electric power from competitive sources - … power from competitive sources page..ii list of tables...

Fuel & Power Experts

Ultra-Systems Technology Pty Ltd

Electric Power fromCompetitive Sources

prepared for

Report No: c1056 June, 1999

Electric Power from Competitive Sources Page..i

ELECTRIC POWER FROM COMPETITIVE SOURCES

CONTENTS

Page

EXECUTIVE SUMMARY III

1 INTRODUCTION 1

2 ELECTRICITY GENERATING COSTS 3

2.1 FOSSIL FUELS 32.1.1 For Coal, the Supercritical Pressure Steam Cycle 32.1.2 For Natural Gas, the Advanced Gas Turbine Cycle. 52.1.3 Oil Firing 6

2.2 RENEWABLE ENERGY TECHNOLOGIES 72.2.1 Solar Photovoltaic 72.2.2 Solar Thermal 82.2.3 Wind 92.2.4 Hydro-electricity 112.2.5 Biomass 11

2.3 NUCLEAR ENERGY 132.4 FUTURE TRENDS IN ELECTRICITY COSTS 15

2.4.1 Capital Investment 152.4.2 O&M costs 17

3 ENVIRONMENTAL ISSUES 19

3.1 ATMOSPHERIC EMISSIONS 193.2 OTHER DISCHARGES 213.3 COST OF ENVIRONMENTAL COMPLIANCE 22

4 SOCIAL/POLITICAL ISSUES 23

4.1 ELECTRICITY PRICING POLICIES RELATED TO ECONOMIC GROWTH 234.2 POLITICAL, MANAGEMENT AND REGULATORY ISSUES 23

4.2.1 Establishing a Competitive National Energy Market 234.2.2 Costs of Regulatory Compliance 244.2.3 Dividend Requirements 25

4.3 WORKFORCE AND THE COMMUNITY 254.4 SITE ACQUISITION & INFRASTRUCTURE 26

5 SUMMARY 27

6 CALCULATION SPREADSHEET 29

6.1 INSTALLATION 296.2 INPUTS 29

6.2.1 Inputs Required for Evaluation 296.2.2 Inputting Values 30

6.3 OUTPUTS 31

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LIST OF TABLES

PageTABLE 1.1: BULK ELECTRICITY SUPPLY COSTS 1

TABLE 2.1: COMMERCIAL WIND TURBINE PERFORMANCE 10

TABLE 2.2: COST OF CAPITAL 17

TABLE 3.1: NOX EMISSIONS FROM COMBUSTION PLANTS 20

TABLE 3.2: CO2 EMISSIONS FROM COMBUSTION PLANTS 20

TABLE 3.3: TRACE ELEMENTS FROM SOLID FUEL COMBUSTION 21

TABLE 3.4: SUMMARY OF ENVIRONMENTAL COSTS 22

TABLE 4.1: WORKFORCE REQUIREMENTS 25

TABLE 4.2: SITE AND INFRASTRUCTURE REQUIREMENTS 26

TABLE 5.1: SUMMARY OF STUDY OUTCOMES 27

TABLE 6.1: INPUTS REQUIRED FOR ELECTRCITYCOSTS.XLS 29

LIST OF FIGURES

PageFIGURE 2.1: CAPITAL COSTS FOR COAL FIRED PLANT 4

FIGURE 2.2: O&M COSTS FOR COAL FIRED PLANT 4

FIGURE 2.3: CAPITAL COSTS FOR NATURAL GAS FIRED PLANT 5

FIGURE 2.4: O&M COSTS FOR GAS FIRED PLANT 6

FIGURE 2.5: CAPITAL COSTS FOR SOLAR PHOTOVOLTAIC 7

FIGURE 2.6: CAPITAL COSTS ASSUMED FOR SOLAR THERMAL PLANT 9

FIGURE 2.7: CAPITAL COSTS ASSUMED FOR WIND PLANT 10

FIGURE 2.8: CAPITAL COSTS ASSUMED FOR BIOMASS FIRED PLANT 13

FIGURE 2.9: CAPITAL COSTS FOR NUCLEAR PLANT 14

FIGURE 2.10: O&M COSTS FOR NUCLEAR PLANT 14

FIGURE 6.1: SPREADSHEET INPUT & DEFAULT VALUES 30

FIGURE 6.2: OUTPUT SUMMARY OF POWER GENERATION COSTS 31

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EXECUTIVE SUMMARY

The Queensland Department of Mines and Energy, through the QTHERM Program, hasretained Ultra-Systems Technology Pty Ltd (UST) to develop the costs and implications of arange of options for bulk electricity generation and supply. The options ranged from differentfossil fuels (coal, oil, gas), renewable energy sources (solar, wind, biomass, etc) and nuclear.

This work was to provide a simplified comparison of the cost of electricity generationaccording to the type of fuel, generation technology and other site related variations. It wasnot meant as a definitive study to identify precise electricity generating costs, but wasproduced in an attempt to put the differences in costs in a global perspective.

The outcomes of this study are contained in this concise report that sets out the results of thework and includes a summary table setting out the advantages and disadvantages of each ofthe supply options. Also, a computer spreadsheet, setting out the costs of electricitygeneration and supply from each of the options is provided. This spreadsheet can be used byinterested parties to manipulate the costs to suit their own applications both in Australia andoffshore, with particular reference to East Asian countries.

ELECTRICITY GENERATING COSTS

Electricity generation costs for fossil fuel and nuclear plants have been obtained from a reportprepared by the Nuclear Energy Agency, the International Energy Agency and theOrganisation for Economic Cooperation and Development – “Projected Costs of GeneratingElectricity – Update 1998”.

Fossil Fuels

In the increasingly competitive market for electricity generation, two basic generationtechnologies have emerged as the “best practice” systems. These are:

For Coal, the Supercritical Pressure Steam Cycle

The latest boiler designs feature pulverised coal firing, with low NOx burners in a balanceddraft or pressurised furnace. These units are generally fitted with advanced particulateremoval systems in the flue gas stream. For high sulphur coals (as for most NorthernHemisphere coals), flue gas de-sulphurisation (FGD) equipment may also be fitted. Basecapital costs are with unit size between about US$1,200/kW for a 200 MWe unit toUS$900/kW for a 700 MWe unit.

The addition of FGD plant leads to higher capital and operating costs. An increase of around8% of base capital costs was assumed, based on the IEA data. It was shown that FGD plantdid not appear to increase O&M costs significantly.

The addition of de-NOx plant to reduce the NOx emissions also leads to higher capital andO&M costs. A value of 12% of base capital costs and an increase of 30% of O&M costs wereassumed.

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For Natural Gas, the Advanced Gas Turbine Cycle.

The latest gas turbine designs feature advanced low-NOx burners, high temperaturemetallurgy in the turbine front rows, and modular turbine blade elements. Where the unit is tobe used for intermediate to base load duty, the gas turbine is combined with a heat recoverysteam generator (HRSG) and a steam turbine, leading to relatively high thermal efficiencies ofup to 55%.

Base capital costs vary with unit size between about US$700/kW for a 300 MWe unit, toUS$680/kW for a 500 MWe unit. The addition of de-NOx plant (SCR) on these units has beenimplemented on a few units and the additional costs are similar to those for coal fired plants.

Oil Firing

Recent trends have seen OECD countries install almost no new generating units based on oilfuel alone and few sites exist where oil fuel alone offers the most economic choice for baseload plant. Since there have been no new oil-fired plants installed and included in the IEAdata, the capital costs for this option were notionally taken as 85% of the costs of coal-firedplant.

Renewable Energy Technologies

Solar Photovoltaic

Photovoltaic electricity generation systems are now in wide commercial use for both smalland large-scale applications. The smaller applications, less than 100 W and upwards, includeoff grid and remote electricity supplies. Larger applications include up to 1 MW gridconnected arrays.

Cost of the technology is still high, compared with other electricity generation technologies.The capital cost for small, simple systems is US$4,000 to US$8,000/kW, depending uponrequirements. For the larger AC grid connected systems of 500 kW to 1 MW and more, thecapital cost is US$7,000/kW to US$5,500/kW.

Performance is dependent upon the availability of good sunlight and is best in clear, dry areassuch as inland Australia. Performance is significantly degraded by cloud cover, haze andindustrial pollution. Annual capacity factors range from 14% in the southern coastal regionsof Australia to 20% in Central Australia.

Solar Thermal

Solar thermal systems are widely used for domestic and some industrial water heating but thetechnology is not currently commercially successful for power generation. There are a numberof commercial development programs now going on to further develop the technology inAustralia and overseas.

