Australian energy projections to

2034–35December 2011

Arif Syed and Kate Penney

© Commonwealth of Australia 2011

This work is copyright, the copyright being owned by the Commonwealth of Australia. The Commonwealth of Australia has, however, decided that, consistent with the need for free and open re-use and adaptation, public sector information should be licensed by agencies under the Creative Commons BY standard as the default position. The material in this publication is available for use according to the Creative Commons BY licensing protocol whereby when a work is copied or redistributed, the Commonwealth of Australia (and any other nominated parties) must be credited and the source linked to by the user. It is recommended that users wishing to make copies from BREE publications contact the Chief Economist, Bureau of Resources and Energy Economics (BREE). This is especially important where a publication contains material in respect of which the copyright is held by a party other than the Commonwealth of Australia as the Creative Commons licence may not be acceptable to those copyright owners.

The Australian Government acting through BREE has exercised due care and skill in the preparation and compilation of the information and data set out in this publication. Notwithstanding, BREE, its employees and advisers disclaim all liability, including liability for negligence, for any loss, damage, injury, expense or cost incurred by any person as a result of accessing, using or relying upon any of the information or data set out in this publication to the maximum extent permitted by law.BREE 2011, Australian energy projections to 2034–35, BREE report prepared for the Department of Resources, Energy and Tourism, Canberra, December.

ISBN 978-1-921812-79-8 (Print)

ISBN 978-1-921812-78-1 (Online)

Postal address:Bureau of Resources and Energy EconomicsGPO Box 1564Canberra ACT 2601Phone: +61 2 6276 1000Email: info@bree.gov.auWeb: www.bree.gov.auFrom 1 July 2011, responsibility for resources and energy data and research was transferred from the Australian Bureau of Agricultural and Resource Economics and Sciences (ABARES) to the Bureau of Resources and Energy Economics (BREE).

AcknowledgementsThis report was undertaken with the support of the Australian Government Department of Resources, Energy and Tourism.The valuable contribution of BREE colleagues; Trish Gleeson and Sally Thorpe of ABARES; Bruce Wilson, Shane Bush and Sarah Hill from the Department of Resources, Energy and Tourism; Brendan Mckenna and Sebastian Wende of the Australian Treasury; and colleagues at the Department of Climate Change and Energy Efficiency is appreciated.

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ForewordIn this report the Bureau of Resources and Energy Economics (BREE) presents its inaugural set of long-term projections of Australian energy consumption, production and trade. The analysis covers the period from 2008–09 to 2034–35 and is prepared using BREE’s E4cast model. It is intended that this information will support decision-making by industry, government and the broader community. The results suggest that the Australian energy sector is at an important crossroads as it adjusts to a carbon-constrained economy. The dynamics of energy markets and uncertainties with respect to future energy costs make long-term energy projections difficult. Nevertheless, projections are needed to guide decision makers about investments and the impacts of energy policies and energy outcomes. BREE’s projections provide this guidance and will assist decision-makers to deliver an efficient, secure and sustainable energy future for Australia.

Quentin GraftonExecutive Director / Chief EconomistDecember 2011

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ContentsSummary 111 Introduction 132 The Australian energy context 14

Energy resources and markets 14Energy policy 17Clean Energy Future Plan 18Other initiatives 19

3 Methodology and key assumptions 21The E4cast model 21E4cast base year data 25Key assumptions 25

4 Energy Consumption 32Total primary energy consumption 32Primary energy consumption, by energy type 32Primary energy consumption, by state and territory 33Primary energy consumption, by sector 34Electricity generation 35Final energy consumption, by energy type 41Final energy consumption, by sector 42

5 Energy production and trade 45Black coal production and exports 47Natural gas production and LNG exports 48Crude oil production and net imports 50

6 Conclusions 52References 53

BoxesBox 1: Other Clean Energy Future initiatives 19Box 2: Key features of E4cast 22Box 3: Australian energy statistics 25Box 4: Carbon capture and storage 38Box 5: Uncertainty surrounding gas prices for electricity generation 40Box 6: Energy use in the Australian transport sector 43Box 7: Australian uranium outlook 46

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FiguresFigure A: Australian energy production 15Figure B: Energy intensity trends 16Figure C: Australian energy exports 17Figure D: Energy forecasting model 21Figure E: Index of world real energy prices, 2008–09 dollars 27Figure F: Index of real levelised cost of electricity generation technologies excluding carbon costs 29Figure G: Australian uranium production 46Figure H: Australian energy balance 47Figure I: Australian black coal balance 48Figure J: Australian gas balance 49Figure K: Australian oil and LPG balance 50

TablesTable 1: Fuel coverage in E4cast 23Table 2: Industry coverage of E4cast 24Table 3: Australian population assumptions 26Table 4: Australian economic growth, by region 26Table 5: Carbon price assumptions, real, 2009–10 dollars 30Table 6: LRET renewable electricity generation target (excluding existing renewable generation) 30Table 7: Primary energy consumption, by energy type 33Table 8: Primary energy consumption, by state and territory 34Table 9: Primary energy consumption, by sector 35Table 10: Electricity generation, by state and territory 36Table 11: Electricity generation, by energy typea 37Table 12: Electricity generation, with alternative gas price assumptions, by energy source 41Table 13: Final energy consumption, by energy type 42Table 14: Final energy consumption, by sector 43Table 15: Final energy consumption, by manufacturing subsector 44Table 16: Energy production, by source 45Table 17: Net trade in energy 48Table 18: Australian gas production 49

MapsMap 1: Distribution of Australia’s energy resources 14Map 2: Advanced electricity generation projects, October 2011 38

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GlossaryBagasse The fibrous residue of the sugar cane

milling process that is used as a fuel (to raise steam) in sugar mills.

Biogas Landfill (garbage tips) gas and sewage gas.

Brown coal See lignite.

Coal by-products By-products such as coke oven gas, blast furnace gas (collected from steelworks blast furnaces), coal tar and benzene/toluene/xylene (BTX) feedstock. Coal tar and BTX are both collected from the coke making process.

Conversion The process of transforming one form of energy into another before use. Conversion consumes energy. For example, some gas and liquefied petroleum gas is consumed during gas manufacturing, some petroleum products are consumed during petroleum refining, and various fuels, including electricity, are consumed when electricity is generated. The energy consumed during conversion is calculated as the difference between the energy content of the fuels consumed and that of the fuels produced.

Crude oil Naturally occurring mixture of liquid hydrocarbons under normal temperature and pressure.

Condensate Hydrocarbons recovered from the natural gas stream that are liquid under normal temperature and pressure.

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Electricity generation capacity

The maximum technically possible electricity output of generators at a given hour. The maximum annual output from generators is equal to generation capacity multiplied by the number of hours in a year.

Gas Gases including commercial quality sales gas, liquefied natural gas, ethane, methane (including coal seam and mine mouth gas and gas from garbage tips and sewage plants) and plant and field use of non-commercial quality gas. In this report, gas also includes town gas (including synthetic gas, reformed gas, tempered liquid petroleum gas and tempered natural gas).

Gas pipeline operation

Gas used in pipeline compressors and losses and operation and leakage during transmission.

Levelised cost The total levelised cost of production represents the revenue per unit of electricity generated that must be met to breakeven over the lifetime of a plant.

Lignite Non-agglomerating coals with a gross calorific value less than 17 435 kilojoules a kilogram, including brown coal which is generally less than 11 000 kilojoules a kilogram.

Liquid fuels All liquid hydrocarbons, including crude oil, condensate, liquefied petroleum gas and other refined petroleum products, and liquid biofuels.

Natural gas Methane that has been processed to remove impurities to a required standard for consumer use. It may contain small amounts of ethane, propane, carbon dioxide and inert

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gases such as nitrogen. Landfill and sewage gas are some other potential sources (also referred to as sales gas in some sectors of the gas industry).

Petajoule The joule is the standard unit of energy in electronics and general scientific applications. One joule is the equivalent of one watt of power radiated or dissipated for one second. One petajoule, or 278 gigawatt hours, is the heat energy content of about 43 000 tonnes of black coal or 29 million litres of petrol.

Petroleum Crude oil and natural gas condensate used directly as fuel, liquefied petroleum gas, refined products used as fuels (aviation gasoline, automotive gasoline, power kerosene, aviation turbine fuel, lighting kerosene, heating oil, automotive diesel oil, industrial diesel fuel, fuel oil, refinery fuel and naphtha) and refined products used in nonfuel applications (solvents, lubricants, bitumen, waxes, petroleum coke for anode production and specialised feedstocks).In this report, all petroleum products are defined as primary fuels even though most petroleum products are transformed (refined). The distinction between the consumption of petroleum at the primary and final end use stages relates only to where the petroleum is consumed, not to the mix of different petroleum products consumed. The consumption of petroleum at the primary energy use stage is referred to collectively as oil, while the consumption of petroleum at the final end use stage is referred to as petroleum products.

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The one exception to this is liquefied petroleum gas (LPG). LPG is not included in the definition of end use consumption of petroleum because it is modelled separately.

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Primary fuels The forms of energy obtained directly from nature. They include non-renewable fuels such as black coal, brown coal, uranium, crude oil and condensate, naturally occurring liquid petroleum gas, ethane and gas, and renewable fuels such as wood, bagasse, hydroelectricity, wind and solar energy.

Secondary fuels Fuels produced from primary or other secondary (or derived) fuels by conversion processes to provide the energy forms commonly consumed. They include refined petroleum products, thermal electricity, coke, coke oven gas, blast furnace gas and briquettes.

Total final energy consumption

The total amount of energy consumed in the final or end use sectors. It is equal to total primary energy consumption less energy consumed or lost in conversion, transmission and distribution.

Total primary energy

The total of the consumption of each primary fuel (in energy units) in both the conversion and end use sectors. It includes the use of primary fuels in conversion activities—notably the consumption of fuels used to produce petroleum products and electricity. It also includes own use and losses in the conversion sector.

UnitsMetric units Standard metric prefixesJ joule k kilo 103 (thousand)L litre M mega 106 (million)t tonne G giga 109 (1000 million)g gram T tera 1012

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Metric units Standard metric prefixesWh watt-hours P peta 1015

b billion (1000 million) E exa 1018

Standard conversions1 barrel = 158.987 L1 mtoe (million tonnes of oil equivalent) = 41.868 PJ1 kWh = 3600 kJ1 MBTU (million British thermal units) = 1055 MJ1 m3 (cubic metre) = 35.515 f 3 (cubic feet)1 L LPG (liquefied petroleum gas) = 0.254 m3 natural gasConversion factors are at a temperature of 15°C and pressure of 1 atmosphere.

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Indicative energy content conversion factorsBlack coal production 30 GJ/tBrown coal 9.8 GJ/tCrude oil production 37 MJ/LNaturally occurring LPG 26.5 MJ/LLNG exports 54.4 GJ/tNatural gas (gaseous production equivalent) 40 MJ/kLBiomass 11.9 GJ/tHydroelectricity, wind and solar energy 3.6 TJ/GWh

Conventions used in tablesSmall discrepancies in totals are generally the result of the rounding of components.

