reducing greenhouse gas emissions in the queensland electricity supply industry-gas and carbon tax s

The Australian Economic Review, vol. 37, no. 3, pp. 287–3032004 The University of Melbourne, Melbourne Institute of Applied Economic and Social ResearchPublished by Blackwell Publishing Asia Pty LtdAbstractThis article examines various greenhouse gas scenarios for the electricity supply industry in the coal-rich state of Queensland. The authors use a dynamic partial equilibrium model of the Queensland electricity system to examine the effects of four alternate policy scenarios: a business-as-usual case, a centrally planned gas-fired case, and two carbon tax scenarios—the first in which the merit order of coal and gas plant is reversed, and the second in which fuel switching is undertaken. The results indi-cate that no scenario is capable of delivering sufficient cuts in emissions to meet a ‘Kyoto equivalent’ industry target. While fuel switch-ing brought about the greatest reduction in emissions, the high cost of this scenario indi-cates that a more efficient outcome for the elec-tricity supply industry in Queensland would be a broad-based Australia-wide approach to emissions abatement, so that carbon reduc-tions can be accessed from industries capable of achieving lower cost emissions abatement.1.IntroductionOver a decade ago, the United Nations estab-lished the Framework Convention on Climate Change to examine methods of reducing harm-ful greenhouse gas emissions. In the absence of such an effort, constantly increasing green-house gas levels are expected to gradually heat up the earth’s atmosphere to the point where sea levels would begin to rise, and weather pat-terns would be altered adversely. The member nations hence set about defining ‘x per cent of 1990 level emissions targets’ for their countries over a five-year commitment period (2008–2012). An agreement on emission targets was reached at the third Conference of the Parties,held in Kyoto, in late 1997. For its part, Austra-lia agreed to a target of 108 per cent of its 1990level emissions. H owever, Australia has re-cently declared that while it intends to meet this objective it is not prepared to ratify the Kyoto Protocol. The essence of the greenhouse policy debate in Australia concerns both the target level to be achieved and the choice of policy mechanisms.Australia’s 1990 emission levels were esti-mated to be in the order of 503 million tonnes (Mt), and thus its annual average emissions tar-get for the five years ending 2012 would be around 544 Mt per annum. By calendar 2000,Australian industry had emitted 535 Mt of greenhouse gases (Australian Greenhouse Of-fice 2000). Of all the industries contributing to greenhouse gas emissions in Australia, one stands out—electricity production. Just 78 sites are responsible for around 33 per cent of Aus-tralia’s total emissions (Australian GreenhouseReducing Greenhouse Gas Emissions in the Queensland Electricity Supply Industry: Gas and Carbon Tax ScenariosPaul Simshauser and George Docwra*Stanwell Corporation Limited andSchool of Economics, The University of Queensland, respectively* The views expressed in this article are those of the au-thors and not necessarily those of Stanwell Corporation.288The Australian Economic Review September 20042004 The University of Melbourne, Melbourne Institute of Applied Economic and Social ResearchOffice 1999a). 1 The clear trend in emission levels within the power generation industry is that they are rising sharply compared with that envisaged under the Kyoto benchmark—par-ticularly in the Australian State of Queensland. The electricity supply industry (ESI) in Queensland was restructured and deregulated during the 1997–98 financial year. The princi-pal objective of the reform process was to en-hance the economic performance of the industry as manifest by improvements in pro-ductive, allocative and dynamic efficiency.However, negative externalities were ignored.The purpose of this article is to examine some policy alternatives that may correct greenhouse gas emissions in Queensland com-pared with a business-as-usual scenario. A par-tial dynamic equilibrium analysis is adopted.This article is set out as follows. Section 2 pro-vides a summary of historical greenhouse gas levels generated by the Queensland ESI over the period 1990–2001. Section 3 sets the stage for an analysis of alternative greenhouse gas policy scenarios with respect to the Queensland ESI. The section discusses demand and supply-side assumptions made in the analysis along with a description of the utility planning model,Prosym. Sections 4 through 7 report the results of various greenhouse gas simulation studies.The scenarios examined are, respectively, the business-as-usual coal-fired scenario, the gas-fired scenario, the carbon tax scenario that re-verses the merit order of coal and gas genera-tion, and finally a carbon tax scenario that induces fuel switching, with power stations converting from coal to gas. Section 8 provides a short conclusion. 