9-1

PAPER 9

FUELS FOR ELECTRICITY GENERATION IN AUSTRALIA

By: D. G. EVANS*

SUMMARY

The generation of electrical power accounts for nearly half the fuel used in Australia. The present and future fuel usage pattern in this industry is therefore of vital importance to the balanced development of Australia's fuel resources. In the past coal has been the principal fuel for electricity, generation. However, with the development of new deposits of oil, gas, and nuclear fuels over the last few years, diversification can be expected, with the choice of fuel being made mainly for economic reasons. Nuclear power generation is not expected to become competitive with generation from fossil fuels until the early nineteen eighties in New South Wales and Victoria, and much, later in the less populous States. Thus, except, for specific non-economic reasons, nuclear stations will not be built for at least another ten years. In the meantime, with power consumption doubling every few years in most parts of Australia, a great development in coal-burning stations for base load, and oil and gas stations for peak load, can be expected in the eastern States, with oil and gas being used for both purposes in South Australia and Western Australia.

1. INTRODUCTION

Before 194-0 the annual consumption of electricity, in Australia was a few hundred kilowatt-hours per head - not much more than in many under-developed countries today. Most of this electricity was generated in small power stations located in capital cities, using fuels brought in for the purpose. Fuel costs were high and efficiencies low, with the result that electricity costs to the consumer were high. Long-distance transmission networks were rudimentary or non-existent.

Senior Research Officer, Department of Chemical Engineering, University of Melbourne, 9-2

In the period 19AO-50 the demand for electricity increased sharply as a result of enforced industrialization during the war and large-scale immi­ gration after it, and a major change of electricity generation and fuel usage policy emerged. Power stations were built on the coalfields, which in turn were mechanized to cope with the rapidly increasing demand for coal, and the electricity generated was transported to the centres of use by means of transmission networks.

This new policy, together with a steady increase in power-station efficiency, permitted a spectacular increase in generating capacity (Fig. 1), with little change in generating cost at a time of rapid cost increases for other basic commodities (Fig. 2). Today about three-quarters of Australia's electricity is produced by the combustion of coal in power stations on the coalfields, most of the remainder being produced in hydro stations.

This had been the policy followed for twenty years, until recently the generation of electricity in Australia entered a new stage characterized by a willingness to choose any possible fuel and burn it in any possible location, provided only that the choices fit into the overall pattern of developments in electricity generation.

The reasons for this change are complex; it is the purpose of this paper to identify and evaluate them, and in so doing to provide a basis for • predicting the pattern of fuel usage to be expected in Australia for the next 10-15 years.

2. FACTORS AFFECTING FUEL CHOICE

The choice of fuel for generating electricity will be. decided by a combination of the following factors:

(i) The overall cost of supplying electricity to the users' premises, including fuel costs, fuel transport costs, capital and operating costs of generating plant and transmission networks, and transmission losses.

(ii) The cost of pollution of various kinds when using some types of fuel. When the pollution can be prevented by using extra equipment the cost of the latter must be added to the overall electricity cost; when this is not feasible a decision must be made as to whether such pollution is tolerable.

(iii) The availability of the chosen fuel over the planned life of the power station, usually 20-30 years.

(iv) The availability of cooling water for the power station.

(v) The time taken between deciding on plant and producing electricity from it.

(vi) The possibility of disposing of waste by-product material from other processes by combustion and steam-raising.

(vii) Political factors.

2.1. Economic Factors

'' 2.1.1. !Fuel Costs.- Table T shows the costs of various fuels in Australia. Goal costs are those at the piower stations, as given by the annual reports of the electricity generating authorities, and include conveying costs from the coalfields.' Oil and gas costs are based o"n delivery to capital cities by tanker or pipeline. Nuclear fuel costs cannot be quoted in the same straight­ forward way, because the initial charge of fuel in the nuclear reactor is part of the initial capital cost of the station. Similarly capital costs in hydro­ electric stations are largely taken up by equipment for gathering "fuel" - in this case water.

Coal in South Australia, Victoria, New South Wales, and parts of Queensland is cheaper than in most other parts of the world. This is because much of Australia's coal occurs in thick seams, and open-cut mining methods can often be used.

2.1.2. Capital Cost of Plant.- The other main component of generating cost is the capital charge* to service borrowings on the capital cost of the plant. Table 2 shows the capital costs of various sizes and types of plant.

Since the capital cost per kW of installed capacity falls as the size of the equipment is increased, there is an inducement for new units to be as large as possible. The limit set by the potential disruption caused by shut­ downs for maintenance is that no individual unit should be larger in capacity than 10% of the grid it serves. Table 3 shows the capacities of the main grids in Australia in 1969, and the sizes of the largest units installed and of those being built or considered.

2.1.3- Operating Cost.- The operating cost of plant (manpower and main­ tenance) is closely tied to the capital cost. In calculations in this paper the'figure of 3*0% per annum is used.*- Although charges will vary somewhat with the type of equipment little error will be introduced by keeping the figure constant, as it is a relatively small proportion of the total cost of generating power.

2.1.4-. Overall Generating Costs and the Effect of Load Factor.- Overall generating costs can be calculated as the sum of the capital charge (incurred whether the plant is operating or not), the fuel cost (incurred only when the plant is running), and the operating cost (incurred mainly when the plant is running). Obviously such a calculation is very sensitive to the load factor, i.e. the ratio of actual output for a period to total output which would have been obtained had the plant run continuously at its maximum rating (m.c.r.).

Rig fluctuations in demand occur from month to month owing to weather changes, and also from hour to hour throughout each day. Fig. 3^ shows that the total installed capacity must be determined by the need to have some emergency reserve over the peaks occurring on the coldest winter days. The result is that about 50% of the plant will be running all the time (except for maintenance shutdowns)., while the remainder will run only part of the time, some of it for perhaps 5-10 hours a day more or less throughout the year and some only 1-2 hours a day on only the coldest days of the winter.

On this basis plant can be divided into three categories: base-load* plant running at overall annual load factors of 70-80%, peak-load plant operating at annual load factors of 20-40%, and reserve plant operating at annual load factors of only 0-5%.