Capital cost of a 160 MW installation with natural gas back-up is estimated to be$US2,750/kW. More recent developments in Australia have identified the cost of new-generation technology at US$1,950/kW to US$2,700/kW for 200 MW plants.

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Annual capacity factors are similar to solar PV systems, with capacity factors of 20% or less.

Wind

Wind power is widely used for commercial power generation and there are almost 8,500 MWof wind generation now installed worldwide. Wind turbine technology is now mature and isfully commercial, from smaller 2.5 kW machines up to utility machines of 1.5 MW or more.

Current capital costs for a 5 MW green fields development in Australia, consisting of 10 x 0.5MWe units, are about $US1,120/kW. International costs for large commercial projects are$US1,100/kW, which this estimated to fall to $US800 to$US900.

The key factor governing performance and ultimately unit cost of energy output is the windresource that is highly site specific and dependant on the prevailing wind velocity.

Biomass

Biomass-based power generation is a commercially proven option with its feasibility largelybeing dictated by the availability of a suitable biomass resource for use as a fuel. Combustionbased steam plants using grate and to a lesser extent suspension firing systems are in wideuse. Gasification of biomass for power generation is not so well developed but is recognisedas a higher efficiency technology for future renewable energy projects.

Capital cost is technology dependent, and reflects strong economies of scale. Typically costsfor a 100 MW sized plant are:

• Steam plant US$1,350/kW

• IGCC plant US$1,500/kW

Typically, biomass energy systems are operated in a co-generation mode and reflect theoperational requirements of a host industry and so capacity factor may be lower than thecapability of the equipment, particularly where the supply of the biomass fuel is seasonal.

Nuclear Energy

Capital costs for nuclear plants vary considerably depending on the type of plant and thecountry of installation. Capital costs were shown to range from US$2,000/kW for a 400 MWeunit to US$1,600/kW for a 1,400 MWe unit.

End-of-life costs were generally treated by adding an annual sum to the operating costs toprovide a “fund” to meet these costs. For light water power reactors, the “fund” amounted to1% of the electricity generation cost, on a discounted basis. This is approximately equivalentto 1.25% of the capital cost of the plant.

Future Trends in Electricity Costs

In the current global economic climate there are a number of factors that have changed toimpact on the costs of electricity. These factors evolved due to the dramatic reform of the

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energy industry in developed countries and will most likely happen in the developingcountries in the near future. Significant issues include the following:

• The influence on the capital component of generating costs in the merchant market hascaused Generators to select the best financing option for each plant investment.

• Market liberalisation has led to the buyer focussing on the type of plant design that willyield the maximum return on the investment. This has seen a shift to proven, reliabledesigns, with improved, lower cost maintenance requirements.

• As an outcome of this, Generators are able to enjoy higher average annual capacity factors(ACF’s) and amortise the capital charges over higher energy output (GWh).

• Equipment vendors have become more competitive. Recent Australian experience hasseen vendors compete vigorously for turnkey plants, with contract prices reported as lowas US$600/kWe (1998).

• Liberalised markets have seen significant reductions in O&M costs. Direct costs havefallen as a result of improved plant automation, maintenance staffing practices and thereorganisation of corporate practices. The cost of fuel has dropped with Generatorsseeking increased competition for all new supplies.

ENVIRONMENTAL ISSUES

Emissions from electricity generating plants vary widely and include emissions to theatmosphere (particulates, SO2, NOx and CO2) and other discharges such as water and sewagedischarges, nuclear waste, noise etc. These are summarised in Table 2 attached.

Environmental costs of electricity production are significant and depend on many factorsrelated to fuel, plant technology, and environmental legislation at National and local level.The costs of environmental compliance emerge as a significant factor in the comparisonsbetween different electricity generation options. Table 1 provides a summary of theenvironmental costs associated with the fossil fuel and nuclear generation options consideredin this study.

Table 1: Summary of Environmental Costs

Cost Item Coal-Fired Plant Gas-Fired CC Nuclear

Air pollution control 6 – 18 % 0 – 6 %Cooling 0 – 2 % 0 – 3 %Environmental charges 0 – 9 % 0 – 5 %SO2 and NOx control 15 – 20 %Particulate control 3 – 4 %Fuel disposal 1 – 4 %Safety systems 15 – 45 %

Total 12 – 42 % 0 – 9 % 15 – 50 %

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SOCIAL/POLITICAL ISSUES

There is no doubt that the supply of electricity is vital to the development of any nation. Thisis particularly so for developing countries. The developed countries have been undergoingradical reform of their energy industries and some of those issues include:

• The current trend in developed economies is towards competitive, corporatised state-owned or privatised business units with generation, transmission and distributionbusinesses separated or sold and cross subsidies virtually eliminated.

• Electricity tariffs have fallen, particularly to industry, and economic activity has beenimproved.

• Markets have been established for electricity trading, just as for any other commodity, andcompetition to deliver cheaper electricity is vigorous and effective. New and sometimesnon-conventional IPPs have entered the market to capitalise on opportunities such ascheap fuel supplies (eg renewables) or local industrial situations (eg co-generation).

The development of large electricity generating projects requires a significant workforce forconstruction, ongoing management and operation of the plants. In addition, significantnumbers are required to provide for related community infrastructure and family support andwhich can lead to a significant increase in the availability of local and National employment.

CALCULATION SPREADSHEET

A MS Excel97©1 spreadsheet has been developed (ElectricityCosts.xls) from the dataevaluated in this study. The spreadsheet allows calculation of the cost of electricity from thevarious generation options, and is available on the 3.5” floppy disk attached to this report.

The spreadsheet allows the user to enter data as required, or to use default values specified inthe algorithms that are developed for the calculation of electricity costs

1 Excel is a registered trademark of Microsoft Corporation.

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SUMMARY

The following table summarises the general outcomes of this study and provides a quick reference on the costs of electric power fromcompetitive sources.

Table 2 Summary of Study Outcomes

Coal Oil Gas Renewables Nuclear

Solar PV Solar Thermal Wind Biomass

Plant Details

Unit Size 200 – 1,300 MW 200 – 750 MW 0.01 – 1 MW Up to 200 MW Up to 1.5 MW Up to 100 MW 600 – 1,300 MWCapacity factor 75 – 95% 75 – 95% 75 – 95% 5 – 20% 5 – 20% Highly site

specific, buttypically around20 – 50%

50 – 80depending onavailability offuel

60 – 90%

Fuel Source

Abundance Very abundant Abundant butcontrolled

Abundant inmany locations

Very abundantbut limitedcapacity factor


Abundant inmany locationsbut limitedcapacity factor

Limitedresources inmost locations

Abundant

Security ofsupply

High Risky due topolitical whimsof unstablegovernments

Moderate.Available from anumber oflimited sources

Subject toweather patterns



Subject toweather patternsto grow primarymass

Risky due topublic pressureonenvironmentalissues

Cost Cheap Moderate Expensive Zero Zero Zero Very cheap Very cheap

Power Plant Costs

Capital Cheap –moderate

Cheaper Cheap Very expensive Expensive Cheap Moderate Moderate –expensive

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Solar PV Solar Thermal Wind BiomassOperating &maintenance

Cheap Cheap Cheap Moderate Expensive Cheap Moderate Moderate

Cost ofelectricitysupply2

100 %Cheap

116 %Moderate

107 %Cheap

1,380 %Very expensive

725 %Very expensive

105 %Cheap

102 %Cheap

115 %Moderate

Environmental Issues

Pollutingpotential

High Moderate Low Very low Very low Very low Low Potentially veryhigh

Difficulty ofcompliance

Hard buttechnology hasdevelopedrapidly

Moderate onlydue to highsulphur fuel oil

Easy Easy Easy Easy Moderate Difficult

Cost ofcompliance

High Moderate Low Very low Very low Very low Low High

Social/Political Issues

Potential to fulfilcommunityenergy needs

Very high Possible but notcurrently infavour

High based onfuel availability

Very low Very low Low Low High but subjectto public opinion

Basis for reformof energy market

High High but risk offuel supply

High Low Low Low Low High but subjectto public opinion

2 The costs quoted here are costs for the default options chosen in the Excel spreadsheet and are generally indicative of the relative costs between the various options.

Electric Power from Competitive Sources Page..1

1 INTRODUCTION

The Queensland Department of Mines and Energy, through the QTHERM Program, hasretained Ultra-Systems Technology Pty Ltd (UST) to develop the costs and implications of arange of options for bulk electricity generation and supply. The options ranged from differentfossil fuels (coal, oil, gas), renewable energy sources (solar, wind, biomass, etc) and nuclear.

