4 Hydro - Kesznyeten 4.4 3.9 Hydro - Gibart 0.5 0.3 Hlydr - Felsodobsza 0.6 0.2 Hydro - Keleti Tarp 0.2 0.1 Hydro - Ikervar 1.4 1.0 Hydro - Nyugati Tar 1.3 1.0 Hydro -

Total MM 5,211.7 4,855.6

(1808P) - 178 - ANNEX4.3 Page 3 of 6

PO1R)aAND C(BL SJBSEIXCRREVEW

Electricity Generatirg Capacity

Table 2 (cont'd): Details of Powr Generating Plant, December 1982

Unit Sizes Installed Plant Fuel Cnmissionirg Station (MN) Capacity(MW) Capability (NW) Type Type /1 Year

ALTracRCDpURS(CCGEWRATNI WTH MUMT)

Diosgyori IM 15.5 Steam CHP 0zdi Kdiaszati U. 25.7 Steam CHP Tiszavasvari AThaloida 2.5 Steam CHP Szalnohi Papirgyar 2.0 Stean CHP Tiszameudi Vegyitxwel 9.0 Steam CHP Alxa4fuzito Timfold 6.3 Steam CHP Tuzfoi Nitrchelnia 8.6 Steau CBP DunaiVasumi 6.4 Steam CHP Csepeli Vasumi 4.2 Steam aHP Csepeli Papirgyar 9.0 Steam CHP Kotamyai Sorgyar 2.6 Steam CHP Hullaleh Haszuosito Mu 24.0 Steam CHP

Total Cogeneration 212.1

Source:WMY

/1 Key to fuel types: VR - vacuumresidual LIG - lignite iL - lightfuel oil BC - brown coal O - gas oil (distillate) Main fuel underlined

M4arch 1984 (1808P) - 179 - ANNEX 4.3 Page 4 of 6

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

Electricity Generating Capacity

Table 3: MVMT Installed Capacity by Fuel Type, 1982

Installed Primary Fuel Secondary Fuel Capacity (MW) _

Lignite Brown coal 800.0 15.4 Brown coal 738.2 14.2 Brown coal Natural gas 235.0 4.5 Brown coal Light fuel oil 12.4 0.2 Black coal 208.5 4.0

Total Coal 1994.1 38.3

Natural gas Vacuum residual oil 2730.0 52.4 Natural gas Fuel oil 131.5 2.5 Natural gas Brown coal 1.4 0.0

Total Gas 2862.9 54.9

Light fuel oil 88.4 1.7 Light fuel oil Brown coal 16.5 0.3

Total Oil 104.9 2.0

Gas oil - 202.0 3.9 Hydro 47.8 0.9

Total MVMT 5211.7 100.0

Source: MVMT (Attachment 2)

March 1984 (1808P) - 180 - ANNEX 4.3 Page 5 of 6

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

Electricity Generating Capacity

Table 4: Age Distribution of MVMT Steam Plant

Age Commissioning Installed Capacity (Years) Dates (MW) (x) (Cum %)

0-5 1978-83 430 8.7 8.7 0-10 1973-77 1920 38.7 47.4 11-15 1968-72 1033 20.8 68.2 16-20 1963-67 569 11.5 79.6 21-25 1948-62 547 11.0 90.7 26-30 1953-57 306 6.2 96.8 31-35 1948-52 117 2.4 99.2 35 pre- 1948 40 0.8 100.0

962 100.0

Source: MVMT (Attachment 2)

Table 5: Size Distribution of MVMT Steam Plant

Unit Size Number of Units Installed Capacity (MW) (No.) (%) (Cum.%) (MW) (%) (Cum.%)

0-19 45 46.4 46.4 371 7.5 7.5 20-49 22 22.7 69.1 541 10.9 18.4 50 11 11.3 80.4 550 11.1 29.5 100 3 3.1 83.5 300 6.0 35.5 150 3 3.1 86.6 450 9.1 44.6 200-215 13 13.4 100.0 2,750 55.4 100.0

97 100.0 4,962 100.0

Source: MVMT (Attachment 2).

March 1984 (1808P) - 181 - ANNEX 4.3 Page 6 of 6

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

Electricity Generating Capacity

Table 6: Autoproducers Generating Plant

In 1981 the installed capacity of autoproducers amounted to about 460 MW, of which nearly 200 MW was operated in conjunction with the MVMT system. Almost all autoproducer power plant consists of small steam turbines designed to provide heat for industrial process use, on-site space and water heating, or district heating, although there is also a small amount of standby diesel plant. An analysis of the installed capacity by industrial subsector is shown in Attachment 1 and summarized in the Table below. Annex 4.9 shows major industrial installations supplying power to the MVNT system.

Installed Electricity Generation Capacity of Autoproducers, 1981

Sector No. Units Capacity (MW) Average Unit Size (MW)

Mining 354 16.2 0.05 Metallurgy 24 160.9 6.7 Machinery 38 19.5 0.5 Building materials 34 9.9 0.3 Chemicals 47 78.4 1.7 Light & Other Industry 27 82.1 3.0 Food Products 37 94.8 2.6

Total 561 480.9 0.82

Source: KSH, "Iparstatisztikai Evkdnyv, 1981" (see Attachment 1).

March 1984 (1808P) - 182 - ANE 4.3 Attachment 1

HUVrA4

POkERAND COAL SUBSTR RE1EW

Electricity Generating Capacity

Electric Power Gernerating Capacity by Industrial Subsector Socialist Industry (as at December 31, 1981)

Sector Nunber of Units Productive Capacity (IW)

Mining 354 16,207 Oil & gas production 326 15,239 Electricity Supply 209 5,230,510 Metallurgy 24 160,895 Iron smlting 1 16 136,159 Alunimnn Smleting 5 24,310 Machinery 38 19,511 Machines & machine parts 11 6,540 Transport equipment 12 8,975 Electrical machinery & appliances 5 2,391 Building materials 34 3,979 Line & cenent 7 1,836 Glass 12 5,346 Cnemicals 47 78,379 Organic, inorganic + pant 15 59,102 Crude oil processing 9 12,294 Gas production & distribution 15 365 Piarmaceuticals 5 6,276 Light Industry 22 36,622 Paper 8 17,868 Textiles 9 15,020 Hides & furs 5 3,734 Other Industry 5 45,500 Food Products 37 94,837 Sugar 19 68,194 Confectionery 3 10,800 Alcohol & starch 6 4,579 Beer 5 11,014

Total 770 5,691,440

Total excluding electricity supply 561 460,930

Source: KSH "Iparstatisztikai Evkoxyv, 1981" (Industry Statistical Yearbook, 1931) Table 55. Note: Industrial plant with installed capacity greater than 1,000 IW shown separately under main headings.

March 1984 (1808P) - 183 - ANEK4.4 Page 1 of 4

POWRAND COAL SUJB9WR REW

PrT&ctiLmof Eimtricity

Table 1: National Prodwtian and Cqm!!mptiaiof Eletricity

Gross Station Net Net Gras Net Nek Netw Yew GCeeration Use Ge-rati Ios Expor I 9x Loosm1pt ca Use (I) Loeses (2) 1 2 3(1-2) 4 5 6(4-5) 7(146) 8(7-2) 9 10(8-9) (11)-(2)/(1) (12)-(9)/(8)

1925 610 40 570 - - - 610 570 95 475 6.5 16.7 1930 882 59 823 - - - 882 823 128 695 6.7 15.6 1935 1,106 70 1,036 - - - 1,106 1,036 122 914 6.3 11.8 1940 1,836 109 1,728 16 1 15 1,851 1,743 180 1,563 5.9 10.3 1945 762 68 694 1 3 -2 760 692 102 590 5.9 10.3 195G 3,001 253 2,748 3 5 -2 2,999 2,746 245 2,501 8.4 8.9 1955 5,428 486 4,942 256 8 248 5,676 5,190 499 4,691 9.0 9.6 1960 7,617 713 6,90) 537 1 536 8,153 7,440 754 6,686 9.4 10.1 1961 8,382 816 7,566 528 30 498 8,880 8,064 751 7,313 9.7 9.3 1962 9,119 902 8,217 957 35 562 9,681 8,779 800 7,979 9.9 9.3 1963 9,665 989 8,676 1,010 8D 930 10,595 9,606 882 8,724 10.2 9.2 1964 10,580 1,042 9,538 1,159 79 1,080 11,660 10,618 941 9,677 9.8 8.9 1965 11,177 1,108 10,069 1,387 98 1,289 12,466 11,358 948 10,410 9.9 8.3 1966 11,861 1,184 10,677 1,704 148 1,556 13,417 12,233 1,004 11,229 10.0 8.2 1967 12,490 1,253 11,237 2,201 296 1,905 14,395 13,142 1,049 12,093 10.0 8.0 1968 13,155 1,313 11,842 2,734 492 2,242 15,397 14,084 1,243 12,841 10.0 8.8 1969 14,069 1,350 12,719 3,337 937 2,400 16,469 15,119 1,357 13,762 9.6 9.0 1970 14,542 1,416 13,126 4,068 663 3,395 17,937 16,521 1,513 15,0O8 9.7 9.2 19n 14,994 1,488 13,506 5,113 767 4,346 19,340 17,852 1,598 16,254 9.9 9.0 1972 16,323 1,651 14,672 5,304 913 4,391 20,713 19,062 1,707 17,355 10.1 9.0 1973 17,644 1,770 15,874 5,732 1,070 4,662 22,306 20,536 1,905 18,631 10.0 9.3 1974 18,985 1,823 17,162 5,756 1,097 4,659 23,644 21,821 1,951 19,870 9.6 8.9 1975 20,472 1,834 18,638 5,802 1,678 4,124 24,597 22,762 1,955 20,807 9.0 8.6 1976 22,050 1,876 20,174 5,578 1,462 4,116 26,166 24,290 2,092 22,197 8.5 8.6 1977 23,402 1,956 21,446 5,408 965 4,443 27,845 25,889 2,195 23,694 8.4 8.5 1978 25,556 2,064 23,492 5,762 1,210 4,552 30,108 28,0S4 2,400 25,644 8.1 8.6 1979 .24,515 1,999 22,516 8,286 2,160 6,126 30,641 28,642 2,366 26,276 8.2 8.3 1980 23,875 1,963 21,912 10,182 2,796 7,386 31,261 29,298 2,831 26,467 8.2 9.7 1981 24,300 1,983 22,317 10,625 2,641 7,984 32,284 30,301 2,949 27,352 8.2 9.7 1982 25,030 2,041 22,989 10,505 1,995 8,510 33,540 31,499 3,090 28,409 8.2 9.8

AverageGrowth Rates (2 p.a.)

1925-1950 6.6 6.5 - - - 6.6 6.5 6.9 1950-1960 9.8 9.6 68.0 -14.9 - 10.5 10.5 10.3 1960-1965 8.0 7.8 20.9 58.2 19.2 8.9 8.8 8.7 1965-1970 5.4 5.4 24.0 46.6 21. 7.5 7.8 7.6 1970-1975 7.1 7.3 7.4 20.4 4.0 6.5 6.6 6.8 1975-1982 2.9 3.0 8.9 2.5 10.9 4.5 4.8 4.5

Sotwce: MVM,'TRsutats Teciques Proviaoie, 1982"

March 1984 M lse) * 184 - ANEX 44 Page 2 of 4

POW ANDCOAL SJBWITR MM/=

Proditiw of Electricity

Table 2: Natioul Produrtie of Electricity by Plart Type

1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981

Stem - Coidenig turbine 12,887 13,156 14,283 15,431 16,767 18,082 19,524 20,8D7 33,8D9 22,281 21,459 21,796 of hAich, WMM 12,332 12,677 13,828 15,027 16,448 17,750 19,232 20,532 22,573 21,655 20,837 21,280

- Baek-Aesum turbine 1,563 1,737 1,921 2,098 2,a59 2,149 2,268 2,369 2,498 2,041 2,267 2,318 of Qiich, WM 1F 966 1,127 1,271 1,364 1,316 1,379 1,432 1,503 1,573 1,514 1,684 1,653

Gas turbine - - 3 8 70 67 86 71 103 40 29 11

Interl ca tial 4 6 5 6 6 10 6 6 8 6 6 5

Hydro 88 97 111 M11 83 164 165 149 138 lb6 114 170

Total 14,542 14,996 16,323 17,644 18,985 20,472 22,049 23,402 25,556 24,514 23,875 24,30D

Specific fuel ccmapticn 13,234 12,%5 12,849 12,665 12,456 12,041 11,886 11,769 11,618 11,497 11,564 11,533 of therml pa statiuc (KJ/Mii)

Source: AW /OM '"rrZgiqa4adaw i Statisxikai Evkme,-' (Enezr lSE V Statistical Ye.rock).

Mas-h 1984 (18) - 185 - ANNX4.4 v3jmot 4

HUWEAWL

POERAMC COAL S3BSO=R RIEW

Producti.x of Electricity

Table 3: MVWPaar Generatima by Fuel Type (G1)

Shares (%) Average Growth (% p.a.) 1970 1971 1972 1980 1981 1982 1970 198 1982 1970-80 1980-82

Brown coal 5,958 5,640 5,781 4,821 4,503 4,933 44.5 21.2 20.7 -2.1 1.2

Lignite 1,648 2,040 2,632 4,721 4,944 4,740 12.3 20.7 19.9 11.1 0.2

Coal by-products 1,321 1,380 1,400 1,305 1,319 1,342 9.9 5.7 5.6 -0.1 1.4

Subtotal coal 8,927 9,060 9,813 10,847 10,766 11,015 66.7 47.6 46.2 2.0 0.8

Ful oil 2,296 3,335 3,362 5,609 2,358 2,707 17.2 24.6 11.4 9.3 -30.5

Natural gas 2,075 1,415 1,931 6,174 9,813 9,958 15.5 27.1 41.7 11.5 27.0

Subtotal hydrocarbm 4,371 4,750 5,293 11,783 12,171 12,665 32.7 51.7 53.1 10.4 3.7

Hydro 88 90 105 150 175 160 0.6 0.7 0.7 5.5 3.3

Total 13,386 13,900 13,211 22,780 23,110 23,8b0 100.0 10D.0 100.0 5.5 2.3

Scurce: MM

March 1984 (1808P) - 186 - ANNEX 4.4 Page 4 of 4

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

Production of Electricity

Table 4: International Trade in Electricity by Country, 1980-1982

1980 1981 1982 Scheduled Actual Scheduled Actual Scheduled Actual Imports

USSR 7,500 8,326 8,000 9,481 8,090 8,730 Czechoslovakia - 549 - 630 80 1,250 Poland - - - - 200 Romania 56 955 - 37 - 230 Austria 252 252 254 254 245 245 Yugoslavia 100 100 40 40 50 50

Total 7,908 10,182 8,294 10,442 8,665 10,505

Exports

USSR - 24 - 7 - 55 Czechoslovakia - 2,276 - 1,974 1,710 1,725 Poland - - - Romania - 15 - 1 - 10 Austria 363 363 400 400 165 165 Yugoslavia 116 116 30 30 40 40

Total 479 2,794 430 2,412 1,915 1,995

Source: MVMT, "Resultats techniques provisoires"

March 1984 (1808P) - 187 - AZEt(4.5 Pag-e-1 of 4

Pam ARMCOaL ssrms R?

Po and Heat Fuel Cas3wpicm

Table 1: Fuels Camm in the Prp&I tion of Heat and Electricity 1970-81

1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 19B0 1981

Coal 202,669 198,647 203,491 208,557 202,026 191,874 194,EG2 194,106 196,976 189,993 191,270 188,454 Crudeoil 285 239 1Y+ 8) 59 44 27 - - - - - Natural gas 47,930 50,706 58,741 75,727 82,811 95,170 120,959 126,249 140,635 155,343 176,365 185,246 Fuelwood 113 113 113 188 126 94 158 162 171 199 138. 205 Briquettes 1,356 1,398 1,298 1,570 1,315 1,143 1,127 1,160 1,424 1,265 1,315 915 Dried Lignite 1,365 1,252 1,168 1,160 1,118 658 691 695 653 532 553 635 Cdoe 2,315 2,516 2,286 2,236 1,754 1,666 1,698 1,294 1,296 1,172 1,102 1,332 other coal products 4 ------12 2 UFG 17 - - - - 8 17 21 17 16 21 22 Gasolie - - - 4 - 4 - 4 4 4 4 1 Keroene - - 4 _ - - - - - 4 - - Gasoil 415 699 754 603 494) Heating oil 2,970 4,254 6,716 3,930 11,618 ) 13,053 14,431 14,562 16,773 14,813 15,019 15,431 Fuel oil 68,751 78,431 84,163 83,C91 94,986 106,060 103,548 119,014 136,686 111,265 92,667 86,294 Coke oven gas 436 691 641 502 615 632 611 862 796 900 841 769 Generator &'water gas 151 46 25 33 21 ------Blast furnace gas 6,402 6,515 6,305 6,201 6,037 5,740 6,280 7,277 7,013 6,887 6,812 7,430 Tsm gas 728 741 925 871 812 833 816 967 900 833 8D1 1,056 Heat energy /1 3,069 3,517 3,571 3,697 3,555 3,768 4,112 4,723 5,125 5,074 5,200 5,108 Electricity 71i 5,568 5,732 6,318 6,741 7,231 7,154 7,377 7,727 8,314 7,968 7,833 7,853

Subtotal 344,544 355,497 376,653 400,191 414,577 427,901 456,454 478,823 516,743 496,298 500,003 500,753

Other prim-y energ 5,288 5,560 6, (Y2 6,485 6,217 6,787 - - - - pcoducts Other seciary -erg 1,637 2,730 2,872 - 3,609 3,471 - - - - - products

Total 351,469 363,787 385,567 406,676 424,403 438,159 456,454 478,823 516,743 496,298 500,003 500,753

Source: AEEFJIMM"Enagia GazdaliodaaiStatiaztikai E*Lzyv 1975" (Energy Eayn Statistical Y.bock 1990), Table 39.

/1 Ccasuetioa of heat and electricity apper to exlude thi=2dynamic lo1a in trazfouatiac and distributin loses.

March 1984 (1&0op) 1N-4K4.5

AM CCXL9 U £VIDI

Par w Het Fel CmnumtiOd

Table 2: Fuel Cad in the Productiu of Elwtriciy an Heat, 1975 (TY)

Other Gm 6 Cdoke Blt Natura Bri- Dried solid G_mo- eutug Fue Own FFzce Tam Fie- Crude Coal Gm VW- Lm=t,, Cdo Fiaes 1. tile oil Oil Ga Gm Go wxd Oil Total

Cmdemingn zbiw 125,039 35,006 ------84 44,464 - - - - - 204,563 tubin 2,290 950 ------8 2,428 - - - - - 5,677 (pmr ony) Bwk-reue turbinm 17,463 12,142 ------4 13,603 - - - - - 43,212 teaP) Gas turbimes ------1,030 ------1,030 N? -pr g rif 7,113 4,1B7 - 193 _ _ - - 8 1,989 - - - - - 13,490

Total 151,876 52,28 - 193 - - - - 1,135 62,484 - - - - - 267,972

Non mW

Ccrsiing turbines 942 1,039 ------7 105 1,507 - - - 3,634 Bm re- urezeturbins 565 754 ------1,474 50 184 - - - 3,027 (pr mly) Bsck- turbimn 4,137 5,522 ------21 10,823 373 1,357 - - - 22,232 (P) Imhitrial boilers /1 29,739 27,788 896 343 595 - 8 - 7,771 29,693 105 2,692 632 46 46 100,353 Internal caution etgim ------4 96 ------100 IfAtrial cntol hatizg 4,442 2,102 218 121 1,034 - - - 3,241 197 - - 188 50 - 11,593 YAh-trial bot vater 172 1.52 29 _ 38 _ - _ 749 1,319 _ - 13 _ _ 8,030 boiler & heaters

Total 39,997 42,885 1,143 465 1,666 - 8 4 11,597 43,576 632 5,740 833 96 46 148,971

TmrAL 191,873 95,170 1,143 657 1,666 - 8 4 12,732 106,060 632 5,740 833 96 46 416,942

Sorce: AEWI/(YM'lezgia Gatdalkod: i Statiaztikai Evkyv Ml75"(MZn Ewnj Statistical Yer-bock 1975).

/1 Ihls caxul towr a aricultural boiles subj;ct to sta.xoay inqiectim6

Muh 1984 (law) - 189 - ARiC 4.5 Ta-e3-! 4

POUR M COALa1BW ElVIEW

P. and Heat Fl Ccx mti

Table 3: Fuel Caonxu in deh Proction of Electricity au Heat, 198D (TCJ)

Other Gm & Cake Blst Watural Bri- Deiad Solid Gwo- H1atu Fuel On Furnace Tao Fi=- Coal Ga c-tt- Ligt Cdce Fuels IW li Oil Oil Gm Gm Go wxd Total

Cmenir ebines 126,561 77,968 ------8) 27,944 - - - - 232,553 B*-presure turbines 2,817 2,744 ------13 1,456 - - - - 7,030 (par -ay) Bwk-presure t,rbines 18,496 18,010 ------86 9,560 - - - - 46,152 (CBP) Gas turbines - - - - _ _ _ 435 - - - - - 435 Nar-pur turbines 11,727 9,8D - 272 _ _ _ _ 83 3.724 - - - - 25,606

Total 159,601 108,522 - 272 - - - - 697 42,684 - - - - 311,776

Comuieizg iurbins 2,588 2,367 ------58D 105 1,290 - - 6,930 Bak-presu turbin 376 1,279 ------2 1,678 76 339 - - 3,750 (per aly) Berk-pessure turbines 2,512 8,551 ------15 11,232 506 2,265 - - 25,081 (CBP) Industrial boilers 22,450 39,720 1,072 147 253 12 21 - 7,762 34,210 154 2,918 625 88 109,432 internsl ccrbustilm eriis ------4 93 - - - - - 97 Tack trial cmntl heatiig 3,521 3,9S5 201 134 816 - - - 4,843 340 - - 172 50 14,042 Industrial hot wter 222 11,961 42 - 33 1607 1,943 - 4 15,812 beaters & boilers

Total 31,669 67,883 1,315 281 1,102 12 21 4 14,322 49,983 841 6,812 801 138 175,144

lT%JFAL 191,270 176,365 1,315 553 1,102 12 21 4 15,019 92,667 841 6,812 801 138 486,92D

Sounze: AE/(WflC "Ezrgia Giadalkodai Statiaztikai E*gxyv 1980" (En=8 E y Statistical Yer-4oi 1980), Table 39.

Hrdc 1984 (1O8P) - 190 -ANN 4.5 AtNX 4

POWR ANDGOLsBSr V

Powr ard Heat Fuel Coxwption

Table 4: FuelCe by Mi17

Aerg Anral Growth Rates (% p.a.) 1955 1965 1975 198D 1981 1982 1955-65 1965-75 1975-8) 19W-8 coal ('000 tcs) Lyinite 2,370 2,871 6,230 7,955 8,060 7,9D0 1.9 8.1 5.0 -0.3 Brnm coal 4,038 8,247 7,916 7,815 7,940 3,470 7b4 -0.4 -0.3 4.1 Coal by-piodts 244 1,258 1,797 1,920 1,970 2,010 17.8 3.6 1.3 2.3

Total 6,652 12,376 15,973 17,690 17,970 18,38D 6.4 2.6 2.1 1.9 oil ( 000 tons) Total 42 491 1,579 1,205 1,100 1,027 27.9 12.4 -5.3 -7.7

Nackral Gas (mllion n3) Total - 254 1,471 3,000 3,350 3,500 - 19.2 15.3 8.0

Energy Equivalent (D) Lignite 19,326 22,038 41,758 53,465 52,970 51,070 1.3 6.6 5.1 -2.3 Brom coal 47,772 92,204 90,969 85,005 84,350 88,630 6.8 -0.1 -1.3 2.1 Coal byits 4,110 13,605 19,314 20,685 21,120 21,600 12.7 3.6 1.4 2.2

Subtotal coal 71,208 127,847 152,041 159,155 158,440 161,300 6.0 2.2 0.9 0.7

Oil 1,649 19,590 63,859 48,900 36,015 41,480 28.1 12.5 -5.2 -7.9 Natural gas - 8,692 52,526 104,505 U6,900 121,820 - 19.7 14.7 8.0

Total 72,857 156,129 268,426 312,560 311,355 324,600 7.9 5.6 3.1 1.9

Fuel Shaes (X Total EreV Equivalent) Coal 97.7 81.9 56.6 50.9 50.9 49.7 Oil 2.3 12.5 23.8 15.6 11.6 12.8 Natural gas - 5.6 19.6 33.4 37.5 37.5

Cwl Type Sumes (X Coal energy Equivalent) Lignite 27.1 17.2 27.5 33.6 33.4 31.2 Braon coal 67.1 72.1 59.8 53.4 53.2 54.9 Coall byl ucts 5.8 10.6 12.7 13.0 13.3 13.4

Source: WM, "Rksultats Tedmiqu Provisoires"

Note: Figures for 198082 are provisimnl.