AbbreviationsABARES Australian Bureau of Agricultural and Resource Economics and

SciencesAEMO Australian Energy Market OperatorBREE Bureau of Resources and Energy EconomicsCCS Carbon Capture and Storage/SequestrationCOAG Council of Australian GovernmentsCSG Coal Seam GasGHG Greenhouse GasIEA International Energy AgencyLNG Liquefied Natural GasLRET Large-scale Renewable Energy TargetNFEE National Framework for Energy EfficiencyNGER National Greenhouse and Energy ReportingNSEE National Strategy on Energy EfficiencyOECD Organisation for Economic Cooperation and DevelopmentORER Office of the Renewable Energy RegulatorPV PhotovoltaicRET Renewable Energy TargetSRES Small-scale Renewable Energy Scheme

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BREE contactsExecutive Director/Chief Economist – BREE Quentin Grafton quentin.grafton@bree.gov.au

02 6276 7483

General Manager Jane Melanie jane.melanie@bree.gov.au02 6243 7502

Micro & Industry Performance AnalysisTheme Leader Arif Syed arif.syed@bree.gov.au

02 6243 7504

Macro & Markets AnalysisTheme Leader Jin Liu jin.liu@bree.gov.au

02 6243 7513

Resources ProgramProgram Leader Alan Copeland alan.copeland@bree.gov.au

02 6243 7501

Quantitative Economic AnalysisTheme Leader Nhu Che nhu.che@bree.gov.au

02 6243 7539

Energy ProgramProgram Leader Allison Ball allison.ball@bree.gov.au

02 6243 7500Data & Statistics ProgramProgram Leader Geoff Armitage geoff.armitage@bree.gov.au

02 6243 7510

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Summary This report delivers BREE’s inaugural long-term projections of Australian energy consumption,

production and trade over the period to 2034–35. These projections are not intended as predictions or forecasts, but as indicators of potential changes in Australian energy consumption, production and trade patterns given the assumptions used in the report.

Relevant government policies that have been introduced or enacted have been incorporated into BREE’s assumptions. This includes the Renewable Energy Target (RET) and the introduction of carbon pricing in 2012.

The assumptions around carbon emission reduction policies included in the E4cast model are based on the Australian Treasury’s publication, Strong growth, low pollution: modelling a carbon price, released in 2011. The transitional arrangements and targeted investment programs included in the Clean Energy Future plan have not been included specifically in the modelling assumptions. Given the uncertainty surrounding future domestic gas prices, a sensitivity analysis was undertaken to assess the effect of higher gas prices on the electricity generation mix.

Energy consumption Total primary energy consumption is projected to grow by around 29 per cent (1 per cent a

year) over the projection period (2008–09 to 2034–35). This moderate growth reflects a long-term decline in the energy intensity of the Australian economy which has been accelerated by a number of policy drivers.

The share of coal in total primary energy consumption is projected to decline, with oil and gas projected to be the dominant energy sources used.

Gas is expected to exhibit the fastest growth among non-renewable energy sources, increasing by an average 3 per cent a year to 2611 petajoules in 2034–35.

The share of renewable energy is projected to increase from 5 per cent of total primary energy consumption in 2008–09 to 9 per cent of total primary energy consumption in 2034–35. This implies an average annual growth rate of 3.4 per cent, with the most significant growth occurring in wind energy.

Western Australia, the Northern Territory and Queensland are expected to exhibit the highest growth in primary energy consumption. These regions are expected to achieve higher economic growth relative to other states, based on the large contribution of the mining sector and the high degree of export orientation.

The electricity generation and transport sectors will remain the two main users of primary energy, together accounting for 63 per cent of projected primary energy consumption in 2034–35.

The share of primary energy consumed by the electricity generation sector is expected to decline over the projection period as the effects of the RET and the implementation of carbon pricing are expected to encourage a change in the energy mix.

The transport sector accounts for around one quarter of primary energy consumption, and this share is projected to remain relatively constant out to 2034–35. Growth in transport is coupled with improving end-use efficiency, which is expected to have a moderating effect on energy consumption.

The fastest growing consumer of primary energy will be the mining sector, with average growth of 5.2 per cent a year expected over the projection period.

Electricity generation Gross electricity generation is projected to grow by around 42 per cent (1.4 per cent a year)

from 245 terawatt hours in 2008–09 to 348 terawatt hours in 2034–35. This growth is expected to come from expansion of gas-fired electricity generation and renewable sources.

A key change over the projection period is the expected shift from coal-fired to gas-fired generation. As the proportion of coal-fired generation declines from 74 per cent to 38 per cent of electricity generation over the projection period, the share of gas-fired generation is expected to more than double from 16 per cent to 36 per cent.

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The use of renewable energy resources in electricity generation is expected to grow considerably at 6 per cent a year over the projection period. Wind energy is projected to account for the majority of this growth, representing 14 per cent of total electricity generation in 2034–35. Strong growth is also expected in other renewable energy sources, including solar energy, geothermal energy and bioenergy, although from a lower base.

Under assumed higher gas prices, total electricity generation is projected to grow at a slower rate of 1.3 per cent a year to 340 terawatt hours in 2034–35. The share of gas in the generation mix is projected to be lower under this scenario (22 per cent), accompanied by a relatively smaller fall in the share of coal, and a slightly increased share for renewables (25 per cent).

Energy production and trade Australian energy production (excluding uranium) is projected to grow at an average annual

rate of 3 per cent over the projection period. At this rate, total production of energy is projected to more than double to 28 401 petajoules in 2034–35.

Coal and gas are projected to account for 96 per cent of Australia’s energy production in 2034–35. Coal production is projected to increase by 96 per cent to 18 956 petajoules (632 million tonnes), while gas is projected to increase fourfold to 8274 petajoules (330 960 gigalitres).

Production of black coal, which includes thermal and metallurgical coal, is projected to grow at 2.8 per cent a year to 18 676 petajoules (623 million tonnes) in 2034–35. Despite this growth, the share of black and brown coal in total energy production is projected to decline from 74 per cent in 2008–09 to 67 per cent in 2034–35.

Strong growth in domestic and global demand for gas has been driving the development of new gas fields and LNG capacity in Australia. Gas production in the western market is projected to grow at an average annual rate of 5.5 per cent to 4771 petajoules in 2034–35. In the eastern market, production is projected to grow at 5.0 per cent a year to 2492 petajoules.

Production of coal seam gas (CSG) is expected to maintain its strong growth trajectory over the projection period, supported by the development of new projects and demand for CSG-fired electricity generation.

The exportable surplus of Australia’s energy production is expected to increase over the projection period, rising by approximately 4.1 per cent a year. The fastest growth is expected in LNG exports, growing at 7.6 per cent a year.

Projections of declining oil production and constraints around petroleum refining suggest Australia’s net trade position for crude oil and refined petroleum products will weaken over the projection period, with net imports projected to increase at an average rate of 3.1 per cent a year.

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1 IntroductionThis report presents the results of BREE’s inaugural energy projections for Australia. The release of these results will be part of an ongoing commitment by BREE to publish regular long-range projections of Australian energy consumption, production and trade, with the support of the Australian Government Department of Resources, Energy and Tourism. The current set of results provides an update to the projections published by ABARE in March 2010, with the following amendments:

Updated base year to 2008–09; Extension of the projection period to 2034–35; Revisions to economic growth assumptions; Revisions to carbon price assumptions; Revisions to long term energy price assumptions; Changes to the Renewable Energy Target policy; An analysis of the effect of different gas prices on the electricity generation mix; and Inclusion of recently announced changes to Australian steel making and petroleum refining

capacity.The report aims to encapsulate these recent developments by providing an assessment of long-term projections of Australian energy consumption, production and trade for the period 2008–09 to 2034–35. These projections are derived using BREE’s E4cast model, which is a dynamic partial equilibrium model of the Australian energy sector.In undertaking these projections, BREE has included policies that have already been enacted. As such, these projections incorporate the Renewable Energy Target and the introduction of carbon pricing in 2012. This scenario does not pre-empt any Australian Government decisions that may affect the final target and policy design, or any specific outcomes that may be achieved by a global commitment to reduce emissions. Given the uncertainty surrounding future gas prices, a sensitivity analysis was conducted to assess the effect of gas prices on growth in energy use.The evolving dynamics of energy markets over the past few years have increased the complexity of long-term energy projections. There is significant uncertainty about technology, investment and government policies in the current environment. The current projections should only be considered as indications of what the future could be given the assumptions used, and not a forecast and what energy use will be into the future.In this report, measures of energy consumption, production and net trade are expressed in energy content terms (typically petajoules or gigawatt hours for electricity) to allow for comparison across the energy commodities. The significance of a commodity in energy content terms may differ to physical production units (such as tonnes, litres and barrels) and value.The report is structured as follows. In chapter 2 the changing energy policy context in Australia is described, with a focus on key policies that are likely to affect long-term

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energy trends. Chapter 3 presents the modelling framework used, as well as the key underlying assumptions. Chapter 4 provides the outlook for Australian energy consumption and electricity generation covering the period 2008–09 to 2034–35, and chapter 5 provides the long-term outlook for Australian energy production and trade. Chapter 6 offers concluding remarks.

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2 The Australian energy contextEnergy resources and marketsAustralia is endowed with abundant, high quality and diverse energy resources (Map 1). Australia holds an estimated 47 per cent of world uranium resources, 10 per cent of world coal resources, and almost 2 per cent of world natural gas resources. In addition, Australia has large, widely distributed wind, solar, geothermal, hydroelectricity, ocean energy and bioenergy resources.Map 1: Distribution of Australia’s energy resources

Source: Geoscience Australia and ABARE (2010)

The development of these resources has contributed to low-cost energy, underpinned the competitiveness of energy-intensive industries and provided considerable export income. Australia is one of the few OECD economies that is a significant exporter of energy commodities, with the major exports being coal, liquefied natural gas (LNG),

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uranium and petroleum.

Australian energy productionAustralia is the world’s ninth largest energy producer, accounting for around 2.5 per cent of the world’s energy production (IEA 2011). Energy production in Australia has been increasing over the past decade, growing at an average annual rate of 3.2 per cent since 1999–00.The main fuels produced in Australia are coal, uranium and gas (Figure A). Of these, coal accounted for around 57 per cent of total energy production in energy content terms in 2009–10, followed by uranium (20 per cent) and gas (12 per cent). Crude oil and LPG represented 6 per cent of total production, and renewable energy 2 per cent. Figure A: Australian energy production

Sources: BREE calculations, and ABARES (2011)

Australian production of renewable energy has been dominated by bagasse, wood and wood waste, and hydroelectricity, which together accounted for 83 per cent of renewable energy production in 2009–10. Wind energy, solar energy and biofuels accounted for the remainder of Australia’s renewable energy production.Although energy production has been increasing over the past 10 years, reserves to production ratios have followed a rising trend. This reflects the addition of new discoveries and the upgrading of resources meeting economic criteria. At current

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rates of production, Australia’s energy resources are expected to last for many more decades.