This work was to provide a simplified comparison of the cost of electricity generationaccording to the type of fuel, generation technology and other site related variations. It wasnot meant as a definitive study to identify precise electricity generating costs, but wasproduced in an attempt to put the differences in costs in a global perspective.

The outcomes of this study are contained in this concise report that sets out the results of thework and includes a summary table setting out the advantages and disadvantages of each ofthe supply options. Also, a computer spreadsheet, setting out the costs of electricitygeneration and supply from each of the options is provided. This spreadsheet can be used byinterested parties to manipulate the costs to suit their own applications both in Australia andoffshore, with particular reference to East Asian countries.

The cost of bulk electricity ($/MWh) sent out from a power station is:

($/MWh)Out tEnergy Sen Total

Costs Annual Totaly SupplyElectricit Bulk of Cost =

Costs of each of the plant options reviewed have been grouped in a number of categories, asset out in Table 1.1.

Table 1.1: Bulk Electricity Supply Costs

Cost Category Sub-category Comments

Capital Costs Design & constructionEngineering and ProjectManagementInterest during construction

Depreciated over the life of the plant,normally by a constant annual amount.rate for IDC3 sometimes varies fromdiscount rate

Operating & Maintenance LabourMaterials

Materials includes consumables, andmajor spare parts during overhauls

Environmental Environmental controlequipmentWaste disposalBy-product salesCarbon credits

Capital costs shown separately inspreadsheet. Vary with technology.

Fuel costs Primary energy supplyTransportHandling & preparation

Energy Sent Out Energy generatedAuxiliary power consumption

Ratio of sent out to generated energydepends primarily on cooling system andcycle efficiency

Rehabilitation DemolitionSite clean-up

Implemented at the end of the plant life,but paid during the life of the plant.

3 Interest During Construction


These cost elements were integrated into a Microsoft Excel spreadsheet that allows a user toenter their own data and produce comparisons specific to their particular applications.

The report includes a brief summary of the environmental impact of each of the options,including greenhouse gases, liquid and solid wastes and visual impacts. In addition, anevaluation of the potential of each option to add or remove from the greenhouse inventory andan estimate of the possible economic benefit/liability of each option in terms of carbon tradingis included.

The report includes a summary of the main social and political impacts of each of thegeneration options considered. These will arise from issues including but not limited to:

• Security of supply for the various technologies and the implication of this on industry,commerce and the general community.

• Number of direct and indirect jobs to be created and maintained; provision for theirhousing, educational and ongoing training requirements; the impact of expatriateconstruction and project management teams on the local community.

• Site requirements including land acquisition, size, location, infrastructure, transportationand security; the financial and social impact of community enrichment and the necessaryprovision of social services.

• Consequences of exchange rate variations and risks associated with the surety of projectfinancing.


2 ELECTRICITY GENERATING COSTS

2.1 FOSSIL FUELS

Within this present study, the following fossil fuels have been examined:

• Coal,

• Natural gas, and

• Oil.

For the range of fossil fuels identified above, costs have been derived using the methodologyset out in the International Energy Agency (IEA) publication “Projected Costs of GeneratingElectricity – Update 1998”4.

In the increasingly competitive market for electricity generation, two basic generationtechnologies have emerged as the “best practice” systems. These are:

2.1.1 For Coal, the Supercritical Pressure Steam Cycle

The latest boiler designs feature pulverised coal firing, with low NOx burners in a balanceddraft or pressurised furnace. These units are generally fitted with advanced particulateremoval systems in the flue gas stream. For high sulphur coals (as for most NorthernHemisphere coals), flue gas de-sulphurisation equipment may also be fitted. The flue gasclean-up systems add to capital and operating costs, although the trend in Europe, Japan andthe US is for regulators to require such measures for new plants.

From the boiler, steam flows to a highly developed steam turbine, based on modular cylinderelements, fitted with up to eight stages of feedwater heating. Depending on fuel quality andcooling water conditions, cycle thermal efficiencies of up to 46% can be achieved.

Capital costs have been derived from the IEA report and are shown in Figure 2.1.

In many countries flue gas desulphurisation (FGD) is installed in new plants, particularlythose that burn higher sulphur northern hemisphere black coals with up to 1.5 to 1.8%sulphur. This leads to higher capital and operating costs as shown. Costs for the addition ofFGD plant have been included in the spreadsheet attached to this report, to permit the plannerto include FGD as an option when evaluating the costs for coal-fired plant. A value of 8% ofbase capital costs has been assumed.

Also, the addition of de-NOx plant to reduce the emission of oxides of nitrogen is required insome countries for new plant. This also leads to increased capital and operating costs, alsoshown in Figure 2.1. A value of 12% of base capital costs has been assumed, based on thedata provided in the IEA report4.

4 Nuclear Energy Agency/International Energy Agency/Organisation for Economic Cooperation and

Development – “Projected Costs of Generating Electricity – Update 1998”.


0

200

400

600

800

1,000

1,200

1,400

1,600

0 100 200 300 400 500 600 700 800

Unit Size (MWe)

Cap

ital C

ost

(US

$/k

We)

PF

FGD

FGD+SCR

Figure 2.1: Capital Costs for Coal Fired Plant

O&M costs include all costs apart from the capital cost and fuel costs. They includemaintenance workforce, consumables, credits from the sale of by-products and wastedisposal. O&M cost for coal fired plants were derived from the IEA report4, as shown inFigure 2.2

0

10

20

30

40

50

60

70

80

90

0 200 400 600 800

Plant Size (MWe)

O&

M C

ost

(US

$/k

W)

PF

FGD

FGD+SCR

Figure 2.2: O&M Costs for Coal Fired Plant

Although the data is very scattered, the “best fit” lines general show the expected downwardtrend as the unit size increases. The effect of FGD plant is shown to be minimal, but there is asignificant increase in O&M costs due to the additional of de-NOx plant, being around a 30%increase over the base cost.


2.1.2 For Natural Gas, the Advanced Gas Turbine Cycle.

The latest gas turbine designs feature advanced low NOx burners, high temperaturemetallurgy in the turbine front rows, and modular turbine blade elements. Where the unit is tobe used for intermediate to base load duty, the gas turbine is combined with a heat recoverysteam generator (HRSG) and a steam turbine, leading to relatively high thermal efficiencies ofup to 55%. These machines have seen rapid improvements in recent years, and designs areavailable from a number of reputable makers at extremely competitive prices. The normal fuelfor such plants is natural gas (both direct delivered by pipeline or through re-gasification ofshipped LNG) although in some cases, liquid fuels – avgas or distillate, may be economic.

Capital costs have been derived from the IEA report and are shown in Figure 2.3.

0

100

200

300

400

500

600

700

800

900

0 100 200 300 400 500 600 700 800

Unit Size (MWe)

Cap

irtal

Cos

t (U

S$/

kW

e)

w/o SCR

with SCR

Figure 2.3: Capital Costs for Natural Gas Fired Plant

Again, the data is very scattered, but shows a trend downwards as the unit size increases. Theaddition of de-NOx plant (SCR5) on these units is being implemented on a few units, but thecosts are very scattered as shown. It has been assumed that the additional costs are similar tothose for coal fired plants at 12% of base capital costs.

The two very low-cost plants with SCR in Figure 2.3 are a 1x250 MWe plant in the USA anda 2x680 MWe plant in Turkey. There is no obvious reason why these two plants should besignificantly lower than the other plants.

O&M cost for gas fired plants were derived from the IEA report4, as shown in Figure 2.4

5 Selective Catalytic Reduction


0

5

10

15

20

25

30

35

40

45

50

0 200 400 600 800 1,000 1,200

Unit Size (MWe)

O&

M C

ost

(US

$/k

W)

w/o SCR

with SCR

Figure 2.4: O&M Costs for Gas Fired Plant

Again, the data is very scattered but the “best fit” line shows a reasonable trend of O&Mcosts. Note that there does not appear to be any additional costs for de-NOx plant (SCR).

Coal seam methane is a promising new fuel for base load gas turbines, and is often availableat relatively low cost, although typically with lower specific energy than natural gas (oftenwith some variability). This low cost fuel requires a more flexible energy conversion process.The economics of a merchant market plant would dictate a gas turbine, and the typicallyvariable flow rates and specific energy of coal gas methane flow often dictate a smallermachine, with a combustion system capable of wide variations in fuel specific energy. Thisinvariably leads to lower thermal efficiency, but may prove economic against other sitealternatives.