Mardc 1984 (l8P - 191 - ANNEK4.6 Page 1 of 3

HUNGARY

POUERAND CNL SJBSECM IRIEW

Production Data for District Heating Systems With an Installed Capacity Greater Than 20 MW, 1980

I- Power Ser- stalled produc- ial Type /1 Peak Heat capacity tion Nui- of Heat deli- of CHP in CHP ber City Plant Fuel Demnd vered turbines cycle (aw) (TJ) (NW) (GWh)

1. Budapest IUP oil 6 20 - - 2. Budapest HP gas 131 1,047 - - 3. Budapest HP gas 100 728 - - 4. Budapest UIP coal, gas 24 143 - - 5. Budapest IHP coal, gas 0 20 - - 6. Budapest HP gas 79 111 - - 7. Budapest M[P oil, gas 125 2,081 9.6 38.0 8. Budapest IP oil, gas 0 333 4.7 13.3 9. Budapest HP gas 24 186 - - 10. Budapest M['P oil, gas 149 3,085 21.9 115.5 +151 11. Budapest IP oil 1 14 1.4 5.5 12. Budapest IP coal, oil 5 66 4.1 13.9 13. Budapest TMDP coal, oil, 760 7,146 66.0 280.6 gas 14. Budapest IHP oil 12 108 - - 15. Budapest NIMfP oil, gas 29 2,027 9.7 45.2 +241 16. Budapest HP geothernal 20 109 - - 17. Budapest HP gas 144 1,202 - - 18. Budapest HP oil 17 150 - - 19. Budapest HP gas 123 1,196 - - 20 Budapest IHP oil, gas 2 21 - - 21. Budapest MIP oil 130 2,633 24.0 121.2 +75 22. Budapest HP gas 35 225 - - 23. Budapest HP gas 15 167 24. Budapest HP gas 38 265 - - 25. Budapest IP oil, gas 44 973 31.0 38.1 +60

Subtotal 2,550 24,056 172.4 671.3

/1 IHP = Industrial heating plant HP = Mnicipal heating plant MVMlP= M heat supply plant

(1808P) - 192 - ANNEK4.6 Page 2 of 3

POaERAND CCAL SUBSCItR EVIEW

Production Data for District Heatirg Systemi With an Installed Capacity Greater Than 20 NW, 1980

In- Power Ser- stalled produc- ial Type Peak Heat capacity tion Nun- of heat deli- of CHP in CHP ber City Plant Fuel demand vered Turbines cycle (M{) -(TJ (MB) (GWh)

26. Kanl6 MJF coal, oil 4 572 5.9 22.5 gas +37 27. Pecs MWM coal, oil 96 3,584 0.0 189.7 +262 28. Kecske[it MJMIF gas 27 192 - - +10 29. Kecskemet IHP gas *2 14 - - +12 30. Kecskae&t HP gas 42 280 - - 31. Be6kscsaba MVMCP gas 30 390 - - 32. Szerencs IP oil 14 227 - - 33. Kazincbarcika 4MEP coal, oil 364 5,445 25.0 128.3 gas +72 34. Ozd IP coal, other 0 417 8.5 25.4 463 35. Tiszapalkaoya MIMEP coal, oil 253 2,351 20.0 83.4 gas +59 36. Miskolc IP oil, gas 0 1,670 7.0 14.3 +178 37. Miskolc HP gas 30 291 - - 38. H6diez7vhsArhely HP gas 6 53 - - 39. Szeged H7MIP coal, gas 58 526 1.4 6.6 40. Szeged HP gas 5 163 - - 41. Szeged HP gas 13 140 - - 42. Szeged HP gas 15 166 - - 43. Szeged HP gas 9 83 - - 44. Dunaujvaros IP coal, oil 0 3,646 49.0 129.3 gas, +170 other 45. Sz&esfeh(mvar MrP oil 21 823 1.2 1.6 +106 46. Sz6kesfeh6rvAr IHP oil, gas 5 64 - - 47. Sz&esfeh6xvkr HP gas 21 102 - - 48. Mosamagyar6vAr IP coal, oil 23 466 10.0 10.3 +28 49. Sopron NIMiP coal, oil 55 661 8.5 22.6 +24 50. Gyor MVMIF coal, oil 99 925 8.0 27.9 51. Gyor IP oil, gas 0 30 3.7 0.1 52. Gyor HP oil 241 1,716 - - 53. Debrecen Wm?MrP oil, gas 37 2306 1.5 7.8 +180 54. Debrecen IHP gas 0 51 - -

Subtotal 2,671 27,354 149.7 669.8 - 193 - ANNEX 4.6 Page 3 of 3

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

Production Data for District Heating Systems With an Installed Capacity Greater Than 20 MW, 1980

In- Power Ser- stalled Produc- ial Type Peak Heat Capacity tion Num- of Heat deli- of CHP in CHP ber City Plant Fuel Demand vered Turbines Cycle TRW- 7TJ73 (MW) (GWh)

55. Gy6ngyds MVMTP coal, oil 16 122 - - 56. MVMTP oil 9 159 0.0 0.2 57. Eger HP gas 28 223 - - 58. Hatvan IP oil 37 285 6.5 0.3 59. Tatabanya MVMTP coal 0 116 0.0 5.4 60. Tatabanya MVMTP coal, oil 8 1625 12.5 88.9 gas +194 61. Dorog MVNTP coal, oil 78 1037 2.5 16.3 +18 62. Llbatlan IHP coal, oil 0 10 - - 63. Szdny IP oil 2 19 3.5 13.6 64. AlmlsfUzit6 IHP oil 4 28 - - 65. Almlsfuzit6 IP coal, oil 0 88 12.6 3.3 66. OroszlAny MVMTP coal, oil 2 286 0.0 23.7 gas +37 67. Salg6tarjAn MVMTP oil 0 879 1.5 6.7 +73 68. Budaors HP gas 10 31 - - 69. Dunakeszi HP gas 7 75 - - 70. Godolld HP coal, oil, 11 51 - - gas 71. Szentendre HP oil 0 51 - - 72. Kaposv5r HP gas 18 136 - - 73. ZAhony HP oil 3 46 - - 74. Hyiregyhlza MVMTP oil, gas 192 2336 9.5 25.2 +115 75. Szolnok IP other 0 26 3.1 13.4 76. Szolnok HP gas 17 111 - - 77. Szolnok HP gas 25 200 - - 78. Paks MVMTP oil 26 296 - - 79. Szekszlrd HP oil 75 495 - - 80. Szombathely HP oil 16 94 - - 81. Peremanton IHP oil 3 37 - - 82. DelatonfUzr6 IP oil 26 422 0.0 11.8 83. Ajka MVMTP coal, oil 175 4802 22.6 160.6 +73 84. Vlrpalota MVMTP coal 48 353 - - +2 85. Varpalota MVMTP coal, oil 30 392 - - +26 86. SzAzhalombatta MVMTP oil, gas 390 7944 40.0 423.3

Subtotal 1,794 22,775 114.4 792.7

TOTAL 7,015 74,185 436.5 2133.8

Source: EGI

March 1984 (1808P) PC,kR At7 OaAL SllWJOR REVI 080321082338110921398310/0

(Ti)

other Other Other Cr-de Nat,ral Geo- Bi- Oth Dry CGoat Tr Hfsac- Petrole Eleetri- 1 C- Fi )O Oil Ga thr e Pi-y Bris,tret LiHyiro7 GOce irl Prdc Ga ft-r Gas LPG7 slir Mrean GLs Oil Feel C41 Predicts a ciy t ureAL

PreEsetia 291,170 23,987 1,962 82,976 206,860 54,087 23,832 13,902 - 12,551 18,732 ------73),032 7Is.tre 42,221 - - 289,296 135,043 - - - 9,961 - 33,700 117 - - - 1,071 21,042 9,030 29,688 363 - - 87,484 659,016 E.prts (528) - - - (417) ------(945) Stark Ch.g. (4,159) (150) - 6,683 (68) - - - (180) - (1,2D1) (19) (118) - - 483 1,386 (252) 2,268 (7,373) (203) - - (2,825)

lOTALAVAILABlE 328,7l4 23,837 1,962 378,955 341,418 54,087 23,802 13,982 9,781 - 32,499 93 (110) _ - 14,105 41,160 8,778 31,95 (6,940) (323) 87,44 1,385,276

Of bid, Crri.l 328,704 14,650 1,962 378,955 341,418 - - 9,781 - 32,499 98 (n1o) - - 14,105 41,160 8,770 31,956 (6,940) (203) - 87,484 1,285,107

Pettola -rfiniaRr - - (377,839) (2,331) ------3,2)3 61,988 (268) 152,858 114,802 32,238 (8,649) (807) (24,935) iqtertigp (20,227) ------26,591 (2,231) - _- (120) (4,716) (321) (44) (1,068) Linite dryiag (3,442) - - - _ - - - - 3,352 ------(103) (13) (326) Cha Fbietion - (851) ------411 - _ - - - _ - - - - - (440) Ccke 0 (35,775) - - - (916) - - - - - 25,5&3 - 1,857 - 3,731 ------(161) (79) (5,768) T-nsgas - - - - (6,001) -- - (8) 8,968 (1,964) (384) (972) ------(341) Othe let re~d G Eleetririty 6 8at (108,454) (205) (1,962) - (185,246) - - - (915) (635) (1,332) _ (2) (1,056) (8,199) (22) (1) - (15,431) (86,294) - 191,642 28,739 (268,026) o Bi,trhibti les- - - (5,108) (18,539) (23,647)

W9 SUPPLYAVAILAlE 82,826 3,59 1,066 146,924 _ - 35 ,457 486 56,275 589 1,737 7,912 (_6432) 16,922 102,095 8,510 169,33 21,448 27.,39 177_300 (96,740) 9

- y Esrte ------(100) - _ (290) - - - (4,290) (11,844) - (4,746) (1,533) (7,638) - - (30,441) B.icekGaes ------_ _ _ _ _ - _ _ - - - swe flC(NG oTPJH 82,806 13,594 - 1,066 146,924 __ _ 35,357 486 56,750 219 1,737 7,912 (6,432) 12,632 9(,251 8,510 167,637 19,915 19,681 177,30 96,740 930,243

OFONSLHG)NBY fSE797 Agri-lb-r 5 Iter 1,379 932 - - 3,106 - - _ 368 - 283 1 - 9 - 88 5,754 45 52,539 922 - 3,648 9,29 77,283 virGsg 484 9 - 1,066 11,285 - - - 52 41 13 16 - I - 17 686 24 2,373 93 43 3,096 5,390 24,789 I..try 14,949 438 - - 99,639 - - _ 277 13 51,764 192 914 1,343 11,649 2)5 36,421 174 L3,863 16,954 - 115,168 46,062 410,024 ef hich Fed Peed-te 333 161 - - 1,409 - - - 35 11 629 - 914 213 - 30 893 4 4,378 1,075 - 21,992 3,973 35,136 961011,0-89 3,791 104 - - 28,629 - - 40 1 48,959 124 - 8 11,643 1 183 19 965 6,290 - 19,168 L3,870 1y3,709 Measinetos 233 34 - - 5,241 - - - 65 - 1,538 14 - 325 - 45 1,143 82 3,603 511 - 15,793 6,508 35,113 IBiLding Mbteriale 68,320 31 - - 23,391 - _ - 36 - 499 4 - 252 - 54 255 13 2,729 8,674 - 4,102 4,000 54,536 Ch,irals 73 2 - - 40,186 - - - 4 - 21 48 - 5 3 6 71 33,224 29 728 106 - 33,150 11,467 119,695 06lsrr 199 106 783 - - - 97 1 118 2 - 65 - 8 723 29 1,460 210 - 23,963 6,24, 34,015 GC tescticn 188 131 - - 420 - - - 149 - 103 4 - 24 - 21 2,548 ]09 6,009 4 - 5,164 1,267 16,141 Tr-srt 6 CG aictiee 4,666 29 - _ 2,463 - - - 322 35 89 6 - 31 - 5 7,699 5,747 3D,626 1,486 4,980 5,499 63,583 Ele-tririty 2 2 -9 -1 1 - 16 - - 1 361 2 206 8 1,720 - 2,329 S-riree - 10 - - 452 - - 23 - 7 _ _ 22 5 5 342 5 1,099 4 1,034 8T3 3,870 Hiend,ld & CGm l 59,104 12,043 - - 29,460 - - 334,105 397 4,475 - - 6,481 - 12,290 36,441 2,404 57,922 - - 42,603 29,493 327,282 INw &-rgyoee _ - _ - - _ _- 823 - - _2,082 - 320,905

3 T3TAL 8),826 13,594 - 1,066 146,934 _ _ - 35,357 486 56,750 219 1,737 7,912 11,649 12,63 92,251 8,510 1641,637 199471 32,2 1 96,7,4 966,176S lErn - _ _ - (10) - - - - - _ _ - _ (18,081) - (1) - - 444 (444) - - (18,092)

Fdeeay 1984 (1808p) - 195 - ANNEX 5.1 Page 1 of 3

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

Power and Coal Demand Forecasting

Institutional Responsibility

1. The Ministry of Industry (IpM) has overall responsibility for energy demand forecasting and planning. The two activities are not separable, because of the widespread supply and demand interaction among supply subsectors and fuels. Although energy demand forecasting and planning and the formal responsibility of IpM, many other institutions have a major involvement. For example, OKGT is heavily involved in preparing the oil and gas supply projections, the Coal Association prepares coal supply projections, EROTERV is responsible for power demand forecasting and supply planning, as well as the computing aspects of the planning model, AEEF and VEIKI prepare data and energy balances and KBFI is responsible for economic analysis. In addition the energy planning process is linked to the overall economic planning framework. NPO prepares economic and social projection, which include outline scenarios for energy prices, imports and aggregate demand, which are used as the basis for detailed projections of energy consumption. NPO is assisted by the Hungarian Academy of Sciences, the National Commission for Technical Development, the various ministries, including IpM and other planning commissions summoned by NPO.

Approach to Forecasting

2. Because of the many possibilities for interfuel substitution, and the interdependence of the supply subsectors, e.g., power and coal, projects of the demand for power and coal are obtained from the national energy planning model. In the past, electricity demand forecasts were prepared on the basis of extrapolating past trends and also by aggregating regional MVMT forecasts that took account of local projects and developments. However, these forecasting techniques produced forecasts with large errors and no longer serve as the basis for generation investment planning, although the regional forecasts are used as a check, especially for the first few years of the forecast.

3. The procedure for forecasting the consumption of energy consists of a series of computer models, executed sequentially in an iterative manner. The link between the national economic planning and energy sector planning is a modified Leontief Input-Output model. This explicitly recognizes not only the interrelationships among the main energy sector, but also their interdependence on energy in general and requirements of particular fuels. The sequence of sub-models and in the energy planning process is described below. - 196 - ANNEX 5.1 Page 2 of 3

4. The procedure for forecasting the demand for energy consisting of a series of computer models, is itself sequentially implemented. First, based on the historical relationship between growth of GDP for each of the main sector of the economy and consumption of energy by type, the demand for solid fuels, oil and natural gas, and power associated with each development scenario is forecast. In these forecasts, a distinction is made between substitutable and non-substitutable demand for electrical energy; the former measured in terms of useful energy and the latter in terms of final energy. The distinction is made for the purpose of ascertaining the extent to which electrical energy can be displaced by other energy products. Second, the forecast of the consumption of electrical energy is used in preparing forecasts of maximum power demand for industrial and non-industrial consumers and that of the entire electricity supply system.

5. Third, these demand projections are employed in developing an investment program for the electric supply system, which addresses the utilization of existing plants and the additional capacity required to meet the forecast base and peak load demand for power, compute on a daily, weekly, monthly and yearly basis. The focus of the program is on establishing a schedule for (a) commissioning new plants which would allow for the existing capacity of the electric supply system to be operated efficiently and economically, and (b) the investments required for the commissioning of new capacity. A computer program optimizes the production of electricity to achieve minimum cost, apportioning the output to be generated by each power plant. Since the type of fuel consumed by each plant is known, the procedure also establishes the fuel requirements by type of fuel for the entire power system.

6. Fourth, based on the forecasts of the demand for fuels associated with each development scenario, energy balances for the nation are computed to establish fuel supply requirements. In preparing the energy balances, special attention is accorded to the following:

(a) given the structure of the forecast demand for energy associated with each development scenario;

(b) specifying the structure of basic energy products required to meet the qualitative demands of consumers; and finally

(c) specifying a structure for energy products that would meet the forecast demand for energy at least cost to the economy.

7. In the fifth step, the data from the energy balances together with the geological information are used in planning the development of coal mining capacity and in preparing alternative scenarios and balances for the production of different types of coal. The forecasts of coal production are based on the following criteria:

(a) the demand for coal be satisfied at a minimum social cost;

(b) investment costs of the different variants be at a minimum; - 197 - ANNEX 5.1 Page 3 of 3

(d) the mix of coal products chosen should satisfy consumer demand optimally.

8. In the sixth step, hourly, daily and seasonal load curves for the forecasteddemand for natural gas are computed, allowing for seasonal changes in temperature. The domestic production of natural gas is then forecasted based on known reserves, the exploitationplans for each natural gas deposit and the results of exploration. The differencebetween the variants of the demand and domestic productionprovide the forecasts for imports of natural gas.

9. In the seventh step, a procedure similar to that for natural gas is used to forecast the domestic productionand imports of crude oil. In addition,based on the forecasteddemand, separate balances for each of the petroleum products are also prepared. These, in turn, are used in determining refinery capacity, the volume and directionof piped delivery and the place and size of storage plants.

10. Finally, the demand and supply parameters for energy associatedeach development scenario are synthesizedand detailed energy balances for the nation as a whole are developed. This modelling process is re-run iteratively until an energy balance that meets the supply constraintsand fulfills economic and policy objectives is achieved. Since the process involved in developingthese energy balances is cumulative,they are referred to in Hungary as vertical models of energy.

February 1984 (1829P) - 198 - ANNEX 5.2

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

Average Nuclear Construction Time Span /1

Reactors Reactors in Operation under Construction Average Average Construction Number Construction Number Time of Time of Country (months) Units (months) Units

Argentina 69.0 1 87.5 2 Belgium 66.0 4 76.3 3 Brazil 131.0 1 135.0 2 Bulgaria 76.5 4 65.0 1 Canada 66.9 11 90.9 12 Cuba 107.0 1 Czechoslovakia 70.0 2 75.0 3 Finland 68.5 4 France 64.8 30 63.1 26 German Democratic Republic 61.0 5 Germany, Federal Republic of 61.5 15 116.2 9 Hungary 113.5 2 India 88.3 4 130.5 6 Italy 64.7 3 104.3 3 Japan 83.5 26 53.6 10 Korea, Republic of 89.0 1 75.0 8 Mexico 108.0 2 Netherlands 44.5 2 Pakistan 62.0 1 Philippines 105.0 1 Poland 73.0 1 Romania 71.0 2 South Africa (Customs Union) 80.5 2 Spain 60.8 4 100.2 11 Sweden 65.2 9 77.3 3 Switzerland 51.3 4 119.0 1 United Kingdom 77.4 17 129.6 9 United States of America 73.3 76 128.4 54 USSR 73.3 16 76.8 4 Yugoslavia 83.0 1

Average, All Countries 68.2 241 100.2 178

Source: IAEA,"Nuclear Power Reactors in the World", (September 1982).

/1 Construction time is defined as the time between first placing of concrete and connection to the grid of the reactor.

March 1984 (1829P) - 199 - ANNEX 5.3 Page 1 of 15

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

Analysis Power Generation Investment Options

A. Objectives of the Study

Introduction

1. A major issue in the power subsector is the choice of investment for power generation after the first phase of the Paks nuclear station is completed in 1989 (4x440 MW). A second substantive issue is the appropriate methodology for appraising power generation investments. Furthermore, it is necessary to test the sensitivity of investment decisions to changes in key parameters (e.g. capital costs), in order to appreciate the risks of various investment strategies.

2. An established computer program was used to evaluate generation investment alternatives. Because of the complexities of the Hungarian power system, e.g. substantial contracted imports, large CHP options, and the interlinked costs arising from the economic dispatch of units with different fuel costs, this analysis could not be carried out satisfactorily without recourse to a computer model.

Objectives

3. The overall purpose of the study was to evaluate a least-cost development program based on data that were available to the mission. This least-cost program could be modified by the authorities to take account of more detailed information on investment costs, technical options, system operation and policy constraints which will be available when their current studies are completed. Specifically, the study had the following objectives;

(a) investigation of the relative economics of lignite, coal, nuclear and CHP projects;

(b) estimation of the long-run marginal cost of generation; and

(c) preparation of generation capacity, generation and fuel consumption projections for the power subsector. - 200 - ANNEX 5.3 Page 2 of 15

Use of the model for tasks (b) and (c) is described respectively in Annex 8 and Chapter V of the main text.

B. The Model

Computer Program

4. The WASP III (Wien Automatic System Planning) package of the IAEA was used for the study. This combines probabilistic simulation for estimating unit operation and fuel costs, with dynamic programming for the long-term optimization of capacity additions. Probabilistic simulation is particularly appropriate to the modelling of predominately thermal power systems, since it can take the random forced outages of plant into account. Dynamic programming enables a wide range of alternative expansion programs to be evaluated efficiently. The program is widely used worldwide and is available to IAEA members at nominal cost.

Demand

5. The forecast for maximum demand and energy generated was provided by IpM. The annual load forecast is shown in Attachment 1. As the IpM forecast did not project beyond 2000 a lower growth rate of 2% p.a. was assumed. The model used "sent out" quantities, i.e. net of power station own use. Since it has been shown that ignoring plant maintenance scheduling can lead to significant errors in fuel cost and loss of load probability (LOLP), the production cost simulation was carried out for four seasons per year. The IpM demand forecast was adjusted by the mission using MVMT historic data to provide quarterly forecasts. The MVMT annual load duration curve for 1981 was adjusted slightly to provide quarterly load duration curves that encompassed the projected maximum demand and energy (Figure 1).

Existing Generating Plant

6. Operational data for existing generating stations and stations under construction were supplied by MVMr. Such data included station capability, minimum loading, heat rates at maximum and minimum load and fuel costs. Information provided by IpM and MVMT was used to estimate the net (sent out) station outputs, forced and maintenance outage rates and fixed operating and maintenance costs. 1/ Details of existing conventional thermal plant are shown in Attachment 1.

1/ Since plant retirement was not considered as an option, the'level of the fixed operating and maintenance costs of existing plant had no effect on the choice of project. - 201 - ANNEX 5.3 Page 3 of 15

7. CHP plant present particular problems in modelling the Hungarian power system. Since CHP plants are generally operated first of all to produce heat and are operated on base load during the heat producing season, these plants were modelled as MW and GWh outputs that had no cost to the system. The GWh outputs were obtained from past operating data and output projections by EGI. This representation of CHP plant is analogous to energy limited hydro plant. Accordingly CHP plant was included in WASP using the hydro modelling capability of the program. This enabled the CHP plant to be scheduled so as to utilize its available energy (CWh) and power (kW).

8. Until 1991 CHP plant amounted to 451 MW operating at a capacity factor of 43%. In 1991, the CHP projects shown in Table 1 were assumed to be commissioned:

Table 1

CHP Projects

Installed Capacity Net Output (MWg) (MWso)

Dunamenti 2x180 338 Gyor 2x48 90 North Pest 2x23, 2x46 130 Almasfuzito lx14 13 Szolnok 1x14 13 obuda 1x46 43 Debrecen 1x8.6 8 Nyiregyhgza 1x9.6 9 Kecskemet 1x7 7

693 651

These CHP projects would have a total net electric power output of 3,710 GWh/a, equivalent to a 65% capacity factor. The new CHP units were assumed to be commissioned in 1991 for almost all of the cases investigated. An exception was a sensitivity analysis to examine the economic justification of new CHP plant (para. 25). Since the supply of heat to the Duna oil refining would be provided by the new 2x180 MW Dunamenti units, the existing old CHP units were assumed to be "retired" and then brought back as new low merit order conventional steam plant. These old units are shown as "DNIC" and "DNID" in the printouts.

Imported Electricity

9. Power imports presented similar problems to CHP plant. No information was available to the mission on the costs of changes to the level - 202 - ANNEX 5.3 Page 4 of 15

of imports. In any case, the Government had provided projections of annual energy (GWh) and maximum transfer (MW) coincident with the system maximum demand. Imports could then be treated as energy limited hydro plant, so that the program dispatched imports to ensure that the projected MW and GWh amounts were utilized. As these amounts appear to be contracted and incremental cost data was not available, no analysis of varying the level of imports was undertaken, although the model would be capable of doing this.

New Projects

10. The projects considered as options were:

(a) Bicske brown coal station, 4x250 MW (BCOL);

(b) Biikkabrany lignite station, 8x250 MW (LIGA);

(d) a further reactor at the Paks nuclear station, lx1,000 MW (NUK 1);

(e) a second additional unit at the Paks station, lxl,000 MW (NUK 2);

(f) a 1,000 MW nuclear unit at another site (NUK 3); and

(g) an unlimited number of 100 MW gas turbines fuelled by distillate oil (V-GT).

Pumped storage was not considered an option for the following reasons: (a) preliminary runs showed that there would be no low running cost plant, i.e. nuclear operating near the margin at night, to provide cheap pumping energy; and (b) the lead time for a pumped storage station would make it a long-term option.

11. Capital cost data are shown in Table 2 below. WASP uses a single cost/kW for each station which includes the construction cash flows compounded to the year of commissioning at the 12% real discount rate. This is conceptually analogous to interest during construction, except that "interest" is calculated at the economic discount rate. Consequently, the present value of the capital costs used in WASP is identical to the present value of the construction cost cash flows. A five-year construction period was assumed for the coal-fired plants, based on worldwide experience, although the Bicske and Biikk&brhny stations were constrained not to be considered before 1991 and 1992 respectively because of the mine construction lead times. The nuclear stations were assumed to have a 9 year lead time which includes the 100 months average construction time in IAEA member countries (Annex 5.2), plus an allowance of 8 months to allow for delays caused by the nuclear station being the first of its type in Hungary and in consideration of the delays to the first Paks units. - 203 - ANNEX 5.3 Page 5 of 15

Table 2

Capital Costs of Generation Alternatives (1983 prices)

Interest Total Installed Cost/kW Cost/kW Constr. During /2 Cost/kW Capacity Installed Sent Out /1 Period Constr. Sent Out Project (MW) (US$/kW) (US$/kW) - (Years) (%) (US$/kW)

Biikkabrgny 2,000 990 1,071 5 39.4 1,493 Lignite B 1,000 1,130 1,223 5 39.4 1,705 Bicske 1,000 960 1,013 5 39.4 1,412 Nuclear 1 /3 1,000 1,120 1,217 9 86.2 2,266 Nuclear 2 75 1,000 1,180 1,283 9 86.2 2,389 Nuclear 3 /3 1,000 1,340 1,457 9 36.2 2,713 Gas Turbine 105 380 400 3 25.8 503

Source: IpM, mission estimates.

/1 Cost/kW based on station capacity adjusted for station use. 12 Interest during construction as a percentage of the cost/kW sent out. 77 Excludes initial fuel loading of US$108/kW.