Australian energy consumptionAustralia is the world’s nineteenth largest primary energy consumer, and ranks fourteenth on a per person energy use basis (IEA 2011). Since 2000, growth in energy consumption has averaged 1.6 per cent a year.Although Australia’s energy consumption is growing, the rate of growth has been declining over the past 50 years. Following annual growth of around 5 per cent during the 1960s, growth in energy consumption fell during the 1970s to an average of around 4 per cent a year, largely as a result of the two major oil price shocks. During the 1980s, economic recession and sharply rising energy prices resulted in the annual growth in energy consumption falling to an average of 2.3 per cent. In the early 1990s, falling real energy prices and robust economic growth contributed to rising energy consumption. Despite this, growth in energy consumption for the decade as a whole also averaged around 2.3 per cent.Figure B shows the long term decline in energy intensity of the Australian economy. This can be attributed to two main factors. First, greater efficiency has been achieved through technological improvement and fuel switching. Second, rapid growth has occurred in less energy-intensive sectors, such as the commercial and services sector, relative to the more moderate growth of the energy-intensive manufacturing and processing sectors.

Figure B: Energy intensity trends

Sources: ABARE-BRS (2010), ABS (2010a)

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Australian primary energy consumption consists mainly of coal, petroleum and gas. In 2008–09 black and brown coal accounted for around 39 per cent of the primary energy mix, followed by petroleum products (35 per cent), gas (22 per cent) and renewable energy sources (5 per cent). The main users of energy in Australia are the electricity generation, transport and manufacturing sectors. Together, these sectors accounted for more than 80 per cent of energy consumed in 2008–09. The mining, residential and commercial and services sectors were the next largest energy consuming sectors.The electricity industry is one of Australia’s largest industries, contributing 1.1 per cent to Australian industry value added in 2008–09 and generated 245 terawatt hours of electricity. Most of Australia’s electricity is produced using coal, reflecting its abundance along the eastern seaboard where the majority of electricity is generated and consumed. In 2008–09, coal-fired electricity generation accounted for 74 per cent of total electricity generation and gas 16 per cent. Over the past 20 years, domestic energy consumption has increased at a slower rate than energy production. Rapid growth in global demand for Australian energy resources has driven this growth in energy production. Consequently, the share of Australian energy production that is exported has continued to increase.

Australia’s energy exports Australia is a net energy exporter, with domestic energy consumption representing only one-third of total energy production, including uranium. Since 1990–91, the value of Australia’s energy exports (in 2011–12 Australian dollars) has increased at an average rate of 9.3 per cent a year. In 2010–11, energy export earnings increased by 16 per cent to $71 billion (in 2011–12 dollars), reflecting increased export volumes and higher export prices (Figure C). Energy exports accounted for 32 per cent of Australia’s total commodity exports in 2010–11.Australia’s largest energy export earners are coal, crude oil and LNG. These exports are significant contributors to the economy, and in 2010–11 export values (in 2011–12 Australian dollars) were estimated at $44 billion for coal, $12 billion for crude oil and condensate and $11 billion for LNG, respectively.

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Figure C: Australian energy exports

Source: BREE (2011)

While Australia is a net energy exporter, it is a net importer of crude oil and refined petroleum. In 2010–11, Australia’s imports of crude oil and refined products were valued at $33 billion (in 2011–12 Australian dollars). Any future expansion of Australia’s energy market, including access to new energy resources, will require investment in energy infrastructure. Additional investment will be required to replace ageing energy assets and also to allow for the integration of renewable energy into existing energy supply chains.

Energy policyAustralia’s energy policy aims to balance the growing demand for energy with the promotion of a lower carbon economy, incorporating international commitments regarding climate change. The policy also seeks the provision of a stable economic environment to encourage investment in the energy sector, particularly renewable energy.Australian Government policies that will shape the energy market over the next 25 years are the Renewable Energy Target (RET) and the introduction of carbon pricing. The RET and carbon pricing are aimed at creating a fundamental shift in consumption, in addition to investment incentives in the energy sector, to induce Australian

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companies and households to internalise the costs of climate change. These strategies are complemented by targeted initiatives, such as the Energy Efficiency Initiative.

Renewable Energy TargetIntroduced in 2010, the RET requires 45 000 gigawatt hours of electricity to be supplied from renewable energy sources by 2020. This target corresponds to around 20 per cent of total electricity generation and is a substantial increase from the previous Mandatory Renewable Energy Target (MRET) of 9500 gigawatt hours by 2020. The RET brought existing state based RETs, such as the Victorian Renewable Energy Target, into a single national scheme.Initially, retailers and large users of electricity were legally required to earn or obtain Renewable Energy Certificates (RECs) equivalent to a set proportion of their electricity purchases. Additionally, households and small businesses could earn RECs on a voluntary basis through solar credits for small-scale renewable energy installations. RECs could then be traded to ensure companies reached their legislated quota and to provide incentives for the adoption of renewable energy sources. From January 2011, the RET has been split into the voluntary Small-scale Renewable Energy Scheme (SRES) and the mandatory Large-scale Renewable Energy Target (LRET) to improve certainty for all involved and to provide incentives targeted at each group. The LRET consists of legislated annual targets for the amount of electricity to be sourced from renewable energy to ensure that 41 000 gigawatt hours is achieved by 2020. Because of the large number of RECs generated by the end of 2010, the annual LRET targets for 2012 and 2013 were increased to support advances in the adoption of renewable energy sources (ORER 2011). Households and small businesses are anticipated to provide, and potentially exceed, the additional 4000 gigawatt hours required to meet the RET through the SRES. Accordingly, RECs have been separated into Large-scale Generation Certificates (LGCs) and Small-scale Technology Certificates (STCs).The Office of the Renewable Energy Regulator oversees the implementation of the RET and the registration of subsequent LGCs and STCs (ORER 2011).The objective of the RET is to advance the development and employment of renewable energy resources over the medium term and to assist in moving Australia to a lower carbon economy (Combet 2009).

Clean Energy Future PlanThe Australian Government passed its Clean Energy Future plan through the Senate on 8 November 2011. The plan reflects the considerations of the Multi-Party Climate Change Committee (MPCCC) that determined that a carbon price and a package of complementary measures would be the most cost-effective and economically responsible way of reducing Australia’s carbon emissions. The emissions reduction targets that have been previously agreed to and were extended under the Clean

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Energy Future plan are: To reduce emissions to 5 per cent below 2000 levels by 2020, which will require cutting net

expected emissions by at least 23 per cent in 2020 A long-term reduction in emissions to 80 per cent below 2000 levels by 2050.

The carbon price is to be introduced on 1 July 2012. It will be fixed for the first three years before transitioning to an emissions trading scheme. From 1 July 2012, the carbon price will be a nominal $23 a tonne of carbon dioxide equivalent (CO2-e), increasing at a rate of 5 per cent a year until 30 June 2015. From 2015, the carbon price will transition to a ‘cap and trade’ emissions trading scheme, open to the international market. Introducing carbon pricing makes large emitters of carbon financially liable for their carbon emissions. During the fixed price period, an unlimited number of permits will be available at a fixed price, and these must be purchased and surrendered for each tonne of reported emissions. The carbon price will transition to an emissions trading scheme in 2015, where the number of available permits will be capped and the permit price will be determined in the marketplace. However, there will be a price cap set at $20 above the expected international price for an equivalent tonne of CO2-e, and a price floor of $15 a tonne CO2-e. At this point the carbon market may also be opened up to international carbon trading. The Government’s Clean Energy Future plan, comprises of a number of institutional arrangements. These include household and industry assistance, innovation and investment programs and transitional measures. Some of the arrangements relevant to the Australian energy projections are discussed in Box 1.

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Box 1: Other Clean Energy Future initiativesA range of government initiatives and support programs are included in the Clean Energy Future plan: Energy Security and Transformation

An Energy Security Council that will collaborate with the Australian Energy Market Operator will be established. Significant work occurring in this area will include the:Negotiation and potential payment for closure of up to 2000 megawatts of emissions-intensive generation

capacity before 2020;Free permit allocations and cash payments to emissions-intensive coal-fired electricity generators, in return for

adopting clean energy investment plans; andShort-term loans to generators to help finance the purchase of carbon permits.Clean Energy Finance Corporation

The Government intends to encourage investment in renewable energy, energy efficiency and low emissions technologies by providing financial support. The Government will invest $10 billion over 5 years beginning 2013–14 through loans, loan guarantees and equity investments. Australian Renewable Energy Agency

The Australian Renewable Energy Agency (ARENA) will provide grant funding to support research, development and demonstration of new renewable technologies, investing $3.2 billion over 9 years beginning 2011–12. It will also oversee existing government renewable energy programs. The Jobs and Competitiveness Program

The Jobs and Competitiveness Program will assist emissions-intensive trade-exposed industries with $9.2 billion transitional assistance between 2011–12 and 2014–15. These industries will receive assistance to cover 94.5 per cent of industry average carbon costs in the first year of the carbon price. Less emission-intensive trade-exposed industries will receive assistance to cover 66 per cent of average industry carbon costs. Assistance will be reduced by 1.3 per cent each year. Other programs

The Clean Technology Program will target energy efficiency in manufacturing industries and support research and development in low emissions technologies. It will provide $1.2 billion over 7 years from 2011–12. There will also be funding to support jobs in food processing, metal forging and foundry industries ($200 million) and funding for the Steel Transformation Plan ($300 million). There will be $1.3 billion directed to the Coal Sector Jobs Package over 6 years from 2011–12, which will provide transitional assistance to the coal industry to assist in the implementation of carbon abatement technologies.

Other initiativesA wide range of policies exist at both the Australian and State Government levels that will assist with creating a lower carbon economy. These include the National Strategy on Energy Efficiency and other related energy efficiency initiatives, the New South Wales Greenhouse Gas Reduction Scheme, and the Queensland Gas Scheme.

Energy EfficiencyThe National Framework for Energy Efficiency (NFEE) is a multi-level government policy announced by the Ministerial Council on Energy in 2004. The NFEE promotes improvements in energy efficiency through encouraging a shift in households’ and companies’ consumption behaviour by improving public information, providing financial incentives, and enforcing standards for the energy efficiency of goods such as light bulbs and air conditioners. To reinforce this desired behavioural shift or ‘step change’, the Prime Minister’s Task Group on Energy Efficiency has recommended establishing a national energy efficiency target of improving energy intensity by 30 per cent by 2020 (PMTGEE 2010). In 2009, the Council of Australian Governments (COAG) agreed on the 10 year

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National Strategy on Energy Efficiency (NSEE). The NSEE seeks to support the NFEE in providing information regarding methods of reducing energy use and improving efficiency, generating public awareness, and facilitating innovations in energy efficient technologies and practices (COAG 2009). The NSEE also strives to remove regulatory obstacles which may prevent improvements in energy efficiency, such as duplication of processes and inconsistent standards.A number of NFEE and NSEE programs are already in place or currently in the process of development in order to address energy efficiency opportunities (DCC 2010).

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New South Wales Greenhouse Gas Reduction SchemeThe New South Wales (NSW) Greenhouse Gas Reduction Scheme (GGAS) commenced in NSW on 1 January 2003. On 1 January 2005, the Australian Capital Territory Government introduced a corresponding scheme utilising the same regulatory bodies and structures. GGAS aims to reduce the emissions associated with the production and use of electricity through imposing mandatory emission reduction targets. The GGAS targets maintaining greenhouse gas emissions (from 2007 until the scheme concludes) at a benchmark of 7.27 tonnes of carbon dioxide equivalent (CO2-e) per person, which is equivalent to 5 per cent below the Kyoto-Protocol baseline year of 1989–90. The NSW government has committed to maintaining the program until the introduction of carbon pricing. The proportion of the greenhouse gas reduction benchmark imposed on each participant is equivalent to their share of electricity sales in NSW (Greenhouse Gas Reduction Scheme Administrator 2007). On 1 July 2009, the NSW Government introduced the Energy Savings Scheme (ESS) to replace the demand side abatement component of GGAS. Companies that supply electricity in NSW are required to meet energy savings targets equivalent to their share of electricity sales in NSW. Participants may trade the Energy Savings Certificates (ESCs) generated through their activities. This provides an incentive for companies to increase their energy savings and rewards companies that exceed their benchmark.