2.1.3 Oil Firing

According to the IEA publication4, recent trends have seen OECD countries install almost nonew generating units based on oil fuel alone. However, oil can provide useful fuel diversityfor gas turbines (and for some coal fired sites at start-up or load stabilisation at up to say, 30%capacity) but few sites exist where oil fuel alone offers the most economic choice for baseload plant. However, oil fuel is suitable for sites where the fuel delivery infrastructure is inplace (such as many Pacific Islands) or where the planned capacity factor is low.

Since there have been no new oil-fired plants installed, the capital costs for this option havebeen notionally taken as 85% of the costs of coal-fired plant and O&M costs have been takenas 90% of the costs of coal-fired plant6.

6 Based on previous data developed from Ultra-Systems’ database.


2.2 RENEWABLE ENERGY TECHNOLOGIES

2.2.1 Solar Photovoltaic

Photovoltaic electricity generation systems are now in wide commercial use for both smalland large-scale applications. The smaller applications, less than 100 W and upwards, includeoff grid and remote electricity supplies such as for houses, villages and in specialisedcommunications applications. These small installations may be grid connected such as thesystems now being installed in Europe, USA and Japan.

The larger applications include 1 MW grid connected arrays at Sacramento (USA), Italy andSpain. Energy Australia has a 500kW PV array at Singleton, NSW and larger 1 MW system isbeing investigated in Queensland and in other states in Australia.

Large systems are commercially available from a number of suppliers such as the majorenergy system developers (eg Enron, Shell, BP Solar, Solarex) and a large number ofengineering and commercial developers. Small systems are widely available from many localand overseas suppliers.

Cost of the technology is still high, compared with other electricity generation technologies.The capital cost for small, simple systems is US$4,000 to US$8,000/kW, depending uponrequirements. For the larger AC grid connected systems of 500 kW to 1 MW and more, thecapital cost is US$7,000 to US$5,500, although these costs are reducing progressively withtechnological advances and increased manufacturing capacities. Capital costs assumed for thisstudy are illustrated in Figure 2.5.

0

2,000

4,000

6,000

8,000

0.0 0.5 1.0 1.5 2.0 2.5Unit Size (MWe)

Cap

ital C

ost

(US

$/k

We)

Figure 2.5: Capital Costs for Solar Photovoltaic

Operating costs are very low, comprising minimal maintenance and cleaning. It is estimated atabout 0.5% of capital investment.


Performance is dependent upon the availability of good sunlight and is best in clear, dry areassuch as inland Australia. Performance is significantly degraded by cloud cover, haze andindustrial pollution. The estimation of performance requires a good knowledge of the solarresource that is site specific and requires separate consideration for different sites. Annualcapacity factors range from 14% in the southern coastal regions of Australia to 20% in CentralAustralia.

2.2.2 Solar Thermal

Solar thermal systems are widely used for domestic and some industrial water heating but thetechnology is not currently commercially successful for power generation. There are 350 MWof hybrid gas/solar thermal generation plant (SEGS) operating in California but this has notbeen commercially successful. Technically, it operates well but the high capital cost and lowannual capacity factor for solar operation makes this uneconomic.

There are a number of commercial development programs now going on to further developthe technology and to drive down costs, in Australia and overseas. Leaders are Solel(producers of the California plants), Steinmuller, Pilkington, AUSTA Energy and PacificPower in Australia.

Capital cost of Californian-type 160 MW SEGS with natural gas back-up7 is $US2,750/kW.More recent developments in Australia8 have identified the cost of new-generationtechnology, presently under development in Australia at US$1,950/kW to US$2,700/kW for200 MW plants.

Developments now under way in Australia indicate solar supplementation of existing fossilfuel plant can be costed at around US$850/kW.

Capital costs assumed for this study are illustrated in Figure 2.6.

7 Pilkington Solar International, “Status Report on Solar Power Plants”, 1996.8 Sinclair Knight Merz, “Technical evaluation and development plan for commercialising the Fresnel

Collector/Big Dish”. Australian Solar Concentration Technology Project, 1998.


0

1,000

2,000

3,000

4,000

0 50 100 150 200 250 300 350

Unit Size (MWe)

Cap

ital C

ost

(US

$/k

We)

Figure 2.6: Capital Costs Assumed for Solar Thermal Plant

Operating and maintenance costs for the solar thermal plant are estimated to 2.6% of capitalcost, based on data that shows maintenance costs between 2% and 3% of capital cost7 andestimates of 2.6% (200MW)8.

For pure solar plants (no energy storage) annual capacity factors are similar to solarphotovoltaic systems, with capacity factors of 20% or less. Most plants under considerationare hybrid with fossil fuel back up, and with overall capacity factor similar to typical fossilfuel plant, nominally, 90% for high availability base load plant. Solar contribution for theseplants is 20% solar/80% fossil fuel.

2.2.3 Wind

Wind power is widely used for commercial power generation and there are almost 8,500 MWof wind generation now installed worldwide. New systems are being installed at 500 to 600MW/year. Most of the growth is in Europe but there is significant growth in USA and Asia.

Wind turbine technology is now mature and is fully commercial, from smaller 2.5 kWmachines up to utility machines of 1.5 MW or more. Most utility sales are in the range 250kW to 600 kW. Smaller off grid and RAPS machines are in the size range of 2.5 kW to 10kW.

The utility market is dominated by European and US manufacturers, such as Vestas, Enercon,Zond, Micon and Nordex Balcke-Durr. The smaller “off grid” market includes emergingcompanies in Australia, such as Westwind.

Capital costs are reducing rapidly. Current prices for 5 MW green fields development inAustralia, consisting of 10 x 0.5 MWe units, are about $US1,120/kW. International costs for


large commercial projects are $US1,100/kW, with this estimated to fall to $US800to$US9009.


0

500

1,000

1,500

0.0 0.5 1.0 1.5 2.0 2.5Unit Size (MWe)

Cap

ital C

ost

(US

$/k

We)

Figure 2.7: Capital Costs Assumed for Wind Plant

Operating and maintenance costs are estimated at 2% of capital costs.

The key factor governing performance and ultimately unit cost of energy output is the windresource. This is highly site specific and must be assessed by a specific site evaluation study.The impact of wind velocity upon performance, as defined by annual capacity factor, isillustrated by the data in the table below.

Table 2.1: Commercial Wind Turbine Performance

Annual Capacity Factor (%)Wind Velocity(m/sec)

Typical Vestas V47-660(660kW)

Vestas V29-225(225kW)

Enercon E-30

5 15 14 16 156 24 24 26 227 34 34 35 328 42 42 43 4210 56 55 5715 100 100 100 100

Wind is highly regarded as a true renewable energy and as such it qualifies as “GreenEnergy”. However, it does have some environmental issues. In particular:

9 Gipe P and Associates, “Overview of Worldwide Wind Generation”, Solar 98.


• Noise. Large wind turbines have a reputation for being noisy and so are not usuallylocated within 1,000 m or more of houses or other noise sensitive areas.

• Visual. The wind turbine is usually located in an exposed, prominent area and so may behighly visual. Low level tree groves and hedge lines may not give sufficient screening.

• In some locations, interference with telecommunications may occur if transmission passesthrough the swept diameter of the turbine.

2.2.4 Hydro-electricity

The costs for hydro-electricity are very site specific and are grossly influenced by theavailability of water, the pressure head available, the proximity to load centres and the likelymode of operation (generally peaking load). In addition, most favourable sites for hydro-electricity have already been utilised in most developed countries, although there is significantpotential for further exploitation in developing countries.

For these reasons, as in the IEA study4, these plants have been excluded from this study.

2.2.5 Biomass

Biomass-based power generation is a commercially proven option with its feasibility largelybeing dictated by the availability of a suitable biomass resource for use as a fuel. This biomassresource may include:

• Natural forests (eg eucalypt)

• Forest and mill residues and wastes from timber processing (eg forest floor waste,sawdust, mill off-cuts and paper industry waste).

• Agricultural and farming residues (eg straw, rice hulls, nut shells, bagasse, animalmanure, abattoir waste).

• Weeds.

• Energy crops (eg eucalypt, willow, alfalfa).

There are examples of all these materials being used for commercial energy production, eitherin stand-alone plants or being co-fired in existing coal fired facilities10.

Some examples of projects are:

• 28 MW circulating fluidised bed power plant at Woodland in California burning woodwaste, rice husks and rice straw.

10 Badin J and Kirschner J, “Biomass Greens US Power Production”, Renewable Energy World, Volume 1,

Number 3, November 1998.


