PROSPECTS of NUCLEAR POWER in FINLAND the Following States Are Members Of

TECHNICAL REPORT SERIES No. 2 Prospects of : Nuclear Power

A JOINT STUDY BY THE INTERNATIONAL ATOMIC ENERGY AGENCY AND THE FINNISH ATOMIC ENERGY COMMISSION

INTERNATIONAL ATOMIC ENERGY AGENCY • VIENNA 1960

PROSPECTS OF NUCLEAR POWER IN FINLAND The following States are Members of

the International Atomic Energy Agency

AFGHANISTAN IRAQ ALBANIA ISRAEL ARGENTINA ITALY AUSTRALIA JAPAN AUSTRIA REPUBLIC OF KOREA BELGIUM LUXEMBOURG BRAZIL MEXICO BULGARIA MONACO- BURMA MOROCCO BYELORUSSIAN SOVIET SOCIALIST REPUBLIC NETHERLANDS CAMBODIA NEW ZEALAND CANADA NICARAGUA CEYLON NORWAY CHILE PAKISTAN CHINA PARAGUAY COLOMBIA PERU CUBA PHILIPPINES CZECHOSLOVAK SOCIALIST REPUBLIC POLAND DENMARK PORTUGAL DOMINICAN REPUBLIC ROMANIA ECUADOR SPAIN EL SALVADOR SUDAN ETHIOPIA SWEDEN FINLAND SWITZERLAND FRANCE THAILAND FEDERAL REPUBLIC OF GERMANY TUNISIA GHANA TURKEY GREECE UKRAINIAN SOVIET SOCIALIST REPUBLIC GUATEMALA UNION OF SOUTH AFRICA HAITI UNION OF SOVIET SOCIALIST REPUBLICS HOLY SEE UNITED ARAB REPUBLIC HONDURAS UNITED KINGDOM OF GREAT BRITAIN AND NORTHERN HUNGARY IRELAND ICELAND UNITED STATES OF AMERICA INDIA VENEZUELA INDONESIA VIET-NAM IRAN YUGOSLAVIA

The Agency's Statute was approved on 26 October 1956 at an international conference held at United Nations headquarters, New York, and the Agency came into being when the Statute entered into force on 29 July 1957. The first session of the General Conference was held in Vienna, Austria, the permanent seat of the Agency, in October, 1957.

The main objective of the Agency is "to accelerate and enlarge the contribution of atomic energy to peace, health and prosperity throughout the world".

Permission to reproduce or translate the information contained in this publication may be obtained by writing to the International Atomic Energy Agency, Karntner Ring 11, Vienna I.

Printed by the IAEA in Austria December 1960 PROSPECTS OF NUCLEAR POWER

IN FINLAND

A Joint Study by the International Atomic Energy Agency and the Finnish Atomic Energy Commission

TECHNICAL REPORT SERIES No. 2

INTERNATIONAL ATOMIC ENERGY AGENCY

KARNTNER RING, VIENNA I, AUSTRIA

1960 PROSPECTS OF NUCLEAR POWER IN FINLAND, IAEA, VIENNA, 1960

STl/DOC/lO/2 FOREWORD

Nuclear power is one of the most important practical applications of atomic energy and a major function of the Agency is to further its development. It became apparent in the Agency's early studies in this field that too often the economics of nuclear power were discussed in general terms and without reference to the multitude of conditions governing each specific power situation, which vary widely from country to country and even within a given country. It was also found that the few specific studies which existed had been carried out in countries where it had already been decided to establish a nuclear power station or even to embark on a full-scale nuclear power program. It was therefore considered that the prospects of nuclear power throughout the world could be realistically assessed only on the basis of a series of studies of as wide a range of different actual situations as possible. At its fourth regular session, the General Conference of the Agency adopted a resolution calling for the con- tinuation of nuclear power surveys in Member States at their request. The Government of Finland invited the Agency to participate in a study of the prospects of nuclear power in Finland during the next decade. The desire of the Government of Finland was, on the one hand, to benefit from the spe- cialized experience of the Agency, and on the other, to make a contribution to the Agency's program of furthering the development of nuclear power. We fully appreciate the value of this contribution and consider it very important for the Agency's program that this first nuclear power study has been undertaken together with a Member State which has long experience in conventional power planning and has consistently looked at nuclear power within the general context of the problem of meeting her growing power needs. The Board of Governors of the International Atomic Energy Agency approved the Agency's participation in the study and work began in March 1960. A joint study group was set up between the Finnish Atomic Energy Commission and the Agency's Secretariat, in co-operation with Imatran Voima Osakeyhtio, the State Power Corporation. The study group was headed by the Chairman of the Finnish Atomic Energy Commission and the Agency designated a member of its technical staff to serve as its representative and as special assistant to the head of the study group. An Agency consultant and other members of the technical divisions concerned with nuclear power activities joined in the group's work when the preparatory stage of the study had been completed. The Agency also con- sulted the Energy Division of the United Nations Economic Commission for Europe. While the emphasis in this Report naturally falls on problems specific to Finland, the method followed, the factors discussed and some of the data presented have a more general validity and may serve as guides to other Member States, especially those that rely largely on hydro power. It is hoped that this first report will prove of assistance to them in assessing the possibility of in- troducing nuclear power.

December 1960 Director General

CONTENTS

1. Introduction and summary of conclusions 9 2. Energy 11 3. Hydroelectric resources .. 12 4. Imported fuels 23 5. Domestic fuels 25 6. Present power situation 31 7. Past growth of power consumption and estimates of future needs 39 8. Power programme until 1965 and probable development until 1970 .... 46 9. Changing role of condensing steam power 53 10. Possible locations for a base-load nuclear power plant in the system.. 62 11. Cost of conventional power 67 12. Cost of nuclear power 82 13. Comparison of nuclear and conventional power costs 90 14. Conclusions 94

1. INTRODUCTION AND SUMMARY OF CONCLUSIONS

The utilization of nuclear power for the production of electricity has been under rapid development, especially in the last five years. In some highly industrialized countries of the world nuclear power plants have been developed and built, first for demonstration purposes or as prototypes but more recently as commercial plants with the aim of achieving, at an early stage, economic competitiveness with other available sources of power. At the initial stages in planning a nuclear power programme an analysis of the overall power situation, including the structure of the power production and consumption, is necessary as well as an economic comparison of nuclear and conventional power costs over a foreseeable period of time. In Finland, the main power resource has been, and still is, hydro power. It is clear, however, that the hydro potential is insufficient to cover the increasing consumption over a long period of time. Already about one half of this potential has been exploited. Thus the country will necessarily have to consider the utilization of thermal power to an increasingly large extent. There is no indigenous coal or oil. For this reason it has become necessary to investigate realistically the possibilities offered by nuclear power. As it was not possible at the present stage in the rapid development of the technology of power reactors and nuclear fuels to make a long-term prediction concerning the possibilities for establishing a substantial nuclear power programme in Finland, this joint study concerned itself with a rather narrow field and limited objectives. The aim of the study was to investigate the criteria and conditions under which nuclear power could feasibly be introduced from the technical and economic standpoints into the country's power programme within the decade from 1960 to 1970. It was decided from the beginning to restrict the study to the possibilities of the production of electricity alone in large central plants. The question of small industrial power reactors capable of producing heat as well as electricity has not been studied. Nor has the possibility of installing small power plants in remote areas in the north of the country been investigated. These subjects could well be treated in subsequent studies, should sufficient interest be shown in them and sufficient technical and cost data become available. The report begins by reviewing briefly the general energy situation in Finland (Chapter 2) and then proceeds to evaluate the existing energy resources of the country and its energy imports (Chapters 3, 4 and 5). An account of the present electric power situation is given in Chapter 6 while estimates of future power consumption up to 1970 are contained in Chapter 7. Chapter 8 describes the power programme designed to meet the anticipated needs and Chapter 9 is specially devoted to the expected role of thermal power within this programme. In this way a preliminary determination is made of the time when a sufficiently large block of thermal power can be economically assigned to base-load duty. This leads to the second part of the report namely to a preliminary comparison of the costs of conventional and nuclear power at the time when a relatively large unit of either type could be operated on base-load. Chapter 10 dis- cusses the possible locations for a base-load nuclear power plant in the system from the viewpoint of optimum load transfer.

9 Chapter 11 proceeds to estimate the probable future costs of hydro power as well as of a thermal conventional plant taking 1960 as a basis and projecting future capital and fuel costs as well as heat rates into the next decade on the basis of explicitly stated assumptions. Chapter 12 gives summary estimates of nuclear power costs for the same tentative dates and endeavours to establish a preliminary generating cost comparison under different sets of assumptions for fuel costs, load factors and interest rates. A comparison of nuclear and conventional power costs is given in Chapter 13. The period under review is one in which certain important changes are expected to take place in the structure of the power production pattern in Finland. Until now hydro power has been by far the most important source of electrical energy. It could even be said that Finland has been a virtually "pure hydro" country, where the role of thermal power - at least condensing steam power - has been that of supporting hydro production in winter months when hydro production was lower than the demand or during any period of low water availability. This situation is valid when sufficient hydro power is available at prices lower than from coal-fired stations. Important changes are, however, already taking place in the face of the sharply reduced coal prices and the prospects of increasing hydro construction costs. As the development of the hydro resources slows down and more thermal power plants are built, the pattern will gradually change from a "pure hydro" to a "mixed hydro-thermal" system. It is fully expected that this change will take place during the next decade and will, of course, continue thereafter. The importance of this change for the prospects of nuclear power is easy to understand. Nuclear power plants with their higher capital costs require large sizes and high utilization factors for economic operation. The present utilization of thermal plants in Finland (300 to 1500 in a year) cannot be con- ceived for nuclear stations. The main technical criteria therefore for the introduction of nuclear power in Finland are size and utilization factor. These are treated at length in Chapter 9 of the report. It is seen that whereas a thermal capacity of 100 MW will have a utilization factor of only 20% in 1960, this will increase to 40-45% in 1965 and 80-85% in 1970. It is estimated that a capacity of 200-400 MW - depending on the rate of increase in the power demands - will have a utilization factor of over 75% around 1970. The second main question has been whether this base-load capacity could be more economically obtained in a nuclear power plant than a coal-fired plant. Here the key factor is the cost of coal. At present, coal is available in Finland at a remarkably low price. The cost of delivered heat is around 450- 500 FM^/Gcal and this leads to total generation costs of the order of 2- 2.5 FM/kWh, with which nuclear power is not at present able to compete. A comparison carried out for 1965 shows clearly that a 150 MW nuclear power plant is not competitive with its coal-fired counterpart even under higher heat costs (750 FM/Gcal). The situation in 1970 may show some important changes, although it is impossible to say that it will definitely favour nuclear power. The comparisons carried out for 1970 are based on many assumptions and it is very difficult to predict the changes over the next ten years in the cost of conventional power on

1) Finnish units and present cost of money are used throughout this report. For converting the Finnish mark (markka) into other currencies the rate US $ 1 = 320 FM may be used.

10 the one hand and that of nuclear power on the other. It can be concluded, nevertheless, that under conditions of low interest rate (6% overall) and high coal heat cost (750 FM/Gcal) nuclear and conventional generating costs may become equal. It is to be noted in this connexion that our estimates of the long-term cost reductions in nuclear power have been rather conservative. It was not intended in this study to determine which type of power reactor is best suited to Finland. The nuclear power costs refer to some well known types merely as examples. When the next study is undertaken at a later date, with technical and cost data based on more experience with nuclear power plants, the question of the best use of the country's own uranium resources should also be approached.

2. ENERGY

The development of the total energy production in Finland during the period 1938-58 is summarized in Table 2.11).

TABLE 2.. 1.

Energy Production in Finland (equivalent 1000 metric tons of coal) ^

Energy source 1938 1948 1951 1955 1958 Water Power 1202 1044 1898 2993 3273

Peat 12 110 112 77 50 Industrial and wood wastes 1190 920 980 1280 1350 Marked wood 1350 1550 1530 1570 1570 Household wood 2400 2400 2400 2490 2490 Total domestic fuels 4952 4952 4980 4980 5022 5022 5418 5418 5460 5460

Solid fuels 1830 2050 2130 2467 2075 Liquid fuels 372 580 917 1820 2450 Total imported fuels 2202 2202 2630 2630 3045 3045 4287 4287 4525 4525

Grand total 8356 8654 9965 L2697 13258

1) The following conversion factors have been assumed Water power 1 kWh = 0. 5 kg coal Firewood 6 m3 =1 ton " Oil 1 ton =1.6 tons " Peat (dried) 1 ton =0.5 ton " Industrial and wood wastes 13 ms = l ton "

It may be seen that the average annual increase is about 4%. This is comparable to the European2^ average (44% over the period 1948-1955). It corresponds also to the average increase of the Gross National Product over the same period. Expectations are that the increase will continue in the next decade at the same rate. The production of hydro power has increased by approximately 10% per year and constitutes today about 1/4 of the total energy production. About 40% is accounted for by domestic fuels, while imported fuels constitute the remaining 35%.

1) Report of the Advisory Commission for Industrialization, March 11; 1959. 2) Excluding USSR.

11 The distribution of the energy consumption between various consumer groups is shown in Table 2.2. for the year 19551).

TABLE 2.2.

Distribution of energy consumption between various consumer groups in 1955 (equivalent 1000 metric tons of coal)

Consumer group Water power Domestic fuels Imported fuels Total * Industry 2450 1650 1800 5900 46.5 Transport 20 300 1400 1720 13.5 Household 520 3470 1090 5080 40.0

Total 2990 5420 4290 12700 100.0

It is seen that 41.5% of the industry's energy needs is covered by hydro power, 28% by domestic fuels and 30.5% by imported fuels. A large proportion (82%) of the consumption for transport depends on imported fuel. In the energy balance, the share of fuels consumed for electricity production is about 5% in a mean water year. The distribution according to different fuels is shown in Table 2.3. for the year 19582).

TABLE 2.3.

Consumption of fuel for electricity production in 1958 ^

Fuel used Amount Equivalent coal (tons) °lo of total

Wood 81,700 ms 13,600 5.4 Industrial and wood wastes 980,000 m3 75,500 30.3 Peat 2,800 t 1,400 0.6 Coal 113,000 t 113,000 45.1 Oil 29,000 t 46,500 18.6

Total 250, 000 100.0

3. HYDROELECTRIC RESOURCES

3.1. Hydro potential

Hydro power has been - and still is - the most important source of electrical energy in Finland. Approximately 85% of the total annual consumption is met by hydro power in a normal year. In a dry year this percentage has been as low as 70%. The estimated hydro power potentials of the different main rivers are shown in Table 3.1. together with the capacity already developed (end 1959) and under construction.

1) Report of the Advisory Commission for Industrialization, March 11, 1959. 2) PULKKINEN, V.. Voima ja Valo (Power and Light), 10 (1959) 219. 3) Approximately 90°]o of the electricity produced thermally is accounted for by this table.

12 TORNION JOKI

^J^KUUSAMO 200 7.

/OULUJOKI Mill.kWh 2850 18000 2780 2370 OTHER WATERCOURSES 1600

VUOKSJ

8920

7820

under construction

harnessed (end 1959) TOTAL COUNTRY

Fig. 3.1. HYDRO RESOURCES IN FINLAND

13 TABLE 3.1.

Hydro power resources and development (million kWh/year)

Present annual^ To be completed River Potential 1) producibility by end 1961 (end 1959)

Kokemaenjoki 1200 960 960 Kymijoki 1650 1130 1130 Vuoksi 2300 1720 1830 Oulujoki 2850 2520 2780 Iijoki 1250 3 3 Kuusamo 200 7 7 Tornionjoki 1600 15 15 Kemijoki 5200 1270 1595 Others 1750 195 210

Total 18000 7820 8530

The majority of the rivers are supplied by large lakes or chains of lakes which also serve as storage reservoirs and help to regulate the flow. The heads available are generally low (10-20 m). The characteristics of known hydro sites have been shown in Table 3.2.

3.2. The character of hydro resources in Finland The country is in general rather flat, the only points reaching above 500 m being situated in the extrems north. The southern part of Finland is very rich in lakes, but most of them are only 70-100 m above sea level. In the central part the lakes are situated somewhat higher, 120-250 m above sea level, but they are not as numerous as in South Finland. The discharge of the rivers is comparatively small during the winter months from November to April. The flood caused by the melting of snow occurs in southern parts in April and May and in northern parts about one month later. The discharge of rivers may vary rather substantially from season to season. This makes regulation very important for the harnessing of hydro resources in Finland. Fig. 3. 2., which shows the flow-duration curves of the principal watercourses, indicates clearly the unfavourable character of the Kemi river in Lapland. The most important rivers have shallow banks and gentle slopes. Thus, the construction of hydro power stations usually includes rather extensive dredging and channel excavation work and, in many cases, long lateral dikes with pumping stations have to be constructed. Also provisions must usually be made for allowing log floating along the rivers when the power stations are in operation.

1) From unpublished data available at Imatran Voima Osakeyhtio. (The total of 18, 000 million kWh/year must be taken as the technical potential which can be exploited by present day construction methods. The theoretical potential has been estimated as 30, 000 million kWh/year.) 2) Annual producibility is defined as the annual energy which would be produced in a mean-water year if the energy consumption curve could be followed exactly. In Finland hydro construction has been kept at such a level that annual producibility corresponds to about 95"jo of the annual consumption, but owing to the low water availability in winter when the load is high the actual production is reduced to 85<7o.

14 TABLE 3. 2.

Characteristics of known hydroelectric sites ( > 10 MW)

Catchment Mean flow Head Constr. flow Capacity Annual producibility Year of Water Course Site area km2 mVs m m3/s MW Million kWh/year commissioning

Vucksi 61,000 Imatra 579 24 780 155 1,000 1929-51

Tainionkoski 579 7. 8 600 40.5 300 1949

579 7. 8 200 13. 5 20

Kuurna 235 7-8 450 25.2 115

it Kaltimo 230 10 316 24 135 1958

ti H 10 150 12 70

it Pamilo 73 49.4 120 54 240 1955

Lieksankoski 102 10. 8 170 14 78 1960

ii Pankakoski 102 12.5 170 16 85 (1963)

354 2, 043

Kymi River 36,500 Kuusankoski 290 9. 5 420 30 180 1945

II Mankala 230 8.1 370 25 130 1949

II Ahvenkoski 99 11. 5 250 23 115 1933

II Keltti 290 6.1 360 16. 5 '110 1939

it Anjala 292 11. 1 177 15. 8 122 1922

292 11.1 240 15 82

•i Myllykoski 291 6.8 360 14 120 1929-35

ti Korkeakoski 23 13 95 10 57 1927-45

n ii Pernoo 118 6.6 180 10 60

II Vuolenkoski 227 3. 5 370 10. 5 55 1958

170 1, 031 TABLE 3.2. (cont'd)

Catchment Mean flow Head Constr. flow Capacity Annual producibility Year of Water Course Site area km2 m3/s m m3/s MW Million kWh/year commissioning

Kokemaki River 26, 000 Harjavalta 213 26.5 360 73.5 400 1939

„ Melonsyostava 138 19.5 300 50 200

• • M it Kolsi 213 12.3 240 26 150 1945

it »t 11 •• 213 120 13 20

Hartola 172 6.1 254 12. 6 60 1950

ti it Aetsankoski 175 8-9 360 23 104

198 934

Oulu River 20, 000 Pyhakoski 245 32 450 120 610 1949-51

H (at Vaala) Nuojua 230 22 450 80 400 1955

ti Utanen 233 15.7 450 55 280 1957

Palli 245 13,9 450 ' 50 260 1953-54

ii Jylhama 224 11-14 450 50 220 1950-51

Montta 245 12 450 40 230 1957

it Merikoski 250 11 400 36 200 1946-50

it Seitenoikea 83 21 160 29.5 130 1961

it it Kallioinen 58 10 140 12 43 1957

it it Aittokoski 62 26 150 37 130 1960

it Amma 43 9-16 110 14 38 1959

ii tt Leppikoski 102 12 220 22 90

546 2,631

Kemi River 50,900 Petajaskoski 500 20 600 100 500 1957

n » 500 20 900 50 160 TABLE 3.2. (cont'd)

Catchment Mean flow Head Constr. flow Capacity Annual producibility Year of Water Course Site area kntf ms/s m m3/s MW Million kWh/year commissioning

Kemi River 50,900 Pirttikoski 290 24 500 110 505 1959-60

tt Juukoski 285 26 500 100 440 (1963)

ft Valajaskoski 485 11 750 70 340 (1960-61)

Taivalkoski 530 15 900 110 500

II ti Ossauskoski 510 15 900 110 475

if ft Isohaara 530 12 460 46 258 1949

11 it 530 12 460 24 127

tt Vanttauskoski 300 16 500 65 330

tt tt Sierila 310 9 500 35 165

tt tt Jumisko 16 96 36 30 100 1953

II tt Pahtakoski 94 13 140 15 50

ft tt Jaapakoski 300 11 500 44 210

(i tt Permantokoski 36 22-25 60 11 50 (1962)

tt tt Ounasjoki 40-130 150 120 600

Kitinent+ Luiro 50-100 60 60 250

1,100 5,060

Ii-River 14,000 Pahkakoski 131 20 200 34 176 (1962)

ft tt Illinkoski 163 14 74

tt tl Raasakka 163 13 250 30 158

" Maalismaa 30 158

•• Kierikki 30 157

It ft Haapakoski 27 140

Konttikoski 21 110 TABLE 3.2. (cont'd)

Catchment Mean flow Head Constr. flow Capacity Annual producibility Year of Water Course Site area km2 m3/s m m3/s MW Million kWh/year commissioning

Ii-River 14, 000 Pudasjarvi 12 75

Kurelampi 12 73

Tirinkoski 11 65

221 1,186

Kitka River Kitka 20 97 70 56 143

Kuusinki River Kiukaankorva 11 30 8 41

Raatekoski 11 60 16 48

80 232

Tornio River 40, 000 240 1, 200

Total 2,910 14, 320 About 45% of the total hydro potential of the country is situated in Lapland. Particularly in this part of the country the harnessing of hydro power is hampered by high construction costs, poor regulation possibilities and remoteness which lead to high transmission costs and large losses. Also, the considerable hydro resources of the border rivers may for various reasons remain undeveloped. Lapland has very few lakes and the head is usually small. In order to improve the regulation possibilities it is necessary to build artificial lakes which, however, are rather expensive and can be economic only if their regulation capacity is used in several successive power stations.