Queensland Gas Scheme The Queensland Gas Scheme was implemented on 1 January 2005. The scheme requires electricity retailers and other liable parties to source a minimum percentage of their electricity from eligible gas-fired generation. The initial requirement was set at 13 per cent and increased to 15 per cent in 2010. There is the potential to increase the required percentage to 18 per cent by 2020 (DME 2011). The objective is to diversify the energy mix, provide support for the state’s gas industry and reduce greenhouse gas emissions. The Queensland Gas Scheme will conclude when carbon pricing is introduced.

Data CollectionRecently, emphasis has been placed on the role that quality data collection plays in ensuring effective development and evaluation of energy policy. Improving the accuracy of the data collected and distributed also helps governments and companies understand the effect of energy policies on supply and demand so that they can adapt their behaviour accordingly. In the NSEE, COAG includes measures for advancing the collection of energy efficiency data and identifying those measures as critical to the effective implementation of energy efficiency policy (COAG 2009). The development and distribution of data collection in Australia is supported by existing legislation such as the National Greenhouse and Energy Reporting Act, as well as organisations such

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as the Australian Bureau of Statistics (ABS) and the Bureau of Resources and Energy Economics (BREE).

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3 Methodology and key assumptionsThe energy sector projections presented in this report were derived using the E4cast model. E4cast is a dynamic partial equilibrium model of the Australian energy sector that can project energy consumption by fuel type, by industry and by state or territory, on a financial year (July–June) basis. The model includes a large number of variables and parameters that are used to approximate the interdependencies between production, conversion and consumption of energy.

The E4cast modelThe E4cast modelling framework employs an integrated analysis of the electricity generation and gas sectors within an Australian domestic energy use model. The model represents two sets of conditions: quantity and competitive price constraints. The competitive equilibrium is achieved when all the constraints are satisfied. A simple schematic of the E4cast model is provided in Figure D.Figure D: Energy forecasting model

E4cast incorporates long-term macroeconomic forecasts from the Australian Treasury and ABARES and current assumptions on the costs and characteristics of energy conversion technologies. A brief overview of the key features of the current version of

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E4cast is provided in Box 2. The model provides an outlook for the Australian energy sector that is feasible (where all quantity constraints are satisfied) and satisfies the economic competitive price conditions (a competitive equilibrium is achieved).

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Box 2: Key features of E4castThe first version of the model was documented in Dickson et al. (2001). Since then, the model has been enhanced and refined in a number of directions, providing a sound platform for the development and analysis of medium and long term energy projections. Key features of the 2011 version of E4cast are outlined below.

E4cast is a dynamic partial equilibrium framework that provides a detailed treatment of the Australian energy sector focusing on domestic energy use and supply.

The Australian energy system is divided into 24 conversion and end use sectors. Fuel coverage comprises 19 primary and secondary fuels. All states and territories (the Australian Capital Territory is included with New South Wales) are

represented. Detailed representation of energy demand is provided. The demand for each fuel is modelled as a

function of income or activity, fuel prices (own and cross) and efficiency improvements. Primary energy consumption is distinguished from final (or end use) energy consumption.

This convention is consistent with the approach used by the International Energy Agency. The current version of E4cast covers the period from 2008–09 to 2034–35. Demand parameters are established econometrically using historical Australian energy data. Business activity is generally represented by gross state product (GSP). Energy intensive industries are modelled explicitly, taking into account large and lumpy capacity

expansions. The industries modelled in this way are: Aluminium; Other basic nonferrous metals (mainly alumina); and Iron and steel. The electricity generation module includes 17 generation technologies. Investment plans in the power

generation sector are forward looking, taking into account current and likely future conditions affecting prices and costs of production.

Key policy measures modelled explicitly are: The introduction of carbon pricing; The Australian Government’s Renewable Energy Target; The New South Wales Government’s Greenhouse Gas Reduction Scheme; The Queensland Government’s Gas Scheme; and The Victorian Government Renewable Energy Target. All fuel quantities are in petajoules. Supply of gas is modelled at the state level. All prices in the model are real, in constant dollars of the base year, and are expressed in dollars

per gigajoule. The base year is 2008–09.

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The model includes 19 energy sources, five conversion sectors, 19 end use sectors and seven regions (Table 1 and Table 2). The demand functions for each of the main types of fuel (such as electricity, gas, coal and petroleum products) have been estimated econometrically and incorporate own price, cross price, income or activity, and technical change effects.Table 1: Fuel coverage in E4cast

Black coalBrown coalCoal by-products - coke oven gas - blast furnace gasCokeNatural gasCoal seam gasOil (crude oil and condensate)Liquefied petroleum gas (LPG)Other petroleum productsElectricitySolar (solar hot water)Solar electricity (solar photovoltaic and solar thermal)Biomass (bagasse, wood and wood waste)Biogas (sewage and landfill gas)HydroelectricityWind energyGeothermal energyOcean energy

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Table 2: Industry coverage of E4cast

Sectors/sub-sectors ANZSIC code

Conversion

Coke oven operations 2714Blast furnace operations 2715Petroleum refining 2510, 2512-2515Petrochemicals naElectricity generation 361End use

Agriculture Division AMining Division BManufacturing and construction Division C

Wood, paper and printing 23-24Basic chemicals 2520-2599Nonmetallic mineral products 26Iron and steel (excludes coke ovens and blast furnaces)

2700-2713, 2716-2719

Basic nonferrous metals 272-273Aluminium smelting 2722Other basic nonferrous metals 2720-2721, 2723-2729

Other manufacturing and construction naTransport Division I (excludes sectors 66 and 67)

Road transport 61Passenger motor vehicles naOther road transport na

Railway transport 62Water transport 63

Domestic water transport 6301International water transport 6302

Air transport 64Domestic air transport naInternational air transport na

Pipeline transport 6501Commercial and services Sectors 37, 66 and 67; Divisions F, G, H, J, K, L,

M, N, O, P and QResidential na

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In E4cast, prices for energy sources used in electricity generation are determined within the model based on demand and supply factors, with the exception of oil and coal where prices are determined on the world market. In some simulations, exogenous gas prices have been used. The direction of interstate trade in gas and electricity is determined endogenously in E4cast, accounting for variation in regional prices, transmission costs and capacities. In E4cast, upper limits on interstate flows of electricity and gas are imposed over the medium term to reflect existing constraints and known expansions that are at an advanced stage of development. Beyond the medium term, it is assumed that any interstate imbalances in gas supply and demand will be anticipated, resulting in infrastructure investment in gas pipelines and electricity interconnector capacity sufficient to meet trade requirements.For internationally traded energy commodities, crude oil, LNG and black coal of export quality, production is exogenous to the model and is drawn from BREE’s (previously ABARES’) commodity forecasting capability. Although Australia is a significant producer of uranium oxide, it is not included in the projections as it is not consumed in Australia and, therefore, does not affect the domestic energy balance. A detailed assessment of Australia’s uranium resources is provided in the Australian Energy Resource Assessment (Geoscience Australia and ABARE 2010).

E4cast base year dataThe base year (2008–09) data in the model are drawn from ABARES’ Australian Energy Statistics (ABARE–BRS 2010). These statistics are largely derived from ABARES’ former fuel and electricity survey (FES). The 2008–09 data, as reported in the projections report, and the published data (ABARE–BRS 2010) may be classified differently. As a result, there may be differences in the figures published. A brief description of the survey and ABARES’ energy balance data is provided in Box 3.From 2010, National Greenhouse and Energy Reporting (NGER) data, sourced from the Australian Government Department of Climate Change and Energy Efficiency, has been adopted as the main energy consumption data source for the Australian Energy Statistics. With the introduction of NGER, survey year 2008–09 became the final year that the FES was conducted. Australian energy statistics using NGER data will be used in the next set of energy projections.

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Box 3: Australian energy statisticsThe Australian energy statistics for 2008–09 are based on ABARES’ fuel and electricity survey (FES), which was a nationwide survey of around 1400 large energy users and producers. The energy users surveyed accounted for around 60 per cent of total Australian energy consumption. Each year, in around October/November, respondents were sent paper-based surveys, requesting information on the quantity of fuels they produced and consumed as well as the electricity they generated. These detailed energy statistics were integrated and reconciled with other databases and information sources. Supplementary data were also collected from various sources, including:

Australian Bureau of Statistics’ international trade data; ABARES’ farm surveys database for the broadacre and dairy farm sectors; Department of Resources, Energy and Tourism’s Australian Petroleum Statistics; Energy Supply Association of Australia; Geoscience Australia; state government departments; and Australian Customs and Border Protection Service.

The detailed FES data on energy consumption provides a platform for estimating energy consumption by region, industry and energy source. The consumption data are reconciled with readily available production statistics to provide a national energy balance.

Key assumptionsThere are a number of economic drivers that will shape the Australian energy sector over the next two decades. These include:Population growth;Economic growth;Energy prices;Electricity generation technologies;End use energy technologies; andGovernment policies.The assumptions relating to these key drivers are presented below.

Population growthPopulation growth affects the size and pattern of energy demand. Projections for Australian population is drawn from the Australian Treasury carbon price modelling and presented in Table 3.Table 3: Australian population assumptions

year populationmillion

2009 21.972020 25.832035 31.19

Source: Treasury (2011)

Economic growthThe energy projections are highly sensitive to underlying assumptions about GDP growth—the main driver of energy demand. Energy demand for each sector within E4cast is primarily determined by the value of the activity variable used and the price

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of fuel in each sector’s fuel demand equation. The activity variable used for all non energy-intensive sectors is gross state product (GSP), which represents income or business activity at the state level. However, for energy intensive industries (aluminium, other basic nonferrous metals, and iron and steel manufacturing) projected industry output is considered as a more relevant indicator of activity than GSP because of the lumpy nature of investment.The GDP and GSP assumptions (Table 4) are drawn from the assumptions used by the Australian Treasury carbon price modelling (Treasury 2011). In 2008–09, Australia’s real GDP increased by 1.4 per cent, following growth of 3.8 per cent in 2007–08. Over the projection period, Australia’s real GDP is expected to grow at an average annual growth rate of 2.8 per cent. A moderation in Australia’s population and labour supply growth will contribute to a gradual reduction in GDP growth in the latter part of the projection period.Queensland and Western Australia are expected to have the highest GSP growth rates over the period to 2034–35, reflecting to a large extent their substantial minerals and energy resource base, relatively high degree of export orientation, and higher relative population growth rates. Table 4: Australian economic growth, by region

Average annual growth 2008–09 to 2034–35 %

New South Wales (and ACT) 2.5Victoria 2.6Queensland 2.9South Australia 2.0Western Australia 3.7Tasmania 1.7Northern Territory 2.5Australia 2.8

Sources: BREE assumptions based on Treasury (2011).

