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Subsidies to the Use of Natural Resources

Environmental Economics Research Paper No.2
This report was prepared by a consultant,
the National Institute of Economic an Industry Research (NIEIR),
for the Department of the Environment, Sport and Territories.
Commonwealth of Australia, 1996
ISBN 0 642 24864 8

Energy production and consumption

2.1 Introduction

The main primary energy sources produced and used in Australia are coal, oil and natural gas. Primary energy sources also include hydro (dams), biomass (wood, sugar cane wastes, etc.), wind and solar sources. In Australia electricity, a secondary energy source, is produced mainly from coal, hydro and natural gas, with minor amounts from oil, biomass, wind and solar sources. The final end-use of energy (tertiary energy) occurs in the transport (cars, etc.), industry (aluminium, etc.), residential (water heating, etc.), commercial (lighting, etc.) and services (in-plant gas use, etc.) sectors.

Financial subsidies to Australia’s energy industries include contributions for research and development, non-recovery of costs associated with public agency services and the direct subsidy to ethanol production to support its use as a non-lead octane enhancer in petrol. Federal and State agencies provide basic geological information (for example from the Australian Geological Survey Organisation 96 AGSO) and other information and management services. Support for energy R&D is provided through a number of agencies (CSIRO, the Energy Research and Development Corporation, higher education research grants, tax deductions, etc.). These subsidies are provided for a range of purposes. Some probably have more than one rationale. Thus, the subsidies to ethanol production and research are probably provided for several reasons: to capture the probable net environmental benefits of ethanol as a fuel; to support an embryonic (“infant”) industry, to provide markets for some agricultural products; and to encourage R&D into means of reducing ethanol production costs. Others are provided to meet the costs of perceived community- wide benefits (public goods aspects) provided by their provision, for example to the AGSO, while others respond to lobbying by industry groups on the perceived community advantages (particularly employment) provided by their industry and the need to match subsidies provided to their competitors in other countries.

Charges for access to community owned resources, generally referred to as royalties or secondary taxation, are an important issue. These secondary taxes are mainly assessed on either revenue from resource sales (ad valorem taxes) or profits (resource rent taxes). Secondary tax systems are shifting towards a profits basis, as an ad valorem basis can cause difficulties for resource firms when prices are low and do not enable the community to appropriate a reasonable return when commodity prices are higher. A major Commonwealth review of petroleum resource taxation in the 1989–90 period resulted in a change from a mainly revenue basis to a mainly profit-based (or resource rent) system. Thus, in 1990 the federal Petroleum Resource Rent Tax (PRRT), introduced in 1987 with effect from 1984, was extended to the major Bass Strait fields and exploration deductibility extended from a project to a company wide basis. State secondary resource taxation, however, remains mainly on an ad valorem basis (see Note 1 below) (see following box for a summary of coal and petroleum resource taxation in Australia). The community returns gained through secondary taxation represent a balance between providing the community with a return for the exploitation of non-renewable petroleum reserves and providing the private sector with a return for the risks undertaken in investing in petroleum exploration and development in competition with foreign suppliers.

The design of a resource charge also has to take into account such factors as compliance costs and the ability to establish a fair cost for deductions. Accordingly, the constraints on community returns reflect the practicalities of developing a taxation system. Factors affecting system development include the constraints of competitiveness and risk factors, market issues such as international prices for traded commodities, and taxation policy issues such as decisions, for various reasons, to tax competitive fuels at different rates.

The pricing of Australian primary energy and end products varies by energy commodity and mainly depends on competition in energy market segments and on variations in Commonwealth product excises and State Government charges. For example, oil is sold at international prices (adjusted for quality and transport costs) while brown coal, with few alternative uses, is essentially priced at production costs; among petroleum fuels, liquefied petroleum gas (LPG), compressed natural gas (CNG) and alcohol fuels are excise free mainly because of their perceived environmental benefits.

In future years the pricing and overall financial regime applying to the energy industries is likely to be significantly affected by competition policy reforms. In April 1995, a national competition policy reform package was endorsed by the Council of Australian Governments (COAG). It includes specific reform elements and agreed processes and principles that will introduce significant micro-economic reforms. These reforms aim to stimulate the competitiveness and growth prospects of sectors such as energy and the overall national economy. The reform package comprises six interrelated elements.