* This includes depreciation allowances, usually calculated-over a 20- or 25-year period, and interest charges on the undepreciated residue. , For' the purpose of calculation in this paper a total flat rate of 9% per annum"for a 25-year period will be used.*- 9-4

Table U shows generating costs calculated for various fuels for each of the grids mentioned earlier, for load factors of 80$, 2%, and 2%, repre­ senting the three categories of equipment mentioned above, and for units as large as the various systems could cope with at the present time.

2.1.5. Energy Transport Costs.- It is cheaper to transmit large quantities of electricity than the corresponding quantities of coal. However, for other forms of energy the situation may be reversed. Table 5> which compares the costs for transporting energy in various forms for a 2,000-MW system,4 shows that it should be cheaper to transport gas to power stations located in the main centre of use, rather than to locate power stations on the gas fields.

For small capacities it is always more economical to move the fuel than the electricity, as was the case throughout Australia in the pre-war period. Small isolated communities dotted throughout Australia usually generate their own power with diesel generators of only a few MW capacity, even though the.cost of diesel fuel brought in by road tanker may be $4-0 or $50 per ton. It is only the two States smallest in area, Victoria and Tasmania, which possess a complete electricity supply network covering virtually the whole State.

2.2. Pollution

As generating capacities increase pollution becomes a greater problem. The most obvious forms of pollution, air pollution from stack emissions and thermal pollution of streams and rivers, have both long since reached the stage where the cost of dealing with them has-become a routine part of the budget for a new station development. This will extend to other forms of pollution as sizes become even bigger, and as public awareness of the dangers and un- desirability of pollution becomes more acute.

2.2.1. Stack Emissions.- Electrostatic precipitators are installed on all large coal-fired boiler plants, to remove fly-ash. However, despite intensive world-wd.de research an economic solution to the problem of pollution by oxides of sulphur is not yet in sight; a partial solution is provided by the use of tall stacks to dilute the oxides before they reach the ground. Pollution by sulphur oxides is not a serious problem in Australia, as.most home-produced coals have low sulphur contents. However, as Table U shows, economics favour the use of gas or oil in metropolitan plants for peak-load generation. Gas should be the preferred fuel, because- of the possibility of sulphur oxide pollution from residual fuel oils.

In the U.S.A., one of the incentives to install nuclear power stations is the resulting absence of stack emissions.

2.2.2. Thermal Pollution.- Power stations convert at least two-thirds of the energy stored in the fuel into low-grade heatf which is discharged into the local water and atmosphere. In earlier days, use of river water as condenser cooling water caused rivers to be heated to the point where fish, were killed and plant growth severely distiArbed; but nowadays if this is likely to occur the heat is transferred to the atmosphere by cooling towers or ponds. The enormous quantities of water vapour thus discharged may reinforce any natural tendency towards fog conditions inareas subject to temperature inversions.

2.2.3. Radioactive Pollution.- Because of the toxicity of radioactive pollution it has always been accepted that designs for nuclear power stations should include stringent safety'precautions to prevent leakage of radioactive 9-5 material. Reactors located in populous areas have therefore included a second barrier to leakage in case of primary failure. The alternative is to locate plant in remote situations so that any accident would not endanger life. In either case the cost of electricity to the consumer is increased. -

2.3. Fuel Availability

2.3.1- Coal and Gas Reserves.- The concept, of generating electricity on the coalfield means that a power station is married to a particular field, whose coal reserves must be large enough to last the life of the station. A good example of this is the Leigh Creek coalfield in South Australia, coal from which is burnt at the Thomas Playford station, in Port Augusta. Despite the low cost of this coal (Table 1 ) no further new generating capacity can be based on it, as existing reserves5 will do no more than see out the life of the existing plant.

Despite big natural-gas finds in several parts of Australia no major station has yet been designed to operate solely on gas, and none is likely to be built until reserves adequate for the life of a station have been established by further exploration. 2.3.2. Imported Fuel Oil.- Oil-burning stations in Australia must depend on imported oil, as local reserves sufficient for electricity generation have not yet been established. Since the cost of electricity from, oil-burning plant is very sensitive to fuel cost (Table J+), plant is usually designed around prices negotiated for long-term bulk supply. In such a situation the supplier is taking the risk on price fluctuations in the world market, and consequently prices may be rather high when viewed against a short-term situation.

2.3.3. Availability of Water in Hydro Stations.- Hydro stations are designed for a certain annual output, based on water catchment records. In drought years these outputs will not be reached, and unless sufficient flexi­ bility is built into the grid in terms of large reserve, capacity or alternative methods of generation, demand will exceed supply, as happened in Tasmania in the summer of 1967.

2.4. Availability of Cooling Water

As noted earlier, conventional thermal plant operating with steam turbines uses enormous quantities of cooling water, and it is therefore essential when selecting a power-station site to choose one near a river or the sea. This means that if water is not available on the coalfield the plant must be built • elsewhere, as happened with the Thomas Playford station at Port Augusta, using Leigh Creek coal.

Nuclear stations, like coal-fired stations, use steam as the thermodynamic fluid and so require a supply of cooling water. They do, however, have the advantage that fuel transport costs are negligible, so that nuclear power plant can be sited wherever cooling water is the cheapest, usually on the sea co£st.

Diesel and gas-turbine plants do not require cooling water, as they use the products of combustion as the thermodynamic fluid and have no condensers. Such plants are expensive to operate, because of high fuel costs and low efficiencies, but they do provide a possible solution to the power-generation problem in localities short of cooling water.

2.5* Delivery Times !. "..'..

The time which elapses between the decision to build a power station and 9-6

the commissioning date is 7-8 years for a large coal or nuclear thermal station. It is difficult to predict system growth rates, and therefore the dates when additional generating plant will be required, so far ahead. For example, a growth rate of 6% per annum requires the system capacity to be doubled in 13 years, but if the growth rate rises to 8% per annum the doubling is required in only 9 years. To meet such contingencies, bridging capacity may be needed - for example, gas turbines, which can be installed within about two years from ordering. Although these plants use expensive fuel their capital cost is low (Table 2), and when the bridging purpose has been achieved they can be switched to reserve capacity.

2.6. Disposal of Waste Materials

Many waste materials may be disposed of by combustion. However, the combustion equipment costs money and the heat energy produced may be an embarrassment. Electricity generation can be considered as a useful means of disposing of some of the heat and recouping the cost of the equipment. Usually the waste material is difficult to burn or is located in unsuitable locations or is in insufficient quantities for economic generation, and the cost penalty incurred has to be offset against the cost of disposal by other means.