2.Historical Greenhouse Gas Levels in the Electricity IndustryThe level of emissions from power generators in Australia is significant. The Australian Greenhouse Office (2000) noted that electricity production in Australia emits about 175.1 Mt of carbon dioxide (CO 2 ), which is approxi-mately 32.7 per cent of total national emis-sions. The historical growth in emissions from electricity production in Queensland over the period 1990–2001 is highlighted in Table 1.In Queensland, the increase in electricity de-mand was 79 per cent. Much of this can be at-tributed to the continual growth in that state’s population, increased per capita income, theTable 1 Queensland Electricity Generation and Related Greenhouse Emissions (1990–2001)Financial year ending Queensland demand (GWh)Interstate exports (GWh)Black coal production (GWh)Gas turbine production (GWh)Hydro production (GWh)Greenhouse emissions (Mt)199025121233246002373221.9199126008241254612576422.7199227224251271013533924.2199328362258283074127125.2199430742270304254654027.1199531385285312194940227.8199632803300321655588328.7199734004309333595789729.8199838826337385036660034.31999389693453854491777034.920004096837040509160982937.120014489917042208217168939.0Net increase (per cent)797278Note : The conversion rates used were 0.89t/MWh for black-coal-fired generators, 0.665t/MWh for gas-fired generators, and 1.1t/MWh for combustion turbines.Source: Energy Supply Association of Australia (1990–2002).Simshauser and Docwra: Reducing Greenhouse Gas Emissions2892004 The University of Melbourne, Melbourne Institute of Applied Economic and Social Researchsubsequent growth in air conditioning units and increased production capacity at the Boyne Island aluminium smelter. The corresponding increase in black coal production was 72 per cent, with greenhouse emissions increasing by 78 per cent.Cavanagh (1999) has highlighted that it is extremely difficult to deregulate a power gen-eration market in a manner that encourages the appropriate economic and reliability outcomes,let alone worry about the environment at the same time. H owever, as he correctly pointed out, in literally no other industry are the con-cepts of competition and the environment so thoroughly intertwined. Heydlauff (1999), re-ferring to the United States, identified a num-ber of deregulation-related issues that concern environmental groups. In particular, restructur-ing and deregulating the ESI will:(i)lower the cost of electricity and increase consumption, with the majority of the in-crease satisfied by idle coal-fired plant;(ii)eliminate demand-side management initi-atives and energy efficiency programs;and (iii)reduce market share for cleaner, renew-able power, which will not be able to compete with traditional fuels when the market price (in the absence of corrective policies, such as pollution pricing) is the determining factor of sales.Evidence of these outcomes in Australia is pro-vided by Scott and Simshauser (1999), Bear-dow and Schaap (2000) and Australian Greenhouse Office (1999a). Consequently,policy interventions to curtail greenhouse gas emissions will be required. 3.Electricity Demand and Supply-Side Assumptions for the ScenariosIn the balance of this article, four emission sce-narios are examined by making structural ad-justments to the supply side. We make only minor modifications to the demand side, as cur-rent studies and historical evidence point to a highly inelastic demand function. For example,a recent study by the National Institute of Eco-nomic and Industry Research (NIEIR) (cited in National Electricity Market Management Company 2001) indicates highly inelastic de-mand, with its estimate of the long-run own-price elasticity of electricity demand in Queen-sland to be in the range of –0.14 to –ing 26 years of US aggregate data, Kamer-schen and Porter (2004) estimated the own-price elasticity of total electricity demand to be between –0.13 and –0.15. These elasticity esti-mates are also consistent with those used by Borenstein and Bushnell (1999). Conse-quently, we believe it is reasonable to assume that demand for electricity is fairly inelastic. In the context of historical demand growth,Kellow (1996) noted that Victorian electricity prices increased by 14.6 per cent in 1980 and by 25 per cent in 1981, while Energy Supply Association of Australia (1998) data indicate that electricity consumption increased by 7.3per cent and 4.1 per cent respectively. Over the 10-year period between 1978 and 1988,Table 2 Aggregate Load Forecast for QueenslandFinancial year Energy demand (GWh)Energy growth (GWh)Energy growth(per cent)Peak demand (MW)Demand growth (MW)Demand growth(per cent)2001–024******** 3.36598191 3.02002–03462621333 3.06772174 