Kemi river The main hydro power source in Lapland is the Kemi river, which at the mouth has a mean flow of 520 m3/s. The duration of the flow under natural conditions is very poor (Fig. 3. 2.). Only one larger natural lake, Kemijarvi, is available for regulation. To improve the flow duration plans of several artificial lakes are being considered, the most important of which are Lokka and Portti- pahta on the upper course of the tributaries Luiro and Kitinen. On the tributary Ounasjoki, it is possible to build a third artificial lake, Tepasto. A chain of small natural lakes, Suolijarvet, is already regulated by the Jumisko power station.

Fig. 3.2. FLOW DURATION IN THE MAIN RIVERS DURING THE PERIOD 1911-50

19 On the main Kemi river (total head about 140 mj a total of nine power stations will be constructed, which without artificial reservoirs would produce 3026 million kWh/year. The surface of Kemijarvi can be regulated up to 7 m, which gives a regulation capacity of 100 million m3. In the nine power stations this corresponds to an energy addition of 325 million kWh/year. The artificial lakes Lokka and Porttipahta can have a storage capacity of 3000 million m3 giving 114 million kWh/year of extra energy in the main river stations. The Tepasto reservoir would have a volume of 1200 million m3, which adds 56 million kWh/year to the producibility of the nine power stations. Several smaller reservoirs have also been planned (total capacity about 2000 million m3, 93 million kWh/year). All these additions, together with the possibility of adding extra units to stations when regulation is improved, increase the production of the main Kemi river to about 3800 million kWh/year. The construction of these artificial reservoirs justifies the harnessing of the tributaries of Kemi river, the most important of which are Luiro and Ounasjoki. Because of rather constant slope and difficulties in building artificial reservoirs, Ounasjoki (head about 216 m) is not very attractive from the point of view of power station construction. Several small steps are to be used, the maximum capacity of one station being only about 40 MW. Luiro (total head about 107 m) is the most favourable of the tributaries of Kemi river, especially as to the regulation possibilities. With the artificial lake Lokka, the biggest station Angelvaara (head 50 m) may be suitable for daily regulation. The planned capacities and producibilities of the main Kemi river and its tributaries, after the regulation is completed, are:

Main Kemi river 820 MW 3800 Ounasjoki 220 " 930 Raudanjoki 30 " 150 Kitinen 20 " 80 Luiro 100 " 300 Kemihaara 50 " 220 Jumiskonjoki 30 " ' 80

Total 1270 MW 5560 million kWh/year

Tornia and Muonio rivers

The border rivers Tornionjoki and Muonionjoki have theoretically rather large potentials, because of the large mean flow (at the mouth of Tornionjoki 360 m3/s). On the other hand the head is comparatively small and the Tornio river area, in particular, is too densely populated to allow higher steps to be artificially created. The natural lakes Tornionjarvi and Tengelionjarvi can be used as reservoirs. Their capacities are, however, not sufficient and artificial reservoirs are to be built as on Kemi river. The utilization of these hydro resources is studied in co-operation with Sweden and Norway. The share of Finland of the Tornio and Muonio rivers as well as the two tributaries is quoted below:

20 Tornionjoki 180 MW 1000 million kWh/year Mu onion joki 100 " 500 Lataseno 50 " 240 Tengelionjoki 20 " 60 " Total 350 MW 1800 million kWh/year

Teno river and Inari area The hydro resources of the northernmost part of Finland are rather small and will probably remain undeveloped because of the remote location. Only the small rivers of the Inari area may be developed later. The hydro potential of this area is shown below: Teno river 120 MW 600 million kWh/year Naatamonjoki 25 120 Inari area 100 450 Tulomajoki 5 30 Total 250 MW 1200 million kWh/year

Oulu river The average flow of Oulujoki at the mouth is 254 m3/s, and the total head of the main branch is about 120 m. Eight power stations have been constructed on the main Oulujoki having a producibility of 2200 million kWh/year. The Hyryn- salmi chain will also have several power stations with a total production of 380 million kWh/year and the Sotkamo chain has some smaller stations producing about 160 million kWh/year. The character of the watercourse of Oulu river is rather favourable as regards regulation possibilities. About 11% of the whole catchment area is covered with lakes, the most important of which is Oulujarvi (about 900 km ). As a result of some excavation and dredging work Oulujarvi forms a reservoir. in which the water level can be changed by 2.7 m corresponding to a regulation capacity of 2300 million m3. In the power stations of the main Oulu river this means an energy addition of some 280 million kWh/year. The upper reaches of the watercourse Oulujoki consist of two chains of lakes, those of Sotkamo and Hyrynsalmi. In the Sotkamo chain one reservoir is formed by several lakes having a total storage capacity of 415 million m3 and another is the lake Ontojarvi with ail equal storage capacity. Some smaller reservoirs are also planned totalling 700 million m3. The main reservoir in the Hyrynsalmi chain is the lake Kiantajarvi, which has a storage capacity of 710 million m3. After completing the regulation programme of the Oulujoki watercourse the total capacity of the reservoir will be about 4800 million m3, which corresponds to two thirds of the average annual flow of the whole watercourse. This means that the storage capacity is big enough to make regulation possible over several years.

Vuoksi river For catchment area and flow Vuoksi is the biggest river in Finland. The catchment area is about 61, 000 km2, of which more than 10, 000 km2 is covered

21 with lakes. Due to this large area of lakes the flow in Vuoksi is better regulated than other rivers in this country (Fig. 3.2.). The average flow during the period 1911-50 was 579 m3/s. The Vuoksi watercourse has several big lakes: Saimaa, Kallavesi, Orivesi, Pielinen, each of which is of the order of 1000 km2. The most important of these is the immediately above the main Vuoksi river situated lake Saimaa (76 m above sea level). The regulation of this lake was made possible in 1954 by rather extensive dredging works at the upper course of Vuoksi. The banks of the lake are, however, too shallow for more than 1.3m regulation of the water level, which corresponds to about 6% of the energy of Vuoksi. The lower limit of the water level is determined by the requirement of securing the ship traffic and log floating on the lake. The regulation of Vuoksi is carried out by means of the Tainionkoski power station according to data on the snow layer thickness in the catchment area and the water level of the upper lakes Kallivesi and Pielinen. The regulation possibilities are nowadays rather good allowing for seasonal as well as weekly regulation. The Vuoksi river is in a very Unique position because only a very short stretch of the upper course belongs to Finland, the rest belonging to USSR since the last war. Thus, according to some agreements the needs of the Russian power stations must also be considered in the regulation of the river, which makes it impossible to cover any temporary load peaks in the Finnish network by the Vuoksi power stations. The Finnish share of the Vuoksi river is harnessed by two power stations, one of which is the biggest station in the country, Imatra, with about 1000 million kWh/year production. The gain obtained by the regulation in the two power stations is estimated to about 112 million kWh/year. On the upper reaches of the Vuoksi watercourse several smaller power stations are built to utilize the heads between the different lakes.

Kymi river

The total head of Kymi river is about 75 m, which is divided into several small steps of 3-12 m. The mean flow is about 300 m3/s and the duration is rather good due to the big lake Paijanne, which serves as a storage in this watercourse. The production of the power stations is about 900 million kWh/year.

Kokemaki river

The total head of 95 m of Kokemaki river is harnessed in eight steps, which produce about 900 million kWh/year. The mean flow at the mouth is 213 m3/s. About 12% of the catchment area consists of lakes, the most important of which are Nasijarvi, Vanajavesi and Pyhajarvi. The increase of the primary energy due to regulation can be of the order of 30 million kWh/year, but satisfactory operation is rather difficult because the storage is formed by several successive basins.

22 4. IMPORTED FUELS It is seen in Chapter 2 that imported fuels play a significant role in the total energy consumption of Finland. In the generation of electricity, however, their share has been rather small. Table 4.1. shows the consumption of imported fuels for electricity production in the recent years.

TABLE 4.1.

Imported fuels used in electricity generation 1) (1000 tons of coal equivalent)

Year Coal Oil Total Total "jo of total fuel import

1955 54 28 72 1.7 1956 271 143 414 9.4 1957 175 101 276 6.2 1958 113 46 159 3.5

The share of imported fuels in electricity generation has been less than 10%, even in a dry year like 1956. In Finland the imported fuels include coal and oil. Natural gas has not been available, but some pipelines are under construction in the Baltic area of USSR and the utilization of natural gas may become possible. At present the fuel imports amount to 15-18% of the total import. When electricity production by thermal means expands in the next decade, the share of imported fuels in the total imports is also expected to rise. It is generally believed that the balance of payments will be adversely affected if this ratio exceeds 25%. It is necessary, therefore, that the fuel imports should not go up faster than total imports.

4.1. Coal Coal has been dominant among the imported fuels. The total quantity and the distribution of coal imports to Finland in recent years is shown in Table 4.2.2).

TABLE 4. 2.

Coal imports

Year Total quantity Poland USSR England Western Europe USA (103 tons) °lo % °lo 1o %

1950 1458 92 - 4 4 - 1951 1991 73 - 12 5 10 1952 2241 71 - 12 8 9 1953 1702 94 - 6 - - 1954 1697 81 4 8 6 1 1955 2076 73 3 7 10 7 1956 1995 72 8 6 3 11 1957 2403 69 9 3 2 17 1958 1874 70 21 3 1 5 1959 2368 68 29 2 1 -

1) PULKKINEN, V. , Voima ja Valo, No. 10, 1959. 2) PONTYS, A., Suomen Polttoainehuolto, Finnish Technical Society, Helsinki, 1959.

23 1200

1000

FM/Ocal

800

600

400

200

0 1950 51 52 53 54 55 56 57 58 59 1960 YEAR

Fig. 4.1. PRICE OF COAL AND FUEL OIL IN HELSINKI (FREE IN STATION) Coal, Crushed Polish, Annual Report of Ekono 1959. Oil, No. 4, R. Christensen, Suomen Polttoainehuolto, Finnish Technical Society 1959

The largest share of coal imports is that of Poland. The share of other countries is fluctuating, mainly due to price and freight cost levels. Fig. 4.1. gives the price of crushed Polish coal during the last decade. This is the coal mostly used in the electrical power industry. The price is "free in Bunker" of a station in Helsinki including freight, taxes, unloading and handling charges. In the interior of the country the corresponding figures have been 100-150 FM/Gcal higher due to the inland transport charges. Because of inflation (some 40% since 1950) and the devaluation in 1957 (about 40%) the prices in Fig. 4.1. are not directly comparable. In any case the increase in price during the times of shortage (1951-52 and 1956-57) and a corresponding decrease in times of surplus (1959-60) may be noted. Average prices of coal, used in the back-pressure and condensing plants throughout the country, have been in some of the past years as shown in Table 4.3.1).

TABLE 4.3.

Average price of coal used in power plants throughout Finland

Year Condensing Back-pressure (FM/Gcal) (FM/Gcal)

1955 890 860 1956 943 1040 1957 1050 1120 1958 820 945

1) PULKKINEN, V., Voima ja Valo, No. 10, 1959.

24 The difference in the prices of coal used in back-pressure and in condensing plants is mostly due to the more remote location of the former coupled with smaller quantities bought. For 1959 the statistics are not yet available, but Fig.4.1. predicts a considerable decrease, say to 600-700 FM/Gcal, for that year. The present low f. o. b.-prices (about $ 6/ton) may allow a figure of 500- 600 FM/Gcal to be reached in 1960 for the average price of coal.

4.2. Oil Table 4.4. reviews the situation regarding the imports of some main oil products during the last decade.

TABLE 4. 4.

Imports of oil products (1000 metric tons)

Year Crude oil Fuel oil (incl. Diesel oil) Gasoline West East West East West East

1950 - - 122 36 156 86 1951 - - 139 40 165 100 1952 - - 184 85 166 117 1953 - - 32 280 46 256 1954 - - 1 495 8 329 1955 - - 74 578 10 349 1956 - - 312 596 13 339 1957 126 90 519 708 14 331 1958 412 472 52 838 14 98 1959 226 864 6 726 16 18

"East" in this table includes USSR and Romania and "West" mainly England and the United States. Since the first refinery in Finland was put into operation in 1957, the import of crude oil has grown rapidly. When considering electricity production, fuel oils are the most important. These are partly produced in the domestic refinery and partly imported. Fig. 4.1. also shows the fuel oil prices during the last decade. The indicated figures (free in station in Helsinki) show a character similar to that of coal. It should be noted that here again the prices are not exactly comparable. Taxes on oil have varied considerably in the past (13-30%), whereas those for coal were nonexistent until 1959. The freight costs of oil have also fluctuated remarkably (30-100% of f. o.b.-price). In fact, the f.o.b. -price of oil has been more stable than that of coal. At present coal and oil are equally taxed (13%) and the price of oil is some 35% higher. This gives a significant advantage to coal and thus in electricity generation the use of oil is rather limited.

5. DOMESTIC FUELS 5.1. Peat It is estimated that about 30% of the area of Finland is covered by marches. The central part of the country, in particular, has very extensive peat re-

25 MARSH AREAS AS PERCENTAGES OF TOTAL AREA

Fig. 5.1. THE REGIONAL DISTRIBUTION OF MARSH IN FINLAND

26 sources. Fig. 5.1. shows the regional distribution of marsh (marsh area in percentage of the total area). The total amount of peat in the country is estimated to approximately 100 x 109 m3 . A substantial part of this, however, is unsuitable for large scale operation owing to the small deposits, small thicknesses, poor quality of the peat or remote location. For instance, in the area north of Rovaniemi the summer is not long enough to make peat production economical. Also, any marsh area with a peat layer thickness less than 2 m is usually out of consideration. Taking into account these restrictions, the following estimates have been made: The area of the peat resources is about 3000 km2, containing some 6 - 109 m3 of peat. This corresponds to about 600 million tons of air-dry peat, or about 300 million tons of coal equivalent. Approximately 10% of the resources are thoroughly studied by the Geological Research Institute (Table 5.1.). In addition to this the existing peat industry has reserved resources of some 12-15 million tons.

TABLE 5.1.

Peat deposits in Finland

Site of the deposit Million m3 of peat

I Vaasan Laani: Alavus 8.6 Jalasjarvi 60.1 Jalasjarvi-Peraseinajoki 47.8 Kauhajoki 71.3 Kauhava 1.8 Keuruu 11.8 Lapua 9.1 Nurmo 2.1 Pihlajavesi 14.4 Teuva 14.4 Toys a 1.9 Virrat 9.2 Ahtari 3.1

Total 255. 6

II Kymen laani: Miehikkaia 1.6 Pyhtaa 37.4 Sippola 46.4 Vehkalahti 5.8 Virolahti 0.8

Total 92. 0

III Oulun laani; Nivala 1.2 Sonkajarvi 2.4 Vaala 66.1 Vuolijoki 20.1

Total 89.8

IV Turun ja Porin laani: Ikaalinen 1.7 KankaanpaS 1.5 Kihnio 5.6 Parkano 42.7 Pomarkku 1.3

Total 52.8

27 TABLE 5.1. (cont'd)

Site of the deposit Million m3 of peat

V Hameen laani* Hattula 6.5 Hameenlinna 5.5 Janakkala 11.6 Kuril 3.0 Renko 2.2 Vanaja 20.1

Total 48.9

VI Kuopion laani; Tohmaj&rvi 43.4

Total 43.4

Total for the country 582.5

The most important peat producers are listed in Table 5.2.

TABLE 5.2.

Largest peat producers in Finland

Name of the company Peat production in 1957, tons

Kainaston Polttoturve Oy, Kauhajoki 20, 100 Kymin Osakeyhtio, Sippola 31, 900 Suo Oy, Kihnio-Parkano-Vaala 39, 100 The State Railroad, Joutseno 22, 900

The role of peat in electric energy production has been of minor importance. Table 5.3. lists the quantity of peat used annually in condensing and back- pressure plants since 1940.

TABLE 5.3.

Peat used in power production

Year Condensing power Back-pressure power (tons of peat) (tons of peat)

1940 5320 150 1945 412 883 1950 767 1218 1955 151 893 1956 4600 2400 1957 1100 3698 1958 400 2414

The use of peat has recently been considered for power production in central power plants. The peat.consumption of a 60 MW power station is of the order of 200, 000- 300, 000 tons/year. Thus, the local peat deposits necessary for 30-50 years consumption in such a station are 6-10 million tons of air-dry peat. In order to reduce the transportation costs it is important that a concentrated peat source of this size is available. The most concentrated peat deposits are shown in Table 5.4.

28 TABLE 5. 4.

Largest peat concentrations

Site of a concentrated peat source Million tons of air-dried peat

Pelso 10 Ylivieska-Iisalmi 4 Kauhajoki-Jalasjarvi 14 Parkano-KihniiJ 7 Alavus-Pihlajavesi 4 Tohmajarvi 5

5.2. Wood

Finland is very heavily wooded. An area of 22 million ha, corresponding to 71% of the total area of the country, is covered by forests. It is therefore natural that wood should be used as a domestic and industrial fuel. The consumption of commercial and household wood fuel was 24.5 million m3 in 1957, thus corresponding to some 30% of the total energy produced. The estimated resources of wood available for energy production are about 27.5 million m3/year. The development of the wood industry for other purposes, however, will probably reduce in a few years the amount of wood available for energy production to about 20 million m3/year. To compensate for this reduction small wood has to be used more than in the past. In the near future, the increase in fuel consumption will correspond to 2-4 million m3 of wood a year. Thus, it is obvious that the available wood resources cannot meet the rapidly growing need of fuel. Wood has been used on a rather small scale for the generation of electric energy (Table 5.5.), the more extensive use being hampered by the high cost of wood as fuel and by the difficulties in transportation. On the basis of the imported fuel prices in 1958, it is estimated that in order to be competitive in a condensing plant the price of wood ought to be around 500 FM/m3, whereas since 1955 prices have been 1200-1400 FM/m3.

TABLE 5.5.

Wood used in power production

Year Condensing power; m3 of wood used Back-pressure power; m' of wood used

1940 245, 200 103, 218 1945 206,439 33,863 1950 65,078 72, 178 1955 23, 973 29, 286 1956 54, 315 59, 749 1957 45, 104 39, 734 1958 9,341 72, 357

5.3. Industrial wastes

A survey carried out by Ekono among 1100 industrial establishments in Finland has shown that wastes from the wood-working and paper-pulp industries are being used as fuel in increasing amounts. This is shown in Table 5. 6.

29 TABLE 5.6.

Wood wastes and industrial wastes used as fuel

Year Wood wastes Waste liquor

1956 2, 513, 600 m3 n. a. 1957 2,647,700 " n. a. 1958 2, 749, 800 " 2, 020, 000 m3

The quantity of waste used presently amounts to over 1 million tons of coal equivalent. The breakdown is shown in Table 5.7.

TABLE 5.7.

Breakdown of industrial wastes used as fuel

Waste (Tons of coal equivalent)

Saw mill wastes 230, 000 Plywood wastes 58, 000 Waste wood 25, 000 Wastes of the pulp industry- - sulphate lye 580, 000 - sulphite lye 200,000 - peeling wastes 33, 000 - waste gase 25, 000 Wastes of paper industry 8,000

1, 159, 000

An important development in the recent years has been the use of the "red liquor" obtained from the acid process in the pulp industry. Up to 75% of this is presently being burnt as fuel. The "black-liquor" obtained in the alcali process has been burnt for some time in order to recover some by-product chemicals. There has been no great changes in this field. For the production of electricity some timber-mill wastes have been used. This is shown in Table 5.8.

TABLE 5. 8.