Examples are: disposal of garbage, bagasse (wkste from sugar cane milling), sawdust, wood waste, and rice hulls. The quantity of electricity generated using these materials is small, and much of it is used internally by private firms. Table 6 gives estimates of the quantities entering grids all over Australia.''

2.7. Political Factors

2.7.1. "Self-sufficiency!?- Individual States in Australia have tradition­ ally aimed at becoming self-sufficient in fuel resources, particularly since 1950, as a reaction against the shortages of the wartime and post-war years. The result has been that the various networks have become unbalanced, and this is one of the main reasons for the present tendency towards interconnection of systems.

2.7.2. The Nuclear Question.- The decision to build Australia's first nuclear power station in the mid'seventies is a political one, in the sense that nuclear power is certainly not economic at this stage (Table 4). However, it would appear to be a positive rather than a negative political decision, since it will facilitate decisions on further nuclear developments when the economics do become favourable. 2.7.3. Pollution Control.- The control of pollution caused by electricity generation using various fuels has already been discussed in Section 2.2. It is merely noted here that the decisions on the extent to which the various pollutants should be controlled are political in nature, and the prevailing community attitudes on this subject are now strong enough to be decisive in the selection or rejection of a particular fuel or the choice of a power-station location.

3. THE DEVELOPING PATTERN OF ELECTRICITY GENERATION

3.1. Development over the Past Twenty Years

The pattern of development from the "generation at the point of use" phase through; the "generation on the coalfield" phase to the present time Is de­ monstrated in Tables 7, 8, and 9, which show respectively the capacities of the 9-7 different types of power station in the various States for the years 1949, 1959, and 1969, the amounts of electricity generated in the same- years, and the quantities of fuel used.1a

The effects of the various factors previously discussed (Section 2) in developing this pattern are now examined.

3.2. New South Wales1 b

In 1949 the major power stations were located in metropolitan Sydney, in Newcastle, and in Port Kembla, burning black coal transported from the coalfields. Little hydro capacity existed.

By 1969 extensive hydro capacity had been introduced by the Snowy Mountains Authority, New South Wales being entitled to about 71$ of the capacity of the Snowy scheme. A policy of generation at coalfields on the coast has been pursued vigorously, culminating in the large new stations at Vales Point and Munmorah. The operation of collieries specifically geared to power-station requirements, together with reduced coal transport costs, have resulted in a marked drop in the prices of coal (Fig. 4) and electricity (Fig. 2).

The original metropolitan stations are now operated only as reserve plant. Peak-load capacity is supplied by the hydro stations and the early coalfield stations, with only the later coalfield stations operating on base load.

New South Wales is now in a favoured position: hydro power is available to provide 40$ of the total required capacity; black coal is cheap, and much of it is available close to sea water for cooling, and relatively close to the industrial and population centres. Four 500-MW units are currently under construction on the coalfield at Liddell, and final development of the Snowy scheme (Tumut 3) will give a further 1080 MW of peak-load capacity.

3.3« Victoria

Generation on the coalfields was forced on Victoria early by the high cost of transporting energy in the form of bed-moist brown coal (Table 5)« By 1949 much of Victoria's electricity was being produced at Yallourn, with metropolitan thermal stations bridging the wartime installation gap. Little hydro capacity was available.

The next 20 years saw major developments in hydro installations and on the brown coalfields at Yallourn and Morwell. The high-voltage grid was extended to cover the whole State, and was linked to the New South Wales grid through the Snowy scheme. By 1969 nearly 90$ of Victoria's electricity was generated in base-load stations burning bed-moist brown coal, with most of the remainder generated in peak-load hydro stations. Most of the old metropolitan thermal si-ations are now on reserve service.

Two new 350-MW units are currently under construction at Yallourri, and another 4-30 MW of hydro capacity will be available on completion of the Snowy scheme (Tumut 3) about 1974- Further peak-load capacity is to. be provided in the form of conventional thermal plant of 350 or 500 MW capacity, fired by gas or oil, both of which are cheaper for peak-load operation than is brown coal . (Table 4)e Since it is cheaper to transport gas than electricity (Table 5) such a plant will be sited in or near Melbourne, irrespective of the fuel chosen.

Such large plant could not depend on Bass Strait oil (unless additional 9-8 reserves with more heavy fractions were discovered), so that if oil is used it will most likely to high-sulphur residual oil from the Middle East. This would certainly present a pollution problem, and it is to be hoped that gas will be used instead, as far as reserves permit.

3.4. Queensland1d

Queensland has a more difficult electricity supply problem than any other State, but at the same time has- the greatest potential for making cheap elec­ tricity. The problem is the supplying of electricity to centres of population and industry extending 1500 miles up the eastern coastlinej the potential is the central Queensland coals, of good quality and capable of cheap mining by open-cut methods to give the cheapest coal in Australia, on a thermal basis (Table 1).

At present there are three separate grids - in southern, central, and northern Queensland - but demand in central and northern Queensland is too small to justify their interconnection. However, plans have recently been announced for interconnection of the central and southern grids by a 275-kV line to supply the southern grid with cheap electricity made from central Queensland coal. This involves construction of an 1100-MW power station in central Queensland, equal in capacity to the whole of the existing central and southern grids combined.

To support such a project vigorous industrial developments are needed in central Queensland, and to this end the Queensland Government is currently negotiating with large metallurgical companies and also with the Commonwealth Government, which is expected to provide special loan funds for building this station.

Historically, Queensland's system developed in a similar way to those of New South Wales and Victoria. In 194-9 most of her electricity was generated in the large towns and cities, using black coal brought in for the purpose. Little hydro capacity existed. By 1969 most base-load electricity was generated on the coalfields: at Swanbank in the south, Callide in the centre, and Collinsville in the north. Several hydro stations in the north were also operating on base load.