2.62003–04489022639 5.77150378 5.62004–0550******* 3.57362212 3.02005–06521301538 3.07513151 2.12006–0753******* 2.77665152 2.02007–085597224164.580804155.4Source: Simshauser (2001).290The Australian Economic Review September 20042004 The University of Melbourne, Melbourne Institute of Applied Economic and Social ResearchVictorian electricity prices increased by 136per cent with the consumer price index in-creasing by 97.5 per cent—indicating a real price increase of about 40 per cent. Over the same period of time, Victorian electricity de-mand increased by 81 per cent.Table 2, taken from Simshauser (2001), pro-vides a load forecast for Queensland between 2001–02 and 2007–08. In the 2003–04 finan-cial year, demand exhibits strong growth. This is primarily associated with the commissioning of industrial loads and the installation of air conditioning units. This load forecast forms the base case.Insofar as the supply side is concerned, the pre-deregulation plant stock is assumed to be available in all scenarios, with its dispatched output being purely a function of the competi-tiveness of the respective short-run marginal cost curves. The pre-deregulation plant stock,fuel source, capacity, availability and short-run marginal cost are listed in Appendix 1.The post-deregulation plant stock includes three committed coal-fired power projects, the 840 megawatt (MW) Callide C project, the 840MW Millmerran project and the 450 MW Tarong North project. The likely candidate to follow is the 700 MW Kogan Creek project, al-though the expected commissioning date re-mains less clear. Still fighting for survival is the Papua New Guinea gas pipeline project. If commissioned as initially envisaged (during 2003), the pipeline would have brought a large number of combined cycle gas turbines (CCGTs) and open cycle gas turbines (OCGTs) into the market, including a 190 MW conversion at Mt Stuart, 380 MW North Queensland Power Project and 110 MW Queensland Nickel Project, all situated in Townsville. Additions in South Queensland would have included the 700 MW Tarong/Wivenhoe project and the 300 MW Gibson Is-land project. The 380 MW Swanbank E project was subsequently committed (albeit with fuel shortages). A list of these committed and un-committed projects, and details of MW capac-ity, status, commissioning dates and owner as initially envisaged, is provided in Table 3.Forward scenarios were derived using Prosym. Prosym is a highly sophisticated util-ity planning model that has been developed over the past 20 years by Henwood Energy, a US-based software firm specialising in elec-tricity system models. Prosym is a partial equi-librium model that utilises linear programming to provide a virtual template electricity system to its users, and the users can then modify the template to mimic local electricity system con-ditions, and simulate various scenarios as spec-ified. Further details of the model are contained in Appendix 2.We have loaded the model with hourly de-mand data (as summarised in aggregate form in Table 2) for three regions: North, Central andTable 3 Committed and Potential Supply-Side Entrants for the Queensland SystemGeneration project Size (MW)StatusIntended dateOwnerCoal-fired generators Callide C 2 × 420Committed May 2001, December 2002CS Energy/Intergen Millmerran 2 × 420Committed January 2003, July 2003Intergen Tarong North 1 × 450Committed July 2003Tarong Energy Kogan Creek 1 × 700UncommittedJanuary 2006CS EnergyGas-fired generatorsNorth Queensland Power Project 1 × 380Uncommitted July 2003Stanwell CorporationMt Stuart conversion 1 × 190Uncommitted July 2003Enertrade Queensland Nickel Project 1 × 110Uncommitted July 2004Unspecified Swanbank E 1 × 380Committed October 2003CS Energy Tarong/Wivenhoe 2 × 350Uncommitted July 2005, July 2006Tarong Energy Gibson Island1 ×300UncommittedJuly 2003UnspecifiedSimshauser and Docwra: Reducing Greenhouse Gas Emissions2912004 The University of Melbourne, Melbourne Institute of Applied Economic and Social ResearchSouthern Queensland. A New South Wales region has also been included to simulate inter-state transfers and has a reserve plant margin of about 20 per cent. The cost and capacity char-acteristics of the supply-side participants were loaded, including the assumed new entrants listed in Table 3. Generator offer pricing in this study is based largely on short-run marginal cost. Minimum technical production load for each installation has been offered at zero, with the remaining capacity at short-run marginal cost. Market clearing is determined in accor-dance with the National Electricity Code, that is, at the price level offered by the marginal generating unit. The assumed short-run mar-ginal costs of new coal-fired generators are be-tween $7 and $10 per megawatt-hour (MWh),with the new gas-fired machines ranging be-tween $21 (for combined cycle) and $45/MWh (for open cycle). All marginal running costs are increased when emissions are priced using the conversion ratios listed below in Table 4. 