NOTE 1 On-shore resources are under State jurisdiction whereas off-shore resources are in federal or shared jurisdictions.

Coal and petroleum resource taxation in Australia

Jurisdiction Coal Oil and gas(see Note 1 below)
New South Wales $1.70/saleable tonne and $0.50/saleable tonne super royalty for specified open cut mines. 10 per cent of well head value for primary licence.(see Note 2 below) 11–12.5 per cent for secondary licence.
Victoria Ex-SECV brown coal, 4.23/GJ. Alcoa brown coal (sold), $0.258/tonne. Alcoa brown coal (power generation), $0.194/tonne. Non ex-SECV/Alcoa coal, 2.75 per cent of sales value. 10 per cent of gross value of production at well head for primary licence. 10–12.5 per cent for secondary licence.
Queensland 7 per cent of free on rail value. 10 per cent of well head value.
Western Australia Export coal, 7.5 per cent of realised value. Non-export, $2.29/tonne, adjusted each year for Collie 1981 examine value. 10 per cent of well head value. 10–12.5 per cent for secondary licence. Resource rent royalty applies to Barrow Island field (25 per cent to Western Australia).
South Australia Value of processed, delivered coal, 2.5 per cent. 10 per cent of well head value.
Northern Territory 18 per cent of accounting operating profit where profit exceeds $50,000. 10 per cent of gross value at the well head less specified deductions for each field.
Tasmania 1 per cent of ex-lease value of sales (n) plus 30 per cent of twice assessed profit/n. 10 per cent of well head value for primary licence. 11–12.5 per cent for secondary licence.
Commonwealth Excise (1993) and export duty (1992) suspended. Resource rent tax (RRT) applies to off-shore fields (Bass Strait, etc.) except the NW Shelf. Royalties and oil production excises mainly apply to fields in inshore and coastal waters (three nautical mile limit), e.g. Barrow Island, some other WA fields and the NW Shelf. The first 30 million barrels of oil produced from any one field are excise free.

Note:1. State royalties apply to onshore, internal waters and coastal waters (three nautical mile limit); Commonwealth crude oil production excise also applies to these areas except Barrow Island where a profits based resource rent royalty is levied (shared 75/25 with WA).
Note 2. A primary licence applies to the first find within a licence block and a secondary licence to a second find within that block.

Source: Royalty Discussion Paper, ANZMECC, 23 September 1991,updated by discussions with energy departments and agencies. For taxation details see Taxation of the Energy Industries, NIEIR,23 June1995.

Corporate tax sections of the Income Tax Assessment Act (ITAA) includes a range of deductions provisions for capital and operating expenses incurred during exploration, development and production of energy resources . These allowable deductions include those for control and repair of environmental disruption and environmental impact studies. Overall the provisions appear to cover reasonable business expenses in a relatively risky business area. In a 1993 country comparative study Kemp found:

(i) that the overall tax system applying to the Australian petroleum industry extracted high community returns,particularly under high cost and relatively low oil price conditions; and

(ii) the Australian regime extracted community returns not out of line with the other countries studied.(see Note 1 below)

This situation does not reveal the extent of any resource use subsidy but does indicate the difficulty of changing fiscal systems in a competitive field. Further study is required to examine the resource subsidy issue in relation to fiscal systems and assess the benefits and costs of changing the current regime.

A large range of environmental externalities is associated with the production,transport/transmission and use of energy, but our survey indicates that to date few attempts have been made to quantify them using Australian data.(see Note 2 below) Energy related externalities, however, are attracting much attention in Australia and overseas, in particular those associated with the enhanced greenhouse effect (see box). Regulations force internalisation of some of these externalities but thus far no attempt appears to have been made in Australia to use economic instruments (taxation, tradable emission permits) in the energy sector for this purpose. Thus estimates (for example from Victorian and Western Australian studies) of externalities have not been included in prices and no tradable emission programs (for example as used in the United States for sulphur oxides) have been attempted in the Australian energy sector.

This chapter of the report deals in turn with fossil fuels, renewable energy, electricity and end-uses of energy, followed by a discussion of road transport issues. This treatment format permits the treatment of specific external effects associated with each primary fuel, with electricity (which is produced from a range of fuels but with some common externalities) and with end-uses where transport, mainly using liquid petroleum fuels, covers a wide range of financial and environmental subsidy issues.