Till recently, peak-load and reserve capacity were provided by the old metropolitan thermal stations. However, unlike New South Wales and Victoria, southern and central Queensland have not had available appreciable quantities of peak-load hydro power, and gas turbines have been used to meet this need, with 150 MW already installed or on order. 1e 3.5. South Australia South Australia has the most difficult fuel supply problem of all the States. She possesses no hydro power and only one coal deposit, which is of low grade, located well away from centres of use and from cooling-water supplies, and too small to support more than 330 MW of base-load capacity. As a result the consumption of fuel oil in South Australia in 1969 was 60$ of Australia's total, although the South Australian grid has only 1% of the total Australian capacity. Fortunately, natural gas has recently been discovered in commercial quantities in central Australia, about 500 miles from the main centres of use.

In 1949 virtually all of South Australia's electricity was generated in power stations in metropolitan Adelaide, burning mostly imported black coal. . In 1955 electricity was first produced from South Australia's only "coalfields" 9-9 station (in fact located at Port Augusta, well away from the Leigh Creek coal­ field because of lack of cooling water). It quickly became the State's base- load station, while the older metropolitan stations were relegated to peak- load and reserve capacity.

When the Leigh Creek coalfield reached the limit of its development plans were put in hand for a major metropolitan station (Torrens Island) based on imported fuel oil, and in 1969 this station produced 25$ of the State's electricity. However, natural gas was discovered in central Australia after a start had been made on construction of the Torrens Island station, and some of the boilers are now being fired with this alternative (and somewhat cheaper and cleaner) fuel. It has been decided that all present and future generating plant at Torrens Island shall be suitable for using either oil or natural gas.

Like central and southern Queensland, South Australia possesses no hydro capacity suitable for meeting peak loads and is turning to the gas turbine to provide this. Units totalling 52 MW are already on order. 1f 3.6. Western Australia

Western Australia, with the largest land area of any of the Australian States, has the smallest population with the exception of Tasmania, and until recently it had little industrial development requiring electricity. This situation is changing rapidly, however, and electricity generation has experienced growth rates of the order of 15$ per annum over the last few years.

As in other States, the first power stations were erected at centres of use, in this case Perth and Fremantle. These were fired by coal brought in to the power stations, mainly from the Collie coalfield located about 120 miles south of Perths Following the rapid growth in population and industry in the south-western corner of the State over the last few years, power stations have been erected on the coalfield itself, at Collie and a few miles away at Muja. By 1969 bhe 24.0-MW Muja station was operating as the State's base-load station, using 90$ of the coal produced, and the price of coal at the power station had fallen sharply (Fig. U), although it was still higher than in most other parts of Australia.

There is little potential for hydro power in the south-western area covered by the grid, and peak-load and reserve capacity are provided mainly by the older metropolitan stations, now converted to oil firing.

The current major development in the State is an oil-fired station of four 120-MW units, located at Kwinana . miles south of Perth, in the centre of the developing industrial area. This station is presumably designed for base-load as well as peak-load operation. The reason for the switch to oil from coal is that the coal is more and the oil less expensive than elsewhere in Australia (a B.P. refinery also is located at Kwinana).

Because of the enormous distances involved it is unlikely that substantial extension of the grid will occur for A long time. Meanwhile power requirements in the small coastal and mining towns are mostiy supplied'by diesel generators. Four 30-MW units are on order for the new steam station at Dampier, and one 30-MW unit is about to be commissioned. Two 30-MW units are being installed by Cliffs Western Mining in their new steam station at Cape Lambert,- and further units are in prospect. 9-10

3.7. Tasmania e

Tasmania has no developed coal resources but an abundance of areas suitable for hydro installations. These have been developed vigorously, and much industry has been attracted to the State because of the cheapness of the electricity produced (Fig. 2)„ As a result Tasmania's production of electricity per head of population is amongst the highest in the world.

Because, as pointed out earlier, complete dependence on hydro electricity has made Tasmania vulnerable to drought, in the last few years 50 MW of reserve capacity in the form of gas turbines has been installed while an oil-fired station of 120 MW is being commissioned at Bell Bay. These will be used to provide bridging capacity until power is available from a new hydro development in the Gordon River area, in the south-western part of the State, and will then be switched to peak-load operation. A.. FUTURE FUEL USE

4.1. ,Future Demand for Electricity

The increases in the annual maximum demand in the various States over the past 15 years are shown in Fig, 5. The demands are plotted on a logarithmic' scale to permit the slopes to be used to calculate the annual growth rates. These range from 6% per annum for Tasmania to 15/6 for Western Australia, The rates have been fairly steady except for a sharp increase for Western Australia about 1960, and it may be expected that they will remain steady for the next few ye'ars, except for a slight drop in Western Australia and an increase in Queensland if plans for industrialization of central Queensland come to fruition.

The broken lines in Fig. 5 give estimates of the likely demand over the . next decade, based on these assumptions. Expected growths in system capacities by 1980 are given in Table 10, assuming that systems should be 25% larger than the expected maximum demand and that 50% of each system would be peak-load or reserve capacity,

4-.2, Future Power Station Construction

4.2,1. New South Wales.- Enormous expansion of both peak-load and base- load capacities will be required by 1980 - over 4000 MW in each category. The New South Wales grid is now big enough to take individual units of 660 MW, i.e. larger than the size at which nuclear power stations in Europe and North America are starting to become attractive. However, as shown in Fig. 6, nuclear plant will not compete with coal-fired plant before about 1985, because of the cheapness of the coal; and therefore operation of the 500-MW nuclear plant at Jervis Bay in the late Seventies will have to be subsidized out of Commonwealth funds.

Completion of the Liddell •coal-fired station by the installation of four 500-MW units, and planned extensions to Wallerawang (one 500-MW-unit), will add 2500 MW of base-load capacity by 1975.T^ The Jervis Bay nuclear station will add a further 500 MW before 1980, leaving a shortfall of only 1100 MW. Tenders have been called for. two additional units, each of 660 MW, to be installed at Vales Point power station; and a new station on Lake Macquarie is planned,^ These schemes: could provide a total of 2,600 MW additional generating capacity, which is considerably more than required - thus releasing- say, 1500 MW to peak-load service.