2 Emissions were calculated based on a standard conversion, multiplying MWh sent out by a ‘tonnes of CO 2 /MWh’ ratio. The assumed ra-tios are illustrated in Table 4. From a plant entry and exit perspective, the model generates sufficient electricity system information (forexample, unserved energy, reserve margins and spot prices) to enable the modeller to carry out optimal plant variations and adjustments in line with the stated objectives and constraints (for example, minimise costs and prices, re-duce environmental emissions and maintain minimum reserve plant margins).In Sections 4 to 7, we provide four scenarios of forward emission levels. The first scenario represents the base case, or business-as-usual scenario. 4.The Business-as-Usual Coal-Fired ScenarioThe business-as-usual scenario in the Queens-land electricity system largely resembles the bloodbath scenarioin Simshauser (2001). In this simulation, new entrants consist entirely of the most polluting technology, coal-fired gen-eration. All four coal-fired entrants (that is, the 840 MW Callide C, 840 MW Millmerran, 450MW Tarong North and the 700 MW Kogan Creek projects) are assumed to be commis-sioned on the dates listed in Table 3. While it is unclear at this stage whether Kogan Creek will emerge, few industry analysts would disagree that it seems to be the most likely scenario. The modelling results are illustrated in Figures 1and 2.Figure 1 provides historical results (1990–99) for comparative purposes, with forecasts for the period 2000–08 (the loading order of plant in Figure 1 is consistent with the legend,reading from bottom up). The forecasts reveal some interesting results. In this intensely com-petitive and oversupplied scenario, the time-weighted average spot price of electricity falls to less than $20/MWh in real (2001) dollars for much of the forecast period. Market share of the four oligopolistic incumbent generators (Stanwell Corporation, CS Energy, Enertrade and Tarong Energy) falls away from a 100 per cent peak in financial year 1999–2000, to a low of 62 per cent by the end of the forecast.Energy from privately owned sources almost doubles, from 20 per cent in 1999–2000 to around 38 per cent by 2007–08. Not surpris-ingly, coal remains the dominant fuel, with 95.8 per cent of the market in 2008. Gas has aTable 4 Emission Conversion RatiosTemplate statistics t of CO 2/MWhPulverised coal, subcritical 0.811Brown coal 1.110Black coal 0.890CCGT: Single shaft 0.422CCGT: Two on one 0.480OCGT0.665Supercritical wet cooled 0.682Supercritical dry cooled 0.705Combustion turbine 1.100Publicly available statistics Stanwell power station 0.818 Tarong power station 0.860 Kogan Creek power project 0.705 Millmerran power project0.846Sources : Sinclair Knight Mertz (1998, 1999) and Lacey (2000).292The Australian Economic Review September 20042004 The University of Melbourne, Melbourne Institute of Applied Economic and Social Researchshare of 0.6 per cent by the end of the forecast period, while other resources such as hydro,pumped-storage, biomass and combustion tur-bines make up the balance. In terms of plant utilisation, the average capacity factor of all coal-fired plant is only 69 per cent by 2008, although those rea-sonably classified as base load (as opposed toFigure 1 Queensland Power Station Production Levels, Business-as-Usual Scenario aEnergy sentFigure 2 Queensland CO 2 Emission Levels, Business-as-Usual ScenarioQuantity of CO 2 emissions (Mt)Level of emissions against 1990 baseline (per cent)Note: (a) Note that the order of the power stations illustrated in the graphs does not necessarily depict the merit order of plant dispatch.Simshauser and Docwra: Reducing Greenhouse Gas Emissions2932004 The University of Melbourne, Melbourne Institute of Applied Economic and Social Researchintermediate) average 80 per cent. In this sce-nario, the New South Wales transmission links send power into Queensland until the 2003calendar year. Thereafter, there is a mild net-flow of power south into New South Wales,averaging around 1500 gigawatt-hours (GWh)per annum.Figure 2 illustrates the growth in emissions against the notional 1990 Queensland Electric-ity Industry Kyoto Protocol target. The quan-tity of CO 2 emissions, illustrated by the bar chart, is measured on the left-hand axis and il-lustrates the absolute growth in greenhouse emissions. Based on the forecast above, emis-sions will increase from around 20 Mt in 1990to around 44.4 Mt in 2007–08. The line graph is measured on the right-hand axis and pro-vides the percentage increase against the no-tional baseline (1990 level) emissions. Under the business-as-usual scenario, Queensland’s increase in greenhouse gases is forecast to be in the order of 124 per cent. This represents 224per cent of