Note 1 Kemp,A.G., Fiscal Aspects of Investment Opportunities in the UK,CS and Norway, Denmark, The Netherlands, Australia, China, Alaska and the US Outer Continental Shelf, University of Aberdeen,September 1993.

Note 2 A comprehensive description of energy production and use externalities is provided in the Externality Policy Development Project: Energy Sector, Identification of effects and externalities, Department of Energy and Minerals, Victoria. This study (VEPDP), however, provided few estimates of externality values.


The enhanced greenhouse effect

The greenhouse effect, due to the build up of carbon dioxide (CO2 ), methane (CH4 ), chlorofluoro-carbons (CFCs), nitrous oxide (N2O), etc. (the “greenhouse gases” — GHGs), is predicted by an international panel of scientists to raise global surface temperatures and result in higher sea levels and changed weather patterns around the globe. The predicted impacts would not be limited to certain regions of the world and all greenhouse gas emissions contribute to the effect. Thus, global warming, and any action decided on to reduce the effect, is of concern to all countries, albeit to varying degrees. It is truly an international environmental, social, economic and political issue.

Countries produce different amounts of greenhouse gases (GHGs) and GHG sources (e.g. coal) and contribute differently to the absorption of greenhouse gases. The production and absorption capacities of countries will change in the future and countries will be differently impacted by the greenhouse effect. Thus, at the outset, it can be seen that international negotiations to devise greenhouse policies will be difficult and complex due to scientific uncertainty and the different current and future situations of the world’s countries.

The major proportion of the man-made CO2 emissions, and possibly, human-related N20 emissions are related to energy, while the emission of CH4 and CFCs from human activities are less related to energy. On a global scale it is estimated that about 60 per cent of GHG emissions emanate from energy production, transmission and use.

Among OECD countries Australian economic activities for domestic and export markets are relatively greenhouse gas intensive. That is, per unit of GDP and per dollar of exports, Australian production and consumption produces (or has the potential to produce,e.g. coal) relatively high amounts of greenhouse gases.

The national greenhouse gas inventory (NGGI) estimates that 53.4 per cent of Australian greenhouse gas emissions come from energy related activities, followed by 24.4 per cent from land use change and forestry, 15.2 per cent from agriculture, 5.7 per cent from solid waste disposal and 1.3 per cent from non-energy industrial processes.

Damages likely to be caused by the enhanced greenhouse effect include increased likelihood of extreme weather events, net agricultural losses, reductions in biodiversity, coastal erosion and submergence, net increases in energy costs, net increases in water supply costs, increased urban smog, and increased health risks and costs.

Valuation of the GHG externalities is complex and few attempts have been made. In the United States, Cline for example, estimates that an average 2.5C temperature rise (the likely result from a doubling of pre-industrial GHG emissions), would cause damage of about 1 per cent of GDP by 2025. Estimates of control costs to attain the target of reducing 1990 GHG emissions by 20 per cent by 2005, range form 0–5 per cent of GDP. Valuation of greenhouse externalities is an evolving field where existing estimates vary considerably.

References: W.R.Cline, Global Warming: The Economic Stakes,Institute for International Economics, Washington DC. United States, 1992; International Greenhouse Issues — a summary, NIEIR, March 1994; NGGI,1994.

2.2 Fossil fuels

2.2.1 Coal

Australia is a major coal producer and the world’s number one exporter. Exports account for about 70 per cent of black coal production but brown coal exports are negligible. Domestic use of coal is divided into metallurgical uses (mainly in the iron and steel industry where coal has important chemical and energy uses), as a heating fuel, and as a primary fuel for electricity production.

Financial subsidies

Coal is mainly a community owned resource in Australia and as such is subject to extraction fees (royalties) imposed by the State Governments. Royalties for extraction by private companies vary from State to State; black coal production is dominated by New South Wales and Queensland, while the lower quality brown coal is only produced in Victoria.

Low black coal prices over the past five years have reduced average rates of return in the industry to lower than would be normally sought. Brown coal mines in Victoria are owned by the State and sell coal to electricity generators at essentially the cost of production.

Public agencies provide geological information services and R&D support to the coal industry. The Australian Science and Technology Council (ASTEC) (see Note 1 below) estimated that about $75 million was being spent on coal research in 1994 of which about $45 million was spent by industry and the remainder by governments (mainly federal) either directly or through contributions to research agencies. Government expenditure on coal R&D accounted for about 24 per cent of total government expenditure on energy R&D. In the Greenhouse 21C package of measures to abate greenhouse gas emissions, $25 million was allocated to aid clean technology R&D in India over the 1995–99 period.