Completion of the Snowy hydro scheme by 1975 will add 1080 MW of peak-load plant at Tumut 3J and a pumped-storage scheme on the Shoalhaven River another 9-11

240 MW by 1976.ID However, as shown in Table 10, another 3,000 MW will be re­ quired by 1980. As noted above, 1,250 MW of this could be made up from partly amortized base-load plant, but it is no longer possible to rely on this source for more than a fraction of the peak-load needs, and increasing amounts of plant specifically designed for this service willTbe^required. For low load- factor, reserve, further pumped-storage hydro plant or gas-turbine plant operating on natural gas from Victoria may be used (Table 4). In the 25$ load-factor region conventional black coal plant will continue to be favoured (Fig. 6).

4*2.2. Victoria.- Victoria will require over 2000 MW of both peak-load and base-load plant by 1980. Although Victorian brown coal is extremely cheap (Table 1) its high moisture content necessitates special plant for combustion, and generating costs with this fuel are higher than with N.S.W. black coal. Research is in progress on a process for dewatering brown coal before combustion which would result in a generating cost structure close to that of black coal." However, should this process not prove successful the break-even point for nuclear fuel could come by 1980, earlier than for New South Wales (Fig. 6).

Completion of the Hazelwood and Yallourn "W" brown coal stations by 1974 will provide 1100 MW of base-load capacity,10 but, as seen from Table 10, another 900 MW will be needed by 1980; this will probably be provided by brown coal plant at Morwell.

Planning for a 1000-MW oil or gas station in Melbourne for peak-load service is under way, and completion of Tumut 3 hydro station will add another 430 MW of peak-load capacity.*0 However, a further 1000 MW will be required by 1980; as in New South Wales, it is no longer possible to rely on old base- load plant, and no doubt pumped-storage hydro plant or further oil'or gas-fired steam-turbine plant will be installed (Fig. 6). For the 2% load-factor reserve plant category, gas-fired gas turbines will almost certainly be used.

4.2.3. Queensland.- Over 1000-MW of both peak-load and base-load plant will be needed by 1980. An 1100-MW coal-fired base-load plant is already planned for Gladstone in central Queensland, and 480 MW of plant is on order to extend the Swanbank station at Ipswich, in southern Queensland.1d Together these will release 350 MW of old base-load plant for peak-load operation, and as coal is so cheap further peak-load capacity should be based on it (Fig. 6). Queensland already has some gas turbines installed and more on order; these should satisfy the reserve plant requirements for some time.

4.2.4. South Australia.- Here a similar position exists to that in Queensland, with more base-load plant on order than will be required by 1980. However, this is oil-fired and gas-fired steam plant, rather than coal-fired, and should serve for both peak-load and base-load requirements. A further 1000 MW of similar plant will be needed before 1980.

As shown in Fig< 6, nuclear fuel is cheaper than fuel oil for base-load generation, for units of 400 MW or larger,, However, the South Australian.grid will not be able to support individual units larger than 200 MW for many years to come, and the suggestion has been- made that it might benefit both Victoria -: and South Australia if their two grids were interconnected via a 500-MW nuclear1 : plant located in the south-eastern portion of the State. A submission along these lines has been made to the Commonwealth Government.16

4.2.5. Western Australia.- Growth rates over the past 10 years have been extremely high, averaging'15$ per annum, and new installations have been barely • able to cope with demand. 480 MW of new plant is on order; it will be oil-fired, 9-12

and could serve equally for peak and base load- However, even allowing for a drop in growth rate to 12%, a further 14-00 MW will be required by 1980. Quite possibly the cost structure by then will again favour further development based on Collie coal. Tenders have already been called for two 200-MW oil- and gas- fired units for extending the Kwinana power station, 4.2*6. Tasmania.- The cheapest hydro power in Tasmania has already been tapped, and while costs are decreasing in other States they are increasing in Tasmania (Fig. 2). The incentive for large industries to be established in Tasmania is therefore not as great as it once was, and growth rates are now the smallest in Australia. However, even at a growth rate of only 6% per annum an additional 900 MW will be required by 1980.

An oil-fired steam plant of 120 MW capacity is being installed at Bell Bay, and a further 530 MW of hydro plant under construction in the Mersey-Forth- and Gordon River schemes should be complete by 1975» There is a potential capacity for at least another 800 MW in the south-western corner of the State, and further development can be expected.

It has been proposed that the Tasmanian and Victorian grids be inter­ connected by an undersea cable, to give greater flexibility to both systems. Although apparently not economic at the moment, this proposal will no doubt be reviewed again in a few years' time.

4.3. Fuel Consumption by 1980 Table 11 summarizes the main categories of plant expected in the . different States in 1980, and the quantities of fuel required, assuming 50% of the installed capacity is base-load plant operating at 80% load factor, 40% is peak-load plant operating at 25% load factor, and 10% is reserve plant operating at 2% load factor«

It is not certain how much of the peak-load plant in Victoria and South Australia will be gas-fired and how much oil-fired; on the assumption of equal capacities of each, Table 11 gives a gas consumption in South Australia approx-. imately equal to the announced contract figure.^e

It is seen that the annual black coal consumption between now and 1980 will almost treble, brown coal consumption will double, and fuel oil consumption quadruple; natural gas will increase from virtually nothing to nearly 50,000 million cubic feet per year.

4.4. The Nuclear Phase

As far as can be seen at the moment, the generation of electricity in Australia will enter yet another phase in the nineteen eighties - the nuclear phase. In this phase the grids of all the eastern states, including South Australia and Tasmania, will be interconnected, and no new base-load plant based on fossil fuels will be built, except possibly in Western Australia. Existing fossil-fuel plant, including new plant .built up to 1985, will gradually be relegated to peak-load operation. Probably the only new fossil-fuel plant built will be that designed specifically for reserve capacity.

These conclusions are based on assumptions which many fossil-fuel-plant engineers would consider over-generous to nuclear fuel. However, these are the assumptions which are currently being made, and only time will tell whether...... •.,,.. :vt^y-:are justified. • •'••%•'/•' .-:;;-- 9-13 5. CONCLUSIONS

Before 1920 most power stations in Australia were built adjacent to the load centres. They nearly all burnt black coal from New South Wales, transported from the docks in small lots. The next 20-30 years saw most new stations being built near the docks, using sea water for cooling water and black coal from New South Wales as.fuel.

In 1930 Victoria chose to develop her own brown coal for power generation, but because of its low calorific value it was cheaper to build the power stations on the coalfields and transport the electricity to the centres of use by high-voltage lines. The coalfields were opened up by large-scale, mechanized mining operations, and by 1950 electricity was cheaper in Victoria than in any other State in Australia with the exception of Tasmania.