• 50 MW JC McNeil Power Station in Vermont, USA that has been generating electricityusing wood waste in a conventional boiler for fourteen years. Overall efficiency of energyconversion was 25%. In a move to boost output and to increase energy conversionefficiency, an IGCC fluidised bed gasification plant is being developed at the site. Thisnew 62MW plant will have a conversion efficiency of 36%.

• At Varnamo in Sweden, a 6 MW electrical and 9 MW thermal combined cyclegasification plant is being developed, and is to be scaled up to 120 MW.

• The utility, Brista Kraft AB, is operating a 44 MW biomass-fuelled power plant outsideStockholm in Sweden. A Foster wheeler circulating fluidised bed boiler is fired withchipped wood and forest waste and electricity is produced in a conventional utility turbo-alternator.

These projects, above, represent larger scale activities. Many biomass sources, particularlyresidues, will only economically support relatively small operations because of the low energydensity of biomass and the consequent high collection and transport costs. Capital andoperating costs of these smaller operations, say 10 MW or less, are relatively higher than thelarger plants. On the other hand, they can be sited in factories for co-generation, near loadcentres, near biomass sources and their infrastructure requirements are less.

Biomass generation is commercially proven at both small and larger scale. Combustion basedsteam plants using grate and to a lesser extent suspension firing systems are in wide use.Gasification of biomass for power generation is not so well developed but is recognised as ahigher efficiency technology for future renewable energy projects. It has the advantage ofoffering a path to electricity generation at higher conversion efficiency with lower emissions.For this reason, considerable development funding is being ploughed into biomassgasification technology.

Capital cost is technology dependent, and reflects strong economies of scale. Costs of onebiomass fuelled plant are given in the IEA paper and costs for a range of plants is given in anUltra-Systems publication11. Typically costs for a 100 MW sized plant are:

• Steam plant US$1,350/kW

• IGCC plant US$1,500/kW


11 Ultra-Systems Technology Pty Ltd. Biomass Resources and their Use for Power Generation in Queensland.

Report to Queensland Transmission and Supply Corporation, 1996.


0

500

1,000

1,500

2,000

2,500

0 50 100 150 200 250

Unit Size (MWe)

Cap

ital C

ost

(US

$/k

We)

Figure 2.8: Capital Costs Assumed for Biomass Fired Plant

Maintenance cost is typically 4% of capital cost, similar to smaller coal fired plant.

Capacity factor is estimated at 90%, on the assumption that dispatch is not limited by the loadside capability of any interconnected electrical system. Typically, biomass energy systems areoperated in a co-generation mode and reflect the operational requirements of a host industryand so capacity factor may be lower than the capability of the equipment, particularly wherethe supply of the biomass fuel is seasonal.

If the biomass is a residue or waste, the establishment of a biomass industry may present alow cost opportunity for disposal, in which case the project may accrue additionalenvironmental and cost benefits.

2.3 NUCLEAR ENERGY

The capital costs for electricity derived from nuclear plants are shown in Figure 2.9 from theIEA report4. The O&M costs, also from the same report, are shown in Figure 2.10.


0

500

1,000

1,500

2,000

2,500

0 200 400 600 800 1000 1200 1400 1600

Unit Size (MWe)

Cos

t (U

S$/

kW

e)

Figure 2.9: Capital Costs for Nuclear Plant

0

10

20

30

40

50

60

70

0 500 1,000 1,500 2,000

Unit Size (MWe)

O&

M C

ost

(U

S$

/kW

)

Figure 2.10: O&M Costs for Nuclear Plant

The treatment of the end-of-life costs for nuclear power plants varies widely12, with mostcountries effectively adding an annual sum to the operating costs to provide a “fund” to meetthe assessed obligations of the facility.

For light water power reactors, the amount required to be set aside for all decommissioningactivities (including reactor, and contributions to the fuel transport and fuel supply chain)amounted to 1% of the electricity generation cost13, on a discounted basis. This is

12 Future Financial Liabilities of Nuclear Activities – Nuclear Energy Agency (1996) – Table I13 ibid – Section 2.4


approximately equivalent to 1.25% of the capital cost of the plant. This value has been used inthe spreadsheet accompanying this report.

2.4 FUTURE TRENDS IN ELECTRICITY COSTS

In the current global economic climate there are a number of factors that have changed toimpact on the costs of electricity. These factors evolved due to the dramatic reform of theenergy industry in developed countries and will most likely happen in the developingcountries in the near future. The reform issues are discussed in detail in Section 4.

The electricity generating costs discussed in the previous Section were derived from historicaldata from mainly government owned electricity authorities that were acting in a monopolysituation. The energy industry reform process has changed the economics of electricitygeneration and this is discussed in the following Sections.

2.4.1 Capital Investment

Investment Cost

The influence on the capital component of generating costs in the deregulated merchantmarket has been profound.

In addition to studies to select the optimum plant type, size and market timing (including thesignificant effort to shift maximum risk to the plant vendors), the large merchant marketOwners take great care to select the best financing option for each plant investment. Thisinvolves seeking and obtaining the maximum local taxation benefits, the willingness of localcapital markets to contribute a high portion of the loan funds (thus minimising the exposure ofthe project to foreign exchange variations), and the minimisation of the Owners investment.

Recent trends have seen merchant market plant Owners arrange attractive financing packageswith Lenders whereby as little as 10% of equity contribution is required. As Owners typicallyrequire about 17 to 20% pre-tax return on equity (depending on the project risk factors), andLenders typically require up to only 2% above local Government Loan rates, this allows theeffective cost of capital to be only marginally higher than for Government funded projects.

Up to this point in time, such novel financing arrangements established by the multi-nationalplayers have not been attractive to conservative Government agencies (or even locally basedprivate utilities), and hence yield a significant benefit to the experienced market players. Inthis context, the recent MITI sponsored opening of the Japanese markets to competition hasseen no Japanese utility secure the first three new IPP plants, and no Japanese equipmentvendor secure any of the new plant so provided14.

Emphasis on Economic Designs

Market liberalisation leads to the buyer focussing on the type of plant design that will yieldthe maximum return on the investment. This has seen a shift to proven, reliable designs, withimproved, lower cost maintenance requirements.

14 Private communication from Mitsubishi Corporation Tokyo office


Owners are also allocating higher responsibility to the plant vendors, through harsh penaltiesfor non-delivery of the guaranteed performance or availability levels. In a depressed plantmarket, vendors are accepting such increasing penalties as the price to pay to receive an order.

Improved Use of Generation Capacity

As an outcome of specifying and constructing more reliable plants, Owners are able to enjoyhigher average annual capacity factors (ACF’s) and amortise the capital charges over higherenergy output (GWh), leading to lower average production costs. Experience in the Victorianelectricity system (Australia) has shown a remarkable increase in ACF, with some browncoal-fired stations lifting availability by over 20%.

In the nuclear industry, experience with standard designs has also led to an improvement inplant availability (US stations improved from 72 to 79% between 1992 and 1996).

The reformed are likely to see a decline in system spare plant margin, as average plantavailability increases. Paradoxically, this should see an increase in the value of standbygeneration capacity to the system, a system service that has been traditionally undervalued.Clearly in most markets in transition, these values will change slowly over time, althoughregulators should ensure that they are taken into consideration when planning the regulatoryregime.

Repowering

The economic life of the plant has a significant influence on the capital charges. Given thedifficulty of securing new sites, one economic solution often proves to be the replacement ofold generating units with later designs. The economic studies for such developments will needto factor in the value of the existing site infrastructure, such as cooling water, coal suppliesand workforce.

Competitive Procurement

Increasing globalisation of trade has forced equipment vendors to become active in foreignmarkets, and compete with domestic (or traditional foreign) equipment suppliers.

Recent Japanese combined cycle plants were provided by US makers at prices much lowerthan for previous plants provided by local Japanese vendors.

Recent Australian experience with coal fired plant for Queensland has seen European,Japanese and US equipment vendors compete vigorously for turnkey plants, with contractprices reported as low as US$600/kWe (1998). However, although it could be expected to seelower prices than normal at these sites as they have limited sharing of site infrastructure, thisprice level was only 65% of the last Government-built plants under similar conditions.

Cost of Capital

The effect on capital charges per unit of electricity production arising from changes in the costof capital under market liberalisation remains uncertain. Clearly, as private owners seek ahigher return than State-owned Agencies, it might at first seem that unit capital changes


would be higher. However as already discussed many merchant market owners will strive tokeep the actual equity very low, and seek low cost loan funds for the balance.

In the recent Australian market where new plants have been funded by a combination ofowner-equity and external loan funds, the illustrative cost of capital is shown in Table 2.2.