Timber-mill wastes used in power production (m3)

Year Condensing Back-pressure

1940 980, 000 154, 000 1945 617, 000 64,000 1950 818,000 220, 000 1955 929,000 290,000 1956 718, 000 289,000 1957 747,000 270, 000 1958 657,000 322, 000

Modern industrial thermal plants are usually equipped with boilers which can use a large variety of fuels, including mixtures.

30 5.4. Nuclear fuels The geological structure of Finland suggests the occurrence of uraniferous minerals. However, because Finland has had no need for nuclear raw materials, prospection has proceeded rather slowly. Thus, information about the uranium resources of the country is very limited at the moment. The Geological Research Institute has carried out systematic air-borne prospection of mineral resources whereby radioactive disturbances were re- corded. These air-borne surveys must, however, be followed by more detailed ground work. In addition to the Geological Research Institute a few private organizations and Imatran Voima Oy are also working on uranium prospecting. Atomienergia Oy, a private company, has been engaged in prospecting work since 1956, carrying out systematic boulder stone search and radon measure- ments. In August 1958 this work resulted in a discovery of promising uranium ore deposits in Eno, where in April 1960 the company initiated production in Paukkajanvaara. The annual production is at present about 30, 000 tons of ore containing approximately 0.2% of U3O8. The company exports concentrates enriched up to 25-30% of U. Bigger production with higher concentrations is planned. Other ore reserves so far investigated by Atomienergia Oy are rather limited. The present mine is, however, located in the zone between Kaltimo and Koli where several promising indications have been encountered. Further explorations are being carried out. Promising uranium ore deposits are also reported by Perno Oy in Pernaja and Imatran Voima Oy in Askola. The discovery in Askola has led to the construction of a pilot plant for experimental recovery of uranium. These experi- ments on leaching, precipitation, and purification of the yellow cake to reactor grade metal by liquid-liquid extraction are now completed. Elsewhere in the country radioactive disturbances and other indications have been found which, however, have not led to detailed investigations. The State Research Institute has investigated the uranium recovery tech- nique in co-operation with Atomienergianeuvottelukunta. The metallurgical methods for fuel element fabrication have also been studied. In conclusion it can be stated that the nuclear raw material resources of Finland are still little known. However, experience gained so far encourages further prospection and gives the promise that nuclear fuel needs may eventually be met by national production.

6. PRESENT POWER SITUATION 6.1. Organization of the power supply industry The Finnish power supply industry consists of several companies, some of which are state-owned. However, all companies operate as private enterprises. There is no nationalization in the power supply industry but the networks of the various companies are interconnected at many points. This makes co- operation on a national scale possible. The power supplying companies can be divided into three groups, namely 1) companies in which the state is the principal stockholder, 2) companies which have private companies as stockholders and 3) industrial companies and municipalities which generate electricity mainly for their own use.

31 The first group is formed by the company Imatran Voima Osakeyhtio with its affiliated companies Oulujoki Osakeyhtio and Kemijoki Oy. These three represent roughly 45% of the total power production of the country. The second group consists of smaller companies like Lansi-Suomen Voima Oy and Pohjolan Voima Oy which in addition to the power stations have also a considerable distribution network. The companies mentioned above produce about 5% of the total production each, the other companies being still smaller. The big paper and pulp companies, e.g. Kymin Oy and Enso-Gutzeit Oy, and municipalities like Oulu and Helsinki cities form the third group of electricity producers. The main part of their production is used by their own plants or consumers to cover the need of process energy or lighting. The former type of consumption has usually the character of a base load. The paper and pulp industry accounts for about one half of the total consumption of the country. On the other hand it produces some 40% of its own needs and thus the consumption of this industry covered by external sources represents about 30% of the total consumption. Fig. 6.1. shows the production of the principal power supply companies in 1958.

Fig. 6.1. THE PRODUCTION OF THE BIGGEST POWER SUPPLY COMPANIES IN 1958

32 6.2. Present installed capacities At the end of 1959 the number of hydro power plants was 220 and the installed capacity about 1400 MW. According to the size of the installed units the hydro power stations are distributed in the following way:

TABLE 6.1.

Hydro units (1959)

Installed capacity in MW Number of stations Total capacity inMW

less than 0. 5 118 25 0.5-5 64 82 5-50 30 609 more than 50 690

Total 220 1406

The number of condensing units at the end of 1959 was 123 and the total installed capacity 570 MW. Table 6.2. shows the distribution of units according to size groups as well as the units installed since 1950.

TABLE 6. 2.

Condensing units (1959)

Size Number of units Total capacity Number of units installed since Total capacity (MW) (MW) 1950 (MW)

5-50 29 377 12 202 1-5 72 178 12 37

below 1 22 14 -

Total 123 569 24 239

The new units installed since 1950 have almost completely replaced the obsolete pre-war units. These have not, however, been dismantled and are useful as emergency reserve capacity. For instance in 1959 (which was considered a dry year) the maximum load taken up by condensing plants (330 MW) was above the capability of the new units. The total production of the condensing units in 1959 was 1021 million kWh, corresponding to a load factor of 35%. At the end of 1959 the total number of back-pressure units was 81 and the total installed capacity about 400 MW. Table 6.3. shows the distribution of units according to the size groups of the total capacity as well as the units installed since 1950.

TABLE 6.3.

Back-pressure units (1959)

Size Number of units Total capacity Number of units installed since Total capacity (MW) (MW) 1950 (MW)

5-50 30 310 18 217 1-5 34 78 19 44 less than 1 17 10 10 6

Total 81 398 47 267

33 A substantial part of this capacity consists of old units which have high fuel costs. As a matter of fact the new units installed since 1950 are taking at present virtually the total back-pressure load. E.g. in 1959 the maximum load was about 230 MW and with a production figure of 1290 million kWh its load factor was around 65%.

Fig. 6.2.

APPROXIMATE DURATION OF NATIONAL LOAD IN 1958-59

6.3. Load in 1958-59

The duration of the national load is rather good for economy in power generation. Approximate load durations for total country are shown in Fig. 6. 2. for the two past years 1958-59. These years are rather good examples of a normal (1958) and of a dry year (1959). The total primary production was 7507 and 7777 million kWh/year respectively, and the hydro production 6509 and 5338 million kWh/year respectively (cf. Table 7.1.). The duration of total load is good, the utilization of the mean load being around 6000 hr a year and the total peak load amounting to 145-150% of the mean load. The duration of the back-pressure power is also good. However, that of condensing power shows a more peaky character at present. Furthermore, the condensing capacity must meet the dry year conditions, so that its utilization in normal years is low (500-1000 hr a year). Fig. 6.3. gives the daily load variation in a winter day (critical season).It can be seen that the daily load regulation is carried out almost entirely by hydro power. The thermal plants are running with nearly constant power.

34 Fig. 6.3. NATIONAL DAILY LOAD IN A WINTER DAY

Fig. 6.4. ELECTRICITY PRODUCTION OF FINLAND 1958-59 (MONTHLY AVERAGES)

Fig. 6.4. shows the monthly load variations in the two years 1958-59. Hydro power cannot fully meet the seasonal load variations. The need of thermal power is greatest in the critical season, i.e. at the end of December, and during the spring and summer the net storable hydro power is spilled or used in electrical boilers. The figure indicates that the differences between normal and dry years are mostly quantitative and not qualitative: the need of thermal power is increased and the available hydro power and surplus is decreased in a dry year.

35 6.4. Operation of the system The hydro system of the country possesses fairly good regulation possibili- tes. In practice, the regulation lakes are filled during the spring and summer when the water flow is high and the load is rather low. In the autumn the incoming water flow due to rainfalls is usually big enough to cover the increasing power demand. In winter the flow is rather low whereas the load is high. Thus the storage reservoirs are emptied to be ready to fill again with the spring flood of melting snow. As an example of operation of a large network in Finland Figs. 6. 5.-6. 7. present the situation in the network of Imatran Voima Osakeyhtio in 1958-59. Fig. 6.5. shows the practice already mentioned in operation of storage lakes. In 1959 the spring and. summer were very dry and consequently the hydro producibility in autumn was low. From Fig. 6. 6. it can be seen, that this company was able to meet its load in a normal year (1958) entirely by hydro. In a dry year (1959) there has been production by condensing power as well. When the condensing capacity of the company is not sufficient to meet the dry year load the company purchases power from other thermal plants (back-pressure and condensing). In normal years Imatran Voima Osakeyhtio provides some of the needs of these companies with her hydro power (notations "substituting condensing" and "substituting bapk-pressure" in Fig. 6. 7.). For instance a back- pressure plant uses some of the water surplus of Imatran Voima for substituting for its electricty and heat needs ("substituting back-pressure" and "electrical boilers") in a normal year and provides for all its needs when surplus is not available (dry year). It is to be noted that although the condensing plants are mainly to supplement the hydro power, they are in practice run with constant capacity when needed, and the load variations are taken by the hydro plants. As to the operation of the storage lakes, there has been some experience in the co-operation of Saimaa and Oulujarvi sincevabout 10 years. The general trend is to adjust the use of the two water storages and of the power stations connected to them in such a way that both of the lakes can be filled up during the spring flood and autumn rains in order to take as much of the winter load as possible. Depending on the different flow and rainfall characteristics of these two watercourses, it is sometimes necessary to use mainly the Oulujoki power stations and store in Saimaa and vice versa. This kind of co-operation between storage reservoirs which are situated far from one another requires, of course, a well-developed transmission system. Since the beginning of 1959 there has also been some co-operation with Sweden. Up to now the energy exchanges have been rather small, appearing mainly in high flow times when the imported electricity has been stored in lakes or used in electrical boilers. It is difficult to predict to which extent the co-operation with Sweden will be used in the future, but at least the export from Finland cannot be very large. In this connexion it may be mentioned that co- operation has also been established between Denmark and Sweden and will soon be initiated between Norway and Sweden as well.

6.5. Transmission network The transmission network which extends practically over the whole country, makes the interchange of energy between the various parts of the country possible. In 1960 the network includes 760 km of 400 kV lines, 1400 km of 220 kV lines and 4000 km of 110 kV lines. Private power supply companies and private

36 Million kWh 1958 1959

VUOKSI III IV V VI VII VIII IX X XI XII I II III IV V VI VII VIII IX X XI XII Fig. 6.5. ENERGY CONTENT IN STORAGE LAKES (IMATRAN VOIMA SYSTEM)

1958 1959

Fig. 6.6. PRODUCTION (IMATRAN VOIMA SYSTEM)

Fig. 6.7. CONSUMPTION (IMATRAN VOIMA SYSTEM)

37 Fig. 6.8. POWER PLANTS AND HIGH TENSION TRANSMISSION LINES IN FINLAND

38 industry own about 1900 km of the 110 kV lines the rest being owned by the state power company, Imatran Voima Osakeyhtio. The transmission network of the country consists of two characteristically different parts: the 400/220 kV system, which takes care of the long-distance transmission of the northern hydro power, and the 110 kV (partly 220 kV) system for collection and principal distribution of power (Fig. 6. 8.). The 400/220 kV system, which in 1960 consists of one 400 kV circuit and two 220 kV circuits, is able to transmit about 1000 MW from Northern to Southern Finland. This is estimated to be adequate until the constructed hydro power of Northern Finland comprises 7500 million kWh/year, or the electricity consumption of the whole country has increased to 20, 000 million kWh/year. If the need of power transmission grows still further, the transmission capacity can be increased first by building another 400 kV line (capacity 1600 MW) and afterwards by providing the lines with series condensers (transmission capacity 2200 MW). Thus, one 400 kV line would be sufficient in the 400/220 kV system, at least up to 1970 and, possibly, even later on. Also, in the main distribution network any substantial additions are not expected until after 1970. It is considered that, if new condensing plants are properly located, there will be no areas with a large power deficit. The distribution network of Central Finland will, however, have to be reinforced, unless a nuclear power station is placed in this area, Similarily, thermal power stations of 200 MW size will call for 220 kV connexion to the principal network from the point of view of running stability.

7. PAST GROWTH OF POWER CONSUMPTION AND ESTIMATES OF FUTURE NEEDS Table 7.1. shows the production and consumption of electricity for each year during the period 1950-1959. Fig.7.1. illustrates the increase in production over the same period.

TABLE 7.1.

Production and consumption of electricity in Finland during the period 1950-59 (million kWh)

P R O D U C T I O N C O N S U M P T I O N

Year Hydroi) Back pressure Condensing^) Total Prime Electric boilers^) Transmission losses

1950 3650 343 168 4166 3201 542 423 1951 3864 416 329 4609 3698 448 463 1952 4261 338 169 4768 3738 525 505 1953 4979 289 135 5403 4189 654 560 1954 4876 540 277 5693 4799 300 594 1955 6190 475 164 6829 5514 633 682 1956 5202 860 583 6645 5854 156 635 1957 6616 715 368 7699 6441 566 692 1958 6960 740 258 7958 6768 451 739 1959^ 5542 1294 1029 7865 7047 88 730

1) In 1959 includes 116 million kWh imported from Sweden. 2) Includes 3-8 million kWh generated by internal combustion machines. 3) This item corresponds to the consumption of the hydro energy which is produced at times of high water in order to avoid spilling and sold to industry at very low prices for making steam in electric boilers. It is regarded in Finland essentially as a heat need and is quoted separately from the prime electrical need. 4) According to preliminary statistics.

39 Million liWh year

10000

TOTAL 'TOTAL PRIME" 7500

5000

2500 TOTAL THERMAL

BACK-PRESSURE

1950 1952 1954 1956 1958 1960

Fig. 7.1. ELECTRICAL ENERGY PRODUCTION IN 1950-1959

It may be seen that by far the biggest part of the production has been by1 hydro power. In the past it has been possible to equip the power system in such a way as to meet 90-95% of the annual energy needs by hydro power in a mean- water year. However, owing to the fact that the water flow has a maximum in the late spring and summer, when the load is low, and the electrical load has a peak in winter, when water flow is at its lowest, this proportion has dropped to about 85%. Electricity production by thermal means has been about 15% of the total in a mean-water year. Approximately 2/3 of that (i.e. 10% of the total) has been generated in industrial back-pressure plants in conjunction with the production of process steam and heat. The balance (5% of the total has been produced in condensing steam plants. The surplus of hydro power, unavoidable in every hydro system with limited regulation possibilities, has been used mostly to produce steam in electric boilers during the times of high water. This low-value electricity has accounted for 5-10% of the primary production. It is possible to distinguish three types of year according to the water conditions, namely, good, mean and dry years. The production pattern in the last ten years according to these three types is shown below: PRODUCTION Type of year Examples Hydro % Back-pressure (%) Condensing % Good 1952,53, 55 90 7 3 Mean 1950, 51, 54 57,58 85 10 5 Dry 1956,59 70 17 13

40 The annual rate of increase of the prime consumption (i.e. total consumption minus electric boiler consumption and transmission losses) has varied considerably in the last ten years. This is shown in Table 7.2.

TABLE 7.2.

Rates of increase of prime consumption

Year Annual rate of increase {"jo) Increase Index (]

1950 8 1.00 1951 15.5 1.16 1952 1.1 1.17 1953 12.0 1.31 1954 14.6 1.50 1955 14.9 1.73 1956 6.2 1.83 1957 10. 0 2. 01 1958 5. 1 2.12 1959 4.1 2.2

For purposes of estimating future needs the prime production (i.e. prime consumption plus the transmission, losses) has usually been taken as a basis.

7.1. The first survey (1954) The first nation-wide estimate of the power consumption over a given period was made in 1954 and concerned a period of five years between 1954 and 1958. The estimate was based on an inquiry conducted by Imatran Voima Oy by means of questionnaires sent to all consumers of electricity whose annual consumption exceeded 0.50 million kWh, as well as to all power producing and distributing companies which supplied power to consumers not connected to the high voltage transmission network of the country1). The inquiry was addressed to 315 industrial establishments, 58 towns and associated villages and 107 distributing companies. Replies which were received stated the maximum and minimum limits of the estimated consumption. It is of interest to show here the results obtained by this survey and to compare these with the actual consumption figures for the same period. This is done in Table 7.3.

TABLE 7.3.

Estimated and actual prime production for the period 1954-58

Consumption2^ (million kWh) Year

1954 1955 1956 1957 1958

Estimated minimum 5375 6170 6690 7190 7635 Estimated average 5540 6360 7090 7700 8300 Actual 5393 6196 6489 7133 7507 Error of estimated average (°lo) +2.6 +2.6 +8. 5 +7.4 +9.6

1) Internal report by K. Hjelt, Imatran Voima Oy, February 1959. 2) Figures refer to prime power production (i.e. prime consumption plus transmission line losses) but exclude the surplus hydro power supplied to electric boilers.

41 It may be seen that the average estimates proved to be too high from 1956 on. This is partly due to two unforeseen events, namely, the general strike in 1956 and the world-wide industrial recession in 1958. It is due to a large extent to the optimistic view taken by consumers with respect to their future consumption . It became necessary in the latter part of 1957 to conduct a new survey for the period 1958-62.

7.2. The second survey (1958) Since the first survey had shown that 95% of the consumption was concentrated in approximately 100 large consumers, it was possible in the second survey, also conducted by Imatran Voima Oy, to limit the inquiry to a smaller number of consumers than previously. This inquiry was addressed to 64 industrial establishments (42 of which represented the woodworking industry), 22 towns and associated villages and 14 distributing companies. Another change from the method of the first survey was the omission of maximum and minimum limits of the estimates. It was merely required that the estimates should be based on definite plans for new construction or expansion. The results of the new estimate are shown in Table 7.4.

TABLE 7.4.

Second Estimate of consumption for the period 1958-62

Consumption (million kWh) Year

1958 1959 1960 1961 1962

Industry

Woodworking 3540 3770 3995 4510 4850 Others 1940 2050 2215 2390 2590

Total 5480 5820 6210 6900 7440

Public and private consumers

Commerce and Public Services 670 735 790 855 940 Households 675 _745 820 900 990

Total 1345 1480 1610 1755 1930

Total net consumption including own consumption of power producers 7QQ0 7490 8030 8890 9630

Transmission losses 725 760 820 890 970

GRAND TOTAL 7725 8250 8850 9780 10600

7.3. Corrections to the second survey It became obvious from a comparison of the estimated figures with actual figures for 1958 (7507 million kWh) that the estimates were again too high. It is believed that the reason lies in the fact that the effect of the two setbacks (the general strike ofl956 and the industrial recession of 1958)were underestimated.

42 A study of the rate of acceleration of the annual consumption (e.g. the increase) was made over the period 1950-57. The average acceleration obtained by the method of least mean square deviation was 33 million kWh/year. The annual increase in 1957 was 600 million kWh, so that with a constant acceleration of 33 million kWh/year the consumption in 1962 could still reach the figure of 10, 600 million kWh obtained by the survey. This target was nevertheless reduced by 100 million kWh and the other figures corrected accordingly. The average progressive increase was therefore 8. 3% which was lower than the previous growth rates (9-11%). The corrected estimate for the period 1959-62 is shown in Table 7.5.

TABLE 7.5.

Corrected estimates for the period 1959-62

Consumption Year 1959 1960 1961 1962 Industry 5690 6180 6780 7400 Non-industrial consumers 1600 1750 1930 2130' Transmission losses 760 820 890 970 Total 8050 8750 9600 10500

It must be noted that the actual production figures for 1959 will give a total of about 7850 million kWh, indicating that the estimate was too high by only 2.5%. In 1960 the growth hitherto has been some 10-15% and a total figure of 8500 million kWh seems to be reached. This means then an error of only 3% in the estimate.

7.4. Balance of power production for the period 1959-62 Together with the corrected estimates of consumption an estimate of the balance of production during the period 1959-62 has been made on the basis of a mean-water year, as well as a dry year1). This is shown in Table 7.6.

TABLE 7.6. Estimate of the balance of production for the period 1959-62 (million kWh)

Year 1959 1960 1961 1962 Alternate A; Mean-water year Hydro 6700 7200 7800 8400 Condensing steam ' 450 500 600 700 Back-pressure steam 900 1050 1200 1400 Total 8050 8750 9600 10500

Alternate B; Dry year Hydro 5750 6150 6600 7100 Condensing steam 950 1150 1200 1400 Back-pressure steam 1350 1450 1800 2000 Total 8050 8750 9600 10500

Actual production Hydro 5542 Condensing steam 1029 Back-pressure steam 1294 Total 7865

1) A dry year is defined here as having a hydro producibility of 80"Jo of that of a mean-water year.