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Real energy pricesEnergy prices affect the demand for, and supply of, energy. The long term energy price assumptions of BREE incorporated in E4cast are presented in Figure E. Long-term energy price profiles will hinge on a number of factors, including demand, investment in new supply capacity, costs of production, and technology. Although the long-run price paths follow smooth trends, in reality, prices are likely to fluctuate in response to short-term market developments.Figure E: Index of world real energy prices, 2008–09 dollars

Sources: BREE assumptions

CoalIn early 2011, coal prices for both thermal and metallurgical coal increased significantly following heavy rain and flooding in Queensland. In the medium term, thermal coal prices are expected to remain significantly above the long term average of the past two decades, although decline in real terms relative to 2010–11. This reflects rising supply costs in China, the world’s largest producer of thermal coal, and also in Australia and Indonesia, the largest exporters, as they develop coal deposits that are deeper underground and/or further away from existing infrastructure. Beyond the medium term, global thermal coal prices are expected to stabilise above the long-term historical average. The higher costs associated with developing new mines and infrastructure is expected to be offset to some extent by the adoption of more advanced technology.

OilIn 2010, oil prices in WTI terms averaged around US$79 a barrel. World oil prices are projected to remain around real US$90–95 a barrel over the medium term, as oil

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demand increases in line with assumed stronger economic growth. The availability of spare production capacity and stocks in OPEC are expected to limit significant increases in oil prices over the medium term.The long-term prospect for oil prices is much less certain. Key factors that are expected to drive long-term oil prices are the cost of developing remaining oil reserves, the volume and timing of investment in production and refining capacity, and technological development in relation to alternative liquid fuels. The estimated capital and production costs for conventional oil sources have increased in recent years because of rising materials, equipment and labour costs. While a rise in the marginal cost of oil production is expected over time, technological developments associated with non-conventional liquids, such as gas-to-liquids and second generation biofuels, have the potential to play a major role in anchoring oil prices below what would have been the case without these new technologies. However, it is not expected that these technologies will be developed in Australia. The assumed development and entry of these technologies underpins the long-term price assumptions used in this report.

LNGIn the long term, international LNG prices are assumed to follow a similar trajectory to oil prices, reflecting an assumed continuation of the established relationship between oil prices and long-term gas supply contracts through indexation in the Asia Pacific market, and substitution possibilities in electricity generation and end use sectors. While in recent years gas prices have decoupled from oil prices in some markets (reflecting relatively abundant supplies of unconventional gas in North America and increased availability of spot supplies of cheaper LNG in Europe and the Asia Pacific), there is considerable uncertainty about whether this will also apply to the Asia Pacific market. Indexation is likely to remain the dominant pricing mechanism in the Asia Pacific region, unless there is a significant convergence of the Atlantic and Pacific markets through LNG exports from North America to the Asian region.Domestic prices for coal and gas are drawn from ABARES’/BREE’s assumptions.

Electricity generation technologiesAustralia has access to a range of electricity generation technologies. This is likely to increase over time as new technologies are developed and the costs of some technologies fall. While a range of factors will affect which technologies are used, the relative cost is the most important.The Electric Power Research Institute (EPRI 2009) assessed the status of different electricity technologies in 2015 and 2030. The EPRI technology status data enables the comparison of technologies at varying levels of maturity. However, market and system factors will have a significant impact on the technology mix and electricity prices in an energy system. For this reason, electricity market prices cannot be extrapolated from technology cost analysis. Market modelling is required to project potential electricity prices arising from market and investment outcomes. The levelised cost of technologies represents the revenue per unit of electricity generated

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that must be met to break even over the lifetime of a plant.While EPRI cost estimates were developed on the basis of generic plant configurations rather than on detailed plant designs or equipment and material costs—and are subject to uncertainty in relation to a number of factors—they provide valuable and comprehensive information on the relative costs of different electricity generation technologies in an Australian setting, and how these costs might change over time. Importantly, these costs do not include the effects of any carbon price.The relative costs of different technologies are more important than the absolute magnitude of these costs in determining their relative prospects in the electricity generation sector (merit order). The EPRI results show that, in the medium term, coal and gas without CCS will remain among the lowest technology cost options. Of the renewable energy technologies, wind is one of the lowest cost options. Despite a significant decline in the costs of solar technologies expected in the future, the costs of these technologies are expected to remain relatively high over the coming years. The costs of geothermal electricity are shown to be competitive with those of other baseload technologies, although this technology is still at a demonstration stage.For technologies that are not covered in detail by the EPRI data (ocean energy, bioenergy and the retrofitting of existing fossil-fuel plants with CCS technology), BREE has drawn on a range of other sources (IEA 2008; Specker, Phillips and Dillon 2009; National Energy Technology Laboratory 2009). There is considerable uncertainty regarding the absolute costs of these technologies. Further, not all units of existing power plants are amenable to be retrofitted with CCS technology. Key considerations include the unit’s age and size, available space and access to geological storage.In 2011, the Australian Treasury modified EPRI technology costs to account for exchange rate movements since the 2009 EPRI report. In E4cast, the assumptions regarding the cost of electricity generation technologies in Australia are drawn from the modified EPRI technology costs, and are presented in Figure F. In addition, there are exogenous and endogenous factors that can contribute to changing electricity generation costs over time. These include carbon prices, and thermal efficiencies, including assumptions regarding future technological changes and learning rates.

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Figure F: Index of real levelised cost of electricity generation technologies excluding carbon costs

Sources: BREE calculations based on modified EPRI technology costs

End use energy technologiesEnd use energy technologies affect the efficiency of energy use. These technologies are assumed to become more energy efficient over time through technological improvements. Further, the NSEE can also be expected to address non-market barriers to the uptake of energy efficiency opportunities. The rate of end use energy efficiency improvement is assumed to be 0.5 per cent a year over the projection period for most fuels in non-energy intensive end-use sectors. For energy intensive industries, the low capital stock turnover relative to other sectors is assumed to result in a lower rate of energy efficiency improvement of 0.2 per cent a year.

Government policiesIn this set of projections, the following key policies have been modelled explicitly in E4cast:

The clean energy future carbon price; The Australian Government Renewable Energy Target (RET); The New South Wales Greenhouse Gas Reduction Scheme; The Queensland Gas Scheme; and The Victorian Government Renewable Energy Target.

Emissions Reduction TargetThe carbon price assumptions are set in reference to the Treasury modelling, Strong growth, low pollution: modelling a carbon price released in 2011. In 2012–13, a

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nominal carbon price of $23 a tonne is used, growing at 5 per cent a year. From 2015, the carbon price will transition to an emissions trading scheme, open to the international market. The price trajectory for the scheme is estimated to start at $29 a tonne in 2016, in nominal terms, growing at a rate of 5 per cent a year. In practice, the carbon price path post 2015 will be determined by the world’s carbon market, within which Australia will trade permits. The projection path for the carbon price assumptions (in real terms) is shown in Table 5.

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Table 5: Carbon price assumptions, real, 2009–10 dollars

2012–13 21.052019–20 29.402029–30 52.602034–35 69.90

Source: BREE calculations based on Treasury (2011)

Renewable Energy Target (RET)The Renewable Energy Target (RET) requires 45 000 gigawatt hours of electricity be sourced from renewable energy sources by 2020. Legislation to implement the Renewable Energy Target (RET) scheme was passed by the Parliament on 24 June 2010. In January 2011, the RET was split into the voluntary Small-scale Renewable Energy Scheme (SRES) and the mandatory Large-scale Renewable Energy Target (LRET). The LRET consists of legislated annual targets for the amount of electricity to be sourced from renewable sources to ensure 41 000 gigawatt hours is achieved by 2020. Small businesses and households are anticipated to provide more than the additional 4000 gigawatt hours through the SRES. The Office of the Renewable Energy Regulator (ORER) oversees the RET. The LRET targets are presented in Table 6 (ORER 2011).Table 6: LRET renewable electricity generation target (excluding existing renewable generation)

Year ending TWh2011 10.42012 16.32013 18.22014 16.12015 18.02016 20.62017 25.22018 29.82019 34.42020 and onwards 41.0

Source: ORER (2011)

In E4cast, this policy intervention is modelled as a constraint on electricity generation—renewable energy must be greater than or equal to the interim target in any given year. In the model, the LRET target is met by a subsidy to renewables that is funded by a tax on non-renewable generators. This is endogenously modelled so that total renewable generation meets the target.

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New South Wales Greenhouse Gas Reduction SchemeThe New South Wales Greenhouse Gas Reduction Scheme requires electricity retailers and other liable parties to meet mandatory greenhouse gas reduction benchmarks. The scheme is implemented in the model by requiring total emissions from state electricity generation to be less than or equal to the product of targeted per person emissions and state population. In effect, the price of carbon is internalised in state electricity supply decisions. However, it is assumed that the scheme will cease in 2012–13 upon the implementation of carbon pricing.

Queensland Gas SchemeThe Queensland Gas Scheme requires electricity retailers and other liable parties to source at least 13 per cent of their electricity from natural gas-fired generation. On 1 July 2008, the requirement was increased to 15 per cent in 2010 and up to 18 per cent thereafter. The scheme has been approximated in the model by requiring the share of natural gas-fired electricity generation in Queensland to be greater than or equal to 13 per cent in 2009 and 15 per cent in 2010. In effect, producers of gas-fired electricity receive a subsidy which is funded by all other generators. In the model, this scheme is terminated from 2012–13 with the implementation of carbon pricing.

Victorian Renewable Energy TargetThe Victorian Government’s Renewable Energy Target (VRET), which requires that 10 per cent of total electricity generation be sourced from renewable energy sources by 2016, was implemented in the model from 2007–08 to 2009–10 before the legislated transition in 2010 into the RET. In the model, generators of renewable electricity under the RET receive a subsidy which is funded by all other non-renewable sources of power.

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4 Energy ConsumptionThis chapter presents the outlook for Australian energy consumption over the period to 2034–35 under the assumptions and policy settings outlined in chapter 3. The projections cover primary energy consumption by energy type and sector; final energy consumption by energy type and end-use activity; and electricity generation. While the discussion focuses on Australian trends, key trends at a state and territory level are also highlighted.

Total primary energy consumptionGrowth in total primary energy consumption has demonstrated a downward trend since the 1960s as a result of changes to Australia’s economic structure, and the effect of technological developments and government policies on energy efficiency in energy conversion and end-use. Growth in Australia’s total primary energy consumption declined from 5 per cent a year in the 1960s to 2.3 per cent a year in the 1990s.This trend is expected to continue, with growth in energy consumption moderating over the projection period. Australia’s primary energy consumption is projected to increase at an average annual rate of 1 per cent from 5784 petajoules in 2008–09 to 7481 petajoules in 2034–35 (Table 7). The moderate growth in energy consumption is largely driven by the implementation of new policies. Between 2008–09 and 2034–35, the Australian Government will introduce a number of measures, including the RET and carbon pricing, that are expected to increase energy prices and dampen the demand for energy. This will be partly offset by assumed strong economic growth over the projection period.The largest decline in consumption growth is expected to occur in the last decade of the projection period. This reflects the assumption of increasing carbon prices.