Table 2.2: Cost of Capital

Funding portion Government Owner Merchant Market Owner

Equity 7% on 5~15% of funds 17% on 5% of funds

Debt 6.2% on balance of funds 6.8% on 95% of funds

Effective Interest Rate 6.3% 7.3%

As the initial plant capital cost is lower than for traditional Government-owned plants by asmuch as 35%, the result of the merchant market owner requiring higher returns on a lowercapital equity capital equates to a 19% reduction in annual capital charges.

However, on the broader question of the effect of using a higher discount rate to assess theproject economics, this can certainly influence the choice of plant, and hence the unit capitalcost. Higher project discount rates lead to the choice of lower-cost plant designs, and favourplant designs with low initial capital cost, but with higher O&M and fuel costs.

In developing countries, this will almost certainly favour plant types with lower initial capitalcosts (such as open- and combined-cycle gas turbine designs) against coal and nuclear plants.However, recent evidence from the Australian coal fired plant tenders suggests that currentprices for sub-critical and super-critical designs were virtually identical, so coal-fired designswill need to be assessed on the higher efficiency of the super-critical design.

Thus, developing countries moving towards market reform will need to be aware that privategenerators may use higher discount rates in planning generation plant alternatives, and thatthis in turn will lead to possible differences in the types of plant adopted.

2.4.2 O&M costs

Liberalised markets have seen significant reductions in O&M costs. The direct operating costsinclude operating and maintenance labour and fuel, whilst the indirect operating costs includespare parts and corporate overheads.

The direct labour costs have fallen as a result of improved plant automation, with theQueensland plants being widely regarded as the world’s best practice in coal firing. Forexample, the Stanwell station of 4 x 350MW capacity has only three operators on theweekend shifts, with all load following and hot starts achieved automatically. It is understoodthat the new Queensland stations now being built by merchant market owners will also featuresimilar staffing levels.

Current designs of natural gas fired combined cycle plants permit fully remote operation, withall functions achieved under automatic control. However, some owners prefer to retain staffmembers on site for physical checking. Similar automation levels and staffing philosophiesare in place for nuclear plants.


Maintenance staffing practices have also changed as a result of competition, with a decreasingreliance on in-house staff and an increased reliance on external providers, including the plantvendors. The tendency to “outsource” the entire “operating and maintenance” functionthrough a separate legal agreement is increasing, and in Australia and UK, plant vendors andGenerators have emerged as major players in this market. For example, GEC (UK) operates alarge workshop in Australia, capable of re-blading and balancing turbine rotors. Also, aneastern State Generator, Pacific Power, has recently secured the contract to operate andmaintain a new 330 MWe coal-fired plant in Western Australia.

In the corporate headquarters, developments have been similarly taking place, withreorganisation into business functional units leading to significant job losses. The shift fromcentralised planning to project-specific planning has led to much of the savings.

Arising from these initiatives, permanent staff levels among the Generators have dropped bybetween 3 and 13% as a result of competition15.

Fuel remains the most significant variable cost of operation, and merchant market plantowners have been quick to review any existing fuel supply agreements, and have soughtincreased competition for all new supplies. Developments in this area have producedremarkable results. In NSW, recently corporatised Government Generators have used contractprovisions to minimise purchases under long-term supply agreements with a single coal mine,and purchase the balance via an annual tender process, open to all fuel suppliers. In one case,this has led to fuel prices dropping from US$0.85/GJ delivered to US$0.65/GJ delivered, a23% saving.

In Australia, deregulation of the natural gas industry is also proceeding, although the lack ofany real competition in the gas pipeline (transport) industry may act to limit real savings at thedelivery point. The key to gas price competition in any market is the availability ofindependent gas suppliers, and a deregulated gas transport system.

For countries that have existing gas shipping import terminals, there is also the prospect ofseeking competitive prices from a number of LNG suppliers. However, care should be takento limit the “spot” purchases of fuel for base load plants, as these must be tied to storagecapacities and fuel consumption.

In North America, a spot market for natural gas supply to power stations and other users hasemerged which has seen buyers take about 15% of their needs from the market. The emergingmarket for spot coal sales in Australia seems to be moving towards the same 15% level.

As the choice of future plant types will depend heavily on future fuel prices, Generators willexamine a range of fuel supply options and pricing. Projections of future fuel pricemovements are developed in the IEA report16, however, the very poor agreement betweenactual and projected17 coal and gas prices in past IEA reports should be noted.

15 IEA paper – Appendix 8 Table A8-316 IEA paper – Annex 517 IEA paper – Annex 5 – Figures A5-5 and A5-6


3 ENVIRONMENTAL ISSUES

Emissions from electricity generating plants vary widely and are difficult to summarise withinthe space of this report. The main environmental issues relate to emissions to the atmosphereand to other discharges, such as water and sewage discharges, nuclear waste, noise etc.

The following Sections set out a brief overview of these issues.

3.1 ATMOSPHERIC EMISSIONS

Environmental legislation to limit atmospheric emissions from fossil fired plants variesbetween countries, with world-wide Greenhouse gas initiatives expected to result in commonstandards in the period beyond 2010. The main emissions of concern include particulates,oxides of sulphur and nitrogen (SO2 and NOx), as well as carbon dioxide (CO2) as the majorgreenhouse gas.

Particulates

Solid fuel fired plants emit particulates from the ash in the fuel. Legislation to limit theemission of particulates from solid fuel-fired plants generally requires that the concentrationof particulates is less than about 50 mg/Nm3. Some countries, eg Japan, impose morestringent emission limits according to locality and proximity of other emitters.

Coal-fired plants normally have electrostatic precipitators or fabric filters to clean the flue gasto very low concentrations of particulates before being emitted to the atmosphere. Thesedevices are generally able to achieve these limits.

Sulphur Dioxide

The emission of SO2 is readily predicted from the sulphur content of the fuel being used, asmost of this sulphur will be converted to SO2 during combustion. For example, coal with a 0.6%adb sulphur content will emit about 350 ppm (dry, @ 6% O2) concentration in the flue gas.

The legislated measurement for the impact of the sulphur compounds in Australia from allcoal-burning facilities is the “Ground Level Concentration” of SO2, currently set to 50ppm atthe station boundary. This level can be achieved when burning the low sulphur Australiancoals in modern boiler plants, without the need for additional de-sulphurisation equipmentfitted to the boiler flues.

Most modern coal-fired plants in Asia and Europe are currently fitted with flue gasdesulphurisation (FGD) to reduce SO2 emissions to very low levels (about 90% removal).This plant exposes the sulphur oxides in the flue gas to activated calcium hydroxide (lime)surface, trapping the sulphur in the form of gypsum (CaSO4).

The fitting of FGD plant leads to higher capital costs, and increased operating costs due tocalcium feedstock costs and fan power losses. It is estimated that FGD imposes an increase incapital costs of about 12% and a reduction of about 1% in sent out electricity. Current costsfor the addition of FGD plant have been included in the spreadsheet attached to this report.


SO2 emissions for oil will relate to the sulphur content of the oil, but gas-fired plants will emitzero SO2, as will all of the renewable technologies and nuclear, with the exception ofbiomass-fired plants. Biomass generally has a low sulphur content and therefore, low SO2

emissions.

Nitrogen Oxides

Coal-fired plant emit relatively high levels of NOx, compared to the other technologiesconsidered in this study, however, all types of combustion will generate NOx. In these plants,the nitrogen in the coal produces most of the NOx emissions from coal, and is very sensitiveto plant operating conditions, particularly the amount of mixing within the combustion zonesof the boiler.

NOx reduction techniques include methods to control the mixing between the combustion airand the fuel. This can be achieved by a number of methods, but best done using speciallydesigned “Low-NOx” burners. Other techniques for NOx reduction include injection ofammonia to chemically reduce the nitrogen oxides to N2, or by using selective catalyticreduction (SCR).

Table 3.1 sets out the rough emissions of NOx from each of the fuel type considered in thisstudy.

Table 3.1: NOx Emissions from Combustion Plants

Fuel Type Uncontrolled Emissions Controlled Emissions

Coal 400 – 1,200 ppm 150 – 400 ppm with Low-NOx burners.Less than 100 ppm with SCR.

Oil 100 – 200 ppm Down to 50 ppmGas 50 – 100 ppm Down to 10 ppmRenewables: Solar & wind ZeroRenewables: Biomass 200 – 400 ppm Generally no reduction mechanisms

installedNuclear Zero

Carbon Dioxide

Emissions of CO2 vary for different fuels, mainly depending on their carbon to hydrogen ratioand the efficiency of utilisation. The estimated emissions are set out in Table 3.2.