43 7.5. Long-term estimates of consumption Detailed forecasts of the power consumption, based for example on the expected rate of development of industrial production in each sector, the increase of the national product, trends in per capita consumption and a region by region survey of private consumption, were not available in Finland at the time this study was undertaken. Some work is being done at present at Imatran Voima, which aims at using the results of the second survey (1958) as a basis for longer-term forecasts. As it was not possible, within the time available for the present study, to make a fresh detailed estimate of future demands some general guidance will be sought from existing information in arriving at the rough estimates presented here. It is pointed out in the Report of the Advisory Commission for Industri- alization (11 March 1959) that the rate of consumption of electrical energy has, in the past, exceeded the rate of industrial production. The industrial production index in 1957 was 179 (1948 = 100) whereas the electrical consumption index was 244 (1948 = 100). This is due to the phase of rapid industrialization and electrification in which Finland has found itself. This phase is expected to continue, at least in the next ten years. Further, in comparison with other Scandi- navian countries the per capita electricity consumption in Finland is still low (Norway 6800 kWh/year, Sweden 3800 kWh/year, Finland 1800 kWh/year), which suggests that the present high rate of increase in power consumption may continue. Recent expansions in the paper and pulp industry will help to increase the power consumption at a faster rate than in the recession years 1958-59. How- ever, it appears that after 1962 the paper and pulp industry will slow down its expansion, since the physical limits set by the annual growth of the forests are being approached. It is possible that the industry will then switch to finer paper products requiring more power, but no indication of this can be seen at present. The development of machine and metal industries has been rapid since World War II and is likely to continue inr future years, especially if a new steel industry is set up. In the field of electrification agriculture has already been electrified in Finland up to 81% and the general country electrification has reached 90%. However, this does not mean that further increases of consumption in the agricultural or private sector is limited. It is well known that consumption per customer may increase substantially once power is made available. On the other hand, the possible electrification of railways cannot have but a very small effect on the overall balance and the world-wide trend towards diesel—driven locomotives should be noted. The estimated share of the various sectors in the consumption of electricity is shown in Table 7.7.

TABLE 7.7. Share of different sectors in consumption

Consumer 1951-54 1955-58 Estimate to 1959-62 °b 1o 1° Paper and pulp industry 51.0 49.2 50.7 Other industries 29.2 29.3 27.1 Industry total 80.2 78.5 77.8

Other consumption 19.8 21.5 22.2 Total consumption 100.0 100.0 100.0 Losses 11.7 10.0 9.2

44 MilliohWhn

FRILUND (1958 ) s

REPORT OF THE COMMISSION 20000- FOR INDUSTRIALIZATION >

15000-

"HJELT C 1959 MIN.)

10 000-

5000-

3000-

1950 1955 1960 1965 1970 1975

Fig. 7.2. CONSUMPTION ESTIMATES

It is noticeable that paper and pulp industries have been responsible for one half of the total consumption. They are, however, also power producers, providing 40% of their own needs. In recent years the share of industry in total consumption has shown some decrease, while "other consumption" has grown more rapidly. "Other" includes in this connexion household, agricultural, other private consumption, public consumption and the self consumption of electrical utilities. The two first- mentioned represent about half of "other consumption", or 10% of total consumption. The specific per capita production in Finland is approximately 1800 kWh/pear. The country is still developing industrially at a fast rate. The average annual increase of 10% in electricity production which has been achieved in the last 15 years may not, however, be maintained in the next ten-year period. The available estimates set the minimum at 7% and the maximum at 9%. The different forecasts at present available are summarized in Fig. 7. 2. It may be possible to take the following mean values as guidance.

Year Prime production 1965 12, 700 million kWh (a mean of 11, 800 - 13, 600) 1970 19, 000 million kWh (a mean of 18, 000 - 20, 000)

It is to be noted in connexion with the mean estimates quoted above that these figures will not be used rigidly in the following chapters of the report. The analysis of the role of thermal power - within which we seek to know the possible place of nuclear power - will be based on consumption targets such as 15, 000 million kWh/year or 20,000 million kWh/year, the time scale being flexible within a reasonable range. Power planning in Finland has, in the past, concerned itself merely with the way in which annual energy demands were to be met. There has always been

45 enough capacity for meeting the peak demand, since the system has been virtually all "hydro" arid was always equipped with supporting thermal capacity for dry years. For this reason, no special attention had to be paid to the system peak demand. The important changes expected in the future (see Chapter 9) make it imperative that serious consideration be given to forecasting the system peak load, which will eventually be the governing factor in determining installed capacity.

8. POWER PROGRAMME UNTIL 1965 AND PROBABLE DEVELOPMENT UNTIL 1970 8.1. General background

The utilization of electricity in Finland for lighting and power dates back to the late 19th century. However, the generation and transmission of electrical energy on a large scale was initiated in connexion with the industrial development in the 1920's and -30's. The first construction stage of the Imatra power station was completed in 1929 and, at the same time, several moderate size power stations were built by private industry and municipalities. By 1940 total hydro producibility had reached about 3000 million kWh/year and the most important power stations formed an interconnected system. As a consequence of the two wars about 1/3 of this producibility was lost reducing the available potential to 2500 million kWh/year in 1945. Since 1945, the rapid growth of energy demand has forced an acceleration in hydro power development. The main effort was directed to the construction of a chain of seven large power stations on the Oulu river, the first of which (Merikoski) was completed in 1948 and the last (Utanan) in 1957. While the power stations on the Oulu river were approaching completion, the development of the Kemi river was started in 1953. The first of these stations (Petajaskoski) was completed in 1957 and three further stations are under construction at present. At the end of 1958 the total installed capacity of hydro power stations was 1335 MW. This corresponds to an annual production of about 7370 million kWh/fy"ear in a normal year. At the end of 1959 the installed capacity of thermal power stations was about 1000 MW, of which approximately 970 MW were steam turbines. The share of condensing units was 569 MW and that of back-pressure 398 MW (see also Chapter 6). A large number of units are, however, too old to run economically or of very small size. The capacity of modern units installed since 1950 was at the end of 1959 239 MW of condensing and 267 MW of back-pressure. Of the pre-war condensing units (total 330 MW) about 200 MW are practically out of service and, accordingly, the usable condensing capacity in 1959 was about 370 MW.

8.2. Construction programme until 1965 Hydro power The construction programme for hydro power is rather well defined until 1965 (Table 8.1.). The development is scheduled to continue at an average rate of 400-450 million kWh/year during 1960-65. Construction work is concentrated

46 in northern Finland where, e.g., four bigger stations of the Kemi river will be completed (Pirttikoski, Valajaskoski, Juukoski, Ossauskoski). The development of the Ii river further south will be started during this period (Pahkakoski) and the tributaries of the Oulu river will be completed (Aittokoski, Seitenoikea). In the southern part of the country some smaller stations will also be built (Lieksankoski, Pankakoski, Kuurna). A comparatively large amount of capital is needed for the hydro power construction programme. This may, in a country like Finland with a shortage of capital, lead to some delay in the construction schedule shown in Table 8.1. Construction costs are also rising gradually, due to less favourable site conditions and longer transmission distances, but the growth in costs in this period is rather small (see Chapter 10). As shown in Table 8.1. the installed hydro capacity will be around 2000 MW in 1965 with nominal producibility of slightly over 10, 000 million kWh/year. Seeing that the total national consumption will by then have reached about 13, 000 million kWh/year, the hydro construction programme will no longer be able to meet the increasing demand during this period.

TABLE 8. 1.

Construction schedule for hydro power

Year Station or site Installed capacity Nominal producibility MW million kWh/year

1958 1335 7370 1959 Pirttikoski I 55 250 Amma 14 - 38 Others 2 10 Total 71 1406 298 7668

1960 Pirttikoski II 55 250 Aittokoski 37 130 Valajaskoski I 23 115 Lieksankoski 14 78 Total 129 1535 573 8241

1961 Palokki 7 30 Seitenoikea 29.5 130 Valajaskoski II 23 115 Others 2.5 11 Total 62 1597 286 8527

1962 Pahkakoski 34 176 Permantokoski 12 50 46 1643 226 8753

1963 Juukoski 100 440 Pankakoski 16 85 Total 116 1759 525 9278

1964-65 Ossauskoski 110 475 Kuurna 25 115 Kitka 56 143 Ii river 30 158 Kokemaki river 50 200 Total 271 2030 1083 10361

47 TABLE 8.1. (cont'd)

Year Station or site Installed capacity Nominal producibility MW million kWh/year

1965-70 Vanttauskoski 65 330 Ii river or Taivalkoski 60-110 315-500 Saimaa area 25 90 Kokemaki river 25 100 Kymir river 15 80 Isohaara III 25 90 Petajaskoski III 50 160 Valajaskoski III 23 115 Kuusamo rivers 24 90 Kitinen and Luiro 60 250 Tornio or Ounas river 0-120 0-600

Total 372 2402 1620 11980 -542 -2572 -2405 -12765

Condensing power The construction programme for thermal power is not so well defined as that for hydro. Firm plans are made for 2-3 years ahead only and, because of the shorter construction times involved, longer-term plans are subject to alterations. Large additions are at present being made to the condensing capacity. The city of Helsinki has just commissioned a 75 MW unit (Hanasaari) and at the end of 1960 Imatran Voima Qy will commission a 125 MW unit in Naantali. At the same time some smaller units are being built by industrial establishments and municipalities. The dependable condensing capacity, which at the end of 1959 amounted to about 370 MW, will rise to approximately 700 MW by the end of 1962. Of these about 570 MW are modern post-war units installed since 1950. In 1963 plans call for a 60 MW unit in Kokkola, which will be built for the copper refinery there and will use mainly the waste heat from the flame melting of copper ores. This plant will have a reasonably high load factor (5000 hr^rear). In 1964-65 second units to Naantali and Hanasaari stations are foreseen. With further smaller units to be installed the total capacity is expected to reach 1000 MW at the end of 1965, and this would then include about 900 MW of post- war units. The construction programme, as far as it is known at present, is summarized in Table 8.2. In Chapter 9 some estimates are made for the peak capacity of condensing power needed in the national system. The maximum peaks anticipated for the years 1960, 1962 and 1965, assuming that water conditions in those years are as bad as in the driest of the last 25 years, will accordingly be 400 MW, 490- 520 MW and 660-770 MW respectively. Allowing 10% for reserve units the needed maximum installed condensing capacity would be

1960 440 MW 1962 570 MW 1965 850 MW

In 1960 the scheduled total capacity is only slightly higher than the predicted needs. In 1962 the post-war units alone would be capable of meeting the peak and in 1965 some excess of capacity would exist.

48 TABLE 8. 2.

Construction programme for condensing power

Year Station or site Total Post-war units

1959 Serviceable capacity 370 MW 239 MW

1960 Hanasaari I 75 MW Others 18 " Total 93 MW 463 " 332 "

1961 Naantali I 125 MW Turku 32 " Others 18 " Total 175 MW 638 " 507 "

1962 Salmisaari III 40 MW Others 20 " Total 60 MW 698 " 567 "

1963 Kokkola 60 MW Others 20 " Total 80 MW 778 " 647 "

1964-65 Naantali II 125 MW Hanasaari II 75 " Others 40 " Total 240 MW 1018 " 887

Back-pressure thermal power Regarding back-pressure steam power, during the five-year period 1955- 1959 the average rate of new capacity added has been about 30 MW/year. As stated in Chapter 6 the total installed capacity of back-pressure plants was 372 MW at the end of 1959. A substantial part of this capacity is, however, old. The size of the back-pressure units is necessarily small owing to the limited needs of individual concerns for steam or heat. The largest are the Kankopaa plant (500-600 tons/hr of steam at 10-4 atm abs. pressure) and the Kuusankoski plant (250-350 tons/hr). The process steam consumed by the paper mills is usually at 2.5-10 atm abs. pressure and 150-200°C temperature. In the modern back-pressure plants of small size (less than 15 MWe) the steam conditions at the turbine stop valve are 60 atm abs., 500°C and in some bigger units even 100 atm abs., 520OC. It has been estimated by Ekono1) that the capacity to be installed during the period 1960-80 will be distributed in turbine size as follows: Unit size (MW) Number of units 35 3 20 16 15 13 10 9 5 14 1 20 75 corresponding to 800 MW

1) Calamnius, "Prognosis of the demand of steam turbines in 1960-1980", Ekono, 1960.

49 Million kWh

PLANTS

1950 1955 1960 1965 1970 1975

YEAR

Fig. 8.1. POSSIBLE DEVELOPMENT OF BACK PRESSURE POWER

The rate of development in back-pressure capacity is closely tied to industrial development. It is shown in Fig. 8.1. for instance that if the surplus hydro power, which serves to substitute for back-pressure power in a normal or good water year, is also taken into account, the total energy follows closely the rate of industrial activity. In recent years the increase has been high, owing to the expansion of the paper and pulp industry. This Will probably continue in the next two or three years. After that, the development is more uncertain, depending on further expansion in the industry. The development of space-heating will also make some additions to-the back-pressure production. In the future, the available hydro surplus will decrease and the back- pressure power in dry and normal water years will approach one another. As far as it can be ascertained, the development in back-pressure capacity may follow the trend shown in Table 8.3.

TABLE 8. 3.

Probable development in back-pressure power

Year Installed Capacity Annual production in a mean-water year (MW) (million kWh/year)

1958 300 750

1962 450 1400 - 1550

1965 550 1800 - 2000

8.3. The probable development of power programme until 1970

For the period 1965-70 only very preliminary plans exist for power construction. The following discussion will thus be a survey of several possibilities rather than the description of a programme.

50 Hydro power It is generally assumed that at least one station on the main Kemi river (Vanttauskoski) will be built in 1965-70. The development of Ii river will continue or - alternatively - a further station on Kemi river (Taivalkoski) will be built. Some smaller remaining sites in the watercourses of Saimaa, Kokemaki, Kymi and Kuusamo have possibilities to be exploited. Regulation of the Kemi watercourse will, at least partially, be carried through by 1970 and some additional units can then be installed at the existing stations (Ischaara, Petajs- koski and Valajaskoski). Beyond these possibilities, all the remaining hydro potential is located either in small and less favourable or international rivers. The tributaries of the Kemi river (Kitinen, Luiro, Ounas river) are perhaps most attractive among the small rivers. Especially Kitinen and Luiro, having in any case the artificial lakes Lokka and Porttipahta, are assumed to be utilized before 1970. Of the international rivers, the Tornio river is at present under joint study and a few alternative plans have been made for its development. None of these, however , seems to be realizable until 1970. The previous possibilities listed in Table 8. 1. result in a total producibility of about 16OO-240O million kWh during 1965-1970. The upper figure corresponds to a construction rate of 480 million kWh/year, i.e. even more than in 1960-65. Because of smaller sizes associated with more construction work per unit the realization of this figure would need an increased organization and machinery. The lower limit calls for a construction rate of 320 million kWh/year, which is certainly within the limits of the present technical capacity. The increasing capital cost for future stations may also reduce the construction rate. The analysis made in Chapter 9 indicates that the production cost of hydro will increase in 1965-70 by 15-20%. The production costs of other generation methods are expected to fall in the same period, making the economic prospects of hydro more and more uncertain. In this study the construction programme for hydro in 1965-70 is assumed to be realized according to Table 8.1. The constructed hydro in 1970 will thus amount to 12, 000- 12, 700 million kWh of producible energy per annum or 2400- 2570 MW of installed capacity.

INSTALLED NOMINAL CAPACITY PRODUCTION

MW year 2500- S xMIN. -12 000

////y/

d> '/ •MAX.

V MAX. rM-'X^ MIN.

1960

YEAR Fig. 8.2. CONSTRUCTION PROGRAMME OF HYDRO

51 Fig. 8.2. summarizes the hydro construction programme. Both the nominal production and the installed capacity will increase rather steadily until 1965. The utilization factor will decrease slightly; today it is about 5500 hr/year and will drop to 5000 hr/year in 1970. Fig. 8.2. indicates also schematically the available hydro capacity in the critical season {end of winter) for a normal and dry year.

Condensing power For the period 1965-70 only some plans in the condensing power construction are known. The city of Helsinki, although concentrating more on the construction of space-heating stations, will extend the Salmisaari station (Table 8.2.). The first peat station (75 MW) is scheduled for 1965-66. The extension of Naantali power station may come into being around 1967-68 or alternatively, if peat shows good economy, a second peat station may be built instead of Naan- tali. In addition some medium and small units are expected to be installed during this period. All these units would make a total addition of 370-500 MW. According to the predictions made in Chapter 9 the condensing peak in 1970 may amount to 1270-1470 MW. With 10% allowance for reserve the needed capacity would then be 1400-1620 MW. At that time the utilization of pre-war units is questionable, and because in 1965 the post-war units will amount to 890 MW, additions in 1965-70 should be 510-730 MW. Some new units with a capacity of 150-250 MW seem accordingly possible. These possible developments are summarized in Table 8.3. where this deficiency of 150-250 MW is filled with one unit to be located in South-East Finland (Kymenlaakso). Depending on the economy and related factors this station can be coal-fired or nuclear. A load factor of 70-80% seems possible for it (see Chapter 9) if the other stations are operated accordingly.

YEAR

Fig. 8.3. CONSTRUCTION PROGRAMME OF CONDENSING POWER

52 This construction programme was discussed on the national scale, neglect- ing the distribution of thermal production among different producers and the interactions among them. This may cause that the needed peak capacity is more than assumed above and that big units cannot be run so efficiently. De- velopment, however, is, in any case, directed towards larger units, which for economic use need closer co-operation among producers. Fig. 8.3. summarizes the anticipated construction programme for condensing power. In the last decade the capacity of condensing steam plants has been very small, but the present transition from a pure hydro generation system to a mixed thermal-hydro system calls for a gradually growing construction rate. It may be noted, that the scheduled programme for 1960-65 is somewhat larger than predicted needs. In 1965-70 the needs will, however, increase very fast so that the excess of capacity will be soon utilized and, in addition, an at least unchanged construction rate will be needed.

TABLE 8. 4. Possible development of condensing capacity

Year Station or site Installed capacity (1965-70) Post-war units Total 1964-65 Total 1018 887 1966-70 Salmisaari IV 60-120 MW Peat I 75 MW Naantali III or Peat II 75-150 MW Vaskiluoto II 60 MW Others 100 MW Kymenlaakso (coal or nuclear) 150-250 MW

520-755 MW 1540-1770 1410-1640

Back-pressure power It is extremely difficult to predict with any accuracy the back-pressure power development up to 1970 since this depends on the industrial development. According to the best available estimates the annual production may range from 2300 to 2500 million kWh/year by 1970. About 10-15% of this may come from space-heating projects.

9. CHANGING ROLE OF CONDENSING STEAM POWER Until now, condensing power has played only a minor role in the production of electricity. This role has been that of supplementing hydro capacity in the winter months when hydro producibility is lower than the demand or during any period of low water availability. During the last ten years, the share of condensing power in total production has varied between 2.6% (1955) and 13.1% (1959) with an average of 5.6% over the whole period. The utilization of condensing power has similarly varied between 500 hr and 2000 hr in a year. At the end of 1959 the total installed capacity of condensing units was 570 MW. Important additions to condensing capacity are presently being carried out. According to the construction schedules and firm plans the installed condensing capacity will increase by 93 MW in 1960, by 60 MW in 1962, by 80 MW in 1963 and the total new (post-1950) capacity may reach 900 MW by 1965.

53 This rapid increase of condensing capacity, mainly by the installation of medium and large-size units, requires some explanation in view of the appar- ently uneconomic utilization of condensing plants until now. The situation prevailing until 1958-59 was consistent with the availability of sufficient hydro power at prices lower than that obtainable from coal-fired stations. Since 1958, however, a sharp decline has taken place in the coal prices. The crushed Polish coal in particular has been available to Finland at prices lower than those of indigeneous coal in Western Europe. This, coupled with the expectation of rising construction costs for future hydro projects has led many municipalities (i.e. Helsinki, Turku) and electricity undertakings (i.e. Imatran Voima) to invest in new condensing units which are considered quite capable of producing electricity as cheaply as from new hydro projects. As the development of the hydro resources is slowing down and more condensing plants are built, two iriajor changes will be seen in the pattern of electricity production in Finland. These are:

a) The reduction in the surplus hydro power available at times of high water This surplus power is characteristic of hydro systems with limited storage . capacities. Even if storage lakes are emptied throughout the winter months, the high water in the spring and summer is more than sufficient to fill them completely, especially since the electricity demand is low. It becomes necessary therefore to pass the excess water through the units if spilling is to be avoided. This power is usually sold to industrial consumers for substituting for their condensing power, back-pressure power and heat needs. For the last purpose industry has installed electrical boilers. This surplus energy has played a rather significant role in the total production figures (during the last 10 years on an average around 20% of total). When the surplus hydro power decreases and eventually disappears, its place will probably be taken by back-pressure plants for meeting heat needs and by the modern large condensing stations for electricity needs exceeding the production of back-pressure plants.

b) The passage of condensing capacity to base-load duty With the increase in the share of condensing capacity in electricity production the load factor of thermal plants will improve and an increasing portion of this capacity will gradually be assigned to base-load duty. It is well known that because of the high capital costs involved nuclear power can be economical only if the plant has a high utilization factor. It is therefore within this base-load thermal production that a place should be sought for nuclear power. For this reason special attention has been given in this study to the evaluation of the changing character of thermal production in the future years.

9.3. Character of condensing power in a mixed hydro-thermal system It has already been stated that in the next ten years the Finnish power system will gradually change from a virtually pure hydro system into a mixed hydro-thermal system. Naturally, hydro will still be the dominant form of power production but the essential feature of a mixed system for the purpose of this study is the increasing high load factor of thermal power.