Aggregate intensity trendsAustralia’s aggregate energy intensity (measured as total domestic energy consumption per dollar of GDP) declined at an average rate of 1.2 per cent a year between 1989–90 and 2007–08 (Petchey 2010). Over the period to 2034–35, Australia’s aggregate energy intensity is projected to decline by around 1.7 per cent a year. This indicates a considerable shift in Australia’s economic structure over this period. The major driver of this trend is strong growth in less energy-intensive sectors, such as the commercial and services sector relative to energy-intensive sectors, such as manufacturing. Improved efficiency through technological development and fuel switching will also contribute to this trend.

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Primary energy consumption, by energy typeOver the projection period, the relative share of each energy type is expected to change significantly in response to the changing policy environment.Non-renewable energy accounted for around 95 per cent of the primary energy consumed in Australia in 2008–09. Of this, coal accounted for 39 per cent of the primary energy consumed; oil 35 per cent; and gas (including conventional and coal seam gas) 22 per cent. Over the projection period, the share of coal in total primary energy consumption is projected to decline to 21 per cent (Table 7). By contrast, the share of gas is projected to increase to 35 per cent.Gas is expected to exhibit the fastest growth among non-renewable energy sources over the projection period, increasing by around 3 per cent a year to 2611 petajoules in 2034–35 (Table 7). This growth is driven by increased use in electricity generation and in the mining sector, and reflects the shift to less carbon-intensive energy sources. The majority of this growth is at the expense of coal. The growth in gas consumption is expected to be greater in the period to 2020, after which the uptake of technologies that are less carbon-intensive is expected to accelerate.

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Table 7: Primary energy consumption, by energy type

Level Share

Average annual growth

2008–09 to

2008–09 2019–20 2034–35 2008–09 2034–35 2034–35

Energy type PJ PJ PJ % % %Non-renewables 5505 6431 6822 95 91 0.8Coal 2240 2106 1541 39 21 -1.4

black coal 1593 1460 1260 28 17 -0.9 brown coal 647 647 281 11 4 -3.2Oil 2021 2441 2670 35 36 1.1

Gas 1244 1884 2611 22 35 2.9

Renewables 279 548 660 5 9 3.4Hydro 45 47 47 1 1 0.2

Wind 14 131 175 <1 2 10.1

Bioenergy 211 329 365 4 5 2.1

Solar 9 22 26 <1 <1 4.1

Geothermal 0 18 48 0 1 -Total   5784 6979 7481 100 100 1.0Numbers in the table may not add up to their totals due to rounding.The figures for 2008–09 presented in this table may not be identical to actual historical data published in ABARES’ Australian Energy Statistics. This is a reflection of the different classification systems.

In 2008–09, around 5 per cent of Australia’s primary energy consumption was sourced from renewable energy. The share of renewable energy is projected to increase by 3.4 per cent a year following the introduction of the RET to account for around 9 per cent of primary energy consumption in 2034–35 (Table 7). The bulk of this increase is expected to come from bioenergy (mainly biomass) and wind energy. Growth is also expected to be strong in geothermal and solar energy, albeit from a lower base.

Primary energy consumption, by state and territoryPrimary energy consumption is projected to increase in all states and the Northern Territory over the period to 2034–35. However, there is variation in the rates of growth reflecting economic growth assumptions, energy resource endowments, economic structure and state-specific policy settings (Table 8).The highest growth in primary energy consumption is projected to occur in Western Australia, the Northern Territory and Queensland. This is underpinned by higher

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assumed economic growth compared with the other states, the large contribution of the mining sector to economic output and the high degree of export orientation. The strongest growth in primary energy consumption is expected to occur in Western Australia, increasing at a rate of 2 per cent a year, with its share of total primary energy consumption increasing from 16 per cent in 2008–09 to 21 per cent in 2034–35 (Table 8).Growth in energy consumption is projected to be more moderate in South Australia and New South Wales driven by assumed lower economic growth. Despite the slower growth, New South Wales is projected to remain the largest consumer of energy. Its energy consumption is projected to increase at around 0.6 per cent a year and increase from 1569 petajoules in 2008–09 to 1851 petajoules in 2034–35 (Table 8).

Table 8: Primary energy consumption, by state and territory

Level Share

Average annual growth

2008–09 to

2008–09 2019–20 2034–35 2008–09 2034–35 2034–35

State/territory PJ PJ PJ % % %New South Walesa 1569 1758 1851 27 25 0.6Victoria 1388 1608 1491 24 20 0.3Queensland 1291 1626 1770 22 24 1.2South Australia 344 394 420 6 6 0.8Western Australia 953 1323 1607 16 21 2.0Tasmania 113 120 135 2 2 0.7Northern Territory 127 150 207 2 3 1.9Australia 5784 6979 7481 100 100 1.0a includes the Australian Capital Territory. Numbers in the table may not add up to their totals due to rounding.The figures for 2008–09 presented in this table may not be identical to actual historical data published in ABARES’ Australian Energy Statistics. This is a reflection of the different classification systems.

Victoria is projected to exhibit the lowest growth in primary energy consumption. The effect of government policies on brown coal-fired electricity generation and other emission-intensive industries such as petroleum refining and chemicals will contribute to the moderate growth. Energy consumption in Victoria is projected to increase by 0.3 per cent a year from 1388 petajoules in 2008–09 to 1491 petajoules in 2034–35 (Table 8).

Primary energy consumption, by sectorElectricity generation, transportation and manufacturing accounted for 89 per cent of Australia’s total primary energy consumption in 2008–09. These sectors are projected

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to account for 81 per cent of projected primary energy consumption in 2034–35 (Table 9).The electricity generation sector accounted for the largest share (44 per cent) of primary energy consumption in 2008–09. Total primary energy consumption in electricity generation is projected to increase from 2557 petajoules in 2008–09 to 2803 petajoules in 2034–35 (Table 9). The combined effect of the RET and the implementation of carbon pricing on the relative competitiveness of generation technologies is expected to encourage a change in the energy mix, with a gradual shift away from coal to gas and renewable energy.In 2008–09, the transport sector (excluding electricity used in rail transport) accounted for one-quarter of primary energy consumption, with a heavy reliance on oil and petroleum products. Consumption in the transportation sector is projected to grow steadily over the projection period, increasing at an average annual rate of 1.2 per cent. Growth in transport energy consumption will be offset by improved end-use efficiency in the sector and high fuel prices such that the share of primary energy consumption is estimated to remain relatively constant at around 26 per cent in 2035 (Table 9).

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Table 9: Primary energy consumption, by sector

Level Share

Average annual growth

2008–09 to

2008–09 2019–20 2034–35 2008–09 2034–35 2034–35

Sector PJ PJ PJ % % %Electricity generation 2557 2827 2803 44 37 0.4

Agriculture 90 124 143 2 2 1.8Mining 235 633 885 4 12 5.2Manufacturing 1164 1277 1312 20 18 0.5Transport 1437 1769 1960 25 26 1.2Commercial & residential

302 349 379 5 5 0.9

Total 5784 6979 7481 100 100 1.0

Numbers in the table may not add up to their totals due to rounding.The figures for 2008–09 presented in this table may not be identical to actual historical data published in ABARES’ Australian Energy Statistics. This is a reflection of the different classification systems.

The manufacturing sector is the third largest user of primary energy in Australia, accounting for 20 per cent of the total in 2008–09. This sector includes a number of relatively energy-intensive sub-sectors such as petroleum refining, iron and steel, aluminium smelting and minerals processing. While primary energy consumption in the sector is projected to increase by 0.5 per cent a year over the projection period, the relative share of the sector is expected to decline to 18 per cent (Table 9). This reflects an ongoing structural shift away from energy-intensive manufacturing, encouraged further by the implementation of carbon pricing.Despite accounting for a relatively small proportion of total primary energy consumption (4 per cent in 2008–09), the mining sector is projected to exhibit the fastest energy consumption growth to 2034–35. This growth will be supported by a large number of energy and mineral projects scheduled for development over the projection period. The considerable volume of investment is a major driver of the expected expansion in the mining sector and the associated growth in primary energy consumption. In 2034–35, the sector is projected to account for 12 per cent of Australian primary energy consumption (Table 9).

Electricity generationGross electricity generation in Australia is projected to increase at an average annual rate of 1.4 per cent from 245 terawatt hours (883 petajoules) in 2008–09 to 348 terawatt hours (1253 petajoules) in 2034–35 (Table 10).Reflecting differences in the availability of technologies and primary energy inputs, primary input prices, capital costs and interregional transmission capacity, the projected growth in electricity generation varies across the states and the Northern Territory. For states that are part of the integrated National Electricity Market (New South Wales and the Australian Capital Territory, Queensland, Victoria, South Australia and Tasmania), the figures in Table 10 reflect electricity consumed and market

49

determined electricity flows across regions.

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New South Wales is likely to remain the largest producer of electricity, accounting for 31 per cent of total generation in 2034–35 and adding 35 terawatt hours to annual generation in 2034–35. South Australia is a small electricity generator in absolute terms. However, it is expected to exhibit the strongest growth in electricity generation, increasing at 2.5 per cent a year over the projection period (Table 10). This growth is being driven by the development of renewable energy generation in the state, which is projected to grow at an average annual rate of 7.4 per cent. Strong growth is also expected in gas-fired electricity generation, increasing at a projected rate of 2.5 per cent a year.In Western Australia, electricity generation is projected to increase by 64 per cent from 28 terawatt hours in 2008–09 to 46 terawatt hours in 2034–35 (Table 10). Much of this expansion will come from growth in gas-fired electricity generation, which is projected to increase at an annual average rate of 2.5 per cent. Gas will account for 72 per cent of the projected expansion in Western Australia’s electricity generation between 2008–09 and 2034–35.By contrast, electricity generation in Victoria is projected to grow at a rate much lower than the national average. Electricity generation in Victoria is largely based on brown coal. The competitiveness of this energy source relative to other technologies is expected to be diminished following the introduction of carbon pricing. Unless Victoria invests in the development of its own low emission electricity generation capacity, it is projected to become more dependent on the importation of electricity from other states.Table 10: Electricity generation, by state and territory

Level Share

Averageannualgrowth

2008–09 to

2008–09 2019–20 2034–35 2008–09 2034–35 2034–35

State/territory TWh TWh TWh % % %New South Walesa 75 96 110 30 31 1.5Victoria 59 77 69 24 20 0.6Queensland 56 65 76 23 22 1.2South Australia 14 20 27 6 8 2.5Western Australia 28 35 46 12 13 1.9Tasmania 9 13 15 4 4 1.9Northern Territory 4 4 5 1 2 1.6

Australia 245 310 348 100 100 1.4a Includes the Australian Capital Territory.Numbers in the table may not add up to their totals due to rounding.The figures for 2008–09 presented in this table may not be identical to actual historical data published in ABARES’ Australian Energy Statistics. This is a reflection of the different classification systems.