12. Fuel prices for new projects were based on IpM figures adjusted to 1983 prices. These were 500 cents/Gcal (48 Ft/GJ) for lignite (Biikkabrgny) and 700 cents/Gcal (67 Ft/GJ) for brown coal at Bicske. Lignite at the next project was assumed to cost 10% more than Biikkabranylignite since the lowest cost resources would be developed first. MVMT's estimate of the economic cost of nuclear fuel was 0.63 UScents/kWh or 25 Ft/kWh. In the model part of this was assumed to be included in the initial fuel loading (US$108/kW) and the remainder as an equilibrium nuclear fuel cost of 0.42 UScents/kWh. Gas turbines were assumed to burn gas oil at a cost of US$29.42/Gcal, or about US$300/ton, equivalent to the border price plus delivery costs. Natural gas might be an option for these units. Gas has an economic cost roughly equivalent to fuel oil, but transmission costs would have to be added to this. Assuming gas oil as fuel is the least favorable assumption for gas turbines. Other (fixed) operating costs were based on IpM planning data. Operating data for new projects are shown in Attchment 1.

Unserved Energy

13. WASP III includes the cost of unserved energy in the objective function as a cost to be minimized. IpM has estimated a function for the cost of unserved energy which involves the cost of emergency imports, followed by - 204 - ANNEX 5.3 P'age 6 of 15 the costs of load shedding. This function was difficult to represent as the polynonial required by WASP given the data available. Unserved energy was therefore modelled in two parts. The first, consisting of 400 MW of emergency imports, was modelled as a conventional thermal plant. The seconclpart was the constant US$l.5/kWh cost of actual load shedding. This representation is not unrealistic since emergency imports are not really unserved energy. The model calculated emergency imports to be small, usually less than 30 GWh, equivalent to a capacity factor less than 1%. However, the model does assume that up to 400 MW of emergency imports would be available when required.

C. The Results

Base Case

14. The optimum solution with respect to the assumptions described in Section B above is presented in Attachment 1 and summarized in Table 3. This case has some interesting characteristics:

(a) it shows that apart from the 651 MWSo of CHP plant assumed commissioned in 1991, no major power-only plant is required until 1995. This result depends on the assumption that these CHP projects could be commissioned by 1991 and would produce the net increment in system capacity of 651 MWSo. For example, if it were uneconomic to maintain the old Dunamenti units in service the Bukkabrany project might need to be advanced. Furthermore, if emergency imports were unavailable then more generating plant would be required. The model estimates that emergency imports in 1994 would amount to 29 GWh, a capacity factor of 0.8% on the 400 MW allowed. However, should these emergency imports be unavailable, the model would probably substitute them with gas turbines, rathr than by advancing base load coal plant;

(b) the solution shows that lignite and brown coal plant are preferred to 1,000 MW nuclear units. A 1,000 MW nuclear station enters neither the optimum solution, nor the 5 solutions closest to the optimum;

(c) Biikkabrany lignite is preferred to the Bicske brown coal option, but Bicske is preferred to the second lignite project. The second lignite project was assumed to have a capital cost 20% greater than BUkkabrany and a fuel cost 10% greater, which indicates the order of the sensitivity of the lignite versus brown coal decision to changes in lignite project costs;

(d) peaking capacity is required throughout the planning period. The model shows 7xlO0 MW of gas turbine capacity being commissioned between 1995 and 2010. Three of these are required in 2010 and this may be because all potential coal and lignite capacity has been - 205 - ANNEX 5.3 Page 7 of 15

used. The model might have chosen domestic or foreign coal options had they been available;

(e) loss of load probabilities (LOLP) after allowing for planned maintenance are less than 0.7% or 61 hours per year (61 h/a) 1995 and 0.655% (57 h/a) in 1994, the last year before the first Biikkabrany unit enter service. These figures are close to the IpM security standard of 50 h/a. The average LOLP for the period 1995-2010 is 1.09% (95 h/a), which suggests that if the cost of unserved energy is US$1.5/kWh, it might be economic to lower the system reliability standard.

15. Seven sensitivity studies were carried out to test how the results (a) to (e) above might change under alternative assumptions. These are described below and summarized in Table 3.

Higher Coal Capital Costs

16. Case B examines the sensitivity of the place of lignite and brown coal options to a 20% increase in their capital costs. This results in some re-arranging of the timing of units from the year 2000 onwards, but the ranking of projects does not differ from the Base Case (Table 3).

Lower Nuclear Capital Costs

17. Cases C and D investigate how far the nuclear capital costs would need to fall before 1,000 MW nuclear units enter the optimal solution. The base nuclear capital cost of US$1120/kW (at 1983 prices) before economic "interest during construction" is low compared to the IAEA base estimate of US$1,620/kW and high and low estimates of US$l935/kW and US$1235/kW, whereas the lignite and brown coal capital costs are close to international levels. The sensitivity analysis is therefore more of an examination of the impact of construction times shorter than the 9 years of the Base Case. Case C is when nuclear capital costs are 15% lower than the Base Case, which would correspond to a 7 year construction period. This assumption has no effect on the optimal solution, which is identical to the Base Case. Case D considers a 25% reduction in nuclear capital costs which would correspond to a 5 year construction period. Construction periods for reactors under construction of less than 7 years have only been achieved by Japan, France and Bulgaria (Annex 5.2) and such a short construction period would be unlikely for the first reactor of a new type in Hungary, given the experience of Paks with multinational contracting and the apparent nuclear production difficulties in the USSR (para. 5.27). Even under the assumption of a 25% reduction of capital cost, only one nuclear unit enters the optimal solution. This is not until 2006, after the BUkkgbrany and Bicske plants have been constructed. Since only one nuclear unit is selected (the second lignite station and gas turbines follow the nuclear statios), it is likely that the cost reduction needed to force nuclear into the optimal solution is nearer 25% than 15%. - 206 - ANNEX 5.3 Page 8 of 15

No Oil Price Escalation

18. The Base Case assumes that the prices of oil and natural gas would be escalated in real terms according to the Bank's current projection, i.e.:

1984 -4.9% 1985 -2.4% 1986-1990 +2.0% p.a. 1991-1995 +4.1% p.a. 1996-2010 +2.0% p.a.

Holding the prices of oil and gas at their 1983 levels results in the investment program shown in Case E. This case does not differ much from the Base Case (Table 3), but as would be expected, gas turbines are commissioned earlier although their total number remains the same.

High Gas Turbine Scenario

19. Case F examines the effects of a number of assumption favorable to fas turbines, i.e.:

(a) gas turbine capital cost of US$315/kW (including economic interest during construction) instead of US$503/kW as in the Base Case;

(b) no fuel price escalation; and

(c) imports being base-loaded, i.e., all the contracted GWh being absorbed, but only 1,100 MW to 1,300 MW of the maximum imported power of about 1,800 MW being taken. Emergency imports were assumed to remain at 400 MW.

Under these assumptions the lignite and brown coal program is delayed slightly, but 18x100 MW gas turbines are chosen for the optimal solution. This result would indicate that imports have an important peaking role and that a lower level of imported power (MW) would lead to more peaking plant being required. However, at the higher base Case capital and fuel costs for gas turbines, the number selected would probably be much less than 18X100 MW.

No CHP Plant

20. The effect of the CHP plant in delaying lignite and coal investment is shown clearly in Case G. New generating plant would be required in 1992, when WASP choses a gas turbine, rather than starting the BUkkabrAny project. Bukk&brany would be advanced about two years to be commissioned between 1993 and 1998, rather than 1995 to 2000 as in the Base Case. A nuclear station is shown for 2009, after the coal and lignite options available to WASP have been - 207 - ANNEX 5.3 P&aWof 15

Tble 3

S&uwey Greratian Expuiai PiErgu /1

CaseA Came B CasC Ca" D Cme E Cam F Case C Case H 14,lwr N,,tasr No Oil Coal Capital Caital Caita1 Price Hih Gs No CHP Lignite +35% Base Cae Coats +20S Costs -152 Coat -252 Ealatim Ttzbin Plat Coal +30Z

(am a (tsie as 1990 Bae Case) - _ _ BaeCase)

1991 HP CHP CNP CN c O - CHP

I192 - - - - - Gr 1,2 GT I -

1993 - - - - - Gr 3,4,5 (B3K1 - (Cr 2

1994 - - - - - cr6.7.8 (B' 2 - (BK 3

1995 (B'1X 3 11 (BK 11 (311 (aNti (a1 1 (IK 4 (ELK1 (Gr t a! (I t ( Ir (a I (0 9 (r 1

1996 31 2 RR 2 RR 2 BXK22 1 2 (3t( 2 BK 5 E.1 2 (RR 3

1997 B3 3 31K 3 BR 3 1(K3 1E 3 31 4 (31 6 1K 3 (EK 7

1998 (31 4 (31K 4 (BI 4 (BX4 (31 4 (3K 5 H1 8 (31( 4 (BK 5 (Bl1 5 (E1 5 (ILK 5 (CrTD (U(K 5

1999 31K 6 31 6 B1 6 E1(6 31 6 3. 6 BCS 1 31 6

2000 (3E1 7 31 7 Dt 7 31(7 (BK 7 (AK 7 (BCS 2 (IK 7 (RE3 L 831(8 B3I( 8 38 (G 2 (IX 8 (BUS 3 (31( 8

2001 (Gr 2 (8ICS 1 (GI 2 BCSt 1E3 8 r 11,12 GT 3,4 (Gr 2 (Gr 3 (Gr 3 (Gl 3 G13 Gr 3 (Gr 3

2OD2 BICS 3 1X 8 BICS I CS1 BICSt BCS t BICS 4 ICS 4

2003 BICS 2 BICS 2 B3S 2 BES2 2 BS 2 BES 2 LB 1 BICS 2

2004 BICS 3 BICS 4 1CS 3 BICS3 (Gr 4 HICS 3 LGB 2 BFCS 3 (Grs5 r5

2005 BICS 4 Gr 4 BICS 4 BCS 4 M 3 Gr 13,14 L1B 3 B3CS 4

2006 L1B I Gr 5 (10B 1 NM 1 BCS 4 BFCS 4 L B 4 LIGB 1 ar 4 (Gr 4

20D7 L13 2 (10 1 IMB 2 - Lim I ar 15, 16 Gr 6, 7 LIGB 2 (Gr 6 17

2(OD L0B 3 L10 2 LIGB 3 LIGB I (LIGB 2 (LIGB 1 Gr 8, 9 10B 3 (Gr 6 (Gr U8

2009 L. 4 L. 3 LIB 4 Gl 3, 4, LB 3 10B 2 N( 1 LIGB 4 5

2010 Gr 5, 66 (LUB 4 Gr 5, 6, Gr 6, 7, (LIGs 4 1B 3 - Or 5, 6, 7 (0r 7 7 8 (Gr 7 7

Pxeant value cast (US$ miion) /2 7,479 7,tG1 7,479 7,477 7,189 7,450 7,859 7,991

Cpcity Additias (WJg)

L eigite 2,772 2,772 2,772 2,079 2,772 2,541 2,772 2,772 BsM, Coal 948 948 948 948 948 948 948 948 Gas turbine 70D E8 700 MD0 7a 1,WO 930 700 N,cats - - - 92D - - 92D - OF 651 651 651 920 651 651 - 651

Total 5,071 5,071 5,071 5,398 5,071 5,940 5,540 5,071

1 COP - cbinmd het and pr; 3K - Bbi&kSr*W lignite; Gr - g turbi; BICS - Bicake brown coal; L.B - lignite plnt; RR 1 - Pd. 5 nuclear unit. /2 Coat in 1983 prices discounted at =22to 1984.

March 1984 (IB2M9) - 208 - ANNEX 5.3 Page 10 of 15 exhausted. It is possible that further coal plant would have been selected in preference to nuclear and some of the gas turbines shown for 2007 to 2010, had it been available. 1/ The results from Case G are used later (paras. 22-25) to investigate the economics of CHP plant.

Higher Coal Prices

21. The Base Case was optimized using IpM estimates of coal and lignite prices, adjusted for inflation to 1983 levels. These cost estimates are believed to be on a financial basis, e.g., accounting depreciation and interest charges and, in the case of coal prices for existing power stations, valuing assets at historic cost. Insufficient data were available to mission to make accurate estimates of the economic costs of brown coals and lignite. However, based on construction cost data of new mines and non-capital operating costs for existing mines it was possible to make rough estimates of the marginal cost of brown coal and lignite. These were about 30% and 35% higher respectively than the figures used in the Base Case. Case H examines the sensitivity of the solution to these large increases in the costs of coal and lignite. The solution is identical to the Base Case. Increasing the price of lignite by 35% and brown coal by 30% for both existing and proposed power stations does not alter the priority of BUkkabrany followed by Bicske shown in the Base Case.

D. Economic Analysis of CHP Projects

Introduction

22. The preceding analysis has been based upon the assumption that the 9 CHP projects would form part of the least cost power development program, after the benefits of district heat production have been taken into account. This assumption is now examined. It must be stressed that although some sound studies of district heating have been carried out in Hungary, the analysis below has been carried out using highly aggregated data. Moreover, the analysis has been carried out for all 9 projects together, whereas some of them may be marginal. The analysis below is intended to be a brief examination of the role of CHP in the generation development program, not a rigorous appraisal of individual projects.

Methodology

23. In the Base Case CHP plant was included as hydro plant scheduled so that the power system could absorb all the available MW and GWh available from

l/ Analysis to estimate the long run marginal cost of electricity showed that a plant burning imported coal would be preferred to nuclear (see Annex 8). - 209 - ANNEX 5.3 Page 11 of 15 the CHP plant. As the timing and output of CHP plant was the same for Cases A to F and Case G it was not necessary to pay close attention to CHP costs. The impact of CHP plant on system costs was obtained by running WASP with CHP plant removed. This led to increased capital and operating costs. The total cost of the system with CHP plant was obtained by adding the present value investment, fuel and other operating costs of the CHP plant to the WASP output costs for power-only plant of the Base Case. From these, the net fuel savings from supplying heat to consumers by alternative means were deducted, representing the non-power benefits of the CHP plant. 1/ CHP projects would be justified if the present value of all CHP and power costs, less net heat benefits were less than the present value of system costs in the power only option.

Results

24. The investment, fuel consumption and fuel savings data for the 9 projects are shown in Table 4.

Table 4

Costs and Fuel Consumption of CHP Projects (1983 prices)

Incremental Fuel Oil/Gas Investment Cost Consumption Fuel Savings Project (Ft million) (Pi) (Pi)

Dunamenti 19,115 34.04 20.44 Gyor 6,100 7.60 5.20 North Pest 7,820 13.85 6.54 Szolnok 1,700 2.52 2.37 Almasfuzito 720 2.47 1.90 Obuda 1,210 3.22 2.19 Debrecen 134 - -0.32 Nyiregyhaza 97 - -0.21 Kecskemet 845 1.65 +1.39

37,741 Coal 62.13 39.50 (US$943 m) Oil 3.22

Source: EGI

1/ Incremental heat transmission and distribution costs are included in the CHP capital costs. - 210- ANNEX 5.3 Page 12 of 15

The results of the analysis are summarized in Table 5. In terms of both capital and operating costs CHP plant would lead to a higher cost power program if the benefits of producing heat are not considered. 1/ However, fuel savings from the avoidance of heat production from conventional boilers offset these higher costs. At domestic natural gas and oil prices the fuel savings are insufficient to offset the higher capital and operating costs. With fuel savings valued at international prices and escalated in real terms the CHP projects become part of the least cost solution.

Conclusions on the Role of CHP in the Generation Program

25. The economics of CHP projects are sensitive to the magnitude of the fuel savings. With fuel savings valued at international prices, CHP projects appear to be part of the least cost power development program. In view of the uncertainty about the estimates of CHP capital and operating costs, fuel consumption and fuel savings, it is recommended that the authorities re-evaluate these projects to confirm that they are indeed part of the least cost programs for meeting power and heat demand. Furthermore, it is recommended that each CHP project be evaluated individually to determine whether it is economically viable. It is possible that some of the CHP projects might not be economically viable. Eliminating such projects would increase the cost advantage of CHP options in the least cost pow(er program.

E. Conclusions

26. Given the planning assumptions described in Section B and the data available to the mission, it appears that the next power generation investment after Paks Units 1-4 (1760 MW) should consist of a number of CHP projects. The largest of these would be the 2x180 MW extension to the Dumamenti power station. However, further analysis is required to confirm that all of these CHP projects would appear in the least cost programs for power and heat and the appropriate timing of the projects. Providing that these projects can result in a net capacity addition of 650 MWSO, it would appear possible to delay the next major power only investment to 1995. This conclusion would also be influenced by the assumptions on imported power, viz about 1800 MW would be available at the time of the system peak, plus an additional 400 MW of infrequently used emergency imports. If these imports were not available, then extra generating capacity would be required. However, if a reduction in imports were to consist of imports at peak, e.g., the 400 MW emergency imports, it is probable that the additional generation would consist of gas

1/ This is partly because the costs of heat transmission and distribution have been included in the CHP capital costs. For the Dunamenti project, the analysis of heat LRMC (Annex 8) indicates that the power generation component alone could be justified as part of the power generation program. - 211 - ANNEX 5.3 Page 13 of 15

Table 5

Review of CHP Economics (Present values to 1984 at 12% discount rate, US$ million 1983 prices)

Program With Program Without CHP Plant New CHP Plant Difference

InvestmentCosts Electricity generation 639.9 1,004.9 CHP plant /1 634.6 -

1,274.5 1,004.9 -269.6

Operating Costs Electricity generation/2 6,509.0 6,803.7 CHP - fuel /3 470.0 - - other _ 107.1 -

7,086.1 6,803.7 -282.4

Unserved Energy 36.5 50.4 13.9

Total Costs 8,397.1 7,859.0 -538.1

Fuel Savings (a) Domestic prices /5 - - - Fuel saving -358.7 358.7 Net present value - -179.4

(b) Border prices (escalated)/6 - Fuel saving -1,599.3 1,599.3 Net present value 1,061.2

Source: WASP outputs, mission estimates.

/1 Based on project cost of Ft 37.7 billion (US$943million), plus economic interest during constructionof 39.4% (5-year constructionperiod). Excludes residual value based on the present value of annuitized costs at 12% discount rate over 25 years. /2 Electricity operatingcosts include both fuel and fixed 0&M. /3 Coal for CHP assumed to cost Ft 75/GJ delivered (US$1.875/GJ)compared to Ft 66.9/GJ for conventionalpower stations located near the pit head. /4 Other CHP costs estimated at 3% p.a. of the investmentcosts. /5 Domestic fuel price (natural gas/fuel)US$2.40/GJ as for Dunamenti power station in WASP model. /6 Border price US$150/t (US$3.70/GJ)for heavy fuel oil exported from Hungary. Natural gas assumed to have same economic cost/GJ. Price escalated at real rates used in WASP model.

(1829P) - 212 - ANNEX 5.3 Page 14 of 15 turbines, although the model has not been run to prove this. Because of the potential importance of the model result that major power-only investment might be able to be delayed until 1995 and the impact of power investment on national investment and the macro economy, it is recommended that the Government evaluate these model findings with view to delaying the major power-only investments.

27. Based on the cost data available to the mission, an additional 1,000 MW nuclear unit at Paks does not appear a high priority in economic terms. Despite the low capital cost of the station compared to IAEA reference data, economic "interest during construction" at the 12% real discount rate puts this option at a disadvantage compared to the coal options. The capital cost (including interst during construction) would have to decrease by 25% before nuclear would feature in the invetment program and even then, the station would not be required this century. A 25% reduction in nuclear capital cost would correspond to a five year construction period, which in our view would be unlikely to be achieved for the first 1000 MW unit in Hungary.

28. Considering the coal options, Biikkabrtny lignite project would be preferred to the Bicske brown coal station, based on the cost data available to the mission. Since Bicske is preferred to a second lignite project with a 20% higher capital cost and 10% higher fuel cost, the advantage of Biikkabrany over Bicske may not be great. The model could be used to test this, although it would be better to wait until more refined investment and fuel cost data are available before carrying out this analysis. The final decision would depend on accurate detailed cost estimates for both power stations and mines. However, given the difficult underground mining conditions for brown coal of low quality for a steam coal, BUkkabrany would probably be preferred if the cost difference were small, because of the lower risks associated with open pit lignite mining, which has already proven to be successful in Hungary.

29. The model indicates the need for more peaking plant to be installed, which we have assumed to be gas turbines. This finding is not altogether unexpected since all plant under construction (Paks) or proposed (CHP, coal and nuclear) is for base loading. The conclusion in favor of gas turbines is not sensitive to the gas oil fuel cost increasing by more than 30% in real terms over the period 1983-1995. Gas turbines also give some flexibility to adjust to unforeseen changes in demand. Since their lead time is only three years, gas turbines can be cancelled or brought forward as the demand forecast changes. Because the CHP plant is justified primarily on fuel savings in district heating& the first gas turbine and Bukkabrany unit shown for 1995 are the first units that would have a changed timing if demand were to differ from forecast. Since a final decision to proceed these units would not be required until the late 1980's, the investment program has some flexibility built into it. Combined cycle plant is an option we have not considered and variations with CHP could be envisioned. Although combined cycle plant usually has an operating regime between base load and peaking plant, this option might change the number of gas turbines and delay the coal investment. It is recommended that the economies of combined cycle be evaluated, particularly if natural gas is available at a cost to the national economy below that of gas oil. - 213 - ANNEX 5.3 Page 15 of 15

30. The model indicates that the present reliability standard of 50 hours/a of load shedding may be too high in relation to the economic cost of outages given to the mission of $1.5/kWh. However, since load is already being shed by the OES system operations at low frequency, additional shedding might involve actual disconnections at a cost higher than US$1.5/kWh. It is recommended that the Government re-appraise both the cost of outages estimate and the reliability standard. The cost of outages should embody both the opportunity cost of outages in the productive sectors and the leisure costs to households. 1/

June 1984 (1829P)

1/ See Mohan Munasinghe, "The Economics of Power System Reliability and Planning", Johns Hopkins, (1981), for a description of the economic issues in setting reserve margins. - 214 - ANNEX 5.3 Figure 1

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

Quarterly Load Duration Curves 1984-2010

oCY) --

. .4

------. . .

(D ------...... -- . ------. ------..-..

co C LEGEND ......

LO _ --. _ ...... JUE-A .US LOADDURTIO C ------SR-- NV ---E -BE-LO A---- D N-- U - -R - ----

E-

(D-~~~~ ~ ~~~~ I I ~~~~~~~~~~~~~~~~~~~~

-JUNFRACUTLONDDRTOF TIMVE

Figure 1 - 215 - ANNEX 5.3 Attachment 1 Page 1 of 29 HUNGARY

POWER AND COAL SUBSECTOR REVIEW

SUMMARY REPORT ON A GENERATIONEXPANSION PLAN FOR

VARIABLE EXPANSIONCASE STUDY - HUNGARY- 1984-2010

PROCESSED BY THE WASP-III COMPUTER PROGRAM PACKAGE OF THE IAEA

STUDY PERIOD

1984 - 2010

PLANNING PERIOD

1984 - 2010

CONSTRUCTIONCOSTS IN MILLION $ ARE REPORTEDONLY FOR PLANTS COt'MISSIONED DURING THE PLANNIIrG PERIOD. ALL. OTHER INFOR11kTION IS GIVEN FOR THE WHOLE STUDY PERIOD.