54 In a mixed hydro-thermal system the character of the thermal production is determined by the pattern of hydro production (incoming flow and regulation possibilities), the system demand and the possibilities for load transfer within the system. In Finland the hydroelectric plants have already achieved a high degree of co-operation and centralized control. Thermal plants are at present relatively independent but, with the construction of large plants in the next decade, it is safe to assume that a centralized control will also be applied to their operation for meeting the national load effectively.

Fig. 9.1. CHARACTER OF HYDRO PRODUCTION IN FINLAND (FIVE MAIN RIVERS, POWER PLANTS AS IN 1958, FORTNIGHT AVERAGES)

Some characteristics of hydro power in Finland are shown in Fig. 9.1.1). The incoming water flow is low during winter. The melting of snow causes a considerable peak flow in spring (May). Another smaller peak is formed by the autumn rains in October-November. Lakes do not, however, have a sufficient capacity for cancelling completely the effect of the difference in time between the peak in incoming water and the electrical load. The lower figure in Fig. 9.1. indicates the available hydro power (i.e. the power proportional to incoming flow and regulation in the reservoirs) and shows that a surplus exists during the summer and a deficit in late winter. This deficit which has a rather short duration (2-3 months only) is to be met at present by thermal power.

1) Data obtained from the Water Regulation Bureau, Helsinki.

55 Fig. 9.1. refers to a system equipped with hydro to such an extent that hydro power could theoretically (i.e. except for the above effect) meet the whole of the annual energy demand in a mean water year. We refer to this situation as rH = 100% ( rH - degree of harnessing of hydro). If rH > 100%, the surplus will be greater, but thermal power needed will be less and conversely if rH < 100%, the surplus will be less but the need for thermal power greater.

70 io 90 100 110 120 HARNESSING DECREE OF HYDRO %

10AD FACTOR •/.

Fig. 9.2. NON-DIMENSIONAL CHARACTERISTICS OF A MIXED THERMAL-HYDRO SYSTEM

Fig. 9. 2. shows the character of thermal power production for varying rH. This is based on a study carried out for the Imatran Voima system1). Alter- natives A and B refer to the cases without and with the two artificial lakes Porttipahta and Lokka. The annual thermal production (shown as a percentage of total production) is that needed for an average year (worked out over the period of 25 years from 1933-57). It may be noted that with rH = 100% the share of thermal production amounts to approximately 10%. If a pure hydro system is wanted (i.e. no thermal production) rH must exceed 120% at least. With de- creasing rH the thermal production is approaching the line marked "no surplus". The duration of the load met by thermal production is shown in the lower curves of Fig. 9. 2. This has been evaluated in blocks of load equivalent to 10% of the mean annual load. It is to be noted that the diagram is dimensionless. With high rH the thermal production has a poor load factor. This improves considerably when rH decreases from 90% to 70%. With further reduction in rn the shape of the thermal load-duration curve approaches that of the total load- duration.

1) LINQUIST, O. and VILJAVUORI, K.. "Regulation studies 1966-68", Imatran Voima Internal Report, 1960.

56 The national system has been assumed to have similar characteristics, with a curve intermediate between alternatives A and B. The position of the national system in 1957 (when rn was 110%) may be seen in the upper figure of Fig. 9.2. In the future, with improved regulation, the national system is expected to approach the alternative B. Admittedly, the Imatran Voima system accounts at present only for 60% of the hydro capacity in Finland, but the plants are situated on all the main rivers in the different regions of the country. Fig. 9. 3. gives an opportunity for comparing the predictions of this method with actual results. It is seen that the predicted stepped load-duration diagram is reasonably close, in its higher part, to the actual curve obtained as an average for the period 1957-59.

LOAD FACTOR %

Fig. 9. 3. CONDENSING LOAD-DURATION CHARACTERISTICS IN 1957-59

The method used for the evaluation is, therefore, the following: on the national scale, the system annual energy production is the total production minus back-pressure production. This corresponds to actual "hydro»+ condensing thermal "production. Hydro producibility is the total annual energy which could be produced by hydro in a mean-water year. The ratio of hydro producibility to actual "hydro + condensing" production is rn- The share of condensing production is obtained from Fig. 9.2. since this depends now only on rH and the regulation possibilities. The actual hydro production and the hydro surplus (including spill) are then obtained by difference. The main characteristics of the condensing production (peak load and the mean utilization factor) are then obtained from the lower curve of Fig. 9. 2. which is dimensionless. The results are summarized in Table 9.1. 'The same information is shown Also in Figs. 9. 4., 9.5 and 9.6. The peak condensing capacity is that corresponding to an extreme dry year of the type of 1941. The utilization of condensing power in Fig. 9.6. is in the form of 100 MW blocks. These results indicate the expected changes in the character of.production as the system becomes more and more a mixed "hydro-thermal" system. The share of condensing production is expected to increase rather rapidly from the present value of 300-400 million kWh/year to something like 4000-5000 million kWh/year by 1970-72. Hydro surplus will decrease gradually. The utilization of condensing power will also increase from the present 1000 hr/year to some 35 000 hr/year in 1970-72. The utilization of the bottom 100 MW block in condensing power will increase very rapidly after 1965. This block would today

57 cn oo

TABLE 9. 1.

Characteristics of hydro and thermal production in the future

Hydro + Total production Back-pressure condensing Constructed rH Condensing Hydro Hydro spill and Peak Utilization production production hydro production production surplus condensing of peak Million kWh Million kWh Million kWh Million kWh % Million kWh Million kWh Million kWh MW hr/ year

8,500 1,100 7,400 8,200 ill 420 6,980 1, 220 400 1,050

10,000 1,450 8,550 8,700 102 770 7,780 920 490 1,600

12,500 1,850 10,650 10,000 94.0 1,360 9,290 710 660 2,100

15,000 2, 050 12,950 10,900 84. 1 2,590 10,360 540 950 2,740

17,500 2, 300 15,200 11,800 77. 6 3, 920 11,280 520 1,210 3, 250

20,000 2,500 17,500 12,700 72. 5 5,260 12,240 460 1,470 3, 600

25,000 2,850 22,150 14,100 63.5 8,400 13,750 350 1,960 4,300 CONDENSING PRODUCTION O (MILLION kWh) 5000 © CONDENSING PRODUCTION (AS •/„ OF TOTAL PRODUCTION)

NEEDEO PEAK CAPACITY © CMW) 1958 1961-62 1966-67 1970-72 © 25000 r UTILIZATION OF PEAK (HOURS/YEAR) / 4000 -J

3000

CONOE NSING 4 V oV BACK- 2000 A F RESSURE y /

1000

£ HYD RO PRODUCTION

10.000 15.000 20.000

TOTAL PRODUCTION MILLION kWh /YEAR

Fig. 9. 5.

7000 10000 15000 20000 TOTAL PRODUCTION MILLION kWh/YEAR PREDICTED CHARACTERISTICS OF CONDENSING POWER IN FUTURE

Fig. 9.4.

PREDICTED HYDRO AND THERMAL PRODUCTION

MIN. ESTIMATE 1960 1965 - TIME SCALE MAX. ESTIMATE 1965 1970

7,500 10,000 15,000 20,000 25,000 TOTAL NATIONAL PRODUCTION MILLION kWh/YEAR

Fig. 9. 6.

PREDICTED UTILIZATION FOR CONDENSING POWER

59 have a utilization of 20% only, but this will reach 40-45% in 1965-66 and 80-85% in 1970-72. Around 1970-72 up to 400-500 MW of condensing capacity may have a utilization exceeding 6000 hr/year. Naturally, this analysis in terms of homogeneous blocks of 100 MW power will not exactly correspond to reality. In actual fact the units will be of different sizes and the economy of utilization will also depend on the fuel burnt. The effect of the different fuels on the character of condensing power must, therefore, be discussed. Table 9.2. shows the amounts of fuel used in condensing plants in some past years.

TABLE 9.2. Fuels used in condensing plants1^ (equivalent coal tons)

1956 1957 1958 (dry year) (mean year) (mean to good year)

Wood 9,000 7,500 1,500 Industrial and Wood wastes 55,000 57,500 50,500 Peat 2.300 500 200 Coal 211,500 138,500 75,400 Oil 79,000 54,000 25,000

Total 356,800 258,000 152,600

It is seen that the consumption of different fuels, except industrial and wood wastes, depends on the water conditions. The majority of industrial and wood wastes is used in back-pressure plants, but some is used in condensing plants. This corresponds to an electricity production with high load factor and explains why our method of system evaluation is not able to predict the tail of the load- duration curve (Fig. 9.3.). The condensing production due to the use of the wastes forms a 10 MW tail with a very high utilization. In future years, the availability of wastes will of course be determined mainly by the development of the paper and pulp and the wood-working industries. It is estimated that the wastes available will increase by a factor of 3 by 1970 and thus account for a total production of electricity of 2 50 million kWh/year. In addition, there are plans for building a plant of 60 MW in Kokkola, where about 200-250 million kWh/year of electricity will be produced on base-load. It is also possible that one or two iron works may be built where about 50 million kWh/year could be produced on baser load by burning waste gases. The estimated development of this process condensing power, using waste or by-product fuels is indicated in Table 9.3. This production is assumed to have a duration of 8500 hr/year so that the mean base-load is also calculated.

TABLE 9. 3. Condensing power generated in industrial processes

1960 1965 1970 million kWh MW million kWh MW million kWh MW

Wastes used as fuel 85 10 170 20 250 30 Other processes - 210 25 350 40 Total 85 10 380 45 600 70

1) This table covers about 90"5i> of the total condensing production.

60 LOAD

OLO UNITS

SMALL AND MEDIUM NEW UNITS

LOAD FACTOR % 1400-

Fig. 9.7. OLD UNITS OR 1200- 6AS- TURBINES PREDICTED CONDENSING LOAD-DURATION CHARACTERISTICS AROUND 1965

(TOTAL PRODUCTION 13, 000 MILLION kWh) SMALL AND MEDIUM 1000 NEW UNITS

Fig. 9. 8.

PREDICTED CONDENSING LOAD-DURATION CHARACTERISTICS AROUND 1970 (TOTAL PRODUCTION 19, 000 MILLION kWh)

Figs.9.7 and 9.8. take this base-load energy into account and indicate also a possible distribution of different condensing units within the estimated durations. Units have been divided roughly into four classes: - process units - large modern units ( 50 MW) - medium and small new units (5 - 50 MW) - old units or gas-turbines The role of nuclear power is within the second group. The average load factor of this group in 1970 is some 55% and at the bottom there will be at least 300 MW with a load factor in excess of 75%. This, therefore, sets the limit to the size of a nuclear power plant for economic operation at that time.

61 10. POSSIBLE LOCATIONS FOR A BASE-LOAD NUCLEAR POWER PLANT IN THE SYSTEM

The following discussion on the location of a base-load nuclear station is based on a study made by Imatran Voima Osakeyhtio for the future regional distribution of the production and consumption of electricity in Finland This study covers the electrical energy situation of the country up to a total national production figure of 22, 000 million kWh/year (corresponding to 1972-73). The results shown graphically in Fig. 10.1. indicate that around 1972-73 the energy deficiency to be met by large thermal plants will exceed 1000 million kWh/year in 4 regions (see Fig. 10. 2. for a map of the regions). These are: Kymenlaakso (region II) deficiency 1100 million kWh/year Helsinki ( " III) " 2100 Turku-Forssa ( " IV) " 1000 " " Keski-Suomi ( " IX) " 1400 " " " The new condensing station to be built in Naantali (eventually 250-300 MW) will satisfy the deficiency in the region Turku-Forssa. The condensing production of the city of Helsinki is expected to reduce the deficiency in region III to some 1400 million kWh/year. Accordingly, three regions, Kymenlaakso, the coast of West-Uusimaa (Helsinki) and Middle-Finland (Keski-Suomi) are considered possible for the siting of a nuclear plant (150-250 MW). A new large condensing plant needed at that time (250-350 MW) could be located in the coastal areas of Kymenlaakso or of Helsinki. The siting of the nuclear plant depends on its size and commissioning date in the following way: 1) Commissioning date: 1967-70. If a nuclear station is to be built the construction of the new conventional condensing station must, in this case, be postponed. The most profitable location for the nuclear plant is Kymenlaakso regardless of the size. Next comes Uusimaa. 2) Commissioning date: 1970-73, plant size: 150 MW. The new condensing plant is commissioned either in Kymenlaakso or in Uusimaa. The nuclear plant could then be located in Middle-Finland. The transmission losses are, in this case, bigger than in other alternatives (difference about 7 MW), but the investment for power transmission is reduced indirectly by 500-700 million FM. 3) Commissioning date: 1970-73, plant size: 250 MW. If a nuclear plant of this size or greater is located in Middle-Finland, this region will have an excess of production. Transmission losses would increase by a factor of 2 (difference 15 MW) and some heavier lines should be built in the region. South-Finland is in this case obviously preferable. The best location for the nuclear plant is then Uusimaa if the new conventional plant is in Kumenlaakso or vice versa. Kymenlaakso should perhaps be more economical because of the high load factors of the local consumption. Table 10.1. shows the balance of production when the total national consumption is 22,000 million kWh/year (1972-73). Two new bigger condensing stations have been assumed for this date, a conventional coal-fired 300 MW

1) NEVANLINNA, L., Regional distribution of electricity production and consumption, Imatran Voima Osakeyhtio, (internal report), 1960.

62 1 1 III. HELSINKI IV. rURKU- FORSSA V. iOKEMA

"'aJ! L — 2 i JP 1 1 M P i 1 1 8 10 12 14 16 18 20 22 8 10 12 14 16 18 20 22 8 10 12 14 16 18 20 22

VI. F'OHJOI S -HAME VII. f TELA- HAME VIII. £ iAVO - K ARJAL/

1 I I 1 1 1 en m m ffTT ma 8 10 12 14 16 18 20 22 8 10 12 14 16 18 20 22 8 10 12 14 16 18 20 22

ix. kfski -- SUOMI ' X. POHJANMAA NUCLEAR PWR 1500 MILL. kWh /YEAR ALTERNATIVE "MIDDLE FINLAND"

XI. OULUN JA LAPINLAANIT 11 ±L 8 10 12 14 16 18 20 22 8 10 12 14 16 18 20 22 8 10 12 14 16 18 20 22

Fig. 10. 1.

PREDICTED REGIONAL DISTRIBUTION OF POWER PRODUCTION AND CONSUMPTION

63 400 KV 220 kV 110 kV PETAJASKOSKI PIRTTIKOSKI

NUOJUA

PIKKARALAI PYHAKOSKI?

N / r \ mr \ PAMILO X IX VAASA7 SEINAJOK! RVARKAUS' / /r PETAJAVESI / . / — r^ ,4-. 1MATRA TAMPERE X'l PORT vm raUM; ,-FORSS? FKORIA Iff HELSINKI TURKU

Fig. 10. 2.

TRANSMISSION REGIONS TABLE 10.1. Power balance when national consumption is 22,000 Million kWh/year

Prod u c t i o n T r a n s m i s s ion C o n d e- n s i n g Region Consumption Hydro Process A lternativ e A lternativ e A B C A B C a) Mean water year (Million kWh/year) 1. Vuoksenlaakso 2200 1400 800 ------2. Kymenlaakso 2720 1250 400 1600 1000 1000 - 530 + 70 + 70 3. Helsinki 2540 - 400 1620 2220 720 + 520 - 80 +1420 4. Turku-Forssa 1200 - 80 1120 1120 1120 - - - 5. Kokem&kilaakso 1400 750 250 50 50 50 + 350 + 350 + 350 6. Pohjois-Hame 1760 450 400 40 40 40 + 870 + 870 + 870 7. Etel.a-Hame 860 - 60 - - - + 800 + 800 + 800 8. Savo-Karjala 1600 1000 260 - - - + 340 + 340 + 340 9. Keski-Suomi 2160 300 400 - - 1500 +1460 +1460 - 40 10. Pohjanmaa 660 150 300 770 770 770 - 560 - 560 - 560 11. Oulu-Lappi 2900 7700 450 - - - -5250 -5250 -5250 Losses 2000 - - - - - +2000 +2000 +2000 Total 22000 13000 3800 5200 5200 5200 + 6340 ±5890 15850 b) Low water year (Million kWh/year) 1. Vuoksenlaakso 2200 1120 850 - - - - 230 - 230 - 230 2. Kymenlaakso 2720 1000 420 1750 1420 1420 - 450 - 120 - 120 3. Helsinki 2540 - 420 2370 2700 1100 - 250 - 580 +1020 4. Turku-Forssa 1200 - 90 1950 1950 1950 - 840 - 840 - 840 5. Kokemakilaakso 1400 600 270 270 270 270 + 260 + 260 + 260 6. Pohjois-Hame 1760 360 420 60 60 60 + 920 + 920 + 920 7. Eteia-Hame 860 - 60 100 100 100 + 700 + 700 + 700 8. Savo-Karjala 1600 800 250 - - - + 520 + 520 + 520 9. Keski-Suomi 2160 240 420 - - 1600 + 1500 +1500 - 100 10. Pohjanmaa 660 120 300 1100 1100 1100 - 860 - 860 - 860 11. Oulu-Lappi 2900 6160 470 - - - -3730 -3730 -3730 Losses 2000 - - - - - +2000 +2000 +2000 Total 22000 10400 4000 5970 5970 5970 t6130 ±6130 ±5650

A B C Explanation of alternatives: Nuclear plant Kymenlaakso Helsinki Keski-Suomi Coal-fired plant Helsinki Kymenlaakso Kymenlaakso station with two units and a 250 MW single reactor nuclear station. The nuclear plant is placed alternatively in Kymenlaakso, Helsinki or Keski-Suomi (Middle- Finland) and the coal-fired station in the remaining coastal region (Kymenlaakso or Helsinki). The direct transmission costs of the'nuclear plant in alternatives "Kymen- laakso" and "Middle-Finland" are very comparable. A station of 150 MW needs two 110 kV lines between the station and the network (200-300 million FM). For a station of 250 MW an additional 220 kV line to the interconnected grid is necessary (300-400 million FM). The "Uusimaa" alternative needs in addition to local lines either one (for 150 MW) or two (for 250 MW) 220 kV connexions to the interconnected grid (300-700 million FM). The "MiddlerFinland" alternative gives an indirect reduction of 500 - 700 million FM in transmission investments. It avoids the construction of a 110 kV line (Nuojua-Kuopio, 200 km), which otherwise is to be built to reinforce the grid in the eastern part of Middle-Finland. If the size of the nuclear plant exceeds 150 MW this reduction will decrease because of other needed rein- forcements. Extra transmission costs for the nuclear plant in different alternatives have been estimated in Tables 10.2. and 10.3. on the basis of annual costs of 7% interest and 20 years amortization and annual losses on the basis of 2000 hr duration and 3. 5 FM per annual kWh.

TABLE 10.2. Extra transmission costs for a 150 MW station (900 million kWh/year)

Kymenlaakso Uusimaa Middle-Finland

Investments (million FM) 240 230 250-600 = -3501) Losses 3 3 10

Annual costs (million FM) - investments 23 22 24-56 -32D - losses 21 21 70 - total 44 43 38

Total annual costs - FM/kW 290 290 250 - FM/annual kWh 0.05 0. 05 0.04

TABLE 10.3. Extra transmission costs for a 250 MW station (1500 million kWh/year)

Kymenlaakso Uusimaa Middle-Finland

Investments (million FM) 620 575 520-600 = -802) Losses 5 _ 6 20

Annual costs (million FM) - investments 58 54 49-56 = -72) <* losses 35 42 140 - total 93 96 133

Total annual costs - FM/kW 370 380 530 - FM/annual kWh 0.06 0. 06 0. 09

1) Investments minus savings of the Nuojua-Kupio 110 kV line. 2) Investments minus savings of the Nuojua-Kupio 110 kV line.