With the large expansion of electricity demand after World "War II a major shift of policy to generation on the coalfields occurred also in Queensland, New South Wales, South Australia, and Western Australia. This resulted in a steady drop in electricity prices over a period of more than fifteen years, while other basic commodities consistently rose in price. Today over three-quarters of Australia's electricity is generated from combustion of coal on the coalfields.

During the same period hydro-electric capacity was developed vigorously in the mountainous areas of the eastern States, much of it on a peak-load design basis. Today hydro electricity accounts for nearly 20% of the electricity generated, more than half of it in Tasmania.

In the late 1960Ts development of peak-load generating capacity attained importance as grid capacities increased in size. With this type of load it is important to reduce capital charges to a minimum, as the plant load factor is so low (typically about 25%). New South Wales and Victoria have switched old amortized base-load plant to this service, and are using hydro capacity from the Snowy scheme. Victoria has also recently announced plans for conventional oil or gas plant, and New South Wales fo* pumped-storage hydro plant. Queensland and South Australia, being more limited in resources, have ordered gas-turbine peak-load plants. Further development of natural-gas reserves in Australia can be expected, and gas should have an assured place in future peak-load electricity generation.

The 500-MW nuclear power station planned for Jervis Bay notwithstanding, nuclear power is not expected to be economic anywhere in Australia before 1980, by which time the consumption of fossil fuels for electricity generation will have approximately trebled - reaching 27 million tons of black coal, 42 million tons of brown and other coal, 3 million tons of oil, and 50,000 million cubic feet of gas per year.

After 19S0 many of the new base-load stations installed are likely to be nuclear fuelled, and existing fossil fuel stations will gradually be switched over to peak-load operation. By 1990 all the main grids in Australia except the Western Australian one could possibly be interconnected - by high- voltage d.c. transmission,'to minimize losses. Most base-load capacity could be nuclear, with peak-load electricity provided only from the cheapest black coal in New South Wales and Queensland, from low-capital-cost gas-fired plant in Victoria and South Australia, and from hydro plant in the eastern States. Although Victorian brown coal is one of the cheapest coals in Australia, unless an economic process for reducing its high moisture content before combustion can be developed the high cost of the boiler system currently required to burn it will preclude its use for peak load generation in this future period. 9-U

6. REFERENCES

(1) Annual Reports

(a) "The Electricity Supply Industry in Australia", 1948-49 through to 1968-69 (Electricity Supply Association of Australia, Melbourne). (b) Annual Report 1969 (Electricity Commission of New South Wales, Sydney). (c) Annual Report, 1969 (State Electricity Commission of Victoria, Melbourne). (d) Annual Report, 1969 (State Electricity Commission of Queens­ land, Brisbane), (e) Annual Report, 1969 (Electricity Trust of South Australia, Adelaide). (f) Annual Report, 1969 (State Electricity Commission of Western Australia, Perth). (g) Report for Year 1968-69 (Hydroelectric Commission of Tasmania, Hobart).

(2) BUCHANAN, R.H., and SINCLAIR, C.G. "Costs and Economics of the Australian Process Industries". (West,Sydney, 1964).

(3) CHAPMAN, R.G. "Generation Planning". Paper to Residential School in power system electrical engineering, Vol. 1, 1301-1321 (University of Melbourne, 1967).

(4) McFADYEN, W.T. Fuel types and fuel resources available to Australia in the future. J. Inst. Fuel. 1969, -£2, 267-275.

(5) HARTNELL, B.W. Black coal: its essential role in Australia's industrial growth. "Fuel and Power in Australia"., pp. 41-62 Ed. H. G. Raggatt (Cheshire, Melbourne, 1969).

(6) EVANS, D.G. and SIEMON, S.R. Dewatering of brown coal, before combustion. Conference on Combustion and Combustion Equipment, The Institute of Fuel, Australian Membership, Canberra, November 1968, pp. 7-1 to 7-14 (The Institute of Fuel, Australian Membership, Sydney, 1968).

(7) KNIGHT, A.W. The development of hydro-electric power in Tasmania. "Fuel and Power in Australia" pp. 143-158. Ed. H. G. Raggatt (Cheshire, Melbourne, 1969).

(8) DEPARTMENT OF NATIONAL DEVELOPMENT. "Energy in Australia", p. 31 (Commonwealth Government Printer, Canberra, 1967). TABLE 1. COSTS OF FUEL AT POWER STATIONS IN 1970

——————————.

Fuel Location $/ton c/kwh in fuel c/kwh generated fiuclear - 0.13

black coal N.S.W. 4.0 0.055 0.15 South Qld 5.5 0.070 0.19 Central Qld 2.6 0.040 .0.11 North Qld 8.0 0.100 0.27 W.A. 6.0 0.097 0.29

brown and Victoria 0.8 0.030 • 0.12 other coal S.A. 2.7 0.069 0.21

fuel oil ex refinery 11.0 0.088 0.25 imported 12.5 0.100 0.29

distillate oil 25.0 gas turbine 0.200 0.74- I natural gas: steam plant Adelaide 0.082 0.23 . steam plant Melbourne 0.102 0.29 gas turbine Adelaide 0.082 0.30 gas turbine Melbourne 0.102 0.38 9-16 TABLE 2. CAPITAL COST OF PLANT IN 1970, MILLIONS OF DOLLARS

A. th erm odyn ami c fluid fuel size, MW 30 120 500

steam nuclear - 36 85

steam brown coal 9 24 64 steam black coal r 6 16 44 steam oil 5 13 35

steam natural gas 5 13 35

gas distillate oil 3 8

gas natural gas 3 8 \

costs are assumed to increase by the 0.7"^ power of the increase in size.