To the extent that R&D support to the coal industry reduces the environmental impact of coal production, transport and use, this support improves the environmental performance of the industry. It is sometimes argued, however, that from an environmental perspective support for coal R&D extends coal’s environmental impacts that are inherently greater than those from other energy sources such as natural gas and renewable energy forms.

The Diesel Fuel Rebate Scheme (DFRS), which applies to several sectors, was allocated $632.1 million for rebates to the mining industry, $397 million to agriculture, $86 million to forestry, $33 million to fishing, and $22 million to hospitals, etc., in the 1993–94 Federal Budget. This rebate applies to diesel fuel used off road in mining operations; the rebate currently amounts to 28.4 cents/litre. The DFRS is mainly justified on the non-use of roads by off road uses of diesel fuel in the forestry, fishing, agriculture sectors, residential and health care (see box). The value of these rebates for the coal mining industry is estimated at $300 million in 1994–95, based on discussions with the Department of Industry, Science and Technology (policy responsibility), Customs (administrative responsibility) and our estimates from tonnages of mined minerals. The Industry Commission study on Mining and Minerals Processing (1991) concluded that the various tax concessions to mining more or less balance out against unfavourable tax treatments.

Transport of coal away from the mine site is mainly by rail. The Commonwealth Grants Commission reports that in Queensland coal haulage rates appear to include a royalty (secondary taxation) element. (see Note 2 below)

Note 1 Energy Research and Technology in Australia, ASTEC, Occasional Paper No. 28, 1994.
Note 2 Commonwealth Grants Commission, Report on General Revenue Grant Relativities, 1994 Update, p.173.

The Diesel Fuel Rebate Scheme (DFRS)

Under the Diesel Fuel Rebate Scheme (DFRS) operated by the Federal Government, rebates of excise are available on diesel purchased for use in specific off-road activities.

In 1994–95 the estimated rebates are (see Note 1 below): mining $632.1 million; agriculture $396.9 million; forestry $85.9 million; Fishing $32.8 million; and residential, hospitals, nursing homes, etc. $22.2 million.

The Industry Commission (IC), in a 1994 study of petroleum products taxation (see Note 2 below) observed, in discussing the DFRS observed re the off-road rationale:

“Regardless of the merits of fuel taxes as road user charges, the existing scheme performs this function poorly because rebates are not available on all off-road use of diesel. And not all rebates for off-road use are at the same rate. But the current rebate scheme was shaped by broader objectives. The inclusion of residential use, and aged and health care institutions, but not other commercial accommodation, appears to reflect a social policy objective.”

In this study, the IC went on to examine options for exempting all intermediate users from taxes on petroleum products; such an approach would make the DFRS redundant.

Is the DFRS for non-road diesel users a subsidy?

In considering the answer to the question the role of the excise duty must be considered. NIEIR estimates all costs of road provision exceed by an estimated $1.2 billion excise duties imposed by the Commonwealth on road fuels and all the other duties, franchise fees, and other levies imposed on road users by governments. If these imposts are viewed as quasi user charges, all non-road users should be exempt from excises, etc. imposed on transport fuels. Rail use exemption would, however, give a competitive advantage to rail over road transport; the Commonwealth does not want to give this advantage, and so does not exempt rail diesel fuel.

Non-road fuel use of petroleum products give rise to externalities, particularly emission externalities. AN ISC study of atmospheric emissions estimated that the value on non-greenhouse externalities from road diesel use amounted to $4 million outside urban areas, where the DFRS predominantly applies, compared to $783 million in urban areas. Off-road emissions, on this basis, would be valued at about $1 million (1994 dollars). This low estimate reflects the low valuation of emission costs in rural areas. Greenhouse emissions from off-road diesel use total about 7 million tonnes of carbon equivalent (Cosgrove, DPIE).

If the excise tax is seen purely as a revenue tax then the DFRS might be seen as a subsidy to DFRS beneficiaries. However, other end-use energy sources, including diesel competing (in some uses) fuels such as natural gas and electricity, are not subject to excise taxes. If the DFRS is seen as a subsidy, the exemption from excises to these energy forms should, therefore, be seen as a subsidy to these other fuels/energy forms.