Table 3.2: CO2 Emissions from Combustion Plants

Fuel Type Specific CO2 Emissions(g/MJ)

Emissions from Plants(kg/MWh)

Coal 85 – 95 for bituminous coal 850 – 950 for subcritical unitsDown to 800 for supercritical

Oil 70 – 75 700 – 750Gas 50 – 55 450 – 500Renewables: Solar & wind ZeroRenewables: Biomass 90 – 100 >1,000

Note that combustion of biomass isconsidered CO2 neutral.

Nuclear Zero


Gas-fired plants have the lowest greenhouse gas emissions, followed by oil, coal and biomass.However, it is generally recognised that the combustion of biomass is considered CO2 neutralas the emissions are sequestered in the next crop of biomass.

Table 3.2 only includes actual emissions at the point of combustion and no allowances havebeen made for “whole of life” emissions that accrue during manufacture of plant components.In this context, although solar PV do not produce any direct emissions, they do contributesubstantial emissions due to manufacture of the fuel cells. Other renewables also contribute toemissions in a similar manner, but not to the extent of solar PV.

3.2 OTHER DISCHARGES

Solid Waste

Ash disposal from solid-fuel fired plants can cause problems due to the discharge of pollutedwater that has leached trace elements, such as arsenic and mercury, from the ash. A list ofelements and their level of concern is set out in Table 3.3. In general, concentrations of traceelements in discharges from solid fuel fired plants are at levels below hazard levels. However,coal-fired plants are required to implement zero discharge of ash sluicing water.

Table 3.3: Trace Elements from Solid Fuel Combustion

Element

Greatest Concern Moderate Concern Minor ConcernArsenicBoronCadmiumLeadMercuryMolybdenumSelenium

ChromiumCopperFluorineNickelVanadiumZinc

AntimonyBariumBerylliumBromineChlorideCobaltGermaniumLithiumManganeseStrontiumTin

In addition to ash formed during combustion, solid wastes are derived from FGD system by-products. Most solids from oxidation type FGD systems are in the form of marketablegypsum and, thus, have relatively low discharge of solid material. Wet FGD processes,however, produce large quantities of moist sludge that must be disposed of.

Water Quality

Power plants generally only discharge treated water streams to avoid environmental problems.The main sources of waste water production are:

• Cooling tower blowdown, ie, the purge stream from recirculating cooling water systems.

• Purge streams from forced oxidation FGD systems.

• Waste streams from other plant process operations, such as blowdown from boilers ordemineralisation systems.


• Waste water from occasional cleaning or maintenance operations.

• Water collected from site area drains, including around coal piles.

Nuclear Plants

The other potentially hazardous discharge of waste is from nuclear plants, where the risk ifradioactive leakage and contamination is potentially disastrous.

Radioactive waste disposal is an area of significant cost for nuclear power plants. The costs ofdisposal of radioactive wastes are generally included primarily in fuel cycle costs. Theseentail temporary storage of fuel elements, transportation, and disposal of high level wastesfrom fuel and reprocessed fuel. All these elements have significant costs associated withenvironmental protection.

For nuclear plants, environmental protection relies heavily on systems to ensure plant safety.The fraction of generation for environmental protection in nuclear plants is greater than othertypes of plant due to the elaborate and costly systems to ensure this safety. It is suggested thatup to 60% of the plant capital cost is related to environmental protection systems18. Thisrepresents about 45% of the levelised electricity generating cost.

3.3 COST OF ENVIRONMENTAL COMPLIANCE

Environmental costs of electricity production are significant and depend on many factorsrelated to fuel, plant technology, and environmental legislation at National and local level.These costs emerge as a significant factor in the comparisons between different electricitygeneration options. Table 3.4 provides a summary of the environmental costs associated withthe fossil fuel and nuclear generation options considered in this study4.

Table 3.4: Summary of Environmental Costs

Cost Item Coal-Fired Plant Gas-Fired CC Nuclear

Air pollution control 6 – 18 % 0 – 6 %Cooling 0 – 2 % 0 – 3 %Environmental charges 0 – 9 % 0 – 5 %SO2 and NOx control 15 – 20 %Particulate control 3 – 4 %Fuel disposal 1 – 4 %Safety systems 15 – 45 %

Total 12 – 42 % 0 – 9 % 15 – 50 %

18 Forsberg CW and Reich WJ, 1991. Worldwide Advanced Nuclear Power Reactors with Passive and Inherent

Safety: What, Why, How and Who. ORNL/TM-11907, Oak Ridge National Laboratory, Oak Ridge, TN,USA.


4 SOCIAL/POLITICAL ISSUES

There is no doubt that the supply of electricity is vital to the development of any nation. Thisis particularly so for developing countries. The following Sections outline some of the socialand political issues that need to be addressed when considering options for electricity supply.

The developed countries have been undergoing radical reform of their energy industries andsome of those issues are also addressed here.

4.1 ELECTRICITY PRICING POLICIES RELATED TO ECONOMIC GROWTH

Historically, government owned and operated electricity generation, transmission anddistribution authorities have acted as effective monopolies with limited accountability. Tariffshave been set to service capital, to provide for depreciation of assets and system developmentand to deliver community service obligations. In general, industrial and commercial tariffshave subsidised domestic tariffs. Generally, market forces have not been considered andreduced industry competitiveness has constrained national economic growth.

The current trend in developed economies is towards competitive, corporatised state-owned orprivatised business units with generation, transmission and distribution businesses separatedor sold and cross subsidies virtually eliminated.

Electricity tariffs have fallen, particularly to industry, and economic activity has beenimproved. Accountability to new owners and their boards has raised performance butincreased asset utilisation has led to higher risks of outage and high short term pricing inresponse to shortages.

Markets have been established for electricity trading, just as for any other commodity, andcompetition to deliver cheaper electricity is vigorous and effective. New and sometimes non-conventional IPPs have entered the market to capitalise on opportunities such as cheap fuelsupplies (eg renewables) or local industrial situations (eg co-generation). Typically, a trulycompetitive national electricity market can be expected to achieve 20% to 25% increase inproductivity together with new job creation in industry. This is particularly evident in Victoriawhere an increase from 70% - 75% boiler availability to 85% - 90% was achieved afterprivatisation of the industry.

4.2 POLITICAL, MANAGEMENT AND REGULATORY ISSUES

4.2.1 Establishing a Competitive National Energy Market

A competitive national energy market (NEM) requires a strong legislative and regulatoryframework to provide for the following:

• National electricity code: This code describes the terms and rules for participation in theNEM for electricity generators, retailers, transmission and distribution network serviceproviders, system operators and customers.


• National electricity code administrator: The administrator supervises implementation ofthe code, ensures that the market remains competitive, collects and publishes statisticsand manages ongoing development of the code.

• NEM management company: The management company manages detailed markettransactions, determines generator merit order dispatch and manages the power system inaccordance with the code.

4.2.2 Costs of Regulatory Compliance

While “light handed” market regulation is generally desired, the reality in most jurisdictions isthat this is more difficult and hence more costly. The regulatory instruments are generallyembodied in market codes, generation and retail licences and related access and pricingarrangements and administered by a government appointed industry regulator.

The OECD has published an international standard on regulatory quality with a decision-making checklist that raises issues such as:

• Is government action justified?

• Is the problem properly defined?

• Is regulation the best form of government action?

• Do the benefits justify the cost?

• Is the regulation clear, consistent and comprehensible?

• How will compliance be achieved?

However, as an alternative to prescriptive regulation, most competitive players in theinternational electricity supply industry find that the most cost-effective way to regulate itsbusinesses is to lift international competitiveness and use performance based regulation.Strong co-operative input from the industry itself in designing the regulatory mechanisms isrecommended. Experience in Australia shows that regulatory compliance is superior andcustomer costs lower with performance based regulation than prescriptive regimes.

Typically, the regulatory authority will have the following obligations and associated powers:

• Issue licences to generators and distributors who meet licence terms

• Determine performance standards (including financial performance) for facilities andservices provided by licensees

• Promote industry competition to secure optimum supply of electricity at reasonable prices

• Safeguard consumer interests and ensure that demands are satisfied

• Ensure that licensees are adequately financed to perform functions


• Promote national economic development

4.2.3 Dividend Requirements

It is natural that newly independent corporations, whether privately or publicly owned, willseek to achieve benchmark or higher dividend returns to satisfy their shareholders. However,it is necessary for the regulator to control the dividends of monopoly fixed assets at a levelrelated to the long-term bond rate plus an acceptable risk premium. Higher returns are neitheracceptable in the customer market nor would they promote efficient allocation of resources ormanagement of assets.