TABLE 3. GENERATING CAPACITIES OF-GRIDS IN 1969

Grid Installed capacity Largest single Largest single MW unit operating(a) unit on order(a) MW MW

New- South Wales (b) 5570 350 500

Victoria (b) 3350 200 350

Queensland, South 1050 66 120 Central 200 30 30 North 230 30 30

South Australia 970 120 200

Western Australia 560 60 120

Tasmania 1010 120

/

i •

(a) Thermal units only; hydro units are not included (b) Capacities for New South Wales and Victoria include Snowy and Hume entitlements y-17 TABLE 4. COST OF GENERATING ELECTRICITY IN 1970

—-' ' - - -..-..• •- fuel type fuel cost load .factor , % of M.C.R. j 80 25 2 brovm coal $0.80/ton 0.61 1.46 15.7

black coal $5/ton 0.50 1.08 10.6 $2.50/ton 0.41 0.98 10.6

fuel oil $12.50/ton 0.57 1.02 8.7 $10/ton 0.51 0.C7 8.7

natural gas 30 c/thou c ft 0.56 1.02 8.7

gas turbine, oil $25/ton 0.97 1.21 6.0

gas turbine, natural gas 30 c/thou c ft 0.54 0.83 5.5 ______• —art 120 HW Dlant fuel type fuel cost load :Factor , % of M.C.R. 80 25 2 nuclear 0.13 c/kwh 0.62 1.46 15.6

brown coal $0.80/ton 0.44 0.99 10.2

black coal £5/ton 0.39 0.77 7.0 $2.50/ton 0.30 0.67 6.9

fuel oil $12.50/ton 0.47 0.77 5.8 $10/ton 0.41 0.71 5.8

natural gas 30 c/thou c ft 0.46 0.77 5.8

gas turbine, oil $25/ton 0.91 1.06 4.3

gas turbine, natural gas 30 c/thou c ft 0.48 0.68 3.7 500 HW plant fuel type fuel cost load factor, % of M.C.R. • 80 25 . .-.- 2 - n • ' • ' ' nuclear 0.13 c/kwh 0.41 0.88 8.9

brovm coal $0.80/ton > 0.33 0.69 7.8

black coal $5/ton 0.33 0.57 . 4.7 O2.50/ton 0.23 0.48 4.6

fuel oil $12.50/ton 0.42 0.61 3.9 * $10/ton o; 36 0.55,. 3.8

natural gas 30 c/thou c ft 0.41 0.61 3.9 r-, -, r-ir-'J • TABLE 5. RELATIVE COST OF TRANSPORT OF ELECTRICAL ENERGY IN VARIOUS FORMS

form method of transport percentage of cost of transport as electricity

natural gas 32 inch pipeline 90

electricity 500 kV line 100

black coal rail 180

brown coal rail 750

TABLE 6. ELECTRICITY SUPPLIED TO GRIDS FROM COMBUSTION OF WASTE MATERIAL IN 1969

'•••• ' •"••— .•_ - • " • - « material j grid quantity of electricity, 106 kWh per year

garbage figures not available t bagasse N.Qld 15

wood waste o • A» 97

rice hulls none 9-19

TABLE 7. GENERATING CAPACITIES OF VAKIOUS TYPES, MW

Plant type year NSW Vic QJd SA WA Tas Aust. total(a)

Hydro 1949 33 51 4 0 0 173 261 1959 223 309 76 0 2 485 1098 (b)1969 1548 948 132 0 2 956 3622

Steam 1949 775 496 173 147 75 0 1666 1959 .1690 1010 564 366 268 0 3898 1959 3989 2398 1323 957 515 0 9229

Internal combustion 1949 25 17 21 11 12 0 86 1959 47 44 38 - 12 23 0 179 1969 36 6 36 12 47 4 168

Gas turbine 1949 0 0 0 0 0 0 0 1959 0 0 0 0 0 0 0 1969 0 0 55 0 0 50 105

Total 1949 833 564 198 158 87 173 2013 1959 1960 1363 678 378 293 485 5175 1969 5573 3352 1546 969 564 1010 13124

(a) Includes Northern Territory, Papua and New Guinea (b) NSW includes 71% of Snowy, Victoria 29% 9-20

TABLE 8. ELECTRICITY GENERATED, 10v kWh PER YEAR

• , .. , NSW Vic ' Qld SA WA Tas Aust.total(a)

Hydro 1949 0.18 0.18 ' 0.02 0.00 0.00 0.92 1.31 1959 0.53 0.62 0.17 0.00 0.00 2.38 3.72 Cb)1969 1.81 1.37 0.51 0.00 0.01 4.57 8.37 1 t 1

Steam turbine 1949 2.92 2.20 0.58 0.46 0.30 0.00 6.45 1959 6.75 4.86 1.78 1.47 0.70 0.00 15.55

• 1969 15.21 11.37 4.39 3.84 1.97 0.01 36.90

Internal combustion 1949" 0.06 0.03 0.03 0.02 0.02 0.00 0.15 1959 0.05 0.08 0.05 0.01 0.05 0.00 0.28 •1969 0.07 0.01 0.07. 0.02 • 0.08 0.00 0.31

Gas turbine 1949 0.00 0.00 0.00 0.00 0.00 0.00 0.00 1959 0.00 0.00 0.00 0.00 0.00 0.00 0.00 1969 0.00 0.00 0.00 0.00 0.00 0.03 0.03

Total 1949 3.15 2.41 0.63 0.48 0.32 0.92 7.91 1959 7.33 5.56 2.0970 1.48 0.75 2.38 19.56 1969 17.10 12.75 r- 3.86 2.06 4.61 45.61

(a) Includes Northern Territory, Papua,and New Guinea (b) NSW.includes 71% of Snowy, Victoria 29% •» 9-21

TABLE 9. FUEL CONSUMED, MILLION TONS PER YEAR

- " • ' •

Year NSW Vic Qld SA WA Tas Aust.total(a)

Black coal 1949 2.11 0.24 0.49 0.24 0.27 0.00 3.36 1959 3.64 0.20 1.15 0.28 0.52 0.00 5.79 1969 6.65 0.01 2.23 0.02 0.91 0.00 9.81

Brown coal (b) 1949 0.00 4.36 0.00 0.14 0.00 0.00 4.50 1959 0.00 8.72 0.00 0.65 0.00 0.00 9.37 1969 0.00 18.05 0.00 2.14 0.00 0.00 20.18

Briquettes 1949 0.00 0.44 0.00 0.00 0.00 0.00 0.44 1959 0.00 0.11 0.00 0.00 0.00 0.00 0.11 1969 0.00 0.30 0.00 0.00 0.00 0.00 0.30