DATE OF REPORT MARCH 1984 - 216 - A Attachment 1 Page 2 of 29

PAGE 2 TABLE OF CONTENTS PAGE

TYPES OF ELECTRICPOWER PLANTS USED 3 1 ANNUALLDAD DESCRIPTION 4

2 FIXED SYSTEM DESCRIPTIONOF THERMALPLANTS 5 DESCRIPTIONOF COMPOSITEHYDRO PLANTS 6 TilERMALADDITIONS AND RETIREMENTS 8 SUMMARYOF INSTALLEDCAPACITIES 9

3 VARIABLESYSTEM DESCRIPTIONOF THERMALPLANT CANDIDATES 10 DESCRIPTIONOF COMP.HYDRO PLANT CAND. 11

4 CONSTRAINTSON CONFIGURATIONSGENERATED 12 5 OPTIMUMSOLUTION ANNUALACDITIONS OF CANDIDATES 15 SUMMARYDESCRIPTION OF SYSTEMCAP. & ENERGY 16 6 ECONOMICPARAMETERS AND CONSTRAINTS SUMMARYOF CAPITAL COSTSOF ALTERNATIVES 17 INITIAL PARAMETERSAND CONSTRAINTS 18 MODIFIEDPARAMETERS AND CONSTRAINTS 20 7 EXPECTEDCOST OF OPERATION FUEL COSTDOMESTIC 27 FUEL COSTFOREIGN 28 O&MAND ENS COSTDOMESTIC 29 TOTALCOST DONESTIC AND FOREIGN 30 8 CASHFLOW OF CONSTRUCTIONAND FUEL INVESTMENTCOST CONSTRUCTIONCOST - DOMESTIC 31 - FOREIGN 32

INTERESTDURING CONSTRUCTION(IOC) - DOMESTIC 34 - FOREIGN 35

CONSTRUCTIONCOST AND IDC - DOMESTIC 37 - FOREIGN 38

CAPITAL CASHFLOW SUMMARY 40 - 217 - ANNEX 5.3 Attachment 1 Page 3 of 29

PAGE 3

THIS IS A LISTOF THE DIFFERENTTYPES OF ELECTRICPOWER PLANTS USED IN TH4ESTUDY. THE NUMERICCODES ARE USED BY THE COMPUTERPROGRAMS

0 NUCL NUCLEARPLANTS 1 GASO N.GAS/LFOPLANTS 2 LI6N LIENITEPLANTS 3 BCOL BROINCOAL PLANTS 4 GTGO GAS TURB & EMERGIMP HYIM HYDRO& IMPORTS CHPP COM3 HEAT/PWRPLAMTS

ANNUALLOAD DESCRIPTION PERIOD(S)PER YEAR : 4 YEAR PEAKLOADGR.RATE MIN.LOAD GR.RATE ENERGY GR.RATELOADFACTOR MW x MW4 GH4 x X

1984 5550.0 - 2138.3 - 33469.5 - 68.84 1985 5740.0 3.4 2211.5 3.4 34615.3 3.4 68.84 1986 5950.0 3.7 2292.4 3.7 35881.7 3.7 68.84 1987 6180.0 3.9 2381.0 3.9 37268.7 3.9 68.84 1988 6410.0 3.7 2469.6 3.7 38655.8 3.7 68.84 1989 6650.0 3.7 2562.1 3.7 40103.1 3.7 68.84 1990 6900.0 3.8 2658.4 3.8 41610.7 3.8 68.84 1991 7145.0 3.6 2752.8 3.6 43088.2 3.6 68.84 1992 7600.0 3.6 2851.0 3.6 44626.0 3.6 68.84 1993 7670.0 3.6 2955.0 3.6 46254.2 3.6 63.84 1994 7945.0 3.6 3061.0 3.6 47912.6 3.6 68.84 1995 8230.0 3.6 3170.8 3.6 49631.3 3.6 68.84 1996 8495.0 3.2 3272.9 3.2 51229.4 3.2 68.84 1997 8770.0 3.2 3378.8 3.2 52887.8 3.2 68.84 1998 9050.0 3.2 3486.7 3.2 54576.4 3.2 68.84 1999 9340.0 3.2 3598.4 3.2 56325.2 3.2 68.84 2000 9640.0 3.2 3714.0 3.2 58134.4 3.2 68.84 2001 9835.0 2.0 3789.1 2.0 59310.4 2.0 68.84 2002 10033.0 2.0 3864.3 2.0 60486.3 2.0 68.84 2003 10235.0 2.0 3943.3 2.0 61722.6 2.0 68.84 2004 10440.0 2.0 4022.2 2.0 62958.8 2.0 68.84 2005 10650.0 2.0 4103.1 2.0 64225.2 2.0 6S.84 2006 10860.0 2.0 4184.0 2.0 65491.7 2.0 68.84 2007 11080.0 2.0 4268.8 2.0 66818.4 2.0 68.84 2008 11300.0 2.0 4353.6 2.0 68145.1 2.0 68.84 2009 11525.0 2.0 4440.2 2.0 69501.9 2.0 68.84 2010 11755.0 2.0 4528.9 2.0 70839.0 2.0 68.84

PA6E 4 - 218 - ANNEX 5.3 Attachment 1 Page 4 of 29

FIXED SYSTEM SUt1MARYDESCRIPTION OF THERMAL PLANTS IN YEAR 1984

HEAT RATES FUEL COSTS FAST NO. MIN. CAPA KCAL/KWH CENTS/ SPIN FOR DAYS 11AIN O&M O&M OF LOAD CITY BASE AVGE MILLION KCAL FUEL RES SCHL CLAS (FIX) (VAR) NO. NAME SETS MO MWl LOAD INCR ODISTC FGRGN TYPE x x MAIN MW $/KWM $/MWH 3 DN1A 1 15. 37. 2867. 2151. 0.0 1005.0 1 10 6.0 37 50. 4.40 0.0 4 DNlB 3 66. 111. 2819. 1744. 0.0 1005.0 1 10 6.0 37 100. 4.40 0.0 5 DUN2 6 66. 202. 2986. 2013. 0.0 1005.0 1 10 6.0 37 250. 2.50 0.0 6 TISZ 4 47. 202. 2986. 2099. 0.0 1005.0 1 10 6.0 37 250. 2.50 0.0 7 GAG1 2 54. 91. 3942. 2508. 492.0 0.0 2 10 9.7 55 100. 2.50 0.0 8 GAc2 3 109. 181. 3655. 2461. 492.0 0.0 2 10 9.7 55 250. 2.50 0.0 9 TSZP 4 17. 43. 3942. 3144. 793.0 0.0 3 10 7.8 46 50. 4.40 0.0 10 OROS 4 19. 47. 3703. 2906. 607.0 0.0 3 10 7.8 46 50. 4.40 0.0 11 BANA 1 51. 86. 3225. 2150. 628.0 0.0 3 10 7.8 46 100. 4.4Q 0.0 12 PECS 2 10. 26. 4778. 3585. 524.0 0.0 2 10 9.7 55 50. 4.40 0.0 13 BORO 4 10. 25. 4061. 3227. 607.0 0.0 3 10 7.8 46 50. 4.40 0.0 14 AJKA 3 11. 27. 4826. 3752. 649.0 0.0 3 10 7.8 46 50. 4.40 0.0 15 NOV7 5 9. 19. 5494. 4061. 691.0 0.0 3 10 7.8 46 50. 4.40 0.0 16 NVGT 2 80. 80. 3344. 3344. 0.0 2942.0 4 10 20.0 37 100. 0.32 0.0 17 KELN 1 30. 30. 3464. 3464. 0.0 2942.0 4 10 20.0 37 50. 0.32 G0. 18 GYR2 1 2. 2. 5256. 5256. 691.0 0.0 3 10 7.8 20 50. 4.40 0.0 19 MATA 1 19. 19. 2747. 2747. 0.0 1759.0 1 10 6.0 20 50. 4.40 0.0 20 PAKS 1 92. 405. 2760. 2480. 0.0 162.0 0 10 16.8 49 500. 3.00 0.0 21 DN1C 0 7. 15. 2867. 2151. 0.0 1005.0 1 10 6.0 37 50. 4.40 0.0 22 DN1G 0 12. 29. 2367. 2151. 0.0 1005.0 1 10 6.0 37 50. 4.40 0.0 23 EMIM 1 100. 400. 2550. 10430. 0.0 2942.0 4 0 0.0 0 500. 0.0 0.0

PAGE 5 - 219 - ANNEX 5.3 Attachment 1 Page 5 of 29

FIXEDSYSTEM SUMMARYDESCRIPTION OF CCilPOSITEHYDROELECTRIC PLANT TYPE HYIM *** CAPACITYIN MW * ENERGYIN GWH *** FIXEDO&l COSTS 0.0 $/iKW-MONTH P HYGROCONDITICN1 R P PROB.:1.00 0 Er, CAPACITYENERGY YEAR J R BASE PEAK 1984 2 1. 784. 839.2083. 2 881. 742.2313. 3 934. 639.2444. 4 787. 835. 2092. INST.CAP.1624. TOTALENERGY 8930. 1985 3 1 920. 882. 2400. 2 1031. 771.2665. 3 1084. 719.2817. 4 925. 878.2410. INST.CAP.1804. TOTALENERGY 10290.

Page 6

FIXEDSYSTEM SUMMARYDESCRIPTION OF COMPOSITEHYDROELECTRIC PLANT TYPE CHPP *** CAPACITYIN MW* ENERGYIN G4H *** FIXEDO&M COSTS : 9.950 $/KW-MONTH P HYDROCONDITION1 R P PROB.: 1.00 O E CAPACITYENERGY YEAR J R BASE PEAK 1984 2 1 157. 294. 426. 2 157. 294. 426. 3 157. 294. 426. 4 157. 294. 426. INST.CAP.451. TOTALENERGY 1702. 1991 3 1 115. 277. 326. 2 115. 277. 326. 3 115. 277. 326. 4 115. 277. 326. INST.CAP.392. TOTALENERGY 1304.

Page 7 - 220 - ANNEX 5.3 Attachment 1 Page 6 of 29

FIXED SYSTEM THERMAL ADDITIONS AND RETIREMENTS

NUMBER OF SETS ADDED AND RETIRED(-) 1984 TO 2010 YEAR: 19.. (2C0./20..) NO. NAME 85 86 87 88 89 90 91

18 GYR2 . . . . -1 . 19 MATA -1 20 PAKS 1 1 1 . 21 DNIC ...... 2 22 DN10 ...... 1

PAGE 8

FIXED SYSTEM SUMMARY OF INSTALLEDCAPACITIES (NOMINALCAPACITIES (MW))

HYDROELECTRIC THERMAL TOTAL HYIM CHPP F U E L TY P E 0 1 2 3 4 YEAR PR. CAP PR. CAP NUCL GASO LIGN BCOL GTGO 1984 2 1624. 2 451. 405. 2407. 776. 725. 590. 6977. 1985 3 1804. 2 451. 810. 23&S. 776. 725. 590. 7544. 1986 1215. 2388. 776. 725. 590. 7949. 1987 1620. 2388. 776. 725. 590. 8354. 1989 1620. 2388. 776. 723. 59D. 8352. 1991 3 1804. 3 392. 1620. 2447. 776. 723. 590. 8352.

PAGE 9 - 221 - ANNEX 5.3 Attachment 1 Page 7 of 29

VARIABLE SYSTEM SUMMARY DESCRIPTIONOF THERMAL PLANTS HEAT RATES FUEL COSTS FAST NO. MIN. CAPA KCAL/KWH CENTS/ SPIN FOR DAYS MAIN O&M O&M OF LOAD CITY BASE AVGE MILLION KCAL FUEL RES SCHL CLAS (FIX) (VAR) NO. NAME SETS MW MN LCAD INCR OMSTC FORGN TYPE X % MAIN MW $/KWM $/MWH 1 BCOL 0 95. 237. 2210. 2860. 700.0 0.0 3 10 7.0 46 250. 2.40 0.0 2 LIGA 0 92. 231. 2389. 3092. 500.0 0.0 2 10 9.0 55 250. 2.50 0.0 3 LIGB 0 92. 231. 2389. 3092. 550.0 0.0 2 10 9.0 55 250. 2.80 0.0 4 NUK1 0 460. 920. 2760. 2480. 0.0 162.0 0 10 16.8 43 1000. 2.80 0.0 5 NUK2 0 460. 920. 2760. 2480. 0.0 162.0 0 10 16.8 48 1000. 3.00 0.0 6 NUK3 0 460. 920. 2760. 280. 0.0 162.0 0 10 16.8 (8 1000. 3.40 0.0 7 V-GT 0 100. 100. 3100. 3100. 0.0 2942.0 4 10 20.0 12 100. 0.32 0.0 8 CC30 0 141. 282. 2313. 1893. 0.0 2942.0 4 10 7.4 26 250. 1.50 0.0

PAGE 10

VARIABLESYSTEM SUMMARY DESCRIPTIONOF COMPOSITEHYDROELECTRIC PLANT TYPE CHPP *** CAPACITY IN tM * ENERGY IN GIgH*** FIXED O&M COSTS 9.950 $/KW-MONTH

P HYDROCONDITION1 R P PROB.: 1.00 0 E CAPACITY ENERGY YEAR J R BASE PEAK

1991 1 1 204. 134. 514. 2 204. 134. 514. 3 204. 13q. 514. 4 204. 134. 514. INST.CAP. 338. TOTAL ENERGY 2056.

1991 2 1 358. 293. 927. 2 358. 293. 927. 3 358. 293. 927. 4 358. 293. 927. INST.CAP. 651. TOTAL ENERGY 3708.

PAGE 11 - 222 - ANNEX 5.3 Attachment 1 Page 8 of 29

C O N G E N CONSTRAINTSON CONFIGURATIONSGENERATED CON: NUMBEROF CONFIGURATIONS XCLOLPMAXIMUM PERICD LOLP; MINIMUM- RES.MARGIN,- CONFIGURATION ZALOLPMAXIMUM AtNNUAL LOLP; MAXIMUM- RES.MARGIN,- CONFIGURATION

RES. PERMITTEDEXTREME CONFIGURATIONS OF ALTERNATIVES XCLOLP MAR- BCOL LIGB NUK2 V-GT CHPP YEAR CON XALOLP GIN LIGA NUK1 NUK3 CC30

1984 1 100.000 10 0 0 0 0 0 0 0 0 0 1C0.000 40 0 0 0 0 0 0 0 0 0

1985 1 100.000 10 0 0 0 0 0 0 0 0 0 100.000 40 0 0 0 0 0 0 0 0 0 1986 1 100.000 10 0 0 0 0 0 0 0 0 0 100.060 40 0 0 0 0 0 0 0 0 0 1987 1 100.000 10 0 0 0 0 0 0 0 0 0 100.000 40 0 0 0 0 0 0 0 0 0

1988 1 100.000 10 0 0 0 0 0 0 0 0 0 100.0G0 40 0 0 0 0 0 0 0 0 0 1989 1 100.000 10 0 0 0 0 0 0 0 0 0 100.000 40 0 0 0 0 0 0 0 0 0 1990 1 100.000 10 0 0 0 0 0 0 0 0 0 100.000 40 0 0 0 0 0 0 0 0 0 1991 4 100.000 10 0 0 0 0 0 0 0 0 2 100.C00 30 2 0 0 0 0 0 2 0 2 1992 19 100.000 10 0 0 0 0 0 0 0 0 2 100.000 30 2 2 0 0 0 0 4 0 2

1993 48 100.000 10 0 0 0 0 0 0 0 0 2 100.000 30 2 2 0 0 0 0 7 0 2

PAGE 12 - 223 - ANNEX5.3 Attachment 1 Page 9 of 29

C O N G E N (CONTD.) CONSTRAINTSON COCFIGURATIONSGENERATED CON: NUIBEROF CONFIGURATIONS XCLOLP MAXIMUM PERIOD LOLP; MINIMUM - RES.MARGIN,- CONFIGURATION %ALOLP MAXIMUM ANNUAL LOLP; MAXIMUM - RES.MARGIN,- CONFIGURATION RES. PERMITTEDEXTREME CONFIGURATIONSOF ALTERNATIVES %CLOLP HAR- BCOL LIGB NUK2 V-GT CHPP YEAR CON XALOLP GIN LIGA NUK1 NUK3 CC30

1994 72 100.000 10 0 0 0 0 0 0 0 0 2 100.000 30 2 2 0 0 0 0 8 0 2

1995 79 100.000 10 0 0 0 0 0 0 0 0 2 100.000 30 2 2 0 0 0 0 8 0 2 1996 104 100.000 10 0 1 0 0 0 0 0 0 2 100.000 30 2 4 0 0 0 0 8 0 2 1997 105 100.000 10 0 2 0 0 0 0 0 0 2 100.000 30 2 5 0 0 0 0 8 0 2

1998 103 100.000 10 0 3 0 0 0 0 0 0 2 100.000 30 2 6 0 0 0 0 8 0 2

1999 100 100.0Q0 10 0 4 0 0 0 0 0 0 2 100.000 30 2 7 0 0 0 0 a 0 2 2000 97 100.000 10 0 5 0 0 0 0 0 0 2 100.000 30 2 8 0 0 0 0 8 0 2

2001 72 100.000 10 0 6 0 0 0 0 0 0 2 100.000 30 2 8 0 0 0 0 8 0 2

2002 137 100.000 10 0 7 0 0 0 0 1 0 2 100.OGO 30 3 8 1 0 0 0 9 0 2

2003 122 100.000 10 0 7 0 0 0 0 1 0 2 100.000 30 3 8 1 0 0 0 9 0 2

PAGE 13 - 224 - ANNEX 5.3 Attachment 1 Page 10 of 29

C 0 N 6 E N (CONTD.) CONSTRAINTSON CONFIGURATICNSGENERATED CON: NUMBEROF CONFIGURATIONS XCLOLP MAXIMliMPERIOD LOLP; MINIMUM- RES.MARGIN,- CONFIGURATION ZALOLP MAXIMUM ANNUAL LOLP; MAXIMUM - RES.MARGIN,- CONFIGURATION RES. PEREITTEDEXTREME CONFIGURATIONSOF ALTERNATIVES XCLOLP MAR- BCOL LIGB NUK2 V-GT Ch'PP YEAR CON ZALOLP GIN LIGA NUK1 NUK3 CC30

2004 103 100.000 10 1 8 0 0 0 0 1 0 2 100.000 30 4 8 2 0 0 0 9 0 2

2005 247 100.000 10 1 8 0 0 0 0 1 0 2 100.000 30 4 8 2 2 0 0 10 0 2

2006 259 100.000 10 2 8 0 0 0 0 1 0 2 130.000 30 4 8 3 2 0 0 10 0 2 2007 276 100.000 10 2 8 0 0 0 0 2 0 2 100.000 30 4 8 3 2 0 0 11 0 2

2008 183 100.000 10 3 8 1 0 0 0 2 0 2 100.000 30 4 8 4 2 0 0 11 0 2 2009 194 100.000 10 3 8 1 0 0 0 2 0 2 100.000 30 4 8 4 2 0 0 11 0 2 2010 188 100.000 10 3 8 1 0 0 0 2 0 2 100.000 30 4 8 4 2 0 0 11 0 2 2519 TOTAL NUMBER OF CONFIGURATIONSGENERATED

PAGE 14 ANNEX 5.3 - 225 - Attachment 1 Page 11 of 29

OPTIMUM SOLUTION ANMUAL ADdITIONS'CAPACITY(MW) AND NUMBER OF UNITS OR PROJECTS FOR DETAILS OF INDIVIDUALUNITS OR PROJECTSSEE VARIABLESYSTEM REPORT SEE ALSO FIXED SYSTEM REPORT FOR OTHER ADDITIONSOR RETIREMENTS

NAME: BCOL LIGB NUK2 V-ST CHPP LIGA NUK1 NUK3 CC30 SIZE (M;N): 237. 231. 920. 100. 0. *ZLOLP 231. 920. 920. 282. YEAR MAINT NOM;NT CAP 1984 0.007 0.000 0...... 1985 0.002 0.000 0. . . . . 1986 0.0C2 0.000 0...... 1987 0.003 0.000 0...... 1988 0.012 0.001 0...... 1989 0.046 0.004 0...... 1990 0.152 0.019 0...... 1991 0.019 0.002 651...... 2 1992 0.067 0.007 0...... 1993 0.224 0.033 0...... 1994 0.655 0.123 0...... 1995 0.698 0.122 331. . 1 . . . . 1 1996 0.904 0.155 231. . 1 . . . . 1997 1.165 0.202 231. . 1 . . . . 1998 0.889 0.118 462. . 2 . . . . 1999 1.184 0.163 231. . 1 . . . . 2000 0.953 0.104 462. . 2 . . . . 2001 1.049 0.120 200...... 2 2002 1.026 0.110 237. 1 . . . . . 2003 1.028 0.104 237. 1 . . . . . 2004 1.033 0.099 237. 1 . . . . . 2005 1.049 0.095 237. 1 . . . . . 2006 0.902 0.071 331. . . 1 . . . 1 2007 0.983 0.075 231. . . 1 . . . . 20C8 1.061 0.079 231. . . 1 . . . . 2009 1.148 0.085 231. . . 1 . . . . 2010 1.111 0.083 300...... 3

TOTALS 5071. 4 8 4 . . . 7 . 2

PAGE 15 - 226 - ANNEX 5.3 Attachment 1 Page 12 of 29

SUMMARYOF FIXED SYSTEMPLUS OPTIMUM SOLUTION INOMINALCAPACITY IN MW, ENERGYIN GWIH) HYDROELECTRIC THERMAL FUEL TYPE TOTAL SYSTEM ENERSYNOT SERVED HYIM CHPP CAPACITIES CAP RES. LOLP. HYDROCONDITION YEAR 0 1 2 3 4 'l PR. CAP PR. CAP NUCL 6ASO LIGN BCOL GTGO Z Z 1984 2 1624 2 451 405 24Q07 776 725 590 6977 25.7 0.007 ci 1985 3 1804 2 451 810 2388 776 725 590 7544 31.4 0.002 0 1936 3 1804 2 451 1215 2388 776 725 590 7949 33.6 0.002 0 1987 3 1804 2 451 1620 2388 776 725 590 8354 35.2 0.003 0 1988 3 1804 2 451 1620 2383 776 725 590 8354 30.3 0.012 C 1989 3 1804 2 451 1620 2388 776 723 590 8352 25.6 0.046 0 1990 3 1804 2 451 1620 2388 776 723 590 8352 21.0 0.152 1 1991 3 1804 5 1043 1620 2447 776 723 590 9003 26.0 0.019 0 1992 3 1804 5 1C43 1620 2447 776 723 590 9003 21.7 0.067 0 1993 3 1804 5 1043 1620 2447 776 723 590 9003 17.4 0.224 2 1994 3 1804 5 1043 1620 2447 776 723 590 9003 13.3 0.655 6 1995 3 1804 5 1043 1620 2447 1007 723 690 9334 13.4 0.698 6 1996 3 1804 5 1043 1620 2447 1238 723 690 9565 12.6 0.904 9 1997 3 1804 5 1043 1620 2447 1469 723 690 9796 11.7 1.165 13 1998 3 1804 5 1043 1620 2447 1931 723 690 10253 13.4 0.889 8 1999 3 1804 5 1043 1620 2447 2162 723 690 10439 12.3 1.184 13 2000 3 1804 5 1043 1620 2447 2624 723 690 10951 13.6 0.958 9 2001 3 1804 5 1043 1620 2447 2624 723 890 11151 13.4 1.049 11 2002 3 1804 5 1043 1620 2447 2624 960 890 11388 13.5 1.026 10 2003 3 1804 5 1043 1620 2447 2624 1197 890 11625 13.6 1.028 10 2004 3 1804 5 1043 1620 2447 2624 1434 890 11862 13.6 1.033 10 2005 3 1304 5 1043 1620 2447 2624 1671 890 12099 13.6 1.049 10 2006 3 1804 5 1043 1620 2447 2855 1671 990 12430 14.5 0.902 8 2007 3 1804 5 1043 1620 2447 3086 1671 990 12661 14.3 0.983 10 2008 3 1804 5 1043 1620 2447 3317 1671 990 12892 14.1 1.061 11 2009 3 1804 5 1043 1620 2447 3548 1671 990 13123 13.9 1.148 12 2010 3 1804 5 1043 1620 2447 3548 1671 1290 13423 14.2 1.111 12

PAGE 16 ANNEX 5.3 - 227 - Attachment 1 Page 13 of 29

G Y N P R O

SUMMARYOF CAPITAL COSTSOF ALTERNATIVESIN $/KW CAPITAL COSTS INCLUSIVE CONSTR. PLANT CAPITAL COSTS PLANT (DEPRECIABLEPART) IDC TIME LIFE lNON-DEPREC.PART) DOMESTIC FOREIGN % (YEARS) (YEARS) DOMESTIC FOREIGN THERMALPLANT CAPITAL COSTS BCOL 0.0 1412.0 28.30 5.00 25. 0.0 0.0 LIGA 1493.0 0.0 28.30 5.00 25. 0.0 0.0 LIGB 0.0 1705.0 28.30 5.00 25. 0.0 0.0 NU.<1 2266.0 0.0 46.30 9.00 25. 0.0 107.6 NUKZ 0.0 2389.0 46.231 9.00 25. 0.0 107.6 NUK3 0.0 2713.0 46.30 9.00 25. 0.0 107.6 V-GT 0.0 503.0 20.50 3.00 20. 0.0 0.0 CC30 0.0 795.0 24.50 4.00 25. 0.0 0.0

CHPP - HYDRO PROJECT CAPITAL COSTS, PROJECT LIFE: 50.

1 1.0 0.0 0.10 1.00 2 1.0 0.0 0.10 1.00

PAGE17

D Y N P R O ECONOMIC PARAMETERSAND CONSTRAINTS ALL COSTS WILL BE DISCOUNTEDTO YEAR 1984 BASE YEAR FOR ESCALATIONCALCULATION IS 1984 1984 INITIAL VALUES : (XX) = INDEX NU156ER;( 03 = NO INDEX READ

NAME OF ALTERNATIVES BCOL LIGA LIGB NUK1 NUK2 NUK3 V-GT CC30 CHPP DISCOUNT RATE APPLIED TO ALL DOMESTICCAPITAL COSTS - %/YR 12.0 DISCOUNTRATE APPLIED TO ALL FOREIGN CAPITAL COSTS - %/YR 12.0

ESCALATIONRATIOS FOR CAPITAL COSTS ( 01 DOMESTIC 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 FOREIGN 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00

MAXIMlJMNUMBER OF UNITS WHICH CAN BE ADCED ( 0)

50 50 50 50 50 50 50 50 50 MINIMUM NUMBER OF UNITS IIHICHMUST BE ADDED ( 0)

0 0 0 0 0 0 0 0 0

PAGE 18 - 228 - ANNEX 5.3 Attachment 1 Page 14 of 29

0 Y N P R 0 (CONTO.) ECONOMICPARAMETERS AND CONSTRAINTS

1984 INITIAL VALUES : (XX) = INDEX NUMBER; ( 0) NO INDEX READ

FUEL TYPE: T H E R M A L HYDROELECTRIC ENERGY NUCL GASO LIGN BCOL GTGO HYIM CHPP NOT SERVED DISCOUNTRATE APPLIED TO ALL DOMESTICOPERATION COSTS - X/YR (14) 12.0 DISCOUNTRATE APPLIED TO ALL FOREIGN OPERATIONCOSTS - X/YR (15) 12.0 ESCALATIONRATIOS FOR OPERATINGCOSTS ( 0)

DOMESTIC 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 FOREIGN 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 MULTIPLYINGFACTOR FOR FUEL COSTS (17)

DOMESTIC 1.00 0.95 1.00 1.00 0.95 1.00 1.00 1.00 FOREIGN 1.00 0.95 1.00 1.00 0.95 1.00 1.00 1.00

COEFFICIENTSOF ENERGY NOT SERVED COST FUNCTION (11) CF1 CF2 CF3

($/KWH) 1.5000 0.0 0.0 PENALTY FACTOR ON FOREIGN EXPENDITURE ( 0) 1.0000

CRITICAL LOSS OF LOAD PROBABILITYIN Z ( 0) 100.0000 DEPRECIATIONOPTION (16) : 1 = SINKING FUND

PAGE 19 - 229 - ANNEX 5.3 Attachment 1 Page 15 of 29

D Y N P R O LISTING OF MODIFIED CONSTRAINTSDURING STUDY PERIOD 1985 YEAR WHEN NEW VALUES ARE IN FORCE : (XX) = INDEX NUMBER; ( 0) = NO INDEX READ

MULTIPLYINGFACTOR FOR FUEL COSTS (17)

DOMESTIC 1.00 0.93 1.00 1.00 0.93 1.00 1.00 1.00 FOREIGN 1.00 0.93 1.00 1.00 0.93 1.00 1.00 1.00

1986 YEAR WHEN NEW VALUES ARE IN FORCE : (XX) = INDEX NUMBER; ( 0) = NO INDEX READ

MULTIPLYINGFACTOR FOR FUEL COSTS (17)

DOMESTIC 1.00 0.95 1.00 1.00 0.95 1.00 1.00 1.00 FOREIGN 1.00 0.95 1.00 1.00 0.95 1.00 1.00 1.00

1987 YEAR WHEN NEW VALUES ARE IN FORCE : (XX) = INDEX NUMBER; ( 0) = NO INDEX READ * ******* ****3 **** *** *** **** *** ** *

MULTIPLYINGFACTOR FOR FUEL COSTS (17)

DOMESTIC 1.00 0.98 1.00 1.00 0.98 1.00 1.00 1.00 FOREIGN 1.00 0.98 1.00 1.00 0.98 1.00 1.00 1.00

1988 YEAR WHEN NEW VALUESARE IN FORCE : (XX) = INDEX NUMBER; l 0) - NO INDEX READ * *** ******* ** *** *** *** *** **** ***

MULTIPLYINGFACTOR FOR FUEL COSTS (17)

DOMESTIC 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 FOREIGN 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00

PAGE 20 - 230 - ANNEX 5.3 Attachment 1 Page 16 of 29

D Y N P R O (CONTD.)