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Under a policy setting that includes the RET and the introduction of carbon pricing, the relative shares of non-renewable and renewable energy in total electricity generation are expected to change considerably over the projection period. In 2008–09, 93 per cent of electricity was generated from non-renewable sources (coal, oil and gas) with the balance coming from renewable energy sources (Table 11). The incentives provided to generators under the RET are expected to be the major driver of the accelerated uptake of renewable technologies in the period to 2020. After 2019–20, renewable electricity generation is projected to continue to increase, albeit at a slower rate. Within non-renewable energy, the key change over the projection period will be the expected shift from coal-fired generation to gas-fired generation. While coal is projected to continue to dominate the energy mix, the introduction of carbon pricing will encourage a switch toward lower-emission energy sources. Black coal-fired generation and brown coal-fired generation are projected to decline by 0.5 per cent a year and 3.7 per cent a year over the projection period, respectively. Reflecting this, the share of coal in the energy mix is projected to decline from 74 per cent in 2008–09 to 38 per cent in 2034–35.While these results imply the partial or full closure of coal-fired capacity over the projection period, there are a number of factors that may reduce the effect of the implementation of carbon pricing on these plants, at least over the medium term. For example, hedging contracts and other financial considerations can be expected to provide some degree of cost insulation to these plants. The longer term role of coal will be heavily dependent on technological developments related to carbon capture and storage (CCS). The timing for deployment of CCS technologies relies on the economic viability of this technology given carbon pricing (see Box 4 for further discussion). In the modelling, the deployment of CCS technologies for new plants will be limited in the short to medium term because of the current relatively high costs compared with other technologies. Nevertheless, some coal-fired electricity generation with CCS may emerge by the end of the projection period, supported the development of subsidised projects.

Table 11: Electricity generation, by energy type a

Level Share

Average annual growth

2008–09 to

2008–09 2019–20 2034–35 2008–09 2034–35 2034–35

Energy type TWh TWh TWh % % %Non-renewables 227 248 265 93 76 0.6Coal 182 178 134 74 38 -1.2

black coal 129 125 114 53 33 -0.5 brown coal 53 53 20 21 6 -3.7

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Level Share

Average annual growth

2008–09 to

2008–09 2019–20 2034–35 2008–09 2034–35 2034–35

Gas 40 64 126 16 36 4.5

Oil 5 5 5 2 2 0.0

Renewables 18 63 84 7 24 6.0Hydro 12 13 13 5 4 0.2

Wind 4 36 49 2 14 10.1

Bioenergy 2 4 4 <1 1 3.5

Solar <1 4 5 <1 1 13.6

Geothermal 0 5 13 0 4 -Total   245 310 348 100 100 1.4

a These figures represent total gross electricity generation output, covering both on-grid and off-grid principal generators, small generators, and non-scheduled generators. Numbers in the table may not add up to their totals due to rounding.The figures for 2008–09 presented in this table may not be identical to actual historical data published in ABARES’ Australian Energy Statistics. This is a reflection of the different classification systems.

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Box 4: Carbon capture and storageCarbon capture and storage (CCS) is one of the key technologies being developed to help reduce global greenhouse gas emissions (GHG) and the only technology available for mitigating carbon dioxide (CO2) emissions from large scale non-renewable energy usage. The underlying concept is for CO2 to be collected from point sources or industries with major CO2 emissions and stored in such a way that it does not enter the atmosphere. The three distinct stages comprising the CCS procedure consist of capture, transportation and long-term storage. Technologies already exist for each of these stages and have been in commercial use for many years. CO2 capture technologies have long been used for high-concentration, high-pressure CO2 sources such as natural gas extraction. CO2 transport has been used for decades as part of enhanced oil recovery techniques. Geologic CO2 storage is being employed at a growing number of sites worldwide. The issue is not whether technologies exist for CCS, but whether the incentives exist for developing them for use on the commercial scale.Many of the proposed CCS technologies are embryonic in nature and have not yet reached a level consistent with long-term, least cost stages of development. This has resulted in a financial gap existing between CCS technologies and current methods of accommodating CO2 emissions. As long as this gap exists, it will slow the widespread adoption of CCS technologies. The uptake of CCS is of particular relevance to Australia given the proportion of electricity generated from coal-fired power plants. Not only does the implementation of CCS require additional capital expenditure, it also imposes additional costs through a loss in thermal efficiency as a greater volume of fuel is used to generate each kilowatt hour of electricity. In order for CCS to be commercially viable it is necessary for the market price of carbon to rise significantly such that it exceeds the cost of the CO2 avoided. Recent estimates put the average cost of CCS to avoid CO2 emissions at around $75 a tonne at 2008 prices (Bukhteeva et al. 2009).

The bulk of the decline in coal-fired electricity generation is expected to be taken up by gas-fired generation, with the share of gas in electricity generation projected to increase from 16 per cent in 2008–09 to 36 per cent in 2034–35 (Table 11). This will be underpinned by the development of new gas-fired electricity generation capacity over the projection period (Map 2). As of October 2011, gas accounted for 37 per cent of advanced electricity generation projects in Australia (Stark et al. 2011).

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Map 2: Advanced electricity generation projects, October 2011

Source: Stark et al. (2011)

Gas-fired generation is based on mature technologies that are more cost competitive compared with renewable energy technologies. Consequently, gas is expected to play a major role in the transition period until lower emission technologies become more cost viable. However, the cost competitiveness of gas-fired generation relies heavily on gas prices. The modelling of gas prices for this set of projections suggests that domestic gas prices are likely to moderately increase over the period to 2034–35.The uptake of gas-fired electricity generation is expected to be substantial in all states. Growth is expected to be particularly strong in New South Wales and Victoria. This will be underpinned by a number of gas-fired generation projects under development or planned. The largest project at an advanced stage of development is the first stage of the Mortlake Power Station Project in Victoria. This project has an announced capacity of 550 megawatts and is scheduled for completion in late 2011 at a capital cost of $735 million (Stark et al. 2011). Electricity generation from gas in Queensland is projected to more than double over the projection period, supported by the development of a number of coal seam gas-fired electricity generation projects. The commissioning of the QSN link and expansion

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of the South West Queensland Pipeline in 2009 have resulted in an interconnected pipeline linking Queensland, Victoria, South Australia, Tasmania and the Australian Capital Territory. This has been driven by the emerging coal seam gas industry in Queensland and is expected to support the uptake of gas-fired generation in the other interconnected regions.In parallel with the increasing share of gas in the energy mix, the use of non-hydro renewable energy is projected to increase significantly between 2008–09 and 2034–35. Wind energy is projected to account for the majority of the increase in generation from renewable energy sources over this period, growing at an average annual rate of 10.1 per cent to 2034–35 (Table 11). Wind energy is projected to account for 14 per cent of electricity generation in 2034–35. Wind energy is a proven and mature technology, and the output of both individual turbines and wind farms has increased considerably over the past five years. Wind energy is relatively cost competitive, notwithstanding site specific factors. The competitiveness of wind energy will be enhanced by a reduction in the cost of turbines and further efficiency gains through turbine technology development (Geoscience Australia and ABARE 2010).Australia has large bioenergy resource potential. Currently, Australia’s bioenergy resources are dominated by bagasse (sugar cane residue), wood waste, and capture of gas from landfill and sewage facilities for generating heat and electricity. In 2008–09, bioenergy accounted for less than 1 per cent of total electricity generation (Table 11). The combination of the RET and the potential commercialisation of second generation technologies using a range of non-edible biomass feedstocks indicate that bioenergy has the potential to make a growing contribution to renewable electricity generation in Australia. However, this growth is likely to be constrained to some extent by competition for inputs used in the production of bioenergy, such as water availability and logistical issues associated with handling, transport and storage. Nonetheless, the use of bioenergy for electricity generation is projected to increase by 3.5 per cent a year over the projection period, but will still account for only 1 per cent of total generation by 2034–35 (Table 11).Australia is a world leader in developing solar technologies; however the uptake has been low because of their relatively high investment cost (Geoscience Australia and ABARE 2010). Electricity generation from solar energy in Australia is largely sourced from photovoltaic (PV) installations. Electricity generation from solar thermal systems are currently limited to small-scale pilot projects. Solar energy is projected to grow at 13.6 per cent a year over the period to 2034–35, but from a very low base (Table 11). The cost of installing solar capacity has generally been declining over time and there is potential for the cost of solar technologies to continue to decline over the projection period given the substantial research and development funds allocated toward these technologies. This will contribute to its competitiveness over the period to 2034–35. In addition, the Australian Government has implemented a number of policies that are expected to increase the uptake of solar technologies, including the Solar Flagships Program and the establishment of the Australian Solar Institute.Australia has large geothermal energy potential. However, these resources are

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currently considered sub-economic because geothermal technologies for electricity generation have not been demonstrated to be commercially viable in Australia. Electricity generation from geothermal energy is currently limited to pilot projects that generate small volumes of electricity. It is important to note that the development of the geothermal industry in Australia is not dependent on a major technological breakthrough; all the technology required already exists. The challenge lies in adapting the technology to make it more commercially viable (Geoscience Australia and ABARE 2010). Given the time expected to achieve commercial viability and the long lead time to bring a new geothermal power plant into operation, geothermal energy is not expected to play a major role in electricity generation over the projection period, although it will grow to 4 per cent of total electricity generation by 2034-35 (Table 11).Hydroelectricity generation is projected to remain broadly unchanged in volume terms over the projection period because of the limited availability of suitable locations for the expansion of capacity and water supply constraints. Over the projection period, most of the expected expansion in capacity is assumed to be associated with the upgrading of existing equipment and small-scale schemes.

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Box 5: Uncertainty surrounding gas prices for electricity generationThere are a range of perspectives on future gas prices in Australia. The modelling undertaken in this report assumes that gas prices are likely to gradually increase over the next two decades as a result of interactions between demand and supply. However, there are a number of factors that could affect the projected price path, including the renegotiation of existing long-term contracts, timeframes for new projects, the pace of development of coal seam gas (CSG), the extent and pace of convergence in gas prices in the eastern gas market and global LNG markets and international developments.The dynamics of the western and eastern gas markets are quite different. As a result, there will be differences in the price paths in these markets over the projection period.In the western gas market, production directed to the domestic market is dominated by only a few suppliers. Other production capacity is limited by reserves or the timing of production is closely linked to LNG projects. Consequently, there can be times when there is a domestic supply shortage and domestic prices are higher than export prices (net of shipping and liquefaction costs) and vice versa. Domestic prices in the western market have increased considerably since early 2007 and are now close to export parity. Tight demand–supply conditions to 2017 are expected to contribute to relatively high domestic gas prices in the western market over this period. Beyond 2017, some production from large LNG projects is planned to be directed to the domestic market, such as Wheatstone and Pluto 2, which will place downward pressure on domestic prices.In the eastern gas market, there are a number of domestic suppliers from both conventional and unconventional sources. Four major LNG projects using CSG are planned to start production in Queensland from 2014. Once operational, these projects have the potential to divert gas from the domestic market, which will support prices increasing towards export parity over the longer term. However, there are a number of factors that may reduce the upward pressure on gas prices. In particular, the gas fields being developed in the eastern market are onshore and are expected to be developed rapidly over the medium to longer term. Relatively low barriers to entry in the eastern market and the large number of suppliers will ensure greater competition within the domestic market and exert some downward pressure on prices. In addition, the extensive gas transmission network linking basins and markets on the east coast should ensure the efficient transfer of supply from lower to higher demand segments of the eastern market, which is expected to further slow LNG demand driven price rises.Given the uncertainty surrounding future gas prices, extra analysis was conducted to assess the effect of a change to the assumptions used on the electricity generation mix. In this analysis, gas prices were increased by around 40 per cent (in the latter part of the projection period) relative to base case assumptions. Under higher assumed gas prices, total electricity generation is projected to grow at a slower rate of 1.3 per cent a year to 340 terawatt hours in 2034–35 (Table 12). The share of gas is projected to be lower under this scenario, at 22 percent, with a relatively smaller fall in the share of coal relative to the main scenario in Table 11. The share of renewables rises marginally to 25 per cent (Table 12).