the notional 1990 Queensland elec-tricity industry baseline—a number substan-tially above 108 per cent.5.The Gas-Fired Scenario: A Central Planning ApproachThis section examines a gas-fired scenario. Ef-ficient CCGT plant has a much greater cycle efficiency than its coal-fired counterparts. The emissions intensity (t/MWh) from a CCGT can be less than half of the emissions arising from coal-fired output (as noted in Table 4).Unfortunately, the Queensland system does not have access to low cost, reliable sources of gas. The abundance of low cost thermal coal generally precludes the entry of all competing energy sources. In reality, gas-fired generation will never compete effectively in the Queens-land gross pool spot market while externality pricing is absent. The short-run marginal cost of baseload coal plant (of between $7 and $13/MWh) is substantially below the marginal pro-duction cost of the most efficient CCGT, at about $21/MWh.This scenario considers the implications of a gas pipeline from Papua New Guinea being in-stalled along the east coast of Queensland. In this scenario, it is assumed that gas is madeFigure 3 Queensland Power Station Production Levels, Gas-Fired ScenarioEnergy sent294The Australian Economic Review September 20042004 The University of Melbourne, Melbourne Institute of Applied Economic and Social Researchavailable at a price of $3 per gigajoule (GJ);gas has historically been available in Queens-land at prices between $3 and $4/GJ. It is not useful to examine gas price sensitivities where the cost of gas is lower than that of coal (which costs $0.50 to $1/GJ in Queensland) because the economic differential is simply too great. To ensure the CCGTs are dispatched, a cen-tral planning approach was adopted to supply-side augmentation. While the pre-deregulation stock of generation plant remains intact, we have assumed that the gas pipeline project is fi-nancially closed, backdated to January 1997.The reason for this is that it enables the preven-tion of the new coal-fired installations entering the competitive market. Thus, Callide C, Mill-merran, Tarong North and Kogan Creek have been removed from the supply curve. The Queensland east coast gas pipeline is assumed to be completed by July 2003, with CCGT plant being commissioned as per Table 3. The results of this scenario are illustrated in Figures 3 and 4.Across the forecast period from 2000 to 2008, modelled spot prices have increased by only $5/MWh above the base case in real terms due to the intensely competitive behaviour as-sumed in generator offer pricing. Since elec-tricity demand is largely price inelastic, and end-use prices (incorporating transmission and distribution charges) are typically in the order of $90/MWh, we have assumed that a $5/MWh increase in the end-use price leads to no change in the business-as-usual load forecast. From a supply-side perspective, gas is supplied during 2003, and gradually ramps up over time. In the business-as-usual scenario (base case) pre-sented in Section 4, coal generators maintained a market share of 95.8 per cent, with gas regis-tering just 0.6 per cent. In this case, coal-fired generation is reduced to 77.1 per cent, while gas rises to 19.5 per cent by 2008. As the in-cumbent generators have proposed most of the gas-fired power stations, their collective mar-ket share remains high at 75 per cent as op-posed to 62 per cent in the business-as-usual scenario.Plant utilisations also vary considerably. The stock of coal-fired installations enjoys a high capacity factor, at 83 per cent, while the collec-tive stock of gas plant registers about 48 per cent. Unlike the business-as-usual scenario, the coal-fired New South Wales system net-exports moderate levels of power into Queens-land throughout the entire outlook period, aver-aging 1600 GWh per annum.Figure 4 illustrates the growth in emissions against the notional 1990 Queensland Electric-ity Industry Kyoto Protocol target. Despite the radical surgery which has been conducted on the business-as-usual aggregate supply func-tion, relatively little improvement is visible inFigure 4 Queensland CO 2 Emission Levels, Gas-Fired ScenarioQuantity of CO 2emissions (Mt)Level of emissions against 1990 baseline (per cent)Simshauser and Docwra: Reducing Greenhouse Gas Emissions2952004 The University of Melbourne, Melbourne Institute of Applied Economic and Social Researchthe 2007–08 emission levels. The net emis-sions amount to 42.3 Mt in 2007–08. The inclu-sion of a gas pipeline has only reduced emissions by around 2 Mt per annum as op-posed to the business-as-usual case. Emissions are still forecast to increase by 113 per cent.This represents 213 per cent of the notional 1990 Queensland electricity industry baseline.However, this result is not surprising. The gas-fired plants operate as high order intermediate or load following installations. The incumbent