Experience in countries that have already moved to a NEM shows that, while initial dividendsappear attractive, as the market settles down and excess capacity is absorbed ordecommissioned, dividend returns and price earnings ratios became comparable to a widerange of industrial assets as would be expected.

4.3 WORKFORCE AND THE COMMUNITY

Table 4.1 sets out the direct employment workforce numbers for the different energy sourcesconsidered, for both construction and ongoing management and operation. The Table does notinclude workforce numbers required to provide for related community infrastructure andfamily support and which can lead to a significant increase in the availability of local andNational employment. As with any country it is assumed there is a reasonably wellunderstood ratio between the direct workforce and the related community population.

Table 4.1: Workforce Requirements

Construction Workforce O & MEnergy Source Unit Output

Peak Total WorkforceMW Number Man years Number

Fossil fuel energyCoal fired 500 400 1000 250

100 200 450 150Oil fired 500 300 600 200

100 150 250 100Natural gas fired 500 250 500 150

100 125 200 75Renewable energySolar photovoltaic 1 30 10 5

0.2 20 5 3Solar thermal 1 40 15 8

0.2 25 10 4Wind 5 20 10 10

0.5 15 5 5Biomass 40 50 60 30

5 30 25 15Nuclear energyPWR/BWR 1000 1000 3000 300PWR/BWR 500 700 2000 200


4.4 SITE ACQUISITION & INFRASTRUCTURE

Table 4.2 sets out the land area and related infrastructure needed for each of the generationtechnologies considered.

Table 4.2: Site and Infrastructure Requirements

Energy Source UnitOutput

ACF EnergyOutput

SiteArea

Comments

MW % GWh/a haFossil fuel energyCoal fired 500 85 3723 20 Includes coal stockpile, ash dam and switchyard

100 80 701 10 Includes coal stockpile, ash dam and switchyardOil fired 500 88 3854 12 Includes oil tankage and switchyard

100 83 727 7 Includes oil tankage and switchyardNatural gas fired 500 89 3898 10

100 84 736 6Renewable energySolar PV 1 20 1.8 1 Assume 12% conversion efficiency

0.2 17 0.3 0.3 Assume 12% conversion efficiencySolar thermal 1 22 1.9 1.5 Assume 15% conversion efficiency

0.2 18 0.3 0.4 Assume 15% conversion efficiencyWind 5 25 11 3 Depends on unit size and wind speed

0.5 20 0.9 Depends on unit size and wind speedBiomass 40 60 210 2 Includes biomass storage

5 40 18 1 Includes biomass storageNuclear energyPWR/BWR 1000 95 8322 15 Includes buffer zonePWR/BWR 500 93 4073 10 Includes buffer zone


5 SUMMARY

The following table summarises the general outcomes of this study and provides a quick reference on the costs of electric power fromcompetitive sources.

Table 5.1: Summary of Study Outcomes


Solar PV Solar Thermal Wind Biomass

Plant Details

Unit Size 200 – 1,300 MW 200 – 750 MW 0.01 – 1 MW Up to 200 MW Up to 1.5 MW Up to 100 MW 600 – 1,300 MWCapacity factor 75 – 95% 75 – 95% 75 – 95% 5 – 20% 5 – 20% Highly site

specific, buttypically around20 – 50%

50 – 80depending onavailability offuel

60 – 90%

Fuel Source

Abundance Very abundant Abundant butcontrolled

Abundant inmany locations



Abundant inmany locationsbut limitedcapacity factor

Limitedresources inmost locations

Abundant

Security ofsupply

High Risky due topolitical whimsof unstablegovernments

Moderate.Available from anumber oflimited sources




Subject toweather patternsto grow primarymass

Risky due topublic pressureonenvironmentalissues

Cost Cheap Moderate Expensive Zero Zero Zero Very cheap Very cheap

Power Plant Costs

Capital Cheap –moderate

Cheaper Cheap Very expensive Expensive Cheap Moderate Moderate –expensive



Solar PV Solar Thermal Wind BiomassOperating &maintenance

Cheap Cheap Cheap Moderate Expensive Cheap Moderate Moderate

Cost ofelectricitysupply19

100 %Cheap

116 %Moderate

107 %Cheap

1,380 %Very expensive

725 %Very expensive

105 %Cheap

102 %Cheap

115 %Moderate

Environmental Issues

Pollutingpotential

High Moderate Low Very low Very low Very low Low Potentially veryhigh

Difficulty ofcompliance

Hard buttechnology hasdevelopedrapidly

Moderate onlydue to highsulphur fuel oil

Easy Easy Easy Easy Moderate Difficult

Cost ofcompliance

High Moderate Low Very low Very low Very low Low High

Social/Political Issues

Potential to fulfilcommunityenergy needs

Very high Possible but notcurrently infavour

High based onfuel availability

Very low Very low Low Low High but subjectto public opinion

Basis for reformof energy market

High High but risk offuel supply

High Low Low Low Low High but subjectto public opinion

19 The costs quoted here are costs for the default options chosen in the Excel spreadsheet and are generally indicative of the relative costs between the various options.


6 CALCULATION SPREADSHEET

A MS Excel97©20 spreadsheet has been developed (ElectricityCosts.xls) to allow calculationof the cost of electricity from the various generation options, and is available on the 3.5”floppy disk attached to this report.

6.1 INSTALLATION

Place the floppy disk in Drive A: and copy ElectricityCosts.xls to a suitable directory onyour hard drive. Double click on the filename to RUN Microsoft Excel97©.

6.2 INPUTS

6.2.1 Inputs Required for Evaluation

Inputs required for the evaluation of electricity costs are set out in Table 6.1.

Table 6.1: Inputs Required for ElectrcityCosts.xls

Input Units Comments

Plant InformationUnit Size MWe Electrical output of one unit in the power station.Number of Units Number of units of [Unit Size] in the power stationPlant Life Years Economic life of the power station over which the

capital costs will be depreciatedAnnual Capacity Factor (ACF) % Percentage of full output generated over one years’

operationCooling Type (Direct orTowers21)

D/T Cooling system employed:Direct from sea water or cooling pond (D) or fromcooling towers (T)

FGD Installed Y/N FGD installed (Yes) or not installed (No)De-NOx Installed Y/N De-NOx installed (Yes) or not installed (No)Generated Efficiency % Cycle efficiency not including auxiliary power

consumptionCapital CostsBase Cost US$/kW Capital cost of base plant not including flue gas clean-

up with FGD or De-NOx plantFGD US$/kW Capital cost of FGD plantDe-NOx US$/kW Capital cost of De-NOx plantDecommissioning US$/kW Cost of decommissioning the plant at the end of its life.

Normally only applicable to nuclear plantDiscount Rate % Interest rate used for depreciating capital costs over

the life of the plantOperating & Maintenance CostsBase Cost US$/kW/a Annual O&M costs taken as a fixed annual chargeFuel CostBase Cost US$/GJ Energy value of the fuelTransport & Handling US$/GJ Energy value of preparartion, handling and transport.

20 Excel is a registered trademark of Microsoft Corporation.21 For dry cooling towers, the effect will be to reduce the turbine heat rate by around 3%. This means that the

cycle efficiency of the unit should be reduced by about 2.8%.


6.2.2 Inputting Values

Values for the input variables set out in Table 6.1 can be input by manually entering them inthe appropriate cells OR by pressing the <default> button on each of the screens.

Figure 6.1 shows the input screens for the various categories of variables. The shaded areasshow the areas on the spreadsheet where the inputs can be inserted manually.

Figure 6.1: Spreadsheet Input & Default Values


The default values used are also shown in Figure 6.1. These can be overwritten if required.

The default values in the PLANT INFORMATION section assume a sub-critical steamcycles. If a super-critical cycle is preferred, then the value of cycle efficiency should beincreased accordingly.

The default values for the capital and O&M costs are calculated from the graphs shown in theprevious Sections. When the PLANT INFORMATION is changed, the values for capital andO&M costs can be calculated using the <default> button, or they can be inserted manually.

6.3 OUTPUTS

A summary sheet is provided in the spreadsheet to display the final calculations for theevaluation and this sheet is illustrated in Figure 6.2.

Figure 6.2: Output Summary of Power Generation Costs

Hard copy output can be printed to a printer using the <Print> function in MS Excel©.

electric power from competitive sources - … power from competitive sources page..ii list of tables...

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