66 11. COST OF CONVENTIONAL POWER 11.1. Items of cost The purpose of the present cost analysis is to provide a basis for comparing the production economy of conventional generation methods of electricity in Finland. Power costs will be related to units sent out and fed into the interconnected network in South-Finland where the consumption is concentrated. The analysis is by no means a complete breakdown of the power costs. Only the items which have appreciable effects on the cost of the different alternatives are taken into account. The figures obtained must be considered relative rather than absolute. For the evaluation of power costs different basic factors are needed. These will be discussed in some detail. Amortization period depends on the useful life of the station in question. In hydro stations permanent construction structures cover the major part of total costs (about 80%) and, accordingly, the engineering life of stations will be long (40-50 years). The present technology allows an overall efficiency of about 90% in converting the hydro potential to electricity and no appreciable improvement is to be expected in the future. The technical life of hydro stations may therefore be assumed to be long. Thermal stations have shorter engineering life and plant technology is advancing rather fast, so that stations which are today older than 20 years are moving towards economical obsolescence. On this basis and in accordance with established practice in Finland the following lifetimes are accepted: Hydro stations 50 years Thermal stations, burning coal, oil or peat 25 years Interest rate in Finland has varied in recent years between 6.5-8% for domestic financing and somewhat lower, down to 5.5%, for foreign financing. In this analysis no specific financing conditions are assumed and two overall interest rates, 6% and 8%, are used as alternatives. Insurances are usually taken against fire only and accordingly the annual premium is very small (0.05% of capital costs). In some few cases (small power companies) insurance on equipment is also taken, in which case the premium may amount to 0.5%. When considering the production of electricity on a large scale, the insurances are being neglected in this analysis. The situation is different in the case of nuclear power and will be discussed in Chapter 11. Taxes are taken into account where necessary for comparison. The income and local taxes which are associated with profit are neglected, because they are the same for the different alternative means. Ad valorem taxes, however, are proportional to the specific cost and should be incorporated. They amount at present to 1% of net property and are strongly dependent on the financing method used. If e.g. 20% of investments is own capital, the ad valorem taxes amount to 0.5 x 0.2 x 1 = 0.1% averaged during the life of the station (amortization of plant and depreciation of loans are assumed to cancel each other). In the case of total self-financing the figure would be 0. 5%. Under present conditions local taxes (13.5%) are to be paid also on the interests of mortgage loans. If 50% of financing consists of such loans, the payment would be some 0.5% of the capital. However, these differences are within the margin of error of the estimates made in this study and are, therefore, neglected.

67 The equipment taxes on capital costs and fuel taxes for coal and oil have been taken into account. It may, of course, be argued that such taxes merely represent internal transfers of currency, so that the actual benefit to the national economy is not easily evaluated. However, it is felt that a comparison of costs without taxes would be unrealistic, since all operations (including that of the state-owned companies) carry taxes. They may, of course, vary in the future. Load factor is taken variable from 50% to 80% for thermal stations. As it was stated in previous chapters, high utilizations in thermal power are expected to be reached first in the latter half of the sixties. For hydro power the load factor depends on water conditions. With present practice in determining the scale of a hydro plant and future regulation possibilities its value is 50 - 55 %. The possibilities of designing future plants for peaking have not been fully studied in Finland, but such possibilities must be rather remote. Power transmission cost is charged on hydro power only. All other plants are considered to be sufficiently flexible in siting, that connecting them to the interconnected network of the consumption area (South-Finland) does not require appreciable extra cost. There will be, of course, some siting conditions to be met with any type of power. Thermal condensing stations should be located in coastal areas for ease of fuel transportation and in marsh areas for peat. The effect of these factors on transmission costs is dealt with in connexion with respective generation methods and also in Chapter 10. All other items in power costs like operation and maintenance, fuel cost, heat rate, etc. , will be discussed in connexion with the respective cost evaluations. All costs are related to present price levels. In doing so, anticipated improvements in technology and expected reductions in prices may be seen immediately. Unit sizes have been chosen at the maximum under respective conditions. E.g. in 1960 and 1965 a 120-150 MW unit is considered to be maximum for transfer of power. A station may, however, include two units with a total net rating of 250 MW. In 1970 a 250 MW unit is expected to be possible. In the case of hydro and peat stations sizes are limited by natural factors and will accordingly be smaller. For condensing and nuclear plants the location in the system may also limit the size. This is discussed in more detail in Chapter 10. Costs have been evaluated for three dates, 1960, -65 and -70. For 1960 the analysis covers only the already existing generation methods, hydro and condensing power.

11.2. Hydro power costs Until now the harnessing of hydro power has shown good economy compared with other possible electricity production methods in Finland. Conditions in South- and Middle-Finland have been favourable enough to achieve capital cost figures of 50, 000- 100, 000 FM per installed kW. When the available hydro potential in the southern part of the country was more or less fully exploited construction moved to Northern Finland, mainly to rivers Kemi and Ii. This means an increase in transmission distance and less favourable site conditions which together will lead to an increase in production costs. In the following, the production costs of hydro power in 1960, 1965 and 1970 will be analysed in more detail.

68 Production costs in 1960

At present hydro construction is concentrated on the first stations of the main branch of Kemi river. Capital costs for these stations (Petajaskoski, Pirttikoski, Valajaskoski and Juukoski- commissioning dates 1958- 62) are varying between 90, 000- 130, 000 FM per installed kW. In the case of a rather, irregular river like Kemi the cost based on installed capacity is not, however, a representative figure. The production costs will be determined mainly by the producibility of energy and these costs based on nominal production (mean water conditions) are more applicable. Whether all production can be used to meet the load depends on the character of the total generation system. In a purely hydro system a significant portion (some 20 %) of energy becomes surplus and the nominal production is not a good basis for economic comparisons. Hydro stations to be built in Finland around 1960 will, however, operate most of their life in a mixed thermal-hydro system, when nearly 100% of water producibility can be used in meeting the load. The above mentioned four stations on the Kemi river have a total installed capacity of 430 MW and nominal producibility of 1990 million kWh/year. Total capital costs are estimated to 44,200 million FM. This corresponds to 103,000 FM per kW installed or 22.2 FM per producible kWh. The producibility of 1990 million kWh will, of course, be achieved only when the watercourse is regulated. In addition to the capital costs for plants, a provision must then be made also for investments in creating the regulation lakes. According to the present plans extensions in the capacity of Kemi lake will be made and two artificial regulation lakes will be created (Lokka and Porttipahta). The former is estimated at 2500 million FM and the latter at 4000 million FM. Kemi lake will serve all stations on the main branch of the river (total nominal production about 3800 million kWh a year), the artificial lakes and the subsidiary stations to be built on the rivers Kitinen and Luiro (about 200 million kWh/year). Regulation will thus add a proportional cost of

2500 4000 "3800 + 4000 = 1,66 FM Per Pr°ducible kWh.

Power transmission is another additional cost to be applied for hydro stations on the Kemi river. When comparing the production costs of hydro with those of thermal stations the long-distance transmission only is taken into consideration. The power from the Kemi area will be transmitted through the existing 400 kV line with a carrying capacity of 700 MW. When some allowance is made for local consumption this line is then sufficient for stations with a total annual production of 4000 million kWh, and with capital costs of 10,400 million FM the power transmission increases the capital costs of hydro by 2.60 FM per producible kWh. The total capital cost is therefore: Hydro plant 22. 20 FM/annual kWh Regulation lakes 1.66 " " " Transmission 2.60 " " " 26.46 or 122, 500 FM/kW installed (52% load factor)

69 Because of varying water conditions some provision must be made for supporting the hydro stations in dry years. In dry years the hydro producibility is assumed to decrease by 20%. This balance must be generated in thermal plants. There are, however, in existence old stand-by thermal stations for this purpose and no extra capital expenditure is needed. Running costs must, however, be taken into account. On the average every fourth year may be character- ized as a dry year and, accordingly, the thermal production will amount to = 5% of the nominal hydro production. In addition, long distance transmission losses of about 5% are also to be generated in thermal plants. In good water years there will be a surplus of hydro production (also 5% in average), which may be made available to industry and used for generating steam in electric boilers. According to past experience the price level, when this surplus energy becomes attractive, will on the average be about 60% of the running costs of older thermal plants. Under these assumptions the running costs of hydro power will be 7% of the running costs of old thermal plants. In old plants the net heat rate is around 3700 kcal/kWh, which with fuel costs of 500 and 750 FM/Gcal results in an absolute value of 0. 13 and 0. 195 FM/kWh for running costs of hydro. The total production cost is shown in Table 11.1.

TABLE 11.1.

1960 hydro production costs

Interest rate {% Fuel heat cost (FM/Gcal) 500 750 500 750

Annual fixed charges: Hydro plant (FM/kWh) 1.68 1.68 2. 08 2. 08 Regulation lakes (FM/kWh) 0.12 0.12 0.15 0.15 Power transmission (FM/kWh) 0.21 0.21 0. 26 0.26

2.01 2. 01 2.49 2.49 Total fixed (FM/kWh)

Running costs: 0.092 0.139 0. 092 0.139 Supporting thermal (FM/kWh) 0.092 0.139 0. 092 0.139 Transmission losses (FM/kWh) 0. 055 0. 083 0. 055 0. 083 Surplus profit (FM/kWh) Total running (FM/kWh) 0.13 0.195 0.13 0.195

Total unit cost (FM/kWh) 2.14 2.21 2. 62 2. 69

An amortization period of 50 years has been taken. Annual operation and maintenance costs were 1.2% of capital costs for hydro, 1% for regulation lakes and 1.8% for transmission lines.

Production costs in 1965 By 1965 the remaining stations on the main branch of the Kemi river will be completed. These stations (Ossauskoski, Vanttauskoski) have a total installed capacity of 285 MW and nominal producibility of 1305 million kWh/year. The regulation lakes and transmission system for these stations will be the same as for the four first stations. The only addition compared to the situation in 1960 is in the capital cost of the plants themselves. The estimated figure now is 24. 20 FM per producible kWh instead of 22. 20.

70 The hydro production costs in 1965 will then be quoted as follows: Capital costs: Hydro plant 24. 20 FM/annual kWh Regulation lakes 1.66 " " " Power transmission 2. 60 " " Total 28.46 FM/annual kWh = 130, 000 FM/kW installed

The production costs are shown in Table 11.2.

TABLE 11.2.

1965 estimated hydro production costs

Interest rate {%) 6 8 Fuel cost (FM/Gcal) 500 750 500 750 Annual fixed charges: Hydro plant (FMAWh) 1.83 1.83 2.27 2.27 Regulation lakes (FM/kWh) j 0.33 0. 33 0.41 0.41 Power transmission (FM/kWh) J

Total fixed (FM/kWh) 2.16 2.16 2.68 2. 68 Running costs (FM/kWh) 0.13 0.195 0.13 0.195

Total unit cost (FM/kWh) 2. 29 2. 36 2.81 2. 88

Production costs show accordingly only a slight increase (about 7%) during the period 1960-65. This is quite understandable because of the similar nature of stations to be built in this period. It should be noted that no allowance has been made for improvements in engineering practice or in manufacturing techniques during this time. If such an allowance, e.g. 1% per annum, is applied the costs in 1960 and 1965 will be more close to each other.

Production costs in 1970 In 1970, after the main branch of the Kemi river has been build, hydro construction must move to less favourable small rivers (Ounas, Kitinen, Luiro, Tornio, Muonio). No definite plans are yet known, but some studies already made indicate that stations will be of rather small size (20-50 MW) and of high capital costs (in the region of 30 FM per producible kWh). Most of the remaining hydro potential is situated further away from the consumption areas than in 1960-65, so that transmission costs will be higher. The present 400 kV line may be sufficient for carrying the capacity of some smaller stations in the Kemi area, but for utilizing all the remaining potential in Lapland (3000-4000 million kWh/year) a second line is needed. Whether the remaining sources can be technically and economically exploited up to the economical capacity of this line is still uncertain. It may be safely assumed that in 1970 the most economical part of the remaining hydro resources will be under construction. One of these may be the rivers Kitinen and Luiro, because they are connected to the artificial lakes Lokka and Porttipahta. Preliminary plans have already been undertaken for developing these rivers, so that they can be taken as examples of hydro stations in 1970.

71 The three stations will have an installed capacity of 60 MW and a total nominal producibility of 250 million kWh/year. Capital costs are estimated to 29. 0 FM per producible kWh including some allowance for future improvements in construction methods. The addition due to the regulation lakes originates in this case from the artificial lakes only (1. 0 FM per producible kWh). Transmission costs may be taken as before because stations will certainly use the first 400 kV line. Hydro production costs in 1970 may then appear as follows: Capital costs: Hydro plant 29.0 FM/annual kWh Regulation lakes 1.0 " " " Power transmission 2. 6 " " " Total 32.6 FM/annual kWh = 136, 000 FM/kW installed

The production costs are shown in Table 11.3.

TABLE 11.3.

1970 estimated hydro production costs

Interest rate (<7o) ( £i Fuel cost (FM/Gcal) 500 750 500 750 Annual fixed charges: Hydro plant (FM/kWh) 2.19 2.19 2.72 2.72 Regulation lakes (FM/kWh) 0. 07 0. 07 0. 09 0. 09 Power transmission (FM/kWh) 0.21 0.21 0. 26 0. 26

Total fixed (FM/kWh) 2.47 2.47 3. 07 3. 07 Running costs (FM/kWh) 0.13 0.195 0.13 0.195

Total unit cost (FM/kWh) 2.60 2.67 3.20 3. 27

The increase in hydro production costs during 1965-70 is then around 15%. This example may, however, be more favourable than other projects on small rivers in 1970. In any case, between 1965-70 there will be a rather sharp increase, say 15-20%, in the hydro production costs.

11.3. Cost of power from coal-fired power stations

Establishing the datum capital costs for 1960

Few coal-fired stations have been built recently in Finland and the cost data available are, therefore, limited. Within the Imatran Voima system a steam plant is at present being constructed at Naantali, the first unit of 125 MW being due for commissioning in November 1960. Part actual and part estimated costs in some detail were available for the works associated with this first unit together with less accurate estimates for the additional work necessary to install a second similar unit. Although the site has been laid out for the possible installation of a third unit, the costs used are appropriate to two units only.

72 It was necessary first to see how typical Naantali might be of future stations. In the design of Naantali a major step forward was taken in steam conditions: Steam pressure at turbine stop valve 180 atm gauge reheat to 535°C Steam temperature at turbine stop valve 525° C and these are not considered likely to be greatly exceeded in the next station built. Site conditions are thought to be representative of future coastal sites. In the harbour some special provision, including a crane, has been made for the receipt of heavy plant components from overseas for Naantali and other power stations. In Finland costs of the major plant items (boiler and turbo-alternator) are very dependent on world market conditions. For Naantali the turbo-alternator order was placed when costs were high and the boiler when costs were low. Some small additional costs have been incurred by building a dual-fired, coal and oil, boiler, but no main storage installation for oil has been provided or included in the costs. These costs provide for the connexion of the generator to the 110 kV switchyard but do not include the further connexion to the higher- voltage transmission system. The costs also include an item for the interest payments incurred during the construction of the station. The costs include the appropriate equipment tax on plant items. With some adjustment of the harbour costs it is considered that these are appropriate for a coastal coal-fired station and are used as the datum coal-fired capital costs. Details of these datum costs adopted are given in Table 11.4. They are appropriate to two-set stations, of installed capacity 250 MW and net capacity 235 MW, situated on the coast and commissioned in 1960. The costs may be summarized as follows: Million FM FM/kW net Equipment and Civil Construction of power station 10,500 44,700 Engineering and contingencies 1,100 4,700 Interest during construction 800 3,600 Total capital cost 12,400 53,000

Forecasting future capital costs for coal-fired stations Any realistic assessment of future costs is difficult because of the lack of historical information. Finland's power industry is at present dependent on the heavy plant manufacturing industries of a number of other countries and plant costs are likely to vary to an extraordinary degree with market conditions. An increasing quantity of component parts, and in some cases complete units, e.g. transformers, are being manufactured in Finland and again it is difficult to predict how this will affect prices for the power industry. Judgment has, therefore, to be exercised on many points in making the best attempt to estimate likely costs in 1965 and 1970 from the single point established for 1960. For

1) Because of lack of domestic turbo-alternator manufacturing.

73 TABLE 11.4.

Datum thermal capital costs for 1960 (Based on Naantali station of 250 MW installed and 235 MW net)

Millions FM FM/kW net Set No. 1 Set No. 2 Total 1. Site Land 150 (150) Site preparation 350 (350) Roads & rails 30 ( 30) Temporary buildings and equipment 65 ( 65) 595 2, 530

2. Boiler Plant 1,258 1,500 2,758 11,730 Building & foundation 310 300 610 2,600

3, 368 14, 330

3. Turbo-alternator Plant 1,855 1,500 3,355 14,280 Buildings & foundations 510 500 1,010 4,290

4,365 18,570

4. Transformers & switchyard (Plant costs only; levelling etc. under site preparation) Main transformers 150 200 350 1,490 110 kV switchyard 50 50 213

400 1,700

5.. Auxiliary electrical equipment 150 150 300 1,280

6. Coal unloading & handling Harbour plant 83 83 353 Civil 117 117 498 Coal stock plant 47 47 200 Civil 48 48 204 Handling plant 110 110 468

405 1,723

7. Cooling water Pumphouse 40 ( 40) Intake & outfall works including tunnels 55 ( 55) 95 404

Plant costs included but small

8. General buildings & equipment Office & Workshop 200 (200) Control room 120 100 (220) 420 1,790 9. Additional expenses Living quarters 200 50 (250) Social expenses (180) Extra erection labour (120) 550 2,340

Sub-total "A" 10,498 44,670

74 TABLE 11.4. (cont'd)

Millions FM FM/kW net Set No. 1 Set No. 2 Total 10. Engineering & supervision Engineering (Head office) 300 100 (400) Local supervision 150 50 (200) 600 2,550

(i.e. 5.72% of sub-total "A")

11. Contingency sum 200 300 500 2,130

Sub-total "B" 1,100 4,680

(i.e. 4.74°lo of sub-total "A")

12. Interest during construction 500 336 836 3,560

(i.e. 7. 2<7o of sub-total "A" plus sub-total "B")

13. Total cost of complete station Sub-total "A" 10,498 44,670 Sub-total "B" 1,100 4,680 Interest during construction 836 3,560 Total cost 12,434 52,910

14. Cost per kW net 53,000 FM/kW net

commissioning during 1965 design decisions would have to be taken during this year and orders placed in the first half on the next, so designs would be based on current thinking. For commissioning during 1970 developments of the next five years can be taken into account before designs are settled. The more important factors which may affect future capital costs and to which some analysis may be applied are: a. Improvement of production techniques in plant manufacturing and civil engineering techniques with time. b. Lowering of plant and civil costs per kW of electrical capacity with increase in size of generating units. c. Lowering of ancillary plant and civil costs per kW of electrical capacity with reducing heat rate. Each of these factors is considered in turn. a. Improvement of production techniques in plant manufacturing and civil engineering techniques with time As mentioned previously, Finland is able to call upon the heavy plant industries of a number of other countries and no quantitative historical evidence is readily available for all the potential suppliers. The need to allow for this factor was accepted and a 1% per annum increase in the cost of all plant items has been incorporated, a rather lower rate of increase than might be deduced from evidence in countries where such equipment is being developed. On the civil engineering side the construction at Naantali, on which the aatum costs were based, was undertaken by the Civil Engineering Department of Imatran Voima which has had many years experience in building hydro stations. No allowance has been made for the lowering of civil engineering costs with time.

75 b. Lowering of plant and civil costs perkWof electrical capacity with increase in size of generating units From consideration of system requirements, maximum single generating unit capacity for the two years under study are: 1965 150 MW net 1970 250 MW net With these unit sizes it may not be possible to install two or more units at one site in quick succession with present ideas on transmission capacity. There are, however, considerable capital economies to be gained by installing two or more units in the generating station and costs have been evaluated both for single-set and for two-set stations. The major component which shows this reduced cost with size is the generating unit itself (boiler, turbine and generator) and the auxiliary equipment and the civil works directly associated with it. After considering foreign experience these costs were reduced in the following way: Date 1960 1965 1970 Net capacity of unit 117.5 150 250 Reduction on datum Datum 7% 22% The datum costs are based on a two-set station. The major increased costs per kW of capacity that would occur in a single-set station would be on site preparation and on the civil works associated with the circulating water, with a smaller increase in ancillary plant items and in other civil engineering works on the site. Allowances for these increases have been made for the single-unit stations for 1965 and 1970.

c. Lowering of ancillary plant and civil costs per kW of electrical capacity with reducing heat rate The capital costs of some ancillary components in the station, e.g. the works associated with circulating water, are lowered with reducing heat rate. For reasons given in the next section, however, the heat rate improvement over that appropriate to the datum costs is not thought likely to be great. The estimated change in capital costs on this account is not significant and has not been incorporated in the figures used. Taking account of these relevant factors, the total capital costs used in the unit generation cost calculations become:

Year Set size Total capital cost FM/kW net MW net Single-set Two-set station station 1960 117 5 53,000 1965 150 53, 000 47,000 1970 250 42,000 38,000

Changes in heat rate

As already noted, a major step forward in steam conditions was made in the Naantali station and steam temperatures and pressures were adopted which havebeenthe economic choice elsewhere for a base-load generating unit of more

76 than double the Naantali unit capacity. The steam temperature at the turbine valve (525°C) selected is close to the present limit for ferritic steels and dis- cussions suggest that there is no desire to move above this limit. Over a period this limit will itself be raised and it is thought that a modest increase in the steam temperature to say 550°C might be adopted. Assuming that the reheat temperature were also increased, this would correspond to an improvement in heat rate of about 2% and this is allowed for in the estimate of 1970 costs, the 1965 heat rate remaining unchanged. If towards the end of the period there appeared to be an economic case for a supercritical unit, the improvement in the heat rate would probably be accom- panied by increased capital costs. The capital cost estimate and heat rate used in this report are both appropriate to subcritical units. There is likely to be a modest improvement in heat rate due to increased generating unit capacity, the present experience suggesting a lowering of heat rate by 1% for a doubling of unit capacity. This has been applied to the 1970 costs, the 1965 heat rate remaining at datum. From these two effects the estimated heat rate for 1970 is reduced from the datum figure of 2400 to 2325 kcal/kWh.