coal-fired installations are dispatched prior to the CCGTs due to their lower short-run mar-ginal cost functions, which determines the order of dispatch in gross pool markets.The introduction of a gas pipeline, grandfa-thered into existence by preventing new coal-fired entry, has made little impact on net emis-sions. Thus, in the absence of externality pric-ing, it appears that the market will yield non-optimal outcomes from an environmental per-spective. Accordingly, in the next case, we consider the impact of compounding the cost of negative externalities into the offer price of electricity producers.6.The Carbon Tax ScenarioWhile the gas-fired scenario shows some im-provement over the base case, further curtail-ment of greenhouse gas emissions is required if the gap between forecast emission levels and the notional Kyoto target is to be achieved.Negative externalities have been priced in order to reduce emission levels. A corrective tax is applied to all producers, otherwise known as a carbon tax, at a value of $25 for each tonne of CO 2 emitted. The value of the tax has been set at this level (that is, $25/t of CO 2 )in order to reverse the marginal running costs of coal-fired plant and combined cycle plant.This in turn ensures that gas-fired plant is dis-patched ahead of coal-fired plant, thus having the desired effect on emission levels.In this scenario, we assume a reduction of 3.8per cent in the business-as-usual load forecast due to the impost of a carbon tax. This assump-tion is based on modelling work undertaken by ACIL Consulting (2001). 3 All other as-sumptions from Section 5 have otherwise been held intact, and thus there are no new entrantFigure 5 Queensland Power Station Production Levels, Corrective (Carbon) Tax ScenarioEnergy sent296The Australian Economic Review September 20042004 The University of Melbourne, Melbourne Institute of Applied Economic and Social Researchcoal-fired installations included in the experi-ment. Figures 5 and 6 illustrate the results.In the carbon tax scenario, spot prices in-crease to $45/MWh in real terms throughout the forecast period. Gas-fired production is clearly visible in 2003–04. Gas-fired production in this scenario increases from 0.6 per cent in the business-as-usual scenario to 33.7 per cent by 2007–08. Coal-fired production drops from 95.8 per cent in the business as usual case to just 63.1 per cent in the corrective tax case. The util-isation of plant also changes markedly. The CCGTs enjoy a capacity factor of 84 per cent while coal stations run at 70 per cent. Power flows from New South Wales into Queensland across the interstate transmission link are posi-tive in the early years due to the lack of capacity in Queensland. However, flows are almost neu-tral following the commissioning of the gas pipeline. This is primarily the result of the im-position of the tax being uniformly imple-mented across the national electricity market.Under the carbon tax scenario, emissions are forecast to increase from 19.8 Mt in 1990 to 37.0 Mt in 2008. In the business-as-usual case,emissions were forecast to rise to 44.4 Mt, thus the introduction of a $25 carbon tax leads to an emission reduction of 7.4 Mt by 2008, and gen-erates corrective tax revenue amounting to $925 million per annum in real dollar terms by 2008. A sensitivity analysis was conductedwhereby the reduction in demand was set at 10per cent in line with ACIL Consulting’s (2001)‘large impact’ estimate. This led to an emission level of 34.6 Mt in 2008 and tax revenue of about $865 million per annum.A carbon tax might be considered a rational policy option during the interim period (that is,the period leading up to the Kyoto Protocol commitment period), notwithstanding that Australia is unlikely to ratify the Protocol, but intends to meet its Kyoto target. Importantly,even with the corrective tax regime, emissions still registered an increase of 87 per cent. It would thus appear that a corrective tax ($25)aimed at reversing the merit order of coal and gas plant is ineffective in bringing about a sub-stantial change in greenhouse gas emissions in Queensland in the time period analysed. The Australian Greenhouse Office (1999b, p. 12)highlighted what would otherwise be consid-ered a radical option for coal-fired power gen-erators, comprehensive fuel switching.The adjustment task facing emitters within the economy will also be affected by the amount of time available to prepare for, or adapt to, change.Investment planning occurs over a finite time ho-rizon, and eventually, all equipment will be re-placed … Abatement can be achieved in a number of ways including purchase of more efficient equipment, fuel switching and/or changes in con-sumption patterns …Figure 6 Queensland CO 2 Emission Levels, Corrective (Carbon) Tax ScenarioQuantity of CO 2emissions (Mt)Level of emissions against 1990 baseline (per cent)。