On the basis of the above discussion we conclude here that the DFRS should not be seen as a financial subsidy to its beneficiaries. The externalities associated with these uses, however, should be estimated and included in subsidy analyses wherever possible.

Note 1 Australian Customs Service and Budget data. 2 Industry Commission, Petroleum Industry, Report 40, July 1994,p.274.
Note 2 Industry Commission, Petroleum Industry, Report 40, July 1994, p.274.

Environmental subsidies

The extraction of coal has a number of environmental impacts. Exploration and mining may cause damage to natural habitats and raise the need for land rehabilitation, which may only partly repair the environmental impacts. Mine wastes may lead to runoff into streams causing siltation and reducing water quality. Black coal mining results in variable amounts of (fugitive) methane emissions thereby contributing to the enhanced greenhouse effect. (see Note 1 below)

In its energy uses (as distinct from its metallurgical uses which account for less than 1 per cent of Australian coal use) (see Note 2 below), coal is mainly used for the production of electricity and steam. Depending on the combustion process, and the composition of the coal, varying solid and atmospheric emissions are produced, for example fly-ash and carbon dioxide. These environmental impacts may be divided into three groups: greenhouse gas emissions; other atmospheric emissions; and solid residues.

Quantification of these impacts in Australia has mainly been for coal use in electricity production, but even in this case the quantification is not comprehensive.(see Note 3 below)

Greenhouse gas emissions (principally CO2 emissions) from coal-fired electricity generating plants, account for about 25 per cent of total Australian non-Montreal Protocol (see Note 4 below) (i.e. non-ozone depleting) greenhouse gas (GHG) emissions. Brown coal used for electricity generation produces, on average, about 6 per cent more CO2 per PJ of fuel than black coal when combusted under standard conditions. The actual CO2 emitted per KWh of electricity produced depends on the actual chemical composition of the coal used and the efficiency of converting the coal into electricity. (see Note 5 below)

Other atmospheric emissions from coal include particulates and oxides of sulphur and nitrogen. Australian coal is relatively low in sulphur content and this, together with the characteristics of Australian soil and water,means that acid rain pollution, a major problem in Europe and North America, is not a significant problem in Australia. A National Health and Medical Research Council report indicates, however, that in coal combustion intensive regions such as Newcastle and Woolongong sulphur dioxide emissions are of some concern. (see Note 6 below) Also environmental problems are associated with coal mining, for example through effects on water supplies from disruption of water tables, leaching from mine wastes, etc.


1 Fugitive Fuel Emissions are those not related to combustion for energy but which arise from emissions associated with production,transmission, storage and distribution of fuel and from mining. In the energy sector, Fugitive Fuel Emissions amounted to a little over 1 Mt of methane or about 16 per cent of total methane emissions, or about 4 per cent of total greenhouse gas emissions. A little under 30 per cent of Fugitive Fuel Emissions were from oil and natural gas systems. Methane emissions from coal mining made up over 70 per cent of Fugitive Fuel Emissions with the majority of emissions from underground black coal mines. From Australian Methodology for the Estimation of Greenhouse Gas Emissions and Sinks, and National Greenhouse Gas Inventory 1988 and 1990: Summary, Department of the Environment, Sport and Territories, 1994,(NGGI Summary, 1994), p.15.
2 ABARE Commodity Statistical Bulletin,1994, p.259.
3 The subject was discussed with Dr Harry Schaap, Director, Environmental Affairs, Electricity Supply Association of Australia (ESAA), who indicated that useful data on externality costs is not available except for the Victorian and Western Australian studies cited below.
4 Greenhouse gas emission totals are generally expressed in these terms as ozone depleting emissions are being reduced under the Montreal Protocol provisions.
5 In 1992, for example, the SECV reported in The SECV and the Greenhouse Effect, Discussion Paper No. 2, April,1992, that the amount of CO2 produced per kWh varied between old and new stations by a factor of almost 2. For emission factors see Australian Methodology for the Estimation of Greenhouse Gas Emissions, Workbook for Fuel Combustion Activities (excluding Transport), Department of Environment, Sport and Territories, July 1994,draft, Appendix B.

6 Steer, K. and Heiskanen, L., Options for Australian Air Quality Goals for Oxides of Sulphur, Public Review Document,November 1993.