Fuel cost At present the delivered heat cost from oil fuel is some 30% higher than from coal. The datum capital costs are for a coal-burning station and generation costs for a coal-burning station only are calculated. Delivered coal prices have shown wide variation over the last ten years but are particularly low at present. Expressed as a heat cost they have varied from rather less than 500 FM/Gcal to twice this figure. These prices include tax and unloading charges in addition to freight, the three items accounting for some 40% of the delivered cost. A typical mark-up for Polish coal would be: Coal price f.o.b. 1750 FM/ton Freight 720 " Tax 270 " Unloading charges 200 2940 FM/ton Calorific value 6000 kcal/kg Heat cost 490 FM/Gcal The f.o.b. coal prices depend very much on the state of the European coal market and are not considered capable of future prediction. The present low price cannot be assumed to continue indefinitely, although only a modest price rise would bring other coal suppliers into the competitive market. Freight rates may also harden and it is considered prudent to take a range of heat costs from 500 FM/Gcal to 750 FM/Gcal delivered at the coast both for 1965 and 1970. Coal supplies may not be received regularly because of frozen harbours throughout the year. In a typical case no coal might be received during the four months January to April inclusive. For lowest cost working the coal stock must have four months supply at the beginning of January and be empty at the end of April, which corresponds to two months average burn in continuous stock. Al- though this might well be exceeded in practice to ensure adequate fuel supplies at the end of winter, much depends on the degree of flexibility of the load regime at the station. Interest payments on a stock of two months burn has been used in the cost estimates.

77 Other costs The only other cost allowed for in the generation cost estimates is that of operation and maintenance. After discussion a figure of 1800 FM/kW net/year has been used at all utilization factors, no attempt being made to separate fixed and running components. The same figure has been used for each year under study, no allowance being made for the probable reduction in operating staff with increasing size of generating unit. No sosts are included for ash disposal as it is considered that some of the ash would be sold, off-setting costs incurred in the local disposal of the re- mainder.

Unit generating costs Generation costs per net kWh are given in the following tables. Table 11.5. shows the make-up of the unit cost for the datum 1960 station for the four utilization factors of 50%, 60%, 70% and 80% consistently used in this study. Unit costs for 1965 are given in Table 11.6. and for 1970 in Table 11.7.

Annual fuel bill For the coal-fired generating stations, operating with an 80 % utilization factor, the annual tonnage of'fuel consumed and the corresponding approximate annual f. o.b. and delivered fuel costs at the lower heat cost of 500 FM/Gcal would be as follows : Year Station Annual fuel f. o.b. Annual fuel cost Size Consumption 109 FM MW net Metric tons Delivered 1965 2 x 150 841,000 1.5 2. 5 1970 1 x 250 679,000 1.2 2.0 1970 2 x 250 1, 358, 000 2.4 4.1

Capital requirement The capital cost of the generating stations listed above would be: Year Station size Capital cost MW 109 FM 1965 2 x 150 14.1 1970 1 x 250 10. 5 1970 2 x 250 19. 0

11.4. Peat fired stations The earliest plans to use peat for the generation of electricity in Finland were drawn up 50 years ago. Primitive methods of collecting and preparing fuel would, however, have resulted in high fuel costs. The main question in peat economy is still that of the cost of heat although working methods have improved considerably. At present the mechanized milling method seems to be most attractive for large scale production. In Finland econimical peat areas are rather small and widely distributed (see Chapter 5). This, together with unfavourable meteorological conditions sets some limits to the possibilities of economic production.

78 TABLE 11.5.

Thermal generation costs - 1960

235 MW net station Generating unit size - Capital cost - 53, 000 FM/net kW 117. 5 MW net Heat rate - 2, 400 kcal/net unit

Utilization factor Interest rates 6 % 8 °lo

°lo Heat cost (FM/Gcal) 500 750 500 750

FM/n et unit

Capital charges 0.947 0.947 1.134 1.134

Heat cost 1.200 1. 800 1. 200 1.800 50 Operation costs, etc. 0.411 0.411 0.411 0.411

Coal storage 0. 012 0. 018 0.016 0.024

Unit cost 2.57 3.18 2.76 3.37

Capital charges 0.789 0.789 0. 945 0.945

Heat cost 1. 200 1.800 1.200 1.800 60 Operation costs, etc. 0. 343 0.343 0.343 0.343

Coal storage 0. 012 0.018 0.016 0. 024

Unit cost 2.34 2. 95 2.50 3.11

Capital charges 0.676 0.676 0. 810 0.810

Heat cost 1. 200 1.800 1.200 1. 800 70 Operation costs, etc. 0. 294 0. 294 0.294 0.294

Coal storage 0. 012 0. 018 0.016 0.024

Unit cost 2.18 2.79 2.32 2.93

Capital charges 0. 591 0. 591 0.708 0.708

Heat cost 1. 200 1. 800 1.200 1. 800 80 Operation costs, etc. 0. 257 0. 257 0.257 0.257

Coal storage 0. 012 0. 018 0.016 0. 024

Unit cost 2. 06 2. 67 2.18 2.79

79 TABLE 11.6.

Thermal generation costs estimated for 1965

150 MW net station 300 MW net station Generating unit size - 150 MW net Capital cost - 42, 000 FM/net kW Capital cost - 47, 000 FM/net kW Heat rate - 2,400 kcal/net unit Heat rate - 2,400 kcal/net unit

Units Utilization factor Interest rates 6 8 6 8 1o

Heat cost FM/Gcal 500 750 500 750 500 750 500 750

50 Unit cost FM/net unit 2. 57 3.18 2.76 3. 37 2.46 3.07 2.63 3.24

60 Unit cost FM/net unit 2.34 2. 95 2. 50 3.11 2. 25 2. 86 2.40 3.00

70 Unit cost FM/net unit 2.18 2.79 2. 32 2. 93 2.10 2.71 2.23 2.84

80 Unit cost FM/net unit 2. 06 2. 67 2.18 2.79 1. 99 2. 60 2.10 2.71

TABLE 11. 7.

Thermal generation costs estimated for 1970

250 MW net station 500 MW net station Generating unit size - 150 MW net Capital cost - 42, 000 FM/net kW Capital cost - 38,000 FM/net kW Heat rate - 2, 325 kcal/net unit Heat rate - 2,325 kcal/net unit

Units Utilization factor Interest rates 6 8 6 8 %

Heat cost FM/Gcal 500 750 500 750 500 750 500 750

50 Unit cost FM/net unit 2. 33 2. 92 2.49 3.08 2. 26 2. 85 2.40 2. 99

60 Unit cost FM/net unit 2.14 2.72 2. 27 2.86 2.08 2. 67 2.19 2.78

70 Unit cost FM/net unit 2.00 2.59 2.11 2.70 1.95 2.54 2.05 2.64

80 Unit cost FM/net unit 1. 90 2.48 1. 99 2. 58 1.85 2.44 1.94 2.53

Peat deposits in western Central-Finland are at present considered suitable for peat power stations. The size and location of deposits suggest a maximum capacity of 60-90 MW for a station, and the area would have resources for 3-4 stations of this size. Experimental peat production with modern machines has been under way for some time and the experience gained hitherto indicates that the heat cost would be no more than 700-800 FM/Gcal free in station. With further improvements and more experience this limit may be reduced.

80 Preliminary plans call for the commissioning of the first peat station in 1965-66. This would have a capacity of 75 MW gross and because the siting is still undecided, no detailed cost estimates have been worked out. Capital costs will, however, be somewhat more than in a coal-fired station of the same size. The estimated figure of 64,000 FM/kW net (for a 75 MW coal station) is certainly not far from being realistic. Self-consumption in a peat station will be little more than in a coal-fired station. A rough estimate gives Some 8% for self consumption, resulting in a 69 MW net rating for a 75 MW station. Taking this into account, the modern steam conditions (520°C 120 atm abs.) are expected to lead to a net heat rate of 2600 kcal/kWh for a 75 MW unit. Operating and maintenance costs also are expected to be higher in a peat station than in a coal-fired station. These costs are estimated at 2500 FM/kW per annum. Because of meteorological conditions the effective peat production time is limited to about 4 months in a year unless new methods of winter operation are used. Some provision must then be made for the interest on peat storage. If a linear production rate in 4 months and a steady burning rate throughout the year are assumed, a continuous stock of about 4 months is obtained. The interest has accordingly to be charged on 1/3 of annual consumption of peat. With the above assumptions the price of energy from a peat station in 1965 and 1970 was calculated. Tables 11.8. and 11.9. review the results obtained. For 1970 conditions some allowance, for improvements and reductions in capital costs and heat rate, has been made similarly to coal-fired stations. Also a somewhat lowered heat cost of 600-700 FM/Gcal is assumed in 1970.

TABLE 11.8.

Estimated cost data for peat-burning stations

Commissioning year 1965 1970 Net rating (MW) 69 69 Plant life (years) 25 25 Net heat rate (kcal/kWh) 2600 2500 Capital costs (FMAW) 64000 55000 Fuel costs (FM/Gcal) 700-800 600-700 Operation and maintenance costs (FM/kW year) 2500 2500

The production cost estimates are shown in Table 11.9.

TABLE 11.9.

Estimated production costs for a peat-fired station

Production costs:

Load factor (°Jo) 50 50 Interest rate (°Jo) 6 8 6 8 Fuel cost (FM/Gcal) 700 800 700 800 600 700 600 700 Unit cost (FM/kWh) 3.57 3.83 3.81 4.09 3.08 3.34 3.29 3.54

Load factor (°Jo) 60 60 Interest rate (1o) 6 8 6 8 Fuel cost (.FM/Gcal) 700 800 700 800 600 700 600 700 Unit cost (FM/kWh) 3.28 3.54 3.48 3.74 2.82 3.08 3.00 3.25

81 TABLE 11.9. (cont'd)

Load factor (

Load factor (%) 80 80 Interest rate (%) 6 8 6 8 Fuel cost (FM/Gcal) 700 800 700 800 600 -. 700 600 700 Unit cost (FM/kWh) 2.93 3.19 3.08 3.35 2.50 ' 2.76 2.63 2.89

It may be noted that production costs of peat stations are higher than those of coal stations, even with the same fuel price. This difference is due to smaller size of the former which is associated with higher capital and operational costs/kW. In fact, in base-load operation for example (load factor 80%), the production costs of peat and coal are equal if the price of peat is about 150 FM/Gcal less than that of coal. The cost of power transmission has been neglected above. Because the siting of peat stations is more or less fixed, some transmission lines to the interconnected grid may be meeded. In the case of Central-Finland, however, stations will actually reduce the need of power transmission from the North and the overall transmission costs may be in fact negative. This would then reduce the production costs, but this correction has been neglected as it is well within the margin of error of the other data.

12. COST OF NUCLEAR POWER

12.1. Introduction

Within the general framework and timetable of the present work it was not intended that any design study of a nuclear station, optimized for Finnish conditions, should be made. Neither is it known what type of contractual arrange- ment would apply when the first nuclear station is built in Finland. It is possible that a Finnish power company would enter into a contract with an overseas supplier for a complete station. This would not, of course, preclude a measure of Finnish control over the design, selection and layout of plant, as well as the sub-division of the work, into several sub-contracts, some of which may go to Finnish firms. The established practice of arranging for the maximum contribution of the Finnish industry to the conventional part of the station may well be followed. It should also be emphasized that the purpose of this chapter is not to derive from economic considerations the type of power reactor best suited to Finland. It is too early to make a specific analysis based on a certain type of reactor, with well-defined technical characteristics and purchased under given financial conditions. The purpose of the present chapter is to suggest a range of nuclear power costs which may be achieved in the next decade, by taking certain proven reactor systems merely as examples. There is no question of choosing, on the basis of this preliminary analysis, between a natural uranium fuel cycle and an enriched uranium fuel cycle.

82 12.2. Limitations of the available cost data It must be borne in mind, when making cost estimates, that nuclear power is still in its early phase of development. As yet, a large amount of experience either with the construction or the operation of nuclear plants for electricity production on a commercial scale is not available. Many of the plants now in existence, upon which the cost data are based, are experimental, prototype or multipurpose plants. Similarly, nuclear fuel costs are largely dependent on the policies of the governments which are able to produce fissionable materials and to manufacture and reprocess these fuels. There is considerable uncertainty as to the cost of fuel manufactured or reprocessed on a commercial scale. A further limitation of the usefulness of published cost data is that these are specific to a given situation only and generally applicable to the country of origin. A valid comparison between different reactor systems developed in different countries must depend on the reduction of all cost datja to a common basis.

12.3. Investment costs Normalized cost data based on studies made in the United States and in Britain have recently been reported by the International Atomic Energy Agency at its General Conference1). These are summarized in Tables 12. 1. and 12.2.

TABLE 12.1-.

Initial investment and operating and maintenance costs for medium and large nuclear power stations based upon recent United States studies2)

Initial investment (US $/kWe) Type of reactor Capacity Plant Fabricated fuel (in core) Operation and maintenance costs (net M We) (US $/kWe/year)

Pressurized Water 75 435 145 9.6 200 282 120 5.5 300 242 120 4.1

Boiling Water 75 470 100 9.7 200 311 75 5.6 300 263 57 4.2

Organic Moderated 75 350 130 13.1 200 241 130 9.0 300 220 120 7.6

Heavy Water Natural Uranium^ 75 640 31 12.7 200 425 12.4 8.0 300 360 9.6 6.4

Gas-cooled Natural Uranium 75 675 9.7 200 452 88 5.6 300 380 4.2

1) "The Development of Nuclear Power", IAEA General Conference, Fourth Regular Session, Paper GC (IV) /123. 2) USAEC, Power Cost Normalization Studies, SL-1674 relating only to planned reactors. 3) Heavy water inventory costs included in plant cost.

83 The estimates for the gas-cooled reactor plants in Britain are based on an averaging of the costs of the latest large commercial power stations being built at present.

TABLE 12. 2.

Initial investment for nuclear power stations based upon recent United Kingdom studies1)

Type of reactor Capacity Reactors Initial investment (US $/kWe) (net MWe) per Station Plant Fabricated fuel in core

Gas-cooled Natural uranium 50 1 700 45 - 60 300 1 280 45 - 60 250 2 295 45 - 60

There have also been estimates, based on the design of the advanced gas- cooled reactor at present being constructed for the Atomic Energy Authority at Windscale, which indicate that a large power station of this type with two 250 MWe reactors could be built in Britain at $ 280/kWe by 19652). As a basis for comparison with coal-fired power stations in Finland two types of reactors will be taken as examples. The graphite-moderated, gas-cooled reactor will be taken as representative of a natural uranium fuel system3). The boiling-water reactor Will be taken as an example of the enriched uranium system4). The question of conventional or nuclear superheating remains to be studied at a later date.

12.4. Basic tender price and total investment cost The method used to arrive at the capital cost estimate, therefore, was to take as a starting point the best estimate of the tender price of a station constructed in the supplying country and treat this as basic price. This price would not be appropriate to Finland if civil engineering construction costs were different from those in the supplying country. No rigorous study was made of this point, but construction cost figures available for a coal-fired station show that these are comparable to other countries in Western Europe. The sizes taken for comparison purposes are 150 MW net and 250 MW net. These were considered to be maximum unit sizes which could be installed in 1965 and 1970 respectively. Obviously not even a 150 MW nuclear plant is en- visaged for 1965. The analysis of the possible development of the thermal capacity shows that a 150 MW or 250 MW station may be utilized with a good (above 70%) load factor in 1970. The 1965 figures are therefore illustrative only.

1) FLETCHER, P. T., Atom (February 1960). 2) WAUGHAN, R. D., "Technical and Economic Development of the Gas-Cooled Reactor", World Power Conference, Madrid, Paper IV B/ll (1960). 3) It is fully appreciated that a heavy-water moderated system using natural uranium (oxide) as fuel has excellent prospects for achieving very low fuel costs. However, the cost data for such a reactor are not so complete at present, since the first such reactor will be commissioned in 1963-64. 4) This choice does not mean the selection of the boiling-water as the most suitable system for an enriched fuel cycle. The pressurized-water and the organic-moderated reactors must also be taken into account in a detailed comparative study.

84 Whereas the "unit" system of coupling a single boiler with a single turbo- alternator set may be applied up to 250 MW sizes in the case of a coal-fired station, it is considered that for a nuclear station more than one generating sets may be associated with reactors of large size. To this basic price must be added the freight cost for the plant items and the insurance during transit. Some items to be transported are carried at normal bulk rates, others are special loads. A rough segregation suggests a representative overall figure for transportation including insurance from Con- tinental ports of 5% of the cost of the items transported, i. e. approximately 2.5% of the basic price. The equipment tax payable in Finland1) at the rate of 15% ad valorem adds 7. 5% to the total tender price. The acquisition of the site, the provision of the site services, of living quarters for the personnel and the connexion of the station to the network are additional to the tender price. An allowance of 4000 and 3000 FM/kW net for the 150 MW and 250 MW sizes respectively has been made for these items, following the study of the similar items for the reference coal-fired' station. The basic price includes a provision for engineering and construction or erection supervision by the manufacturer, but it is considered prudent to allow for additional engineering and supervision usually carried out by the Finnish power undertaking. A contingency sum is also allowed for, primarily to cover changes in detailed design once the contract is let. A total of 5% of the cost of the station has been included for these items taken together. The final addition to obtain costs comparable with those used in coal-fired stations concerns the interest payments incurred during the construction. A discussion of the reference coal-fired station costs indicated that this was dependent on the particular terms of payment under the various contracts. The cumulative effect of interest during construction has been taken as equivalent to an increase of the cost by 10%. This neglects the difference between the two basic interest rates (6 and 8%) taken, but the difference is considered within the error of the many assumptions made. It follows that the total investment cost (excluding fuel) as a function of the basic tender price may be given by the formula: Total investment cost = 1.1 x (1.15 x Basic tender price + A) where A is 4000 FM/kWe and 3000 FM/kWe for the 150 MW and 250 MW plants respectively. The estimated capital costs for these two systems are shown in Table 12.3.

TABLE 12.3.

Estimated capital costs for nuclear power plants built in Finland (103 FM/kW net)

Gas-cooled, natural uranium Boiling-water

Reactor net electrical capacity (MWe) 150 250 150 250

Basic tender price 126(US$400) 90(US$280) 96(US$300) 70(US$220)

Total investment (excluding fuel) 165 118 126 93

Assumed year of commissioning 1965 1970 1965 1970

1) There is no incication that the government will give a preferential treatment to one or another type of power plant by exempting it from this tax. Although, theoretically, the pure economic benefit to the country can be better evaluated independently of the taxes, the real situation requires that taxes be included in the comparison.

85 It should be noted that the basic price for the gas-cooled reactor is taken from British estimates and that for the boiling-water from the US estimates. The total investment costs shown may appear rather large, but it must be remembered that they are looked at from the viewpoint of the power undertaking which has to meet many costs other than the basic tender price. The difference between the 1965 and 1970 costs is due to the increased size and only to a small measure to the improvements expected with time.

12.5. Fuel costs Although Finnish uranium is now being processed on a small scale and "yellow cake" concentrates are being produced, no cost data is available for the possible production of metallic uranium in Finland. In any case, it is not the purpose of this study to indicate the direction in which the nuclear fuel policy of a future Finnish nuclear power programme should be guided. It is merely assumed that nuclear fuel will be available at world prices. The fuel element fabrication and reprocessing costs can at present be based on a substantial through-put of similar elements, which could exist only in the country of origin of the fuel elements. Special fuel elements of an entirely novel design for any single station would increase the costs substantially.

Natural Uranium Nuclear stations commissioned in 1965 or in 1970 would most probably benefit from the reduction in the world prices of natural uranium which is expected to take place when the present post-war contracts expire. Considering that already offers of natural uranium have been made for a price of US$34^cg, a world price level of $25/kg may well be established by 1965. Fabrication costs for natural uranium elements are probably around $16/kg at present and may be expected to go down to about $10/kg by 1970. The former figure will be assumed to apply in 1965 and the latter figure in 1970. It is assumed that the 150 MWe reactor (in 1965) would have a specific power of 0.7 kWe/kg, and that the 250 MWe reactor (in 1970) would be designed with a specific power of 0. 9 kWe/kg of fuel. Since it is assumed that a 2-months supply is required for reserve and a further 2-months supply is required for cooling at the station, this total of 4-months supply increases the inventory per kWe by approximately 10% for a 150 MW reactor in 1965 and by 7% for a 250 MW reactor in 1970. Thus the fuel inventory costs per kWe are estimated at $64 (or 20,400 FM) for the 150 MW reactor commissioned in 1965 and at $42. 2 (13, 500 FM) for the 250 MW reactor commissioned in 1970. Regarding the fuel cycle costs, it will be assumed that the average burnup is 3000 MWd/ton and that some advantage exists in returning the irradiated fuel to a reprocessing plant which is assumed, for the purposes of this study, to be in the supplying country. This advantage naturally depends on the value of natural uranium, the "buy-back" price and the transportation cost of irradiated elements. It will be assumed conservatively that a $3/kg net credit is involved in this process. The alternative possibility of increasing the burnup to the limit and not reprocessing the fuel may, at some future time, be seriously considered. Thermal efficiencies, based on actual design data of planned reactors have been taken as 29% for the 150 MWe reactor commissioned in 1965 and 33. 5% for the 250 MWe reactor commissioned in 1970, due allowance being made for the low (5°C) average condenser inlet water temperature in Finland.