LISTING OF MODIFIEDCCNSTRAINTS DURING STUDY PERIOD 1989 YEAR WHEN NEW VALUES ARE IN FORCE (XX) INDEX NUMBER; ( 0) NO INDEX READ

MULTIPLYINGFACTOR FOR FUEL COSTS (17)

DOIMESTIC 1.00 1.03 1.00 1.00 1.03 1.00 1.00 1.00 FOREIGN 1.00 1.03 1.00 1.00 1.03 1.00 1.00 1.00 1990 YEAR WHEN NEW VALUES ARE IN FORCE (XX) INDEX NUMBER; ( 0) NO INDEX READ

MULTIPLYINGFACTOR FOR FUEL COSTS (17)

DOMESTIC 1.00 1.06 1.00 1.00 1.06 1.00 1.00 1.00 FCREIGN 1.00 1.06 1.00 1.00 1.06 1.00 1.00 1.00

1991 YEAR WHEN NEW VALUES ARE IN FORCE (XX) INDEX NUMBER; ( 0) = NO INDEX READ

MULTIPLYINGFACTOR FOR FUEL COSTS (17)

DOMESTIC 1.00 1.10 1.00 1.00 1.10 1.00 1.00 1.00 FOREIGN 1.00 1.10 1.00 1.00 1.10 1.00 1.00 1.00 1992 YEAR WHEN NEW VALUES ARE IN FORCE (XX) INDEX NUMBER; ( 0) NO INDEX READ ******** *** * ** *** **** ** **

MULTIPLYINSFACTOR FOR FUEL COSTS (17)

DOMESTIC 1.00 1.14 1.00 1.00 1.14 1.00 1.00 1.00 FOREIGN 1.00 1.14 1.00 1.00 1.14 1.00 1.00 1.00

PAGE 21 - 231 - ANNEX 5.3 Attachment 1 Page 17 of 29

D Y N P R O (CONTD.)

LISTING OF MODIFIED CONSTRAINTSDURING STUDY PERIOD

1993 YEAR WHEN NEW VALUES ARE IN FORCE (XX) = INDEX NUMBER; ( 0) NO INDEX READ

MULTIPLYINGFACTOR FOR FUEL COSTS (17)

DOMESTIC 1.00 1.19 1.00 1.00 1.19 1.00 1.00 1.00 FOREIGN 1.00 1.19 1.00 1.00 1.19 1.00 1.00 1.00

1994 YEAR WHEN NEW VALUES ARE IN FORCE (XX) INDEX NUMBER; ( 0) NO INDEX READ * ** ** **** *** *p*** ******** **y**** *

MULTIPLYINGFACTOR FOR FUEL COSTS (17)

DOMESTIC 1.00 1.24 1.00 1.00 1.24 1.00 1.00 1.00 FOREIGN 1.00 1.24 1.00 1.00 1.24 1.00 1.00 1.00 1995 YEAR WHEN NEW VALUES ARE IN FORCE (XX) = INDEX NUMBER; ( 0) = NO INDEX READ ** ** *** **** ***** ***** ** ****** ****

MULTIPLYINGFACTOR FOR FUEL COSTS (17)

DOMESTIC 1.00 1.26 1.00 1.00 1.26 1.00 1.00 1.00 FOREIGN 1.00 1.26 1.00 1.00 1.26 1.00 1.00 1.00

1996 YEAR WHIENNEW VALUES ARE IN FORCE (XX) INDEX NUMBER; ( 0) NO INDEX READ ********* ** **** ***** ****** ** **

MULTIPLYINGFACTOR FOR FUEL COSTS (17)

DOMESTIC 1.00 1.29 1.00 1.00 1.29 1.00 1.00 1.00 FOREIGN 1.00 1.29 1.00 1.00 1.29 1.00 1.00 1.00

PAGE 22 - 232 - ANNEX 5.3 Attachment 1 Page 18 of 29

D Y N P R O (CONTD.) LISTING OF MODIFIEDCONSTRAINTS DURING STUDY PERIOD

1997 YEAR WHEN NEW VALUES ARE IN FORCE : (XX) = INDEX NUMBER; ( 0) = NO INDEX READ **************** i* * **** * * *****

MULTIPLYINGFACTOR FOR FUEL COSTS (17)

DOMESTIC 1.00 1.31 1.00 1.00 1.31 1.00 1.00 1.00 FOREIGN 1.00 1.31 1.00 1.00 1.31 1.00 1.00 1.00 1998 YEAR WHEN NEW VALUES ARE IN FORCE (XX) INDEX NUMBER; ( 0) = NO INDEX READ

MULTIPLYINGFACTOR FOR FUEL COSTS (17)

DOMESTIC 1.00 1.34 1.00 1.00 1.34 1.00 1.00 1.00 FOREIGN 1.00 1.34 1.00 1.00 1.34 1.00 1.00 1.00

1999 YEAR W4HENNEW VALUES ARE IN FORCE (XX) INDEX NUMBER; ( 0) = NO INDEX READ

MULTIPLYINGFACTOR FOR FUEL COSTS (17)

DOMESTIC 1.00 1.37 1.00 1.00 1.37 1.00 1.00 1.00 FOREIGN 1.00 1.37 1.00 1.00 1.37 1.00 1.00 1.00 2000 YEAR WHEN NEW VALUES ARE IN FORCE (XX) INDEX NUMBER; ( 0) NO INDEX READ

MULTIPLYINGFACTOR FOR FUEL COSTS (17)

DOMESTIC 1.00 1.40 1.00 1.00 1.40 1.00 1.00 1.00 FOREIGN 1.00 1.40 1.00 1.00 1.40 1.00 1.00 1.00

PAGE 23 - 233 - ANNEX 5.3 Attachment 1 Page 19 of 29

D Y N P R O (CONTO.) LISTING OF MODIFIEDCONSTRAINTS DURING STUDY PERIOD

2001 YEAR WHEN NEW VALUES ARE IN FORCE : (XX) = INDEX NUMBER; ( 0) = NO INDEX READ

MULTIPLYINGFACTOR FOR FUEL COSTS (17)

DOMESTIC 1.00 1.42 1.00 1.00 1.42 1.00 1.00 1.00 FOREIGN 1.00 1.42 1.00 1.00 1.42 1.00 1.00 1.00

2002 YEAR WHEN NEW VALUES ARE IN FORCE (XX) INDEX NUMBER; ( 0) NO INDEX READ

MULTIPLYINGFACTOR FOR FUEL COSTS (17)

DOMESTIC 1.00 1.45 1.00 1.00 1.45 1.00 1.00 1.00 FOREIGN 1.00 1.45 1.00 1.00 1.45 1.00 1.00 1.00

2003 YEAR W3EN NEW VALUES ARE IN FORCE (XX) INDEX NUMBER; ( 0) NO INDEX READ

MULTIPLYINGFACTOR FOR FUEL COSTS (17)

DOMESTIC 1.00 1.48 1.00 1.00 1.48 1.00 1.00 1.00 FOREIGN 1.00 1.43 1.00 1.00 1.48 1.00 1.00 1.00

2004 YEAR WHEN NEW VALLJESARE IN FORCE (XX) INDEX NUMBER; ( 0) NO INDEX READ ** * ** **** *** ******* ** * *** * *

MULTIPLYINGFACTOR FOR FUEL COSTS (17)

DOMESTIC 1.00 1.51 1.00 1.00 1.51 1.00 1.00 1.00 FOREIGN 1.00 1.51 1.00 1.00 1.51 1.00 1.00 1.00

PAGE 24 - 234 - ANNIEX5.3 At tachment 1 Page 20 of 29

D Y N P R O (CONTO.)

LISTING OF MODIFIED CONSTRAINTSDURING STUDY PERIOD

2005 YEAR WHENNEW VALUES ARE IN FORCE: (XX) = INDEX NUMBER; ( 0) = NO INDEX READ

MULTIPLYING FACTORFOR FUEL COSTS (17)

DOMESTIC 1.00 1.54 1.00 1.00 1.54 1.00 1.00 1.00 FOREIGN 1.00 1.54 1.00 1.00 1.54 1.00 1.00 1.00

2006 YEAR WHENNEW VALUES ARE IN FORCE (XX) INDEX NUMBER; ( 0) NO INDEX READ

MULTIPLYING FACTORFOR FUEL COSTS (17)

DOMESTIC 1.00 1.57 1.00 1.00 1.57 1.00 1.00 1.00 FOREIGN 1.00 1.57 1.00 1.00 1.57 1.00 1.00 1.00

2007 YEAR WHENNEW VALUES ARE IN FORCE (XX) INDEX NUMBER; ( 0) NO INDEX READ * *** *** ***** *** ** ** ***** ** *** *** *

MULTIPLYING FACTORFOR FUEL COSTS (17)

DOMESTIC 1.00 1.60 1.00 1.00 1.60 1.00 1.00 1.00 FOREIGN 1.00 1.60 1.00 1.00 1.60 1.00 1.00 1.00

2008 YEAR WHENNEW VALUES ARE IN FORCE (XX) = INDEX NUMBER; ( 0) NO INDEX READ **** * **** ** *** ** ******** *** *** ** *

MULTIPLYING FACTORFOR FUEL COSTS (17)

DOMESTIC 1.00 1.64 1.00 1.00 1.64 1.00 1.00 1.00 FGREIGN 1.00 1.64 1.00 1.00 1.64 1.00 1.00 1.00

PAGE25

D Y N P R O (CONTO.)

LISTING OF MODIFIED CCIISTRAINTSDURING STUDYPERIOD

2009 YEAR WHENNEW VALUES ARE IN FORCE: (XX) = INDEX NUMBER; ( 0) = NO INDEX READ ************X********** >*** ** *

MULTIPLYING FACTORFOR FUEL COSTS (17)

DOMESTIC 1.00 1.67 1.00 1.00 1.67 1.00 1.00 1.00 FOREIGN 1.00 1.67 1.00 1.00 1.67 1.00 1.00 1.00

2010 YEAR WHENNEW VALUES ARE IN FORCE: (XX) = INDEX NUMBER; ( 0) = NO INDEX READ ** ******* ** ** *** *** **** ****** ***

MULTIPLYING FACTORFOR FUEL COSTS (17)

DOMESTIC 1.00 1.70 1.00 1.00 1.70 1.00 1.00 1.00 FOREIGN 1.00 1.70 1.00 1.00 1.70 1.00 1.00 1.00

PAGE26 - 235 - ANNEX 5.3 Attachment 1 Page 21 of 29

EXPECTEDCOST OF OPERATION FUEL COST DOMESTIC

TYPE OF PLANT NUCL GASO LIGN BCOL GTGO HYIM CHPP YEAR TOTAL COSTBY PLANTTYPE (1000$)

19S4 136778 0 0 84607 52171 0 0 0 1985 1358M 0 0 84480 51408 0 0 0 1986 134335 0 a 84022 50313 0 0 0 1987 131747 0 0 830C6 48741 0 0 0 1988 133365 0 0 83581 49784 0 0 0 1989 134789 0 0 83989 50800 0 0 0 1990 136334 0 0 84261 52072 0 0 0 1991 133905 0 0 83740 50165 0 0 0 1992 135232 0 0 84.098 51134 0 0 0 1993 137234 0 0 84335 52899 0 0 0 1994 150473 0 0 84475 65998 0 0 0 1995 175253 0 0 106397 6857 0 0 0 1996 198560 0 0 128296 70263 0 0 0 1997 222176 0 0 150204 71971 0 0 0 1998 257756 0 0 193520 64236 0 0 0 1999 280622 0 0 215396 65226 0 0 0 2000 316499 0 0 258171 58329 0 0 0 2001 326744 0 0 258G93 68051 0 0 0 2002 354112 0 0 258988 95124 0 0 0 2003 382029 0 0 259202 122826 0 0 0 2004 409663 0 0 259331 150337 0 0 0 2005 437511 0 0 259413 178098 0 0 0 2006 459689 0 0 283384 176305 0 0 0 2007 481746 0 0 307305 174440 0 0 0 2008 5C4952 0 0 331173 173778 0 0 0 2009 527007 a 0 355017 171990 0 0 0 2010 537102 0 0 355493 181609 0 0 0

TOTALS 7371495 0 0 4904573 2466922 0 0 0

PAGE27 - 236 - ANNEX 5.3 Attachment 1 Page 22 of 29

EXPECTED COST OF OPERATION FUEL COST FOREIGN

TYPE OF PLANT NUCL GASO LIGN BCOL STGO HYIM CHPP

YEAR TOTAL COST BY PLANT TYPE (1000$)

1984 292464 10531 281789 0 0 144 0 0 1985 238123 21062 217014 0 0 47 0 0 1986 228367 31593 136711 0 0 63 0 0 1987 2209i7 42118 178723 0 0 76 0 0 1988 254763 42123 212444 0 0 196 0 0 1989 292279 42124 249368 0 0 787 0 0 1990 335470 42124 290828 0 0 2519 0 0 1991 302026 42123 259637 0 0 267 0 0 1992 353134 42124 309829 0 0 1182 0 0 1993 407997 42124 362370 0 0 3504 0 0 1994 463364 42124 410623 0 0 10617 0 0 1995 476278 42124 419731 0 0 14423 0 0 1996 490465 42124 426156 0 0 22185 0 0 1997 506136 42124 434348 0 0 29665 0 0 1998 469828 42124 410852 0 0 16852 0 0 1999 488347 42124 423553 0 0 22671 0 0 2000 461156 42124 401191 0 0 17841 0 0 2001 504221 42124 433041 0 0 29057 0 0 2002 498300 42124 429088 0 0 27088 0 0 2003 495070 42124 426127 0 0 26819 0 0 2004 492670 42124 423478 0 0 27069 0 0 2005 490447 42124 420878 0 0 27446 0 0 2006 491508 42124 421889 0 0 27495 0 0 2007 497084 42124 425137 0 0 29823 0 0 2008 501005 42124 426517 0 0 32364 0 0 2009 507892 42124 430563 0 0 35206 0 0 2010 578080 42124 470120 0 0 65836 0 0

TOTALS 11337378 1074142 9791994 0 0 471242 0 0

PAGE 28 - 237 - ANNEX 5.3 Attachment 1 Page 23 of 29

EXPECTEDCOST OF OPERATION OPERATION& MAINTENANCEAND ENERGYNOT SERVED(ENS) DOtIESTIC TYPEOF PLANT : NUCL GASO LIGN BCOL GTGO HYIM CHPP ENS YEAR TOTAL COST BY PLANTTYPE (1000$) 1984 213070 14580 81039 24444 38275 729 0 53849 153 1985 226509 29160 80046 24444 38275 729 0 53849 5 1986 241094 43740 80046 24444 38275 729 0 53849 10 1987 255783 58320 80046 24444 38275 729 0 53849 119 1988 256083 58320 80046 24444 38275 729 0 53849 419 1989 255784 58320 80046 24444 38195 729 0 53849 200 1990 256992 58320 80046 24444 38195 729 0 53849 1407 1991 329630 58320 83161 24444 38195 729 0 124534 245 1992 329850 58320 83161 24444 38195 729 0 124534 506 1993 332175 58320 83161 24444 38195 729 0 124534 2791 1994 338492 58320 83161 24444 38195 729 0 124534 9107 1995 346290 58320 83161 31374 38195 1113 0 124534 9592 1996 356935 58320 83161 38304 38195 1113 0 124534 13306 1997 369506 58320 83161 45234 38195 1113 0 124534 18947 1998 376978 58320 83161 59094 38195 1113 0 124534 12560 1999 390184 5S320 83161 66024 38195 1113 0 124534 18836 2000 399313 58320 83161 79884 38195 1113 0 124534 14104 2001 401762 58320 83161 79384 38195 1881 0 124534 15785 2002 407980 53320 83161 79884 45021 1881 0 124534 15178 2003 414924 58320 83161 79884 51847 1881 0 124534 15296 2004 421476 58320 83161 79884 55672 1881 0 124534 15023 2005 429005 58320 83161 79884 65498 1881 0 124534 15726 2006 433791 58320 83161 87646 65498 2265 0 124534 12367 2007 443740 58320 83161 95408 65498 2265 0 124534 14554 2008 452879 58320 83161 103169 65498 2265 0 124534 15931 2009 462997 58320 83161 110931 65498 2265 0 124534 18288 2010 463232 58320 83161 110931 65498 3417 0 124534 17371 TOTALS 9606480 1487160 2224537 1496309 1236438 36585 0 2867626 257825

PAGE 29 - 238 - ANNEX 5. 3 Attachment 1 Page 24 of 29

EXPECTEDCOST OF OPERATION TOTAL COST DOMESTIC AND FOREIGN TYPE OF PLANT NUC! GASO LIGN BCOL GTGO HYIM CHPP ENS

YEAR TOTAL COST BY PLANT TYPE (1000$)

1934 642312 25111 362828 109052 90446 874 0 53849 153 1585 600520 50222 297060 103924 89683 777 0 53849 5 1986 603795 75333 276757 108467 88587 792 0 53849 10 1987 608446 100438 258769 107451 87015 805 0 53849 119 19S8 644210 10C443 292490 108026 88058 925 0 53849 419 1989 682852 100444 329415 108434 £8995 1516 0 53S49 200 1990 728796 1G0444 370874 108706 90268 3248 0 53849 1407 1991 765561 100443 342798 108185 88360 996 0 124534 245 1992 818257 100444 392990 108542 89329 1911 0 124534 506 1993 877407 100444 445531 108780 91094 4233 0 124534 2791 1994 952328 100444 493784 108920 104193 11346 0 124534 9137 1995 997821 100444 502S92 137771 107052 15536 0 124534 9592 1996 1045959 100444 509317 166601 108459 23298 0 124534 13306 1997 1097816 1C0444 517509 195439 110167 30778 0 124534 18947 1998 1104562 100444 494014 252614 102432 17966 0 124534 12560 1999 1159153 100444 506715 281420 103422 23784 0 124534 18836 2000 1176967 1M0444 484352 338055 96524 18954 0 124534 14104 2001 1232726 100444 516202 333578 106247 30938 0 124534 15735 2002 1260390 100444 512250 338872 140145 28969 0 124534 15178 2003 1292021 100444 509288 339087 174673 28700 0 124534 15296 2004 1323813 100444 506639 339216 209009 28950 0 124534 15023 2005 1356963 100444 504039 339297 243596 29327 0 124534 15726 2006 1384986 100444 505051 371030 241803 29761 0 124534 12367 2007 1422567 100444 508298 402713 239938 3208S 0 124534 14554 2008 14583J4 100444 509679 434342 239276 34629 0 124534 15931 2009 1497894 100444 513725 465948 237488 37471 0 124534 18238 2010 1578412 100444 553282 466423 247107 69253 0 124534 17371 TOTALS 28315312 2561295 12016536 6400881 3703359 507827 0 2867626 257825

PAGE 30 - 239 - ANNEX 5.3 Attachment 1 Page 25 of 29

DOMESTIC CONSTRUCTION COSTS

YEAR # PLANT 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 SUM

1991 1 HB-1 0.3 ...... 0.3 1991 1 FIB-2 0.3 ...... 0.3 1995 1 LIGA 9.0 37.5 84.6 87.8 28.4 ...... 247.3 1996 1 LIGA . 9.0 37.5 84.6 87.8 28.4 ...... 247.3 1997 1 LISA . . 9.0 37.5 84.6 87.6 28.4 ...... 247.3 1998 2 LIGA . . . 18.1 75.0169.2175.6 56.7 ...... 494.6 1999 1 LIGA . . . . 9.0 37.5 84.6 87.8 28.4 ...... 247.3 20C0 2 LIGA . . . . . 18.1 75.0169.2175.6 56.7 . . . . . 494.6

END TOTAL 9.7 131.1 284.8 363.6 203.9 0.0 0.0 0.0 46.5 227.9 340.9 313.7 56.7 0.0 0.0 1978.9

PAGE 31

FOREIGN CONSTRUCTION COSTS

YEAR # PLANT 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 SUM

1995 1 V-GT . 3.9 23.4 12.6 ...... 40.0 2001 2 V-GT ...... 7.8 46.9 25.3 . . . . . 80.0 2002 1 BCOL . . . . . 8.8 36.4 82.1 85.2 27.5 . . . . 239.9 2003 1 BCOL ...... 8.8 36.4 82.1 85.2 27.5 . . . 239.9 2004 1 BCOL ...... 8.8 36.4 82.1 85.2 27.5 . . 239.9 2005 1 BCOL ...... 8.8 36.4 82.1 85.2 27.5 . 239.9 2006 1 LIC-S ...... 10.3 42.8 96.6100.2 32.4 282.4 2006 1 V-GT ...... 3.9 23.4 12.6 40.0

END TOTAL 0.0 23.4 0.0 8.8 174.1 241.5 266.4 284.7 3.9 12.6 0.0 53.0 237.7 247.9 301.0

PAGE32 - 240 - ANNEX 5.3 Attachment 1 Page 26 of 29

FOREIGN CONSTRUCTIONCOSTS (CONTD.) YEAR # PLANT 2002 2C03 2004 2005 2006 2007 2008 2009 SUM

2007 1 LIGB 10.3 42.8 96.6100.2 32.4 . . . 282.4 2008 1 LIGSB . 10.3 42.8 96.6100.2 32.4 . . 282.4 2009 1 LIGB . . 10.3 42.8 96.6100.2 32.4 . 282.4 2010 3 V-GT . . . . . 11.8 70.3 37.9 120.0

END TOTAL 247.9 301.0 229.2 102.7 266.4 284.7 144.4 37.9 2369.3

PAGE 33

DOMESTIC INT. DURING CONSTR. YEAR 4 PLANT 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 SUM

1991 1 HB-1 0.0 ...... 0.0 1991 1 HB-2 0.0 ...... 0.0 1995 1 LIGA 6.7 17.8 27.6 17.9 2.3 ...... 72.3 1996 1 LIGA . 6.7 17.8 27.6 17.9 2.3 ...... 72.3 1997 1 LIGA . . 6.7 17.8 27.6 17.9 2.3 ...... 72.3 1998 2 LISA . . . 13.5 35.6 55.2 35.8 4.5 ...... 144.6 1999 1 LIGA . . . . 6.7 17.8 27.6 17.9 2.3 ...... 72.3 2000 2 LIGA . . . . . 13.5 35.6 55.2 35.8 4.5 . . . . . 144.6 END TOTAL 6.8 52.1 90.1 101.3 38.0 0.0 0.0 0.0 24.6 76.8 106.6 77.6 4.5 0.0 0.0 578.3

PAGE34 - 241 - ANNEX 5.3 Attachment 1 Page 27 of 29

FOREIGN INT. DURING CONSTR.

YEAR # PLANT 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 SUM

1995 1 V-GT . 1.3 4.3 1.0 ...... 6.6 2001 2 V-GT ...... 2.6 8.5 2.1 . . . . . 13.2 2002 1 PCOL ...... 6.5 17.3 26.8 17.4 2.2 . . . . 70.1 2003 1BCOL ...... 6.5 17.3 26.8 17.4 2.2 . . . 70.1 2004 1 BCOL ...... 6.5 17.3 26.8 17.4 2.2 . . 70.1 2005 1 BCOL ...... 6.5 17.3 26.8 17.4 2.2 . 70.1 2006 1 LIGB ...... 7.7 20.4 31.5 20.4 2.6 82.5 2006 1 V-ST ...... 1.3 4.3 1.0 6.6

END TOTAL 0.0 4.3 0.0 6.5 59.1 71.3 80.4 75.9 1.3 1.0 0.0 26.4 70.0 74.4 86.4

PAGE 35

FOREIGN INT. DURING CONSTR. (CONTO.)

YEAR # PLANT 2002 2003 2004 2005 2006 2007 2008 2009 SUM

2007 1 LIGB 7.7 20.4 31.5 20.4 2.6 . . . 82.5 2008 1 LIGB 7.7 20.4 31.5 20.4 2.6 . 82.5 2009 1 LIGB . . 7.7 20.4 31.5 20.4 2.6 82.5 2010 3 V-ST . . . . . 3.8 12.8 3.1 19.7

END TOTAL 74.4 86.4 54.5 15.4 80.4 75.9 26.8 3.1 656.8

PAsE 36 - 242 - ANNEX 5.3 Attachment 1 Page 28 of 29

DOMESTICCONSTRUCTION & IDC YEAR e PLANT 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 SUM

1991 1 HB-1 0.4 ...... 0.4 1991 1 HB-2 0.3 ...... 0.3 1995 1 LIGA 15.8 55.3112.2105.7 30.6 ...... 319.6 1996 1 LIGA . 15.8 55.3112.2105.7 30.6 ...... 319.6 1997 1 LIGA . . 15.8 55.3112.2105.7 30.6 ...... 319.6 1998 2 LIGA . . . 31.5110.7224.3211.361.3 ...... 639.1 1999 1 LIGA . . . . 15.8 55.3112.2105.7 30.6 ...... 319.6 2000 2 LIGA . . . . . 31.5110.7224.3211.3 61.3 . . . . . 639.1 END TOTAL 16.4 183.3 374.9 464.8 241.9 0.0 0.0 0.0 71.1 304.7 447.5 391.3 61.3 0.0 0.0 2557.2

PAGE 37

FOREIGN CONSTRUCTION& IDC YEAR # PLANT 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 SUM

1995 1 V-GT . 5.2 27.7 13.7 ...... 46.6 2001 2 V-GT ...... 10.4 55.4 27.3 . . . . . 93.1 2002 1 BCOL ...... 15.3 53.7108.8102.5 29.7 . . . . 310.1 2003 1 BCOL ...... 15.3 53.7108.8102.5 29.7 . . . 310.1 2004 1 BCOL ...... 15.3 53.7108.8102.5 29.7 . . 310.1 2005 1 ECOL ...... 15.3 53.7108.8102.5 29.7 . 310.1 2006 1 LIGB ...... 18.0 63.2128.1120.7 35.0 364.9 2006 1 V-GT ...... 5.2 27.7 13.7 46.6 END TOTAL 0.0 27.7 0.0 15.3 233.2 312.8 346.7 360.6 5.2 13.7 0.0 79.4 307.7 322.3 387.4

PAGE38 - 243 - ANNEX 5.3 Attachment 1 Page 29 of 29

FOREIGN CONSTRUCTION& IOC (CONTD.)