Solid residues (fly-ash) constitute a storage and disposal problem for electrical utilities; efforts are underway to use more of the fly-ash in concrete production, road-works, etc., for example by Pacific Power. Liquid residues are minor but discharge of cooling water has environmental impacts in streams and oceans (e.g. in the Latrobe Valley, Victoria).

In 1992 the Victorian Energy Externalities project identified a range of environmental externalities which can be associated with the supply of electricity from nonrenewable primary sources (see Table 1).

An earlier study for the Western Australian Government (Stocker et al, 1990) F Stocker, L., Harman, F., Tophan, F., Comprehensive Costs of Electricity Supply in Western Australia , Renewable Energy Advisory Council, Government of Western Australia, 1990, p.25. arrived at estimates of external costs in the range of 4 to 28 cents per kilowatt hour for black coal based electricity.

The externality elements estimated by Stocker, et. al., are presented in Table 2. The bases for these estimates is as follows. For coal mining the cost of rehabilitation of mine sites was estimated from United States data adapted to Western Australia. The CO2/greenhouse estimate was derived from a 1988 NIEIR study on re forestation and chemical removal of CO2 . In the case of sulphur and nitrogen oxides the cost data was developed from an OECD study on control of these gases. Finally the resource depletion cost element was based on a German study on the costs of substituting renewable energy for coal in the generation of electricity. Details of these estimates and their sources are set out in Section 4 of the Stocker, et. al. report.

Externalities not valued by Stocker, et. al., include:

Table 1 Potential externalities associated with electricity supply from primary non-renewable fuels

External factor


Greenhouse gas emissions
  • release of CO2 , CH4 , N2 O and water vapour.
Degradation of water resources
  • waste and coolant discharges
  • acid drainage from deep and open cut mines into the water table and river systems
  • acid rain associated with emissions of SO2 and NOx
Air quality reduction
  • discharge of ash and dust particles
  • NOx emissions react to produce photochemical smog
Land and crop damage
  • acid rain affects growth of crops and other flora
  • open cut coal mining
  • transmission corridors
  • structural corrosion due to acid rain
  • noise
  • impact on aesthetic values

Source: Philpott,R., Identification of effects and externalities, Externalities Policy Development Project: Energy Sector, Department of Manufacturing and Industry Development, Victoria, Australia, August 1992.

All these cost elements estimated in the Victorian and Stocker studies are controversial 96 particularly those for carbon dioxide and resource depletion.

In the energy segment of the Victorian externalities policy development project (VEPDP) negative externality values were only estimated for the relatively efficient Loy Yang A brown coal station in Victoria’s Latrobe Valley. (see Note 1 below) 1 These values are presented in Table 3.

The central values developed, which exclude GHG impacts, amount (central value) only to about 0.1 per cent of production costs (as estimated in the report). Besides GHG impacts, coal mining, depletion, socioeconomic and decommissioning impacts were not included. The report commented that:

“the $0.000025 per kWh likely understates the total externality value for Loy Yang. Furthermore, Loy Yang has already installed extensive pollution control equipment and meets or exceeds EPA environmental standards. These factors significantly reduce the impacts of residual emissions and externality costs. Another power station with lower levels of pollution control would be likely to have a higher externality value; possibly in the range of $0.01/kWh.”

Note 1 Externality Policy Development Project: Energy Sector, Consultants’ Summary Report for the Victorian Study (VEPDP, Summary), Department of Energy and Minerals, October, 1993.

Table 2 Application of damage/avoided damage costs to black coal based electricity generation in Western Australia

Source of damage (costing basis) Cost (/KWh, 1990 $s)
Mining (land rehabilitation) 0.2
CO2 (sequestration) 1.8–10.0
NOx and SO2 (control costs) 0.5–4.0
Resource depletion (sustainability) 1.3–13.8
Total 3.8–28.0

Table 3 Estimated externality values for Loy Yang A (A$ 1991/KWh)