86 The net fuel costs are therefore estimated at 1.83 mills (or 0. 59 FM) for the 150 MW reactor and 1.33 mills (or 0.43 FM) for the 250 MW reactor. It is obvious that these two reactors would, over the greater part of their lives, enjoy the same benefits regarding fuel, fuel fabrication or transportation costs, so that their average net fuel costs would not differ by a large margin, but it is suggested that the two above figures may be taken as the high and low limits which may apply.

Enriched Uranium Regarding enriched uranium, what has been done was to take the US list prices which have long been published and to estimate the influence of the reduction of natural uranium prices to $25/kg on the price of enriched uranium. The 1965 case is assumed to represent the present technology in reactor design and fuel fabrication, while the 1970 case is to reflect several expected improvements in the field of boiling-water reactors. The average specific power is, for instance, taken as 3.5 kWe/kg of fuel in the 1965 case and 6.0 kWe/kg in the 1970 case. Other parameters are shown in Table 12. 5. The prices of 1.9% and 2.1% enriched uranium are taken as $150/kg and $180/kg respectively, when the price of natural uranium goes down to $25/kg. The fabrication costs assumed are $140/kg for 1965 and $l00/kg for 1970. Four months supply of fuel in addition to that in the core constitutes the fuel inventory. This is equivalent to 12. 2% and 14. 3% more fuel per kWe than in the core for the first and second cases respectively. Under these assumptions the fuel inventory cost amounts to $93 (or 30,000 FM) per kWe for the reactor commissioned in 1965 and $53.5 (or 17,000 FM) per kWe for the reactor commissioned in 1970. For the fuel cycle costs a net credit of $45/kg of fuel is assumed to exist for returning the irradiated fuel to a reprocessing plant in the supplying country. The net fuel costs are therefore estimated at 2.9 mills (or 0.92 FM) per kWhe for the reactor in 1965 and at 1.96 mills (or 0.63 FM) per kWhe in 1970. Similarly to the natural uranium case these must be considered as the upper and lower limits over the lifetimes of the two reactors.

12.6. Other costs Insurance is of significance in the case of a nuclear power plant whereas it could be neglected for a conventional plant. Limited guidance is available in Finland since the question has not yet arisen, but from a study of practices in other countries which have already started work in this field, a simple assump- tion of an annual premium of 1% of the capital cost of the station (including fuel inventory) has been made. Operation and maintenance costs for a nuclear station have been taken as 10% higher than the corresponding costs for a coal-fired station, i. e. 1980 FM/kW net, without any subdivision into fixed and running components.

12.7. Summary of costs Details of the nuclear power generating costs are given in Tables 12. 4-. and 12.5. An amortization period of 20 years has been assumed. Calculations refer to two alternative interest rates (6 and 8%) and to a range of utilization factors ranging from 50% to 80%. The point has already been made that the capital costs of the different reactor types are not equally well based on experience. Some

87 00 TABLE 12. 4. 00

Estimated nuclear generating costs

(Gas-cooled natural-uranium system)

Basic data

Reactor net rating (MWe) 150 250

Station thermal efficiency (%) 29 33, .5

Fuel burnup (MWd/t) 3, 000 3, 000

Fuel inventory cost (FM/kW) 20,400 13, 500

Assumed date of commissioning 1965 1970

Capital cost (excl. fuel) (FM/kW net) 165, 000 118, 000

Cost of generation

Interest rate ('7°) 6 8 6 8

Utilization factor ("Jo) 50 60 70 80 50 60 70 80 50 60 70 80 50 60 70 80

Capital charge (FMAWh net) 3.28 2.73 2.34 2. 05 3.84 3.20 2. 74 2.40 2. 35 1.96 1.68 1.47 2.74 2.29 1.96 1.72

Fuel inventory " 0.41 0.34 0. 29 0.25 0.47 0.40 0.34 0.30 0. 27 0. 22 0.19 0.17 0.3i 0. 26 0. 22 0.20

Fuel replacement " 0.59 0.59 0. 59 0.59 0. 59 0.59 0. 59 0.59 0.43 0.43 0. 43 0.43 0.43 0.43 0. 43 0.43

Fuel hold up 0. 01 0. 01 0. 01 0.01 0. 01 0.01 0.01 0.01 0. 01 0. 01 0. 01 0.01 0.01 0.01 0. 01 0. 01

Operation & maintenance 0. 45 0.38 0. 32 0.28 0.45 0. 38 0. 32 0.28 0. 45 0.38 0. 32 0. 28 0. 45 0. 38 0. 32 0. 28

Insurance " 0.42 0.35 0. 30 0.26 0.42 0.35 0. 30 0.26 0. 30 0.25 0.21 0.19 0. 30 0.25 0. 21 0.19

Total 5.16 4.40 3.85 3.44 5.78 4.93 4.30 3.84 3. 81 3.25 2.84 2. 55 4.24 3.62 • 3.15 2.83 TABLE 12. 5.

Estimated nuclear generating costs

(Boiling-water reactor system)

Initial enrichment of fuel (*) 1.9 2.1

Reactor net rating (MWe) 150 250

Thermal efficiency (%) 31.5 33.5

Fuel burnup (MWd/t) 11, 000 15, 000

Fuel inventory cost (FM/kW) 30,000 17,000

Assumed date of commissioning 1965 1970

Capital cost (FM/kW) 126, 000 93, 000

Cost of generation (FMAWh)

Interest rate (<#>) 6 6 8

Utilization factor <°]o) 50 60 70 80 50 60 70 80 50 60 70 80 50 60 70 80

Capital charges (FM/kWh net) 2. 50 2.10 1. 80 1.57 2. 90 2.44 2. 09 1.83 1.85 1. 54 1.32 1.16 2.16 1.80 1.54 1.35

Fuel inventory charge 0. 60 0.50 0.43 0.37 0.70 0.58 0. 50 0.44 0.34 0.28 0.24 0.21 0.40 0. 33 0.28 0. 25

Fuel cycle costs 0.92 0.92 0.92 0. 92 0. 92 0.92 0. 92 0.92 0. 63 0. 63 0. 63 0. 63 0.63 0. 63 0.63 0. 63

Fuel storage " 0. 01 0. 01 0. 01 0. 01 0. 01 0. 01 0. 01 0. 01 0. 01 0. 01 0. 01 0.01 0. 01 0. 01 0. 01 0. 01

Operation & maintenance " 0.45 0.38 0. 32 0. 28 0.45 0.38 0. 32 0. 28 0.45 0.38 0. 32 0. 28 0.45 0.38 0. 32 0.28

Insurance 0.36 0. 30 0. 26 0.22 0. 36 0.30 0.26 0. 22 0. 25 0.21 0.18 0.16 0.25 0. 21 0.18 0.16

Total 4. 84 4.21 3.74 3.37 5.34 4.63 4.10 3.70 3. 53 3. 05 2.70 2.45 3.90 3.36 2.96 2. 68 attempt has been made to predict the trend of the costs for 1970, but clearly many unforeseen developments may take place in the meantime. Truly competitive fuel costs will take some time to come about. It must be pointed out that in no case a design has been optimized for Finnish conditions. Undue importance should not therefore be attached to the small differences between the two reactor types. The purpose is to compare the prospective coal-fired station costs with the possible range of nuclear station costs.

13. COMPARISON OF NUCLEAR AND CONVENTIONAL POWER COSTS

13.1. Basis of the comparison Before comparing the estimated costs for future years of the power generated in a coal-fired and a nuclear station, it is well to consider the limitations of these estimates. The basic capital costs have been obtained by two fundamentally different methods. For the coal-fired stations they are based upon a reference datum applicable to 1960 (an actual station being completed in Finland), some suggested trends and some probable trends of costs towards the future. For the nuclear stations they are based upon the relatively limited data available on the commercial construction of complete power stations outside Finland. With the addition of some specific costs to the "basic price" an attempt has been made to reach the actual cost of a station to a power undertaking in Finland. Thus the aim has been to make the costs strictly comparable, but with these two different approaches the results must be qualified. Some reduction in the estimated capital costs of nuclear stations could result from the construction of many nuclear stations of the same type in other countries. There would then be scope for standardization of many of the component parts of the stations and for spreading of development costs. A reduction in price, if close repeats of the station were to be supplied to several other countries, of between 5 and 10% would not be impossible on these accounts. It must be pointed out, however, that no provision has been made in the estimates for spare parts for the capital equipment, although a purchaser of a plant from abroad niight wish to hold a stock of spares. On coal prices no attempt has been made to predict future trends. A low1) (500 FM/Gcal) and a high (750 FM/Gcal) heat cost has been used in the calculations. These representative heat costs include tax which is based on the "f.o.b. + freight" cost of fuel. For typical calorific value this amounts to approximately 10% of the delivered heat cost. For the nuclear fuel costs, it must be stated that apart from the natural uranium fuel truly commercial world prices are not yet established. The provision of enriched uranium is subject to bilateral or international arrangements and many components of the costs (such as the transport of irradiated fuel, reprocessing, etc.) can only be estimated very roughly. Some attempt has been made to estimate the influence of the expected reduction of natural uranium prices on the price of enriched uranium. No tax has been allowed for the uranium fuel.

1) The low value corresponds approximately to the present level in the cost of imported Polish coal. The high value is the average of the last 10 years.

90 It is no part of this study to take account of any special governmental action that may affect the cost of generation at nuclear power stations. The cost estimates have been made as they would appear to a power undertaking. The present rates have been adopted with respect to taxes on equipment and coal. The impact of these on the cost comparison between coal-fired and nuclear stations is rather arbitrary, however, and the effect of omitting both these taxes is discussed later. It is seen in Chapter 10 that sites on the south coast that may be used for constructing a thermal station could be (within the framework of this study) equally suitable for coal-fired or nuclear stations. Either type of station would, therefore, have the same relationship to load centres and would carry equal transmission costs. Their function within the integrated supply network would also be strictly comparable, at least for an appreciable part of their useful lives, since a modern coal-fired or a nuclear plant would increasingly take over the base-load generation as prospects for new low-cost hydroelectric stations diminish. Depending on the date of installation and the size of the thermal station, its utilization factor would increase in the early years of its life and remain at a high value for many years. Under these conditions, a simple comparison of the costs per kWh at the same utilization factor provides a satisfactory basis of comparison, provided that the true utilization factor selected is appropriate to the use of the plant over its whole life. More complete comparison involving the estimation of total system costs would be particularly difficult at present when the transition from a purely hydro system to a mixed thermal-hydro system is in its very early stages. It must be pointed out that a useful life of 20 years has been assumed for the nuclear station and the initial fuel inventory has been depreciated over the same period, whereas a useful life of 25 years has been assumed for the coal- fired station. Obviously, should the nuclear station be replaced after 20 years by a more efficient type and not by the same plant, the strict comparison of the cost of power would be affected. However, the effect of this is considered to be of secondary importance.

13.2. Discussion of the results

Figs. 13.1. and 13.2. show the comparison of coal-fired and nuclear power costs estimated for the 1965 and 1970 conditions. Obviously, the 1965 comparison is hypothetical since the power situation is not likely to allow the construction of a base-load thermal plant other than those already undertaken. It is seen, however, if a comparison were to be made on the basis of a 150 MW plant, that the nuclear costs would be far from competitive over the whole range of utilization factors, independently of the possible changes in the interest rate (6 or 8%) or the cost of heat from coal (500 or 750 FM/Gcal). In 1970, however, the situation may change considerably. Although the coal-fired power costs are reduced owing to the improvements discussed in Chapter 11, the nuclear power costs are expected to be reduced more radically. It must be stated that in this case the comparison is based on a larger plant (250 MW), but the development in the power situation is such that this size of thermal plant may easily be assigned a base-load duty in 1970.

91 6.0-t 6.0-

CaJ INTEREST RATE 6% Cb) INTEREST RATE 8%

i NUCLEAR \ 2 4.0H 4.0 NUCLEAR

is z < < cc cc HEAT COST 750 FM/Gcal Hi 304 HEAT COST 750 FM/Gcal 3.0H

< < i— i— o o

HEAT COST 500 FM/Gcal 2.0H HEAT COST 500 FM/Gcal 2.0-1

50 60 70 80 50 60 70 80 UTILIZATION FACTOR % UTILIZATION FACTOR %

Fig. 13.1.

COMPARISON OF ESTIMATED NUCLEAR AND COAL-FIRED PLANT GENERATING COSTS 1965 (150 MWe PLANT)

4.0-1 4.0 01 i— o

2.04 2.0-1 HEAT COST 500 FM/Gcal HEAT COST 500 FM/Gcal

50 60 70 50 60 70 UTILIZATION FACTOR % UTILIZATION FACTOR %

Fig. 13.2.

COMPARISON OF ESTIMATED NUCLEAR AND COAL-FIRED PLANT GENERATING COSTS 1970 (250 MWe PLANT)

92 The differences in the cost of power from different types of nuclear power plants are of secondary importance here. We are mainly concerned with the advantages of building a nuclear power plant, the exact characteristics of which will have to be very carefully determined at a later date. The main clear indication is that, under conditions of low interest rate (6%), a nuclear plant of 250 MW may become competitive at high utilization factors (80%) should the coal prices rise to give a heat cost higher than 750 FM/Gcal. It is impossible to predict the possible changes in the values of these different parameters over the next ten years. But, a close watch must be kept in Finland over the development of the cost of nuclear reactors and nuclear fuels, on the one hand, and the price of coal on the other.

13.3. Effect of taxes It has been stated that all the estimates discussed above included the equipment and coal taxes but assumed no tax for uranium fuel. It can be argued that the real benefit to the Finnish national economy, in choosing one form of investment over another, can only be seen clearly if the taxes (which correspond to internal transfer of money) are eliminated from the comparison. Taking a 250 MW station for 1970 as the basis and comparing a natural uranium gas-cooled reactor station with a coal-fired station at the highest practicable utilization factor of 80% the following differences are obtained.

Interest rate

Coal-fired 6% 8%

Heat cost 500 750 FM/Gcal 500 750 Total generation cost with taxes 1.90 2.48 FM/kWh 1.99 2.58 Total generation cost without taxes1) 1.75 2.29 FM/kWh 1.84 2.36

Nuclear Total generation cost with taxes 2.55 FM/kWh 2.83 Total generation cost without taxes 2.43 FM/kWh 2.69

The difference between the two generation costs in seen to remain marginal.

1) Omitting the tax on coal also reduces the heat cost to 450 and 675 FM/Gcal respectively.

93 14. CONCLUSIONS There can be no doubt that nuclear power has potentially a promising future in Finland. Already about one half of the 18, 000 million kWh/year hydroelectric potential, which is considered technically exploitable with present-day construction methods, has been harnessed. There are no coal or oil deposits in the country. Because of the large areas over which the peat deposits are distributed, this fuel has severe limitations in economical collection and production on a large scale. Finland's economy, which has made a remarkable recovery since the last war, continues to develop at a fast rate. Industrial investments have been kept at a high level and account at present for about one third of the total investment. This has led to a steady increase (at the rate of 4% per year) in the real national income. The average annual increase in electricity production has been approximately 10% since 1948. It is estimated that even with a relatively conservative rate of 8% per year in the next decade, the electricity production will reach about 19, 000 million kWh in 1970. According to the present plans and estimates for hydro development, about 60% of this will be generated by hydro power in a mean-water year. The remaining 40% will be thermal power and will amount to about 3. 8 million tons of coal. If about 1/3 of this can be generated (in back- pressure plants or process condensing plants) by the use of industrial and wood wastes as fuel, a total of 2.5 million tons of coal or its equivalent will be required in 1970 for electricity production alone. This is about ten times as much as today's consumption in a mean-water year and more than half of the present total fuel imports. Considering that these fuel imports amount to 15-18% of the total imports at present, a disproportionate increase in the importation of energy requirements is certainly not desirable in a country where foreign trade plays such a vital part in the economy. Thus the present lively interest in the prospects of nuclear power in Finland is entirely justified on national economic grounds. No long-term predictions concerning the possibilities for establishing a substantial nuclear power programme can be made at the present time, since the development of nuclear power is still in its early stages. The aim of this study has therefore been to look for the threshold conditions for the economical use of the first nuclear power plant in Finland. A period of ten years is probably the maximum under the present circumstances for any prediction of this kind. It will be seen in the relevant sections of this report that the picture regarding the future power situation becomes rather unclear towards 1970. An attempt has been made to predict the trends of power costs (both conventional and nuclear) for 1970. But these costs are subject to many assumptions and unforeseen developments may easily change the picture radically. For instance, nuclear power costs have been based on two types of power reactors selected as examples. While these types are today considered as proven and are most likely to remain in the field, the possibility of a technological "breakthrough" which may bring another type to the forefront cannot be ruled out. Whatever these uncertainties, however, it can be said that size and utilization factor will remain the main technical criteria for the introduction of nuclear power in Finland. Nuclear plants with their higher capital costs require large sizes and high utilization for economic operation. The present utilization of thermal plants in Finland (300 hr to 1500 hr in a year) does not permit the economic operation of a nuclear station. It is seen in Chapter 9 of this report,

94 however, that through the expected rapid expansion of thermal power during the next decade, both these parameters will be improved considerably. A thermal capacity of 100 MW is limited to a very low utilization (20%) in 1960, but this will increase to 40-45% in 1965 and 80-85% in 1970. It is estimated that a nuclear base-load plant of 250 MW can be operated in 1970 with a utilization factor of over 75%. Whether this base-load could be more economically produced in a coal-fired plant will depend, of course, on the relative economics of the two alternatives. In view of the uncertainty with regard to many of the elements of such a comparison, it has been considered wiser to be rather conservative in estimating the long-term cost reductions of nuclear power. The main criteria of economic competitiveness of nuclear power are the cost of coal and the rate of interest for the capital. At present, coal is available in Finland at a remarkably low price. This is the result of a sharp decline which took place in 1958. Our estimates lead to the conclusion that nuclear power will become economical in 1970, if coal prices were to go up by more than 50% of the present level. It is impossible to predict whether this will happen, but it must be remembered that' coal prices have fluctuated rather widely in the last ten years. A high value equivalent to twice the present level has also been experienced. The rate of interest in Finland has varied in recent years between 6. 5-8% for domestic financing and has been rather low (5-6%) for foreign financing. Thus, of the two alternatives (6% and 8%) used in this study the lower one is definitely realistic. It may therefore be concluded that the threshold conditions for economic nuclear power in Finland may be satisfied towards the end of the ten-year period which has been reviewed. This first study has aimed at identifying and discussing the factors which are important in any serious consideration concerning the use of nuclear power. The work of bringing the economic evaluations and comparisons up to date must continue and the next phase of the studies must be embarked upon as soon as clear indications as to the threshold conditions are observed. It is clearly difficult to lay down a complete plan of action for the next phase of the studies, but this phase must include: - studies on the domestic and foreign exchange requirements of a nuclear power project; - a detailed comparison of fuel cycle costs, including the possibility of using Finnish uranium; - optimization studies for determining the reactor sizes and the turbo- alternator unit sizes for best operation within the interconnected system; - power cost studies, based on many different power reactor systems; - a study on the possible advantages of non-nuclear superheating.

In addition to the above questions, which refer to the large central power station, it would be very advisable to initiate studies on the possibility of using smaller industrial power reactors capable of producing heat as well as electricity. The small sizes required, together with the desirability of using high pressure steam at the turbine inlet (of the order of 100-140 atm abs.) for a good turbine efficiency, have so far ruled out the possible application of heat reactors in Finland. Moreover, the present low cost of fuel (wood wastes, liquor or coal) is another obstacle in the way of the economic use of nuclear power for heat and back-pressure electricity. But this question must be studied as more data becomes available about such reactors. The possible use of small power plants in

95 remote areas in the north of the country should also be investigated in the light of the expected technical developments in the next decade. As and when the results of the above types of studies relating to the first nuclear power station become positive, .further studies on a substantial nuclear power programme should be undertaken. These will necessarily entail a comparative economical analysis of the alternative investment programmes and fuel costs over a long period of time, taking into account the appropriate operation of each plant within the system. While the present study has dealt with the specific conditions existing in Finland, it is felt that the method followed, the factors discussed and some of the data supplied are sufficiently general to be useful to a number of countries, especially those where hydro power is predominant. It is hoped that the pilot aspects of this study will be helpful to such countries in assessing the future prospects of nuclear power.

96 mmssmi mm.