YEAR # PLANT2002 2003 2004 2005 2006 2007 2008 2009 SUM

2007 1 LIGB 18.0 63.2128.1120.7 35.0 . . . 364.9 2008 1 LIGB . 18.0 63-2128.1120.7 35.0 . . 364.9 2009 1 LIGB . . 18.0 63.2128.1120.7 35.0 . 364.9 2010 3 V-GT . . . . . 15.6 83.1 41.0 139.7

END TOTAL 322.3 387.4 283.7 118.1 366.7 360.6 171.2 41.0 3026.0

PAGE39

CAPITAL CASH FLOWSUMMARY FUEL CONSTRUCTION IDC YEAR DOrf. FOR. TOTAL DOM. FOR. TOTAL DOM. FOR. TOTAL SR. TOT. 1984 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1985 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1986 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1987 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1988 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1989 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1990 0.0 0.0 0.0 9.7 0.0 9.7 6.8 0.0 6.8 16.4 1991 0.0 0.0 0.0 46.5 0.0 46.5 24.6 0.0 24.6 7-1.1 1992 0.0 0.0 0.0 131.1 3.9 135.1 52.1 1.3 53.4 188.5 1993 0.0 0.0 0.0 227.9 23.4 251.4 76.8 4.3 81.0 332.4 1994 0.0 0.0 0.0 284.8 12.6 297.4 90.1 1.0 91.1 388.6 1995 0.0 0.0 0.0 340.9 0.0 340.9 106.6 0.0 106.6 447.5 1996 0.0 0.0 0.0 363.6 0.0 363.6 101.3 0.0 101.3 464.8 1997 0.0 0.0 0.0 313.7 8.8 322.4 77.6 6.5 84.1 406.5 1998 0.0 0.0 0.0 203.9 53.0 256.9 38.0 26.4 64.4 321.3 1999 0.0 0.0 0.0 56.7 174.1 230.8 4.5 59.1 63.6 294.5 2000 0.0 0.0 0.0 0.0 237.7 237.7 0.0 70.0 70.0 307.7 2001 0.0 0.0 0.0 0.0 241.5 241.5 0.0 71.3 71.3 312.8 2002 0.0 0.0 0.0 0.0 247.9 247.9 0.0 74.4 74.4 322.3 2003 0.0 0.0 0.0 0.0 266.4 266.4 0.0 80.4 80.4 346.7 2004 0.0 0.0 0.0 0.0 301.0 301.0 0.0 86.4 86.4 387.4 2005 0.0 0.0 0.0 0.0 284.7 284.7 0.0 75.9 75.9 360.6 2006 0.0 0.0 0.0 0.0 229.2 229.2 0.0 54.5 54.5 283.7 2007 0.0 0.0 0.0 0.0 144.4 144.4 0.0 26.8 26.8 171.2 2008 0.0 0.0 0.0 0.0 102.7 102.7 0.0 15.4 15.4 118.1 2009 0.0 0.0 0.0 0.0 37.9 37.9 0.0 3.1 3.1 41.0 0.0 0.0 0.0 1978.9 2369.3 4348.1 578.3 656.8 1235.1 5583.2

Page 40 - 244 - ANNEK5.4

POER ANDCOAL SUBSE=C REVIEW

Technical and Cost Data on Potential Heat Production Projects

Power Station Power Dunamenti Station CHP Power (South- Dunamenti CHP Station Station CHP CUP Budapest (Budapest Station North- Borsod Station Station +DVK/3 +DKV/3 Gybr Pest /Miskolc Szolndk Almbsfuzito

Boilers

Number 2 2 2 8 - 3 1 Steam Production (t/h) 800 800 220 200 - 50 100 Steam Pressure (bar) 165 165 101 100 - 31 71 Steam Temp. (OC) 540/540 540/540 540 500 - 400 500 Fuel Coal Coal Coal Coal Coal Coal

Turbines

Number 2 2 2 4 1 1 1 Turbine Type Pass- Pass- Pass- Back Conder- Pass- Pass- out out out Pressure sing out & out & & Heat- Heat- Back Back ing /2 ing Pressure Pressure Capacity (14We) 2xL80 2x180 2x48 2x23+ 60 14 14 2x46 Peak Heat (NWth) 1667 3117 718 1373 383 194 98 Demarnd Fuel Consump- (PJ/a) 34.(Yi 7.6 13.85 2.65 /1 2.52 2.47 /2 tion Hydrocarbon (PJ/a) 20.44 5.2 6.54 3.58 2.37 1.90 Fuel Saved CHP electricity (Gih/a) 2188 373 578 223 79 103 Production Heat Supplied (Pi/a) 16.56 4.4 8.18 2.97 /1 1.67 2.25 irvestment (Ft.million)15,941 19,115 6,100 7,820 2,450 IL,700 720 Cost

/1 Increaseto supply districtheat to Miskolc. /2 Increasefrm new boilers. 7 DKV = Duna oil refinerynew to the DunamentiPowr Station.

March 1984 (1829P) - 245 - ANN1E5.5

POIR ANDC(AL SUBSEC1RREVIE

Technical and Cost Data on Potential Heat Production Projects

Power Station Power Power Power Powr Old Station Station Station Station Obuda Sopron Debrecen Nyiregh3z Kecskewet

Boilers

Number 1 1 - - 2 Steam Production (t/h) 200 50 - - 50 Steam Pressure (bar) 10 31 - - 35 Steam Temp. (°C) 500 400 - - 440 Fuel Oil & Gas Coal - - Coal

Turbines

Number 1 - 1 1 1 Turbine Type Heating - Back Heating Heating Pressure Capacity (NW) 46 - 8.6 9.6 7.0 Peak Heat (NW) 363 134 397 /2 271 /2 150 Demand Fuel Consump- (PJ/a) 3.22 /3 0.84 /1 - - 1.65 tion Hydrocarbon (PJ/a) 2.19 0.93 -0.32 -0.21 1.39 Fuel Saved CHP electricity (GWh/a) 263 3.8 64.2 46.4 43.9 Production Heat Supplied (PJ/a) 1.85 0.69 - - 1.65 Investmnnt (Ft.million) 1210 445 134 97 845 Cost

Source: EGI.

/1 Increase fromexpanding district heating using coal as a fuel. /2 Demad in 1990. /3 Consumption of oil & gas.

March 1984 (1829P) - 246 -- 246 - ~~~ANNEXPagel1of6.1 7

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

Demand Management

Energy Management Program

1. In 1978 it became obvious to the Government that the oil price increase of 1973, the impact of which in Hungary was delayed by the 5-year averaging of the Bucharest Principle, would have serious consequences for the balance of payments. The delayed effect of increased oil prices would be made worse by the high energy intensity of industry in Hungary and because oil accounted for about 37% of primary energy supply in 1978. With a potential energy crisis looming, the Politburo passed a resolution in 1978 for developing and energy policy. At the same time measures were taken to get enterprises in industry and agriculture to develop material and energy management plans as part of their annual enterprise plans. In December 1980, the Council of Ministries approved the energy management program for the Sixth 5-Year Plan (1981-85) and the action program for implementing it.

2. The objectives of the Energy Management Program are:

(a) to reduce the growth rate of fuel consumption during 1981-85 to a maximum of 2% and a maximum of 3.5% for electric power;

(b) in the longer term, increase the utilization of domestic energy sources particularly coal and nuclear energy;

(c) reduce the consumption of oil and gas in power generation from 64% in 1980 to 59% by 1985 of which the share of oil is to be reduced by 4%. The growth in power demand is to be met prodiminately by nuclear power and additional imports of electricity. The consumption of hydrocarbons in power generation in 1985 is not to exceed its 1980 level; and

(d) petroleum demands which continue to grow during 1981-85 e.g. gasoline for automobiles, are to be met from savings in other sectors, fuel substitution and increased efficiency in end use.

3. The principal means of executing this policy are:

(a) pricing fuels to producers according to international prices;

(b) regulation of energy consumption at the enterprise level by Government agencies;

(c) a system of credits, grants and subsidies to encourage energy conservation and inter-fuel substitution; - 247 - ~~~~~ANNEX6.1 - 247 Page 2 of 7

(d) tightening technical standards for the performance of energy using equipment and the thermal insulation of buildings;

(e) a program of major investments in energy conservation, particularly in heavy industry and metallurgy;

(f) research and development in energy utilization and conservation; and

(g) a publicity campaign in the mass media and schools.

Regulation of Energy Consumption

4. Permits are required from AEEF for the consumption of energy by enterprises, i.e., excluding households. Levels of consumption for which permits are required are:

Coal 800 TJ/a Coke 100 t/a Heavy fuel oil 500 t/a Light fuel oil (space & water heating 1 t/a Light fuel oil (process use) 50 t/a Gas (natural and manufactured) 200 m3 /h (winter) LPG 1 t/a Electricity 1 MW (installed capacity)

The permits specify the quantity of each fuel that the enterprise is permitted to use. In issuing the permits, AEEF takes into consideration whether lower grade fuels could be used, the proportion of energy required as steam and hot water and carries out a local investigation as to whether district heating or supply from boilers at other enterprises is feasible, especially if they use coal. Each enterprise has to designate a person responsible for energy management. Success in energy management is supposed to be taken into account when evaluating the performance of managers and setting their bonuses. The permit system is monitored by boiler inspectors from AEEF who have to carry out a statutory boiler safety inspection each year. The inspectors check whether the enterprises has a permit and whether the maximum permitted quantities of fuel have been exceeded. Consumption in excess of the permitted level is allowed for legitimate reasons, e.g., if production has increased. In addition, the inspector carries out a boiler efficiency test to check whether the boiler is operating at its specified efficiency. AEEF may levy a penalty if the boiler efficiency is too low and in such cases, a report is sent to the operator's manager and ministry and the manager may have his bonus reduced.

Impact of Energy Management Program

5. As Table 1 shows, the energy intensity of all sectors except services fell by 12%-14% during the period 1981-1982. The fall in intensity was - 248 - ANNEX 6.1 Page 3 of 7 especially pronounced in the energy intensive industrial and transport sectors, where the trend for intensity to decline in the early 1970's had begun to designate. This sharp fall is in part due to the success of the

Table 1

Energy Intensity by Sector (kJ per Forint of Industrial GDP, 1981 prices)

Year Industry Agriculture Construction Transport Services

1970 2,389 381 376 1,767 71 1975 1,988 534 340 1,264 51 1976 2,021 567 331 1,217 48 1977 1,959 525 407 1,197 47 1978 1,933 582 344 1,185 46 1979 1,850 570 322 1,106 43 1980 1,859 544 330 1,077 43 1981 1,711 528 298 995 52 1982 1,602 467 289 941 55

Source: Mission estimates. energy management program, assisted by mild winters. It is arguable how much of the decrease was due to the response to prices and how much due to the licensing scheme, since the system for regulating energy consumption by producers mutually reinforced the signals given by increases in energy prices. Using boiler inspectors to reduce the costs of administering the system was innovative. Determining the quantitative effect of the permit system on energy demand is outside the scope of this review, but in view of the costs of administering the permit system (to enterprisess as well as the Government), it would be interesting to evaluate the additional energy savings that occurred above those that would have been achieved through the effect of prices alone. In particular it would appear worth evaluating how binding the permits have been on energy consumption. Even though the permit system may have generated substantial energy savings, this is by no means clear. In view, of the costs of administering this system, the Government should commission a study to review it towards the end of the current 5-Year Plan, when more data on energy consumption are available, before extending the system for another 5 years.

6. Energy conservation and interfuel substitution, beyond savings easily achieved through improved operating practices, involves the substitution of capital for energy. Capital, as well as energy, is a scarce resource, particularly in Hungary. The action program has safeguards against uneconomic - 249 - ANNEX 6.1 Page 4 of 7 investment in energy conservation. Energy conservation or fuel substitution projects presented to OEGH or NBH for grants or credits have to have the "H" factor calculated. This is similar to the benefit/cost ratio, calculated at a 12% real discount rate. The H factors asssist the authorities to establish priorities for financing the projects, but gives less guidance as to whether the overall process or enterprise is economically viable. However, an analysis of the conservation and energy substitution program suggests that the action plan is, on average, well founded (Table 2).

Table 2

Energy Conservation and Rationalization Program

1981-85 1986-90 1991-45 1946-2000

Energy Benefits (PJ/a)

Savings from conservation 32 32 26 16 Energy substituted by lower value fuels 25 35 30 30

Investment Costs (US$ million, 1983 prices)

Conservation 303 319 191 223 Fuel substitution 207 303 255 255

Investment Cost Per Toe saved (US$/toe) /I

Conservation 59 83 75 88 Fuel substitution 52 54 53 53

Source: IpM, "Information on Energy Development Provided for World Bank" mission estimates.

/1 Cost per toe saved assumes the investment has a 15-year life and a discount rate of 12%. One toe is equivalent to 42.7 GJ.

The average investment cost per toe saved is about US$60/toe. This can be compared to the economic cost of fuel oil (exported at the margin) of about US$150/toe (US$140/t), and the delivered cost of brown coal of about US$70-90/toe. Saving oil and natural gas, which has an identical economic cost (Annex 7, para. 15), is clearly justified. Investment to save brown coal would be justified on average, but there may be marginal projects where the - 250 - ANNEX 6.1 Page 5 of 7 investment cost is greater than the present value of coal saved. Substitution of brown coal for fuel oil would lead to savings of between US$60-80/toe, compared to a cost of about US$50 per toe substituted and would be justified on average, although again there may be uneconomic projects at the margin. As natural gas has an economic cost equivalent to heavy fuel oil, the substitution of gas for fuel oil (or for coal) would not clearly be economically justified, although substitution of gas for distillates oil might. These figures indicate the need for the Government to continue to scrutinize energy conservation and substitution projects carefully and the importance of economic pricing of energy to ensure that enterprises initiate viable projects at the margin.

Policies for Coal Utilization

7. The program contains a number of measures for increasing the use of coal. These include:

(a) replacement of 300,000 oil stoves (small boilers) of commercial consumers by coal-fired equipment to substitute 60-100,000 tons of fuel oil and gas oil by 300,000 tons of high quality coal;

(b) converting boilers back to coal which have been converted to other fuels;

(d) studying the establishment of coal based CHP plants in Budapest, Miskolc, Gyor Varpalota, Esztergom/Dorog and Almasfiuzito, (Annex 5, para. 51);

(e) conversion of the Dunamenti Power Station to coal (Annex 5, para. 18);

(f) examination of the feasibility of upgrading coal by producing coke briquettes and powder, and enriching lignite; and

(g) a pilot fluidized bed combustion plant at Gyor.

Electricity Demand Management

8. Electricity demand management in Hungary is achieved two ways: (a) through the system of permits (para. 4); and (b) by remote control of consumer loads. Under the permit system, consumers with an installed capacity greater than 1 MW are required to obtain a permit from AEEF. These permits specify the quantity of electricity e.g. maximum demands, MWh consumption. The permitted maximum demands of the consumer during the day and at the time of system peak form the basis of the contracted maximum demands on which the consumer is billed by MVMT (see Chapter VI). Annual contracted demand is billed each month at 1/12 of the annual charge/kW. Any excess demand - 251 - ANNEX 6.1 Page 6 of 7

during any month is billed at the full annual charge. A consumer exceeding his contracted demand every month by 1 kW would, in theory, pay 12 time the annual charge per kW. The fieldwork by AEEF during the negotiation of permits also enables a priority to be set for load shedding in event of a shortfall of generation.

9. The audio frequency injection system has been commissioned in Gyo5r, whereby a signal is superimposed on the distribution system to activate instruments to disconnect loads such as space and water heaters in households. Because of the thermal storage in such loads, it is possible to transfer,their consumption of electricity from peak to off-peak periods. There is a policy under the Action Program to extend the use of storage space and water heaters by households, by granting credits to households, advertising campaigns and by stimulating the manufacture of electrical heat storage devices. However, the introduction of off-peak heating to households has been retarded by weaknesses in low voltage distribution networks. A potential consumer of off-peak electricity first needs the agreement of the MVMT local office that networks will not be overloaded.

10. Transferring loads off-peak leads to future savings in generation and transmission investment, although local reinforcement of the distribution system may be necessary and in addition, further distribution investment may be required since distribution peaks have shifted to shortly after midnight in some countries where night storage devices are common. A major benefit from night storage devices is achieved in countries where the marginal energy cost is high during the peak, e.g. when gas turbines are used, and low at night, e.g. when there is surplus run of river hydro capacity. In these countries, substantial fuel savings are achieved when loads are shifted off-peak. this is not the case at present in Hungary. Incremental changes to both peak and off-peak load are met by oil and gas fired plant. The marginal fuel cost is essentially the same at all times of the day and year (see Chapter VI). Fuel savings from night storage heating are therefore negligible. Indeed, night storage space heating could actually lead to a greater fuel cost to the economy if oil or gas supplied in the form of electricity at a thermal efficiency of around 34% were being substituted for direct coal heating. Moreover, given the hourly pattern of imports, which follow the daily variation in demand, the scope for generating more electricity at night is limited. If the Hungarian power stations were to operate at constant load all day, the amount of energy that would have to be transferred from the morning and evening peaks to other times would amount to about only 25% of daily consumption. The case for load management in Hungary rests mainoy on capacity savings and we have doubts as to whether these are significant for LV consumers.

11. MVMT does not have contracts for interruptible supply with large industries, although the existing tariff structure provides good incentives for avoiding consumption during peak periods. Experience in other countries has shown that a number of industries can accept shedding some loads for small, infrequent periods when the power system is under stress. This enables the utility to reduce load at the most appropriate times and may have a - 252 - ANNEX 6.1 Page 7 of 7 smaller impact on the production of large industries than the comparatively blunt instrument of time of day or maximum demand tariffs. The cost of arranging such disconnection is essentially the cost of communications links from the utility's control center to the consumer, plus more complicated metering and billing. Furthermore, autoproducers co-operating with MVMT are paid under a simple tariff, i.e.:

Ft/kWh US cents/kWh

Peak 1.75 4.4 Day 1.15 2.9 Night 0.55 1.4

The marginal energy cost of MVMT's own generation is 1.20 Ft/kWh based on oil/gas fired generation and this does not vary significantly by time of day or year (Annex 7, para. 16). The incremental cost of generation from brown coal is about 0.70 Ft/kWh. The cost of autoproduction probably lies within this range, although the cost to autoproducers is complicated by joint heat production. 1/ Therefore, the prices for the peak and night periods probably do not give autoproducers sufficient incentive to control their own consumption and export to MVMT. Moreover, the present tariff for purchases from auto producers does not provide them with an incentive to maximize exports when the system is under stress.

12. It appears that some savings could be made by providing more flexible arrangements for supply to large industries and for purchases from autoproducers. Such savings would require closer communications links to be established between MVMT control centers and the enterprises and would require more expensive metering that recorded consumption at least every half hour. The savings from the better co-ordination of autoproducers output with system requirements may be small, since the operation of industrial CHP plant ca be inflexible. However, experience in industrialized countries has shown large savings from load management of industrial consumers. The economics of audio frequency control of household loads seem uncertainty because of the lack of fuel savings and the additional investment in distribution required. Moreover, other alternatives such as natural gas, district heating, coal or even oil may provide space and water heating at lower economic cost. In view of the potential benefits of industrial load management and the uncertain economics of residential load management, it is recommended that MVMT commission a study that would evaluate the options from a technical and economic viewpoint and recommend a program of action to implement a load management program.

1/ The relevant cost to autoproducers is the incremental fuel cost arising from increasing the power output of a CHP plant with heat output held constant. This cost could be estimated from a model of heat flows in a CHP station.

March 1984 (1829P) - 253 - ANNEX 6.2 Page 1 of 5

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

MVMT Electricity Tariffs for Producers

Demand Charges Energy Charges Basic Peak Peak Day Night ----(Ft/kW/a)---- … (Ft 7k/a)------

Jan. 1, 1973 - Dec. 31, 1975

Power Tariffs Basic network 300.0 660.0 0.30 0.39 0.20 mv 366.0 876.0 0.38 0.38 0.20 LV 450.0 1,170.0 0.44 0.44 0.20 Railways - - 0.45 0.45 0.45 Trams - - 0.55 0.55 0.55 Pricing by Energy Single time period - - 1.50 1.50 1.50 Double time period - - 2.00 0.85 0.85 Triple time period - - 2.00 0.85 0.30 Public lighting Traditional 3,066.0 - 0.30 0.30 0.30 Modern 4,740.0 - 0.30 0.30 0.30

'Jan. 1, 1976 - Dec. 31, 1977

Power Tariffs Basic network 300.0 660.0 0.40 0.40 0.25 MV 420.0 1,020.0 0.47 0.47 0.25 LV 540.0 1,320.0 0.56 0.56 0.25 Railways - - 0.54 0.54 0.54 Trams - - 0.66 0.66 0.66 Pricing by Energy Single time period - - 1.80 1.80 1.80 Double time period - - 2.40 1.00 1.00 Triple time period - - 2.40 1.00 0.30 Public lighting Traditional 4,320.0 - 0.36 0.36 0.36 Modern 5,690.0 - 0.36 0.36 0.36

March 1984 (1829P) - 254 - ANNEX 6.2 Page 2 of 5

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

MVMT Electricity Tariffs for Producers

Demand Charges Energy Charges Basic Peak Peak Day Night ---- (Ft/kW/ a)------(Ft/kW/a)-----

Jan. 1, 1978 - Dec. 31, 1979

Power Tariffs Basic network 300.0 660.0 0.95 0.45 0.25 Main distribution substation 360.0 720.0 1.00 0.50 0.25 MV I 420.0 1,080.0 0.60 0.60 0.30 MV II 210.0 600.0 1.00 1.00 0.30 LV I 540.0 1,500.0 0.70 0.70 0.30 LV II 270.0 720.0 1.20 1.20 0.30 Railway - - 0.65 0.65 0.65 Trams - - 0.80 0.80 0.80 General Tariffs Demands to 2.5 kVA 360.0 - 1.80 1.80 0.60 Demands to 3.5 kVA 600.0 - 1.80 1.80 0.60 Demands to 5.0 kVA 900.0 - 1.80 1.80 0.60 Demands greater than 5.0 kVA - - 1.80 1.80 0.60 Public Lighting Directed lights 4,320.0 - 0.50 0.50 0.50 More intensive lights 5,700.0 - 0.50 0.50 0.50

Jan. 1, 1980 - June 30, 1980

Power Tariffs Basic network 360.0 780.0 1.00 0.56 0.40 Main distribution substation 390.0 840.0 1.00 0.60 0.40 MV I 420.0 1,080.0 0.85 0.85 0.45 MV II 210.0 600.0 1.20 1.20 0.45 LV I 540.0 1,500.0 1.15 1.15 0.45 LV II 270.0 720.0 1.50 1.50 0.45 Railways - - 0.80 0.80 0.80 Trams - - 0.95 0.95 0.95 Pricing by Energy Demands to 2.5 kVA 360.0 - 2.20 2.20 0.60 Demands to 3.5 kVA 600.0 - 2.20 2.20 0.60 Demands to 5.0 kVA 900.0 - 2.20 2.20 0.60 Demands greater than 5.0 kVA 180.0 - 2.20 2.20 0.60 Public Lighting Directed lights 4,320.0 - 0.70 0.70 0.70 More intensive lights 5,700.0 - 0.70 0.70 0.70

March 1984 (1829P) - 255 - ANNEX 6.2 Page 3 of 5

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

MVMT Electricity Tariffs for Producers

Demand Charges Energy Charges Basic Peak Peak Day Night ---- (Ft/kW/a)------(Ft/kW/a)-----

July 1, 1980 - March 15, 1981

Power Tariffs Basic network 360.0 780.0 1.10 0.70 0.50 Main distribution substation 390.0 840.0 1.10 0.75 0.50 MV I 420.0 1,080.0 1.00 1.00 0.60 MV II 210.0 600.0 1.40 1.40 0.60 LV I 540.0 1,500.0 1.30 1.30 0.70 LV II 270.0 720.0 1.70 1.70 1.70 Railway - - 0.90 0.90 0.90 Trams - - 1.10 1.10 1.10 General Tariffs Demands to 2.5 kVA 360.0 - 2.20 2.20 0.80 Demands to 3.5 kVA 600.0 - 2.20 2.20 0.80 Demands to 5.0 kVA 900.0 - 2.20 2.20 0.80 Demands greater than 5.0 kVA 180.0 - 2.20 2.20 0.80 Public Lighting Directed lights 4,320.0 - 0.85 0.85 0.85 More intensive lights 5,700.0 - 0.85 0.85 0.85

March 16, 1981- Oct. 31, 1983

Power Tariffs Basic network 360.0 780.0 1.25 0.80 0.50 Main distribution substation 390.0 840.0 1.30 0.85 0.50 MV I 420.0 1,080.0 1.10 1.10 0.70 MV II 210.0 600.0 1.50 1.50 0.70 LV I 540.0 1,500.0 1.50 1.50 0.80 LV II 270.0 720.0 1.90 1.90 0.80 Railway - - 1.00 1.00 1.00 Trams - - 1.20 1.20 1.20 General Tariffs Demands to 2.5 kVA 360.0 - 2.60 2.60 0.80 Demands to 3.5 kVA 600.0 - 2.60 2.60 0.80 Demands to 5.0 kVA 900.0 - 2.60 2.60 0.80 Demands greater than 5.0 kVA 180.0 0 2.60 2.60 0.80 Public Lighting Directed lights 4,320 - 1.20 1.20 1.20 More intensive lights 5,690.0 - 1.20 1.20 1.20

March 1984 (1829P) - 256 - ANNEX 6.2 Page 4 of 5

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

MVMTElectricity Tariffs for Producers

Demand Charges Energy Charges Basic Peak Peak Lay Night ---- (Ft/kW/a)------(Ft/kW/a)-----

Nov. 1, 1981 - August 1, 1982

Power Tariffs Basic network 360.0 780.0 1.45 1.00 0.50 Main distribution substation 390.0 840.0 1.50 1.05 0.50 MV I 420.0 1,080.0 1.30 1.30 0.70 MV II 210.0 600.0 1.70 1.70 0.70 LV I 540.0 1,500.0 1.70 1.70 0.80 LV II 270.0 720.0 2.10 2.10 0.80 Railway - - 1.10 1.10 1.10 Trams - - 1.35 1.35 1.35 General Tariffs Demands to 2.5 kVA 360.0 - 2.80 2.80 0.80 Demands to 3.5 kVA 600.0 - 2.80 2.80 0.80 Demands to 5.0 kVA 900.0 - 2.80 2.80 0.80 Demands greater than 5.0 kVA 180.0 - 2.80 2.80 0.80 Public Lighting Directed lights 4,320.0 - 1.35 1.35 1.35 More intensive lights 5,690.0 - 1.35 1.35 1.35

August 2, 1982 - Dec. 31, 1982

Power Tariffs Basic network 450.0 960.0 1.55 1.05 0.50 Main distribution substation 480.0 1,080.0 1.55 1.10 0.50 MV I 540.0 1,200.0 1.37 1.37 0.70 MV II 300.0 660.0 1.80 1.80 0.70 LV I 720.0 1,560.0 1.80 1.80 0.80 LV II 360.0 810.0 2.20 2.20 0.80 Railway - - 1.18 1.18 1.18 Trams - - 1.44 1.44 1.44 General Tariffs Demands to 2.5 kVA 360.0 - 3.00 3.00 0.80 Demands to 3.5 kVA 600.0 - 3.00 3.00 0.80 Demands to 5.0 kVA 900.0 - 3.00 3.00 0.80 Demands greater than 5.0 kVA 180.0 - 3.00 3.00 0.80 Public Lighting Directed lights 4,320.0 - 1.55 1.55 1.55 More intensive lights 5,690.0 - 1.55 1.55 1.55

March 1984 (1829P) - 257 - ANNEX 6.2 Page 5 of 5

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

MVMT Electricity Tariffs for Producers

Demand Charges Energy Charges Basic Peak Peak Da Nght -----(Ft/kW/a)----(---F-t w kW/a)…----

Effective Jan. 1, 1983

Power Tariffs Basic network 450.0 960.0 1.70 1.10 0.55 Main distribution substation 480.0 1,080.0 1.75 1.15 0.55 MV I 600.0 1,200.0 1.50 1.50 0.70 MV II 300.0 660.0 2.00 2.00 0.70 LV I 720.0 1,560.0 2.00 2.00 0.85 LV II 360.0 810.0 2.40 2.40 0.85 Railway - - 1.25 1.25 1.25 Trams - - 1.52 1.52 1.52 General Tariffs Demands to 2.5 kVA 360.0 - 3.10 3.10 0.90 Demands to 3.5 kVA 600.0 - 3.10 3.10 0.90 Demands to 5.0 kVA 900.0 - 3.10 3.10 0.90 Demands greater than 5.0 kVA 180.0 - 3.10 3.10 0.90 Public Lighting Directed lights 4,320.0 - 1.70 1.70 1.70 More intensive lights 5690.0 - 1.70 1.70 1.70

Source: IpM

March 1984 (1829P) - 258 - ANNEX 6.3 Page 1 of 4

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

The Long-Run Marginal Cost of Electricity

Principles of Electricity Pricing

1. The level of existing tariffs can be compared to the economic cost of electricity. The economic cost of electricity is the long run marginal cost (LRMC) of supply, with all inputs used in the production and distribution of electricity also being valued at their economic cost. The economics literature shows that a power utility pursuing the sole objective of economic efficiency, i.e. maximizing social welfare, should set the price of electricity equal to its LRMC. However, in practice departures from this rule may be justified, e.g. when other fuels are not priced at their economic cost, to meet financial objectives and on grounds of equity. Nevertheless, LRMC serves as a useful benchmark against which to review existing tariffs.