Externality category (units) Annual emissions Low ($/KWh) Central ($/KWh) High ($/KWh)
PM10 — Human health (tonnes PM10 ) 383 1.3x10 -5 1.8x10 -5 2.3x10 -5
PM10 —Visibility (tonnes PM10 ) 383 1.3x10 -6 n/a 1.7x10 -6
NOx — Human health (tonnes NOx) 24 332 0 0 0
SO2 — Human health (tonnes SO2 ) 46 862 0 0 0
Ozone — Human health (tonnes NOx) 24 332 1.2x10 -6 1.9x10 -6 3.3x10 -6
Air toxics — Cancer (tonnes As) 0.206 n/a 1.6x10 -6 n/a
Air toxics — Cancer (tonnes Be) 0.0013 n/a 3.5x10 -10 n/a
Air toxics — Cancer (tonnes Cd) 0.0118 n/a 2.0x10 -8 n/a
Air toxics — Cancer (tonnes Cr) 1.38 n/a 6.2x10 -7 n/a
Air toxics — Cancer (tonnes Ni) 0.0502 n/a 4.0x10 -9 n/a
Waste water discharge — (ML/year) 18 250 0 0 5.3x10 -6
Land use/solid waste (hectares/year) 17.8 9.7x10 -7 1.9x10 -6 2.9x10 -6
Greenhouse gas (GHG) (tonnes CO2 ) 17 441 0 0 0.03
Total ($/KWh) 0.000017 0.000025 0.03004

Source:VEPDP, Summary, p.3–13.

It should be noted that at the time of the study the Loy Yang A station represented the newest and probably most advanced environmental design of a power station in Australia. Therefore almost all values estimated for this station are likely to be low estimates for the rest of the coal fired power stations in Australia.

As can be seen from Table 3, the VEPDP only developed one estimate (in the high case) for greenhouse gas externalities. This was undertaken using damage and control cost considerations (see p.3–10 of the VEPDP report) for the Loy Yang A station where a stated high value of 3 /kWh was derived.

In 1988 NIEIR estimated that greenhouse externalities valued by estimating reforestation costs to absorb (sequester) carbon dioxide from then existing Victorian brown coal stations, would add about 22 per cent (2.3/kWh in 1994 $s) to average electricity prices.(see Note 1 below) A current NIEIR update of these estimates for the whole of the Australian electricity industry puts the reforestation costs at 4/kWh, within a range of 1-8 /kWh (see Note 2 below). A major caveat to the estimates is the feasibility of attaining the extent of reforestation required given the soil and water resources available.

Integrating the VEPDP, Stocker and NIEIR estimates, and netting out the most extreme and contentious values gives an estimate of externalities associated with electricity production from coal in Australia of about 1-9/kWh. If greenhouse externalities are not included the values range from about 0.5/kWh (mix of station vintages) to 4/kWh for coal based stations.

These estimates are significant in terms of total (capital, operating) electricity production costs which are in the range of 4.5–6.0 cents per kWh (see Note 3 below), depending on how assets are valued and the type of plant being considered.

Recent North American studies indicate externality values for coal fired generation range from 0.5 to 5.0 cents per kWh with CO2 , SOx and NOx accounting for over 85 per cent of the total.(see Note 4 below)

A study of the environmental impact of the German power industry by Hohmeyer (1988) found that if environmental costs associated with conventional generation techniques were factored into production costs, the price of electricity would double.

At 2/kWh, the value of the environmental subsidy, including greenhouse externalities, to Australian coal based electricity (88 per cent of total) in 1994 would be about $2.396 billion. As the above discussion indicates, however, the average value could be much higher than 2/kWh. Within the 2/kWh estimate subsidies to coal per se for mining, transport and depletion impacts are given a relatively low weighting (around 10 per cent) as less work on these values appears to have been undertaken.

1 Costing and Pricing of Electricity in Victoria, Victorian Solar Energy Council, 1988.

2 Abatement of greenhouse gases: policies and their impacts, NIEIR,Energy Working Party Papers, November 1994. The wide range is due mainly to difficulties in estimating forest sequestration rates and the costs of reforestation (land, planting, maintenance).

3 Personal communication with industry (ESAA, individual utility) personnel; costs net of externality estimates.

4 Haites, E., Potential Rate Impacts of Environmental Externality Regulation in the United States, Proceedings: 1994 Innovative Electricity Pricing. EPRI TR-103629, Electric Power Research Institute, Palo Alto, California, February 1994.

These environmental externality estimates from the most extensively analysed and quantified area illustrate:

(i) the wide divergence of opinion on environmental externality evaluation;

(ii) the importance of deciding on what externalities to include and how to value them; and

(iii) the importance in externality valuation of distinguishing between new and older equipment because of the higher emissions usually associated with older equipment.

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