Oil 1949 0.08 0.02 0.01 0.01 0.01 0.00 0.12 1959 0.02 0.30 0.01 0.07 0.02 0.00 0.43 1969 0.04 0.03 0.02 0.35 0.14 0,01 0.65

Wood,etc. 1949 0.04 0.05 0.03 0.00 0.04 0.00 0.16 1959 0.03 0.01 0.02 0.10 0.00 0.00 0.16 1969 0.00 0.00 0.00 0.17 0.00 0.00 0.17

Gas(c) 1949 0.00 0.00 0.00 0.00 0.00 0.00 0.00 1959 0.00 0.00 0.00 0.00 0.00 0.00 0.00 1969 0.00 0.00 0.12 0.00 0.00 0.00 0.12

(a) Includes Northern Territory, Papua and New Guinea (b) Includes Leigh Creek coal » (c) Thousand million cubic feet per year 9-22

f

TABLE 10. ESTIMATION OF NEW GENERATING CAPACITY REQUIRED BY 1980

NSW Vic Qld SA WA Tas

Total grid capacity

Maximum demand in 1969, MW 4,000 2,400 1,100 800 500 700

Present growth rate, % p.a. 9 7 8 9 15 6

Assumed future growth rate, % p.a. 9 7 10 9 12 6

Estimated maximum demand in 1980, MW 11,000 6,"300 3,200 2,400 2,000 1,500

Demand in 1980 plus 25%, MW 14,000 8,000 4,000 3,000 2,500 1,900

Base load capacity

Base load in 1980, 50% of total, MW 7,000 4,000 2,000 .1,500 1,250 950

Base load in 1969, MW 2,900 2,000 ^700 700 300 500

New base load required, MW 4,100 2,000 1,300 800 950 450 New base load planned or on order, MW 3,350 1,100 1,650 900 500 550

Shortfall in base load, MW 750 900 -350 -100 450 -100

Peak load capacity

Peak load (plus reserve) in 1980, 50% of total, MW 7,000 4,000 2,000 1,500 1,250 950

Peak load in 1969, MW 2,700 1,400 300 300 300 500

New peak load required, MW 4,300 2,600 1,200 1,200 950 450 Peak load planned or on order, MW 1,300 1,400 50 150 0 100

Shortfall in peak load, MW 3,000 1,200 1,150 1,050 950 350 TABLE 11. ESTIMATED ANNUAL FUEL REQUIREMENTS IN 1980

fuel plant type NSW Vic Qld SA WA Tas Aust.Total MW ton/y HW ton/y MW ton/y MW ton/y MW ton/y MW ton/y MW ton/y black coal base 6500 16.8 - 1900 4.9 - 750 1.9 - 9150 23.6 peak 2700 2.1 1600 1.3 4300 3.4 total 4too iG.q — H 3500 6.2 _ _ 750 1.9 _ _ 13,450 27.0

brown coal base - 3600 38.9 - 300 2.1 - - 3900 41.0 peak 200 0.7 200 0.7 total — _ 3800 39.6 •. — 300 2.1 _ _ _ - 4100 41.7

oil base - _ 600 1.0 500 0.8 1100 1.8 peak 1000 0.6 650 0.4 1000 0.5 150 0.1 2800 1.1 total _ _ 1000 0.6 _ _ 1250 1.4 1500 1.3 150 0.1 3900 2.9

gas (a) base - - 600 13 - - 600 13 peak 1000 21 650 14 1650 35 total _ _ 1000 21 _. _ 1250 27 - - - 2250 48

nuclear base 500 - - - - - 500 peak

total 500 a* —• • «• 500

hydro (b) base 100 - - 950 1050 peak 2900 1400 600 4900 total 2900 1400 100 - - 1550 5950 — fuel plant type NSW Vic Qld SA WA Tas Aust Total MW ton/v MW ton/y MW ton/y MW ton/y MW -ton/y VM ton/y MW ton/y reserve (c) all types 1400 800 400 300 250 200 33^,0 total all types 14,000 8000 4000 3000 2500 1900 33,400

I

(a) gas consumptions in thousand million c ft (b) includes Snowy entitlements (c) fuel consumption is negligible 9-2A

Z-0

WA-... 2-5

. '••...-•.WA •^-—.-v^V -—^ Qld o SA&' 245 "^a*~»>*NSYV V?C'*'...' SA

8 1-5 - s I

J « •Tot i „~.-.^S I 051 y^ S"

o a o o a oO> e 1950 1955 I960 1965 1970 1975 year *> c Figure 2 Changes in the average cost of electricity to consumers 1945 1950 1955 I960 1965 1970 in the various states. year figure 1 The increase in electricity generating capacity installed In Australia.

100

oe

I

i%m

S mid o night •u o Figure 3 Fluctuations in demand for electric power in Victoria: o a June day of maximum demand 1950 1955 I960 1965 1970 !975 b Average December day y«ar Figure •» Changes in the average cost of coal at power stations "in the various states. 9-25

1-2

1955 I960 1965 1970 1975 I960 10 year Figure 5 Growth in annual maximum demand for electric power in the various states. (Broken lines show extrapolations to future maximum demands based on growth rates given 0-8- in Table 10). i >» 0-6

0-4 J? o k.

e 0-2

*S 8 0-01 JL -L 1965 1970 1975 I960 1985 1990 yaor

Figure 6 Changes in the cost of generating electricity in different ways: a, nuclear fuel; b, brown coal; o, black coal; d, fuel oil; full lines are at a load factor of 80* HCK, broken lines at 25* HCR. Assumptions made are: (i) fossil fuel costs increase by 2* p.a. from 1970 costs, which are: brown coal §0.80 per ton; black coal $3.00 per ton; fuel oil $12.50 per ton (ii) nuclear fuel costs 0.13 c per kWh generated (ill) plant size is 350 MW in 1970 and Increases by 7% p.a. (iv) plant costs in 1970 are: nuclear $67 million; brown coal $50 million; black coal $33 million) fuel oil $27 Billion. Costs increase by the 0.7th power of the increase in size, (v) for nuclear plant improved technology results in a capital cost reduction of 2t p-a. (vi) capital charges are at a flat rate of 9% p.a. (vli) operating charges are at a rate of Si of capital cost p.a., computed only for the period the plant Is operating.