2. LRMC has two components. The first is the capacity cost which, in principle, is the cost of bringing forward (or delaying) future generation, transmission and distribution investment to meet a sustained increase (decrease) in demand (kW). The second component is the cost of producing an extra kWh at a particular time of the day or year, which is mainly the fuel consumed in generation, adjusted for transmission and distribution losses. The calculation of LRMC is described below.

LRMC of Capacity

3. Marginal Capacity Costs may be divided into three categories: (a) generation; (b) transmission; and (c) distribution. The marginal capacity costs of generation and transmission can in principle be estimated using the computer models used in system planning. The least cost development plan is re-optimized to meet a sustained increase (decrease) in demand. The marginal capacity cost is then calculated as the difference between the present value costs of the original and re-optimized development program, divided by the increment in demand.

4. This was the approach adopted to estimate the LRMC of generating capacity. The WASP computer program was used to re-optimize the base case with demand increased by 200 MW, roughly equivalent to one year's increase in maximum demand. This resulted in the generation program being advanced (Attachment 1). Compared to the base case, the advanced investment program resulted in additional capital, fixed 0 & M and unserved energy costs. These costs were evaluated over a 20-year period typical of the life of electricity consuming plant and appliances in Hungary (Attachment 2). In addition, system average fuel costs increased because high running cost plant would be used - 259 - ANNEX 6.3 Page 2 of 4 more intensively during the period before major investments are advanced, although this is partially offset by the lower level costs of the base load units that were advanced. These negative fuel savings are included in the LRMC. Calculation of the LRMC of generating capacity is described in Attachment 3 and summarized below:

USt/kWSO/a (1983 prices)

Generation capital cost 66.5 Generation fixed 0 & M 2.8 Additional outage costs 3.7 Less, fuel saving - (-1.1)

Total LRMC of generating capacity 74.1

5. The long-run average incremental cost (LRAIC) is often taken as proxy for the LRMC of transmission and distribution. LRAIC is calculated using the planned investment and projected maximum demand for each voltage level, i.e.

LRAIC = PV (Investment Cost + Incremental Operating Costs) PV (Annual increments in maximum demand) where PV denote present value. Highly aggregated transmission investment data were available for three years to enable a rough calculation to be made (Attachment 4). This shows the LRAIC delivered from the transmission system to be US$14.1/kWJa. Information on planned distribution investment and projected demand by voltage level was not available, so that a crude approach had to be adopted. A distribution company is planning to invest Ft 500 m (US$12.5 m) over five years for MV distribution and another Ft 500 m for LV distribution. Maximum demand, measured at 120 kV, is projected to increase by 250 MW over this period. Allowing for 4.7%MV losses at peak and 12.3% LV peak losses, annual operating costs equal to 1% of investment and a 30-year life, estimates of the LRMC's at 12% discount rate are:

LRMCMV = 12,500 x 0.1241 + 125 = 7.0 US$/kW/a 250 (1 - 0.047)

Assuming that 50% of the power is sold at MV, the LV cost is

LRMCLV 12,500 x 0.1241 + 125 = 16.1 US$/kW/a 0.5 x 250 (1 - 0.047)(1 - 0.123)

Table 1 shows the estimated marginal capacity costs at each voltage level, adjusted for peak losses. - 260 - AINEX 6.3 Page 3 of 4

Table 1

Marginal Capacity Costs by Voltage Level (US$/kW/a, 1983 prices)

Item Voltage Peak Distribution Level Losses (%) Generation Transmission V_ TV Total

Net generation - 74.1 - - - 74.1 Transmission 7.3 79.9 14.1 - - 94.0 MV 4.7 83.9 14.8 7.0 - 105.7 LV 12.3 95.6 16.9 8.0 16.1 136.6

Source: Mission estimates.

Marginal Energy Costs

6. Marginal Energy Costs are the additional costs of fuel and other items whose consumption varies with power station use, e.g. lubricants, filters, chemicals, etc., incurred in producing an extra kWh. Such costs vary from hour to hour, depending on system operation. Marginal fuel costs are used to optimize system operation at the National Dispatch centre. The control computer loads plants, either fully, or until their marginal fuel costs are equal, at which point the equal marginal costs of the partly loaded plants are equivalent to the system marginal fuel cost. These marginal system costs are known for the current and previous days at the National Dispatch Centre. They do not necessarily hold for the future, when new tariffs would apply, because of changes in demand, scheduled imports and generating plant available. However, in principle, the computer model used to control systems operations could be adapted to calculate marginal fuel costs in the future for tariff design. Based on the current mode of system operation and taking into account the commissioning of Units 1 & 2 at the Paks nuclear station, it appears that incremental kWh will continue to be supplied from oil and gas-fired power stations during 1983-84. Imports of electricity are effectively fixed by contract, so that an extra kWh at a particular time would normally be generated in Hungary.

7. Marginal energy costs should be calculated using the economic cost of fuel. The economic cost of heavy fuel oil exported at the margin from Hungary would be US$150/t ($3.70/GJ). In the future, this price might rise to the f.o.b. export price of about t160/t if Hungary ceases to be a net exporter of fuel oil after the catalytic cracker is fully operational. The power stations operating at the margin burn both natural gas and fuel oil. Gas supplies to Hungary are fixed in the medium term for contractual and technical reasons. Even if supplies were to increase, power generation would continue to be the marginal consumer, being allocated the difference between total gas supply and the demands of other consumers. It is unlikely that gas supplies would increase to the point where - 261 - ANNEX 6.3 Page 4 of 4

natural gas would displace coal or could not find willing consumers outside of power generation. For the next few years therefore, the opportunity cost of natural gas will be fuel oil consumed in power generation, since a marginal change in gas supply would result in a corresponding change in MVMT fuel oil consumption. The economic cost of natural gas for power generation was therefore taken to be US03.70/GJ ($158/toe).

8. Examination of MVMT daily load curves and system operation indicated that the dual fired Tisza (4 x 215 MW) and Dunamenti (6 x 215 MW) power stations would operate at the margin at all times of the day and year. Steam power stations in Hungary are not shut down during the low load period at night, so that the marginal system cost is the incremental fuel cost of these units, i.e. US$31.2/MWh for Dunamenti and US$32.5/MWh for Tisza. Marginal fuel costs are shown in Table 2 after rounding the incremental costs to $30/MWh and adjusting for losses in transmission and distribution. The marginal cost of supply each tariff category is shown in Annex 6.4.

Table 2

Marginal Fuel Costs (USc/kWh)

Voltage Level Losses (x) Marginal Cost

Transmission 3.5 3.3 Sub-transmission 1.4 3.4 MV 2.9 3.5 LV 6.7 3.7

Source: Mission estimates

March 1984 (1829P) - 262 - ANNEX 6.3 Attachment 1

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

Generation Capacity Additions With and Without a 200-MW Increment in Maximum Demand (MW installed)

Base Case Advanced Case Year Lignite Brown Coal Gas Turbine Lignite Brown Coal Gas Turbine

1984 1985 ------1986 ------1987 - - - - - _ 1988 - - - - -

1989 - - - - - _ 1990 ------1991 /1 - - - - - 1992 - - 1993 - - - - 1994 - - - 250 - _ 1995 250 - 105 - - 105 1996 250 - - 500 - - 1997 250 - - 500 - 1998 500 - - 250 - - 1999 250 - - 250 - 105 2000 500 - - 250 - 105 2001 - - 210 - 250 - 2002 - 250 - - 250 2003 - 250 - - 250 -

Total 2,000 500 315 2,000 750 315

Source: WASP outputs.

/1 CHP plant commissioned in 1991 is justified primarily on district heating fuel savings so that its timing does not change.

March 1984 (1829P) - 263 - ANNE 6.3 EarEMiRt2

POER ANDCcAL BRTt REVIEW

Data for Calculation LR. of Geerati Ca>rity (USs '000, 1983 prices)

Base Case Advared Progran Unserved Net Er*rg Generated (GWh) Unserved Net Generatian Yr capital /2 Fixed 08M /3 Er Total aP Inports Capital /2 Fixed O8M /3 Ewrg Total (GWi)

1984 - - 153 33,470 1,702 8,93D - - 428 34,676 1985 - - 5 34,615 1,702 10,290 - - 94 35,821 1986 - - 10 35,882 1,702 10,290 - - 184 37,088 1987 - - 119 37,269 1,702 10,290 - - 450 38,475 1988 - - 419 40,103 1,702 10,290 - - 148 39,862 1989 - - 419 38,656 1,702 10,290 - - 991 41,309 1990 - - 1,407 41,611 1,702 10,290 - - 4,607 42,817 1991 11 /1 245 43,088 5,012 10,290 /1 /1 402 44,294 1992 - - 506 44,626 5,012 10,290 - - 1,896 45,832 1993 - - 2,791 46,254 5,012 10,290 - - 6,743 47,460 1994 - - 9,107 47,913 5,012 10,290 43,972 6,930 9,921 49,119 1995 50,706 7,314 9,592 49,631 5,012 10,290 6,734 384 21,471 50,837 1996 43,972 6,930 13,306 51,229 5,012 10,290 87,945 13,860 14,105 52,436 1997 43,972 6,930 18,947 52,888 5,012 10,290 87,945 13,860 9,175 54,094 1998 87,945 13,860 12,560 54,576 5,012 10,290 43,972 6,930 13,213 55,783 1999 43,972 6,930 18,836 56,325 5,012 10,290 50,706 7,314 14,464 57,531 2000 87,945 13,860 14,104 58,134 5,012 10,290 50,706 7,314 16,090 59,341 2001 13,468 768 15,785 59,310 5,012 10,290 42,667 6,825 15,483 60,517 2002 42,667 6,825 15,178 60,486 5,012 10,290 42,667 6,825 15,08 61,692 2003 42,667 6,825 15,296 61,723 5,012 10,290 42,667 6,825 14,736 62,929

Present Value

0% 457,314 69,475 148,566 947,788 77,070 204,440 499,981 77,067 159,3D9 971,913

12% 88,778 15,134 30,472 351,681 25,011 84,724 102,071 15,697 36,027 361,771

/1 Capital and fixed 0 & M costs of CHP plant e2cclxIed as they are the sam for both cases. /2 Capital costs are imremnits to the stream of amniitized costs (US$ '000 p.a.). 7T Fixed 0 & M costs are the imremats to the strean of fixed 0 & Mcosts arising fommthe cossiomin of the unit.

March1984 (1829P) - 264 - ANNEX 6.3 Attachment 3 Page 1 of 3

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

Calculation of LRMC of Generating Capacity

(a) Capital Cost Element PV (incremental annuitized capital costs for advanced program) - PV (incremental annuitized costs for base program) 200 MWSO

102,071 - 88,778 200

66.5 US$/kW/a

(b) Fixed 0 & M Element = PV (incremental fixed 0 & M costs for advanced program) - PV (incremental fixed 0 & M costs for base program) 200 MWSo

= 15,697 - 15,134 200

= 2.8 US$/kW/a

(c) Cost/kW for Additional Unserved Energy = PV (value of unserved energy advanced program) - PV (value of unserved energy for base program) 200 MWS

= 36,027 - 30,472 200

= 27.8 US$/kW - 265 - ANNEX 6.3 Attachment 3 Page 2 of 3

This is the total outage cost per kW over the 20-year planning period. It can be translatedinto an annual cost by multiplyingby the annuity factor for 20 years at 12% discount rate, i.e. 0.1339.

Therefore:

Outage cost element = 27.8 x 0.1339 = 3.7 US$/kW/a

(d) Fuel Savings Element

An increment in maximum demand results in changes to the investment program that may involve bringing forwardplant with low fuel costs (e.g. lignite) which lowers the average fuel cost of the system. The fuel saving is defined as the differencebetween the average cost/kWh in the advanced and base cases, multipliedby the hours of utilizationof incrementaldemand. Because the fuel cost of imports and CHP were not evaluated in WASP, the output of these plants, which did not differ between the base and advanced cases, was subtractedfrom the total generation.

PV (fuel costs base case) = US$4,099 million PV (fuel costs advanced case) = US$4,314 million

3 Average fuel cost advanced case - 4,314 x 10 361,771 - (84,724 +25,011)

17.12 US$/MWh

3 Average fuel cost base case - 4,099 x 10 351,681 - (84,724 + 25,011)

- 16.94 US$/MWh

Saving in average fuel cost/MWh 16.94 - 17.12

- 0.18 USt/MWh

(The fuel saving is negative because of the more intensiveoperation of high cost thermal plant and new gas turbines before the low fuel cost plant is advanced).

Projected system load factor = 68.84%

Hours of utilization - 8,760 x 0.6884

- 6,030 h/a - 266 - ANNEX 6.3 Attachment 3 Page 3 of 3

Therefore fuel saving element = - 0.18 x 6.030 = - 1.1 US$/kW/a

(e) Total LRMC of Generating Capacity:

Capital cost - 66.5

Fixed 0 & M cost - 2.8 Unserved energy cost 3.7 Less, fuel saving = - (-1.1)

74.1 USt/kWso/a

June 1984 (1829P) - 267 - ANNEX 6.3 Attachment 4

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

Calculation of LRAIC of Transmission

Present Value 1983 1983 1984 1985 (12% d.r.)

Investment (current prices) (Ft million) .. 791 848 1,088 -

Inflation index (1983 = 100) - 100 108 116 -

Investment (1983 US$ million) /1 - 19.8 19.6 23.4 56.6

Maximum demand (MWSO) 5,310 5,520 5,730 5,950 -

Maximum demand delivered from transmission network (MW) /2 4,923 5,118 5,312 5,116 -

Incremental demand (MW) - 195 194 204 530

Incremental 0 & M (US$ million p.a.) /3 - 0.2 0.2 0.2 0.5

Assuming a 30-year economic life and 12% discount rate, the annuity factor is 0.1241

Therefore LRAIC = (56.0 x 0.1241 + 0.5) x 103 530

= 14.1 US$/kW/a

Sources: NBH, mission estimates.

/1 Converted using an exchange rate of US$1.00 = Ft 40 X2 Adjusted for 7.3% peak losses. /3 0 & M calculated as 1% p.a. of the total capital cost.

March 1984 (1829P) - 268 - ANNEX 6.4 Page 1 of 2

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

Marginal Costs and Tariffs

Table 1; Marginal Cost of Supplying Tariff Categories

Peak Coincident Marginal Costs Load Factor Demand Energy Total Tariff Category (%) (c/kWh) (c/kWh) (c/kWh)

Power Tariffs

Basic network 86.7 1.2 3*.3 4.5 Sub-transmission 84.0 1.3 3.4 4.7 MV tariff 1 93.6 1.3 3.5 4.8 MV tariff 2 57.8 2.1 3.5 5.6 LV tariff 1 70.7 2.2 3.7 5.9 LV tariff 2 74.8 2.1 'I.7 5.8

Traction

Rail 85.0 1.4 3.5 4.9 Train 68.9 1.8 3.5 5.3

General Tariffs (LV) 51.9 3.0 3.7 6.7

Public Lighting 45.3 3.4 3.7 7.1

Residential

Total 49.2 3.2 3.7 6.9

Night rate - - 3.7 3.7

Source: Mission estimates, MVNT.

March 1984 (1829P) - 269 - ANEX 6.4 Page Z ot 2

HUWAW

POW:RAN) COALSJBSW= REITO

Marginal Costs arndTariffs

Table 2: Caqparison of Average Tariff Leels to IRC

Ratio Total Peak Day Night Day Denid Peak Coincident Energy D dand Average Average Enery Enery Energy Peak Demmid LoadFator Cost Cost Price LRS /1 Price As W() (X) (%) (2) (USc/dih) (USc/dWh)(USc/kWh) (USc/kWh) (USc/kWh) % of IR1

P>er Tariffs

Basic Network 39 50 20 95 86.7 2.93 0.47 3.40 4.5 76 Sub Trananission 30 50 20 95 84.0 3.03 0.54 3.56 4.7 76 WTariff 1 30 60 10 160 93.6 3.55 0.48 4.03 4.8 84 MVTariff 2 30 60 10 80 57.8 4.68 0.51 5.19 5.6 93 LV Tariff 1 3) 60 10 140 70.7 4.71 0.84 5.55 5.9 94 LV Tariff 2 30 60 10 145 74.8 5.16 0.40 5.56 5.8 96

Traction

Rail 85.0 3.13 - 3.13 4.9 64 Tram 68.9 3.80 - 3.80 5.3 72

General Tariffs (LV) 95 5 51.9 7.20 0.17 7.37 6.7 110

Piulic Lightirg - - - - 45.3 4.25 3.58 7.83 7.1 110

Residential

Budapest 1.88 6.9 27 Large toms 3.00 6.9 43 Taows 3.88 6.9 56 Villages 4.88 6.9 71 Night rate 1.00 3.7 27

Source: Mission estiates, WM.

/1 IAC is taken fron Table 1 of this Amex.

Jtne 1984 (1829P) - 270 - ANNEX 6.5 Page 1 of 10

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

Economic Cost of District Heat

Basis of the Economic Cost of Heat

1. There are similarities between the economic cost of district heat and the economic cost of electricity. First, both commodities are not traded internationally so that their economic cost is the long run marginal cost of producing an extra unit, calculated with all inputs, e.g., fuel, valued at their border prices. Second, there are similarities between the nature of the marginal costs. These may be divided into two categories 1/:

(a) The marginal cost of expanding the system capacity (pro,duction, transmission and distribution) to meet a sustained increment in demand; and

(b) The marginal cost of producing an extra unit of energy (GJ) when capacity is fixed, which is mainly the marginal cost of fuel.

Furthermore, as in electricity generation, there is a diverse production technology. There are high capital cost, low fuel cost, back-priessure CHP turbines to meet the heat base load, condensing turbines to meet the shoulder heat loads and low capital cost, high fuel cost boilers to meet short duration peak heat loads.

2. However, unlike conventional thermal electricity generation, complications arise in estimating the economic cost of heat when heat is produced jointly with electricity. Separating the costs of joinitproducts completely is an intractible problem, and an allocation of joint costs is, to a large extent, arbitrary. However, some general principles may be stated. First, those costs which can unambiguously be separated should be identified and allocated to heat or electricity. For example, the electricity generator is clearly a power cost, whereas the costs of some pipework, valves, heat exchangers etc. are obviously costs of providing heat. Second, apparently joint costs can often be separated by establishing the costs of decisions the utility would take if the demand for one of the joint products was temporarily

1/ A third category is the marginal cost of connecting a new consumer to the network. Since this cost is reflected in connection charges rather than the tariff, it is not examined here. - 271 - ANNEX 6.5 Page 2 of 10 or permanently changed. For example, the additional fuel costs required to provide an extra GJ of heat can be estimated from a heat balance model of a CHP plant. If there is a corresponding change in electrical output, then this can be valued using a power system operations or long term planning model. The cost of bringing forward heat production capacity can be estimated net of any incremental electricity costs/benefits, if models are used to establish least cost heat and power investment programs.

Method of Estimating LRMC of District Heat

3. In principle the economic cost of district heat supply should be calculated for each of the 45 or so cities where district heating systems exist, since because of differences in growth in demand and age and technology of plant would lead to significant differences in economic cost. However, data were available only to carry out an approximate calculation of the economic cost of heat supply in Budapest. Based on summary information obtained from the Budapest heating study the economic costs of producing and distributing steam and hot water were calculated. The calculation of the LRMC of heat should take account of the present imbalance in heat production capacity. The heat system has a higher proportion of hydrocarbon fired boiler plant then today's fuel prices would justify. The LRMC of heat will depend on timing of programs to rationalize heat and power production which have not yet been prepared by the Government.

4. The LRMC of heat production was calculated assuming that in the foreseeable future, all new heat production capacity would consist of CHP plant. The LRMC of heat supply capacity can be defined as the net present value of advancing/retarding the investment program for heat production, transmission and distribution in response to a unit investment in peak demand (MW). Since the marginal plant will be CHP, altering its timing will produce additional costs or benefits in electricity supply, which should be added or substracted from the cost of heat. A further complication is that most CHP projects, e.g., Dunamenti CHP project, are justified primarily on fuel savings grounds. Such projects should be implemented as quickly as technically possible, so that they are not strictly "marginal" in the sense that their timing can be adjusted in response to changes in heat demand.

5. Although these problems are soluble, the mission lacked the data needed to make an accurate calculation of the LRMC of heat supply. A simple approach had to be adopted which consisted of:

(a) basing the LRMC of heat production capacity on the investment and fixed operating costs of the Dunamenti CHP project for the case of hot water, and the North Pest CHP scheme for the case of steam;

(b) reducing the cost of heat production capacity by the benefit for associated power production. The unit value of CHP power output was calculated as the difference in capital, fixed 0 & M and unserved - 272 - ANNEX 6.5 Page 3 of 10

energy costs between the generation programs with and without CHP estimated by the WASP computer program (see Annex 5.3) divided by the incremental CHP capacity;

(c) until CHP capacity is increased in the 1990's an extra GJ of heat at the margin will be produced from oil or gas fired boiler plant. The marginal fuel cost of heat at present is therefore the cost of heavy fuel oil or natural gas (US$/GJ) adjusted for boiler efficiency and heat distribution losses;

(d) when new CHP capacity is commissioned it will meet the heat base load, and boilers will probably continue to meet the winter peak loads. The marginal cost of fuel in winter would therefore continue to be the cost of boiler fuel oil, adjusted for heat losses in the boiler. Providing that CHP plant capacity is sufficient for it to operate at the margin, the marginal cost of fuel in summer would be the additional cost of fuel for an extra unit of heat, with power output held constant. Without a heat balance model of the CHP stations the marginal fuel cost was taken as the average fuel cost of a CHP plant, i.e., total fuel input cost, less the value of power produced, divided by the quantity of heat produced. Power was valued at the marginal fuel cost in the oil/gas fired plant operating at the margin; and

(e) the LRMC of transmission pipelines and distribution networks was estimated as the long run average incremental cost (LRAIC), which is often used a a proxy for LRMC in power and water suply when investment is lumpy, data are scare and technology is uniform.

Calculation of the LRMCof Heat Supply

(a) Heat Production Capacity

6. For hot water, the marginal cost of heat production capacity was taken as the cost of the Dunamenti CHP project (2 x 180 MWe), even though this project will also supply steam to the Duna oil refinery.

CHP station investment = US$349.5 million at 1983 prices. cost

Annual cost = US$44.6 million p.a. (25 yr. life, 12% discount rate)

Fixed Operating Cost uSt10.5 million p.a. (3% of investment) - 273 - ANNEX 6.5 Page 4 of 10

7. The value of the power capacity benefits were obtained using data obtained from the WASP model described in Annex 5.3 . Conceptually, the power capacity benefits are the cost savings from delaying the commissioning of power-only plant when CHP plant is commissioned, plus the value of any increases in power system reliability arising from the CHP plant. The difference in costs between generation programs with and without 651 MWSO of incremental CHP capacity are shown in Table 1.

Table 1

Value of CHP Power Capacity (US$ million, 1983 prices) /1

Program With Program With No CHP CHP Difference

Capital cost of power-only plant 1,983 1,263 720 Fixed 0 & M of power-only plant 2,479 2,350 129 Unserved energy 99 72 27

Total 876

/1 Costs are present values to 1991 at 12% discount rate, of costs incurred during the period 1991-2010.

Unit value of power capacity = 876,000,000 651,000

- 1,346 US$/kW so

Annual cost at 12% over the 20-year period 1991-2010 = 180 US$/kW/a

Based on the net (sent out) output of the Dunamenti units of about 338 MW, the value of the power capacity benefits is

338,000 x 180 = US$60.8 million p.a.

No allowance is made for heat reserve capacity since economically redundant boiler plant will continue to be available. Therefore, based on the Dunamenti heat output of 762 MW: - 274 - ANNEX 6.5 Page 5 of 10

Marginal cost of heat production = (44.6 + 10.5 - 60.8) x 106 capacity 762 x 103 = - 7.5 US$/kW/a

Adjusting for 8% distribution losses:

Marginal delivered cost of heat = - 7.5 production capacity 1 - 0.08

= - 8.1 US$/kW/a

The negative marginal cost would indicate that the project which is an extension to an existing station, has lower capital and fixed 0 & M costs than the proposed power-only projects.

8. For steam, a similar calculation was made for the NordL Pest CHP station (3 x 46 MWe' 370 MWth)

Investment Cost = US$195.5 million Annual Investment cost = US$24.9 million p.a. Fixed operating costs = US$5.9 million p.a. Total power benefit = 0.180 x 3 x 43 US$23.2 million p.a.

Marginal cost of heat production capacity = (24.9 + 5.9 - 23.2) x 106 370 x IOJ = 20.5 US$/kW/a

Adjusting for 8% distribution losses, Marginal delivered cost of heat production capacity = 22.3 US$/kW/a

(b) Heat Distribution Capacity

9. The LRAIC of heat distribution capacity is defined as:

LRAIC = PV (Incremental investment and operations costs) PV (Annual increments in demand (MW)) where PV denotes present value.

Cash flows are shown in Table 1. LRAIC's for hot water can be calculated separately for the transit pipeline and distribution networks, using data on the Dunamenti project obtained from the Budapest Heating Study. - 275 - ANNEX 6.5 Page 6 of 10

LRAIC hot water transit = (100.9 x 0.1275 + 1.55) x 106 359 x 103

= 40.1 US$/kW/a where 0.1275 is the factor to annuitize the investment cost over a 25 year life at 12% discount rate.

Adjusting for distribution losses:

LRAIC hot water transit, delivered heat basis = 40.1 1 - 0.08

= 43.6 US$/kW/a

LRAIC hot water networks = ((48.5+3.4)x0.1275+0.8)x106 859 x 103

= 8.6 US$/kW/a

Adjusting for 8% distributionlosses: LRAIC hot water networks, delivered heat basis = 9.4 US$/kW/a

The LRAIC of steam distribution was based on data for the North Pest project contained in the Budapest Heating Study (Table 1).

For steam distribution: LRAIC, delivered heat basis = (9.6 x 0.1275 + 0.2) x 106 131 x 10, X (1-0.08)

= 11.8 US$/kW/a

10. On a deliveredheat basis: - 276 - ANNEX 6.5 Page 7 of 10

LRMC of capacity for hot water = - 8.1 + 43.6 + 9.4

= 44.9 US$/kW/a

LRMC of capacity for steam = 22.3 + 11.8

= 34.1 US$/kW/a

(d) Marginal Fuel costs:

11. 1985-1990: At present oil or gas fired boilers operate all year round. During the period before new CHP capacity can be commissioned any additional GJ of heat would come from this plant. The economic cost of gas is thermal parity with the fuel oil price of Ft 6,000/ton (US$150/t) (Annex 7). With a fuel oil net heat value of 40.5 GJ/t and a typical boiler efficiency of 85%, the marginal fuel cost is 150 40.5 x 0.85

= 4.4 US$/GJ

Adjusting to 8% distribution losses, the delivered cost is marginal fuel cost of delivered heat

- 4.0 1 - 0.08

= 4.7 US$/GJ

12. 1991-2010: After future investment in CHP plant, the marginal unit of heat might be met from CHP plant rather than boilers, particularly during the summer. The marginal fuel cost of heat during the summer would be the fuel cost of producing an extra GJ of heat from a CHP plant. Depending on the CHP technology, an extra GJ of heat might also result in some extra kWh of electricity being produced. In the absence of detailed information on heat and power production possibilities, it was assumed that for the Dunamenti and North Pest CHP stations, the marginal fuel cost did not differ from the average fuel cost and that heat and power are produced in the same proportions at each level of output. Under these assumptions the marginal fuel cost in summer would be: - 277 - ANNEX 6.5 Page 8 of 10

Hot Water Steam

CHP Station Dunamenti Nord Pest Annual fuel consumption (Pi) 34.04 13.85 Annual heat production (PJ) 16.56 8.18 Annual power production (GWh) 2,188 578 Fuel price (US$/GJ) 1.87 1.87 Fuel cost (US$million/a) 63.6 26.2 Value of power production (us/jMwh) 26.2 26.2

Total value of power production (tmillion/a) 57.3 15.1

Economic cost of heat ($/GJso) 63,6 - 57.3 25.9 - 15.1 16.56 8.18

= 0.38 1.32 Economic cost of heat adjusted for 8% distributionlosses = 0.41 $/GJ 1.44 $/GJ

This calculationof the marginal fuel cost of district heat is based upon an electric power value of USt26.2/MWh produced by the CHP plant. The value of power was calculatedas the difference in total fuel cost between the generation program with and without new CHP plants (see Annex 5.3) for the first year of their operation. The value of power decreases as lower fuel cost power-onlyplant is commissionedduring the mid 1990's and thereafter. The LRAIC of power generated in the 1991 CHP plants is calculated from the WASP outputs to be US$16.9/MWh,which would result in marginal fuel costs for district heat of US$1.6/GJ for hot water and US$2.0/GJ for steam. The fuel cost of producing heat can thereforebe expected to decline as new CHP plant is commissionedand then rise in real terms as the value of power generated falls.

Summary

13. Estimating thLeeconomic cost of district heat is more difficult than for electricitybecause of the large number of heating systems in Hungary, the lack of detailed year-by-yearinvestment programs for most of them and the complicateddynamics of the transitions from the present sub-optimal production capacity to more balanced systems. With these reservationsand the limitationsof the data available,preliminary estimatesof the LRMC of heat in constant 1983 prices are: - 278 - ANNEX 6.5 -777T 10

Hot Water Steam

Production and distribution capacity (US$/kW/a) 44.9 34.1

Fuel (USt/GJ) - Winter, all years 4.7 4.7 - Summer, 1991 0.4 1.3 - Summer, 1991-2010 1.6 2.0

These estimates of LRMC are for a balanced system that is unlikely to be reached before 1991. A potential increment in heat consumption in the interim, if it is met, would be supplied mainly from oil and gas fired boilers, which might later need replacement by CHP plant. However, without detailed investment programs and operating data it is not possible to establish the path of LRMAC during the interim period before the new CHP plant is comnmissioned. once a detailed heat investment program has been approved for Budapest, it is recommended that a LRMC pricing study be carried out. 279- - AANNEX6.5 Page 10 of 10

HUWARY

POWR ANDCCAL SUBSECItR REVEW

Calculation of LRAIC of Heat Distribution

(N) (NW) Investnent (Ft million, 1983 prices) Incremental Gross Heat Demand Incremental Denand Dunamenti Project North Pest Project Operating Costs Year Hot Water Stean Hot Water Stean Transit Netwrtk Stean Hot Water Stean Hot Water

1982 1,268 1,383 1983 1,342 1,398 74 15 1984 1,421 1,414 79 15 - - - - - 1985 1,503 1,429 83 16 ------1986 1,591 1,445 88 16 675 325 - - - - 1987 1,684 1,461 93 16 1,376 661 - - - - 1988 1,782 1,477 98 16 1,376 661 250 240 - - 1989 1,886 1,493 104 16 1,378 662 250 - - 6 1990 1,995 1,510 110 16 1,513 727 250 - - - 1991 2,112 1,526 117 17 676 324 - - 19 - 1992 2,235 1,543 123 17 675 325 - - _ _ 1993 2,366 1,561 130 17 - - - - - 281 1994 2,504 1,577 138 17 - - - - - 1995 2,650 1,595 146 17 ------1996 2,804 1,612 154 17 - - - - - 1997 2,968 1,630 163 18 ------1998 3,141 1,648 173 18 - - - - - 1999 3,324 1,666 183 18 - - - - - 2000 3,518 1,684 194 18 - - - - -

TCIAL 2,250 300 7,669 3,685 750 240 19 290

Present Value (12V to 1983) 859 131 4,035 1,939 382 136 8 94

Present Value (USt million) 859 131 100.9 48.5 9.6 3.4 0.2 2.4

Sairce: EGI, mission estimates.

March 1984 (1829P) - 280 - ANNEX 6.6 Page 1 of 3

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

Benefits From Metering District Heat

1. It is well established, in water supply as well as in district heating, that metering supply can reduce consumption substantially by as much as 50%. A survey carried out in Hungary has shown significant differences in energy consumption for space heating between those households using natural gas, which is metered and those using district heating or gas fired central heating, which is not metered (Table 1).

Table 1

Specific Heat Consumption

Heating System kJ/m 3 /a

Individual gas heating (metered) 249,232 Gas-fired communal boiler 385,508 Boiler houses over 5 MW capacity 362,384 Heating plant in the capacity range 5-20 MW 361,643 Heating plants over 20 MW capacity 328,915 Existing heating power staions 272,000 - 310,000 Assumed up-to-date heating power station 179,000

Source: EGI

These figures may be used to investigate the net benefits from metering district heat. Taking a typical apartment size of 130 m3 , total heat consumption would be about 32 GJ/a if gas were used and about 39 GJ/a (130 MJ/m3 ) for district heat. Natural gas has a lower end use efficiency than district heat and the end use efficiency of natural gas for heating is probably about 70% because of flue losses etc., compared to say 90% for district heating. Therefore, the useful energy consumption of a household would be 22 GJ/a for gas and 35 GJ/a for heat. There are price differences also between natural gas and district heat. The price of gas is UStl.69/GJ delivered, or US$2.41/GJ on a useful heat basis. The average cost of district heat is about US$1.83/GJ delivered, or US$2.03/GJ for useful heat, although the marginal price of district heat is zero. These data enable the approximate demand curve shown in Figure 1 to be constructed. - 281 - ANNEX 6.6 Page 2 of 3

Figure 1

Demand Curve for Heat

Pri;e PeGCst H&8ea.t

I A X7 X4 36 94; Vusekwk ijet (GWTJc)

The benefit from reduced heat consumption is the saving in the cost of heat supply. A conservativelylow estimate of this would be the fuel saved in producingheat, which would amount to 188 Ft/GJ or 4.70$/GJ, since oil/gas fired boiler heating plants are expected to be the marginal suppliersof heat until at least 1991. The annual fuel saving would therefore amount to

4.7 x (35-24) = US$51.7/a.

The costs are the cost of the meter (usually a conventionalwater meter) and the cost of meter reading, billing and periodic meter overhauls. These are not available, so the maximum value at which metering breaks even is calculated. In addition, the reduction in consumptionleads to a fall in consumer surplus, the difference between what a consumer is willing to pay and what he actually pays. This is shown as the area OBCD in Figure 1. However, the amount actually paid by the consumer OACD is assumed equal to the present fixed charge, so that the net loss in consumer surplus is the area ABC. Therefore

Net loss in consumer surplus = 1/2 (35-24) x 2.03 = 11.2 US$/a

The breakeven cost of metering is therefore

51.7 - 11.2 = 40.5 US$ per consumer p.a.

Assuming a five year meter life, the present value of the breakeven cost is $146, whereas the cost of meter installationand meter reading is probably in the order of half this. For example, if the cost of a meter installed was $60 and meter reading cost $5 p.a., a project to meter district heat would have an - 282 - ANNEX 6.6 Page 3 of 3

economic rate of return greater than 50% over an assumed 5 year meter life (Table 2). If the average annual saving of US$19/a (Table 2) were obtained from all the 175,000 residential district heat consumers, the total annual saving would be US$3.3 million.

Table 2

Benefits of Metering District Heat

Year Cost Benefits Net Benefits

0 60.0 - -60.0 1 5.0 40.5 35.5 2 5.0 40.5 35.5 3 5.0 40.5 35.5 4 5.0 40.5 35.5 5 5.0 40.5 35.5

Net Present Value

0% 117.5 12% 68.0

Internal economic rate of return 52%

Average annual saving = 68.0 x 0.27774 /1 =- US$8.9/a

Source: Mission estimates.

/1 Annuity factor for 5 years at 12% discount rate.

March 1984 (1829P) - a83 - AtN 6.7 P4e 1 ot 2

HN;RW

P^R AM CM SB EWJ

EI3m ftenditure md i e

Tabl 1: Per Capita Hdold Enrw Expweditre an Per CqAita Hmiold E?M!Rwizzd Ie emm. 1L981

E;^enit±e anEgna Electricity VS Eurgy VS Fueil District Total Total Total Z of ToWal X of Total Lgbt Reat Electricity Gm Er- I E ii IItU EInidiwm imam

$ftkers - ten 527 298 525 257 1,607 37,917 39,012 1.4 1.3 4.2 4.1 - villqes 899 6 548 128 1,581 36,457 38,0a4 L5 1.4 4.3 4.2 - total 708 156 536 195 1,595 37,208 38,546 1.4 1.4 4.3 4.1

C-qzerativ &Peaan 842 22 526 152 1,542 40,093 41,60D L3 1.3 3.8 3.7 Tw IrmeHuehold 772 19 499 134 1,424 37,514 41,533 1.3 1.2 3.8 34

White Collar Worker - tam 346 415 616 485 1,826 48,119 46,486 L3 1.3 3.8 3.9 - villa U79 U 734 131 2,055 47,696 46,701 L5 L6 4.3 4.4 - tow 579 302 649 386 1,916 48,OD1 46,546 L4 1.4 4.0 4.1 itactive- ttm 924 275 736 489 2,424 35,706 37,296 2.1 2.0 6.8 6.5 - villae 1453 4 564 174 2,195 36,084 37,306 L6 1.5 6.1 5.9 - total 1205 131 645 322 2,303 35,906 37,301 L8 L7 6. 6.2

White Coll Warkers -zqwt & p-fe-iAl 566 335 700 463 2,T4 55,484 52,413 L3 1.3 3.7 3.9 - otheu 584 287 628 353 1,852 44,761 44,006 1.4 1. 4.1 4.2 Inactive: r occqtimi -uxkes 1278 121 635 275 2,339 34,303 35,647 L9 1.8 6.7 6.5 - cO-qperative & peseus 1479 10 49D 182 2,161 37,717 38,798 1.3 1.3 5.7 5.6 - *hite collar 728 364 9%9 7D6 2,727 41,527 43,675 2.3 2.2 6.6 6.2

So:irs: ESR%fiztorthsstatiaztika 1981" HamodwldStatistics 1981).

Marc 1964 (1829P) - 284 - AUN 6.7

P EOAND CM L 3S91RP

Ereru Exuw itum an d

Table 2: Exiture a Ea by H bold Incim Lesi, 1961 (Ft. p.r c4ite)

16,8D1 21,6D1 26,401 31,201 36,CD1 401,d31 45,601 - 21,600 - 26,4C0 - 31.20D - 36.0CD - 40.80D - 45,60D - 55,20D 55.201 +

umime pFr capita 19,664 24,189 28,856 33,529 39,196 42,929 49,667 69,035 E.rgy eqmdixre per caita - fl S ligh 513 5S0 613 664 796 901 881 1,105 - district hemvLog 39 124 146 183 148 162 231 278 - electricity 369 459 466 MSD 618 603 729 762 so- W7 142 154 199 232 254 258 331 total 1,08 1,305 1,379 1,534 1,796 1,920 2,099 2,476 l msV1% of i - electrical 1.9 L9 L6 1.5 L6 L4 1.5 1.1 - tow 5.2 5.4 4.8 4.6 4.7 4.5 4.2 3.6

White Collar i mi-per capita 23,293 28,818 33,604 38,426 43,015 49,785 70,965 EzmzV expenditure Per caPita -fuel S ligt 370 576 512 632 544 622 666 -district heatirg 149 2C 31 257 253 29D 539 - electricity 552 528 560 576 644 699 92D V-W 23D 255 319 369 382 431 622 - total 1,3D1 1,563 1,682 1,834 1,853 2k,032 2,747 E=V as 1 of ierin -electricity 2.4 L8 1.6 L5 L5 1.4 1.3 - total 5.6 5.4 5.0 4.8 4.3 4.1 3.9

Inactiwe AWmni-a pr capita 19,438 23,925 28,695 33,587 38,255 43,103 49,920 70,95 Ergy exemdiite per capita - he&l S light 1,193 1,224 1,036 1,147 1,239 L378 1,525 1,197 - district beatir 23 ea 113 73 96 277 258 408 - elwtricity 397 574 595 670 729 839 892 889 - gas 125 244 338 372 39D 348 38D 659 - totad 1,738 2,13D 2,132 2,262 2,454 2,812 3,0C5 3,153 Eurn - 2 of i - electricity 2.0 2.4 2.1 2.0 L9 1.9 1.8 1.3 - total 8.9 8.9 7.4 6.7 6.4 6.5 6.1 4.4

Co-ertia + Penmt m e pr cAPit 19,272 24,220 29,741 33,572 38,412 43,131 49,260 74,235 Er eipazliture pr capita - fuel S light 601 617 793 779 1,099 996 1,113 1,124 -district heatirg - 14 37 40 25 28 15 19 - electricity 364 460 485 471 555 658 685 874 - 1.22 109 137 162 194 152 179 284 - totl 1,087 1,199 1,452 1,452 1,903 1,84 1,992 2,3D1 Eir as Z of i8 - electrical 1.9 L9 L7 1.4 1.5 1.5 1.4 1.2 - total 5.6 .5.0 5.1 4.3 5.0 4.3 4.0 3.1

TODIxzm Fau*olds Mm ii per capita 23,041 28,797 33,462 38,439 42,903 49,896 69,278 Enery puediture p capita - ful S light 496 698 730 865 1,021 1,083 1,029 -district heatiAg 19 23 36 10 19 - 29 - eletricity 402 434 456 533 545 65D 756 -P 101 10 1.21 136 156 186 245 - total 1,018 1,263 1,363 1,544 1,740 1,919 2,059 Kmrg an % of inme - tehmical 1.7 L5 1.4 1.4 1.3 1.3 1.1 - total 4.4 4.4 4.0 4.0 4.1 3.8 3.0

Sgot e: 21 'Ukt5a utatiaztika 1981" lciudiold Statistics, 1981)

1984 (1829P) - 285 - ANNEX 6.8 Page 1 of 2

HUNGARY

POWER AND COAL SUBSECTOR REVIEW

Estimates of Long-Run Marginal Production Costs for Typical Brown Coal and Lignite Projects

Brown Coal Lignite Ft/t US$/t Ft/GJ US$/GJ Ft/t US$/t Ft/GJ US$/GJ

1. Supplies 220 5.5 16.4 0.4 76 1.9 11.4 0.3 2. Wages 250 6.3 18.7 0.5 34 0.9 5.1 0.1 3. Other 130 3.3 9.7 0.2 78 2.0 11.7 0.3 4. Operating cost 600 15.0 44.9 1.1 188 4.7 28.2 0.7

5. Investments 3,200 - - - 1,600 - - - - early replacement 800 - - - 80 - - - - other 2,400 - - - 1,520 - - -

6. Capital recovery - replacement invesements 160 4.0 12.0 0.3 16 0.4 2.4 0.1 - other investments 288 7.2 21.5 0.5 182 4.6 27.2 0.7

7. Production cost 1,048 26.2 78.3 2.0 386 9.7 57.7 1.5 (4+6)

Assumptions and Explanations

All cost data In constant 1982 terms. Exchange rate Ft 40 = UStl

Brown coal West Hungarian Eocene brown coal from new deposits in Tatabanya area (in particular Many). Heating value 3,200 kcal/kg = 13.38 GJ/t.

Lignite Biikkabrany lignite. Heating value 1,600 kcal/kg = 6.69 GJ/t.

Supplies Including spare parts, consumables, energy.

- brown coal: actual Csordakut mine (typical / modern W. Hungarian Eocene mine). - 286 - ANNEX 6.8 Page 2 of 2

- lignite: actual Thorez mine (Ft 91/t), adjusted for lower overbur(lenat BUkkabrany (83%).

Wages Including taxes on wages.

- brown coal: actual average of Csordakut, Borsod and Oroszlany coal mines (modern and efficient mines).

- lignite: actual Thorez mine (Ft 41/t) adjusted for lower overburden at Biikkabrany (83%).

Other Excluding financial charges.

- brown coal: actual average of Borsod and Oroszlany coal mines.

- lignite: actual Thorez mine (Ft 94/t), adjusted for lower overburden at Biikkabrany (83%).

Investments Per ton of annual production capacity.

- brown coal: KBFI estimate for Many II mine.

- lignite; 50% of brown coal, based on comparison actual cost of Csordakut and Thorez mine adjusted for time difference and lower overburden at BUkkabrany. (According to KBFI capital cost estimate for BukkAbrany, lignite would only account for 33% of brown coal).

According to actual cost of Csordakut and Thorez, investments which are depreciated over less than 10 years (replacement investments) account for 25% in the case of brown coal and 5% in the case of lignite.

Capital Recovery A capital recovery factor of 0.2 (8 years average lifetime, 12% real discount rate) has been used for replacement investments and 0.12 (30 years lifetime, 12% real discount rate) for other investments.

June 1984 (1829P) - 287 - ANNEX7.1 Pag~e1of 2

HUtIARY-

POtER ANDCOCL RJBSE9DR REVIEW

A. Coal Subsector Projects urder ConstruCtion (millicn forints at 1983 prices, US$1 = 40 forints)

Capacity N/Year IrplAeientation E,pendi- Specific Replace- Full Prco Capital ture to Capital Cost Project Descripticn Total nent Start ducticn Cost 12-31-82 Forints/TPY A. Minixg Projects

Lignite

p Duiar (Veszpre Co.) 0.5 0.4 1982 1985 300 n. a. 600 Nagyegyhaza (Tatabanya Co.) 2.1 Late 1987 6,700 4,640 3,190 Many I (Tatabarya Co.) 1.0 1.8 1970s 1988 4,370 1,280 4,370 LelEsehecy II (Dorog Co.) 1.0 0.5 1982 1988 3,200 400 3,200 Kanyas (Nograd Co.) 0.7 0.7 1982 n.a. 500 n.a. 715

Subtotal Brown Coal 7.4 4.4 16,970 6,920

Blak Coal

Lias GavermiamtProgram mid (Mecsek Co.) 3.4 3.0 1982 1980s 26,000 210 7,650

Subtotal Mining 43,430 6,920

B. Coal-Washirg/Briquetting

Brown Coal Borsod Coal Washirg Plant 2.5 1981 1985 620 n. a. Oroszlany Air Separaticn 0.4 1983 1986 340 Veszpram Briquettixg 0.5 1982 n.a. n.a. n.a. Tatabanya Fine Coal Washitg 1.5 1983 1986 350 - Nograd Coal Washirg Plant 0.6 1983 1986-87 390 -

Black Coal Mecsek Cokirg Coal Flotation, Phase I 0.2 1983 1986 1,390 - Y4ecsekBriquetting 0.3 1983 1986 290 -

Subtotal Washirg Briquettirg 3,380

Total Uder Constructicn 46,810 6,920

Source. Coal caemanies, IpM and KBF.

June 1984 (1829P) - 288 - ANNEX7.1 Pageo 2 o 2

HUNG,Aff

POWR ANDCOAL SUBMCltR REVIEW

B. Coal Subsector - Possible Future Projects (million forints at 1983 prices, US$1 = 40 forints)

Specific Operatirg Capacity Capital Capital Cost Cost Project Description M /year Cost Forints/tFY FtrintstlPY

A. Minirg Projects

Lignite Existing Thorez Mine /1 7.2 2,0O0 280 266 (Matraalja) (existing) Thorez Mine Expansion 10.0 18,500 1,850 n.a. Buld:abrany (new mine) - Variation 1 10.0 n.a. n.a. n.a. 2 13.0 n.a. n.a. n.a. 3 21.0 21,500 1,080 127 Torony (NewMine) 20.0 28,700 1,440 226

Brwn Coal Reopenirg Borokas Mine (Dorog) 1.0 4,320 4,320 861 Kerekdaii MNineExpansion (Dorog) 2.0 7,180 3,600 679 New Man II Mine (Tatabanya) 3.0 10,000 3,330 793 New Bdckd II Mine (Oroaziany) n.a. nea. na. n.a. New Aijka Mine (Veszprei) 3.0 n.a. n.a. na. New Mizserfa II Mine (Nograd) 0.7 1,030 1,480 559 Feketevolgy Mine Expanion (Borsod) n.a. n.a. n.a. n.a. Lyukobanya Mine Expansion (Borsod) n.a. n. a. n.a. n.a. NewDubicanje Mine (Borsod) 2.2 3,450 1,570 520

Hard Coal New Maze South Mine - Variation 1 - open pit 7.5 46,500 6200 nea. - Variation 2 - undergroaui 4.0 30,000 7520 n.a.

B. Coal Processirg Projects grnquetting (Matraalja) 0.5 700

Bron Coal Briquettirg (Dorog) 0.3 nea. BrownCoal Char (Tatabarya) 0.3 700

Hard Coal Coking Coal Flotation Phase II 0.2 2,000

Source: Coal mining companies, IpM and KBFI.

March 1984 (1829P) HUNGARY ao~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ ~ ~ ~ ~ ~ I~~~~~BRD18191

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