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Table 12: Electricity generation, with alternative gas price assumptions, by energy source

Level ShareAverageannual

growthEnergy Source

2008–09TWh

2019–20TWh

2034–35TWh

2008–09%

2034–35%

2008–09 to2034–35 %

Non-renewables

227 225 256 93 75 0.5

Coal 182 181 176 74 52 -0.1 black coal 129 129 137 53 40 0.2 brown coal 53 53 40 21 12 -1.1Gas 40 39 74 16 22 2.4Oil 5 5 5 2 2 0.0Renewables 18 63 84 7 25 6.0Hydro 12 13 13 5 4 0.2Wind 4 37 49 2 14 10.1Bioenergy 2 4 4 1 1 3.3Solar <1 4 4 <1 1 13.5Geothermal 0 5 14 0 4 -Total 245 288 340 100 100 1.3Numbers in the table may not add up to their totals due to rounding.The figures for 2008–09 presented in this table may not be identical to actual historical data published in ABARES’ Australian Energy Statistics. This is a reflection of the different classification systems.

Final energy consumption, by energy typeTotal final energy consumption, the amount of energy used in end-use applications, is projected to increase from 3645 petajoules in 2008–09 to 4978 petajoules in 2034–35, a rise of 37 per cent over the projection period and an average annual rate of increase of 1.2 per cent (Table 13). Electricity and renewable energy are projected to continue to grow strongly to meet energy demand in end-use sectors over the projection period. This will contribute to the declining relative share of petroleum products in final energy consumption by 2034–35. Nonetheless, in absolute terms, the consumption of petroleum products is projected to increase by 36 per cent between 2008–09 and 2034–35.

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Table 13: Final energy consumption, by energy type

Level Share

Average annualgrowth

2008–09 to

2008–09 2019–20 2034–35 2008–09 2034–35 2034–35

Energy type PJ PJ PJ % % %Coal 162 151 147 4 3 -0.4

Petroleum products

1738 2143 2359 48 47 1.2

Gas 749 909 1025 21 21 1.2

Renewables 171 232 265 5 5 1.7Electricity 826 1042 1182 23 24 1.4

Total 3645 4478 4978 100 100 1.2Numbers in the table may not add up to their totals due to rounding.The figures for 2008–09 presented in this table may not be identical to actual historical data published in ABARES’ Australian Energy Statistics. This is a reflection of the different classification systems.

Final energy consumption, by sectorThe transport and manufacturing sectors are the major drivers of Australia’s final energy consumption, accounting for 40 per cent and 32 per cent of final energy consumption in 2008–09, respectively (Table 14). Growth in final energy consumption will tend to be greater in less energy intensive sectors such as the commercial and residential sectors. This is the continuation of a long term trend in the Australian economy that is expected to be accelerated by the introduction of carbon pricing.

TransportFinal energy consumption in the transportation sector is projected to grow at an average rate of 1.2 per cent a year between 2008–09 and 2034–35 (Table 14). While the sector is expected to account for 40 per cent of the increase in final energy consumption over the projection period, the relative share of transportation in total final energy consumption is projected to remain unchanged in 2034–35. These projections reinforce the downward trend in road transport fuel consumption over the past 30 years. Within the transport sector, the road transport segment is the largest contributor to final energy consumption. In 2008–09, road transport accounted for more than three-quarters of the energy used in the sector, with the bulk of this coming from passenger transport. Energy use in the road transport sector is projected to increase by 1.2 per cent a year to 2034–35, driven by passenger and rail transportation. Energy use in the air transport sector (domestic and international) is projected to

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grow at 2.2 per cent a year to 406 petajoules in 2034–35. This reflects rapid growth in passenger demand for air transport. As a result, the share of air transport in the transportation sector is projected to increase from 16 per cent in 2008–09 to 21 per cent in 2034–35.The transport sector is highly dependent on oil-based petroleum products and this trend is expected to continue over the projection period. There are a range of alternative low-carbon fuels that have the potential to complement or replace conventional oil in the longer term such as coal-to-liquids, gas-to-liquids, and second generation biofuels. However, significant further research, development and demonstration would be required to allow these fuels to make a substantial contribution to meeting transport energy needs. Similarly, electric vehicles and hybrid electric cars are not expected to make a significant contribution to the road transport fuel mix by 2034–35 (Box 6).

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Table 14: Final energy consumption, by sector

Level ShareAverage annual

growth2008–09 to

2008–09 2019–20 2034–35 2008–09 2034–35 2034–35

Sector PJ PJ PJ % % %Agriculture 96 131 150 3 3 1.7Mining 231 345 480 6 10 2.9Manufacturing 1153 1304 1333 32 27 0.6Transport 1445 1780 1972 40 40 1.2Commercial & residential

720 918 1043 20 21 1.4

Total 3645 4478 4978 100 100 1.2The figures for 2008–09 presented in this table may not be identical to actual historical data published in ABARES’ Australian Energy Statistics. This is due to different classification systems.

Box 6: Energy use in the Australian transport sectorThe transport sector is the largest final energy consumer in Australia, accounting for 40 per cent of final energy consumption. Over the period to 2034–35, consumption in this sector is projected to grow at an average annual rate of 1.2 per cent reflecting assumed on-going economic and population growth that will stimulate demand for freight transport and increase rates of vehicle ownership. Given the demand for oil and petroleum products for transport fuels is relatively unresponsive to changes in prices, there is not expected to be a dramatic change from the transport modes, consumption patterns and fuels currently used. However, rising fuel costs and increasing discernment in the market may result in small changes to transport energy consumption, including improved energy efficiency, an increased uptake of alternative fuels and the development of alternative transport modes. In the short term, the major driver of changes in consumption is likely to be energy efficiency, which will be achieved through tightening fuel efficiency standards, tyre efficiency and eco driving. Commercial incentives faced by freight operators may encourage significantly more efficiency investment, although uncertainty about future oil prices and high investment costs could limit the uptake of available opportunities. Efficiency gains are likely to drive small changes within transport energy consumption, but an overall increase in consumption may absorb these changes. The environmental performance of the sector in the long term will be influenced by the small, but growing role of alternative fuels and other technological breakthroughs. As barriers to use are reduced and technology improvements continue, alternative fuels may have an increasing market presence in Australia. Currently, the most viable alternative fuels are biofuels and LPG, although the usage rates are low, with biofuels accounting for 0.5 per cent of the Australian transport fuel supply in 2007–08. With policy assistance, electric vehicles may become commercially viable within the projection period, although at low levels of market penetration. Future changes in the quantum and patterns of transport fuel consumption will be influenced by the policy environment. The introduction of carbon pricing, fuel excise arrangements, targeted alternative fuels strategies or other efficiency measures could all affect future demand.

ManufacturingThe manufacturing sector is the second largest energy end user in Australia, with minerals processing—iron and steel making, alumina refining and aluminium smelting—contributing to the relatively high energy intensity of the sector. The manufacturing sector has grown relatively slowly over the past decade so that the share of the sector as a proportion of total final energy consumption has remained around 32 per cent (Table 14). Over the period to 2034–35, the sector is projected to grow at 0.6 per cent

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a year, supported by growth in the economy and ongoing global demand for energy intensive, resource based output. However, the growth in the sector is well below the growth in final energy consumption projected across all sectors (1.2 per cent). This reflects the continuation of a long-term structural shift toward the commercial and services sector in the Australian economy. This is further reinforced by the introduction of carbon pricing as the rising cost of energy provides incentives to reduce the energy intensity of the economy. As a result, the share of manufacturing in final energy consumption is projected to decline to 27 per cent in 2034–35 (Table 14).Final energy consumption in non-ferrous metals is projected to grow at 0.5 per cent a year from 518 petajoules in 2008–09 to 586 petajoules in 2034–35 (Table 15). This growth will be supported by the planned expansion of alumina refining capacity over the projection period. BHP Billiton’s Worsley refinery Efficiency and Growth project in Western Australia will increase the refinery’s annual production capacity by 1.1 million tonnes once completed in 2012 while the expansion at Rio Tinto Alcan’s Yarwun refinery in Queensland will increase capacity by 2 million tonnes from 2012. The implementation of carbon pricing will increase the cost of energy inputs for minerals processing. As a result, growth in energy-intensive minerals processing is expected to be relatively subdued over the projection period. In addition, Xstrata announced in May 2011 that it intends to phase out its copper smelting and refining activities in Australia by the end of 2016.In the iron and steel industry, final energy consumption is projected to decline at an average annual rate of 0.8 per cent over the projection period to 77 petajoules in 2034–35. This, in part, reflects BlueScope Steel’s closure of capacity in New South Wales. In August 2011, BlueScope announced that it would close its number six blast furnaces at Port Kembla and Western Port hot strip mill as part of a restructure aimed at returning it to a profitable generation level.

MiningWhile only accounting for a small proportion of final energy consumption, the mining sector is projected to exhibit the fastest growth among the manufacturing subsectors. This will be underpinned by the large number of energy and mineral projects assumed to be completed over the projection period. A major contributor to this growth will be the substantial increase in the relatively energy-intensive production of liquefied natural gas (LNG).As a result of these developments, the mining sector’s share of final energy consumption is projected to increase from 6 per cent in 2008–09 to 10 per cent in 2034–35 (Table 14). The growth of 2.9 per cent a year is slower than in previous years, which is driven, in part, by an assumed 0.5 per cent a year reduction in the energy intensity of mining industries.

Commercial and residentialThe commercial and residential sector consists of wholesale and retail trade, communications, finance, government, community services, recreational industries and households. The sector accounted for 20 per cent of total final energy

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consumption in 2008–09, and is projected to increase to 21 per cent in 2034–35. Energy use in the sector is projected to increase by 1.4 per cent a year to 1043 petajoules in 2034–35 (Table 14).The commercial and residential sector relies heavily on electricity and is expected to remain the major driver of growth in electricity consumption over the projection period. In the residential sector, energy consumption is influenced by population growth, household income, energy prices and lifestyle choices. Energy is a relatively small component of household expenditure (ABS 2010b). In addition, current pricing arrangements, particularly for electricity, do not provide strong price signals to residential energy consumers. As a result, households have not tended to be highly responsive to changes in prices. However, the Council of Australian Governments (COAG) is committed to a national rollout of smart meters (meters that allow energy users to observe the real time cost of their energy consumption) where benefits are considered to outweigh the costs. Such developments should drive an increased demand response to prices.

AgricultureAgriculture accounts for a small proportion of final energy consumption, with a share of 3 per cent in 2008–09 that is projected to remain unchanged to 2034–35. Petroleum products are the major fuel used on farms. Energy use in the agriculture sector is projected to increase by 1.7 per cent a year to 2034–35 (Table 14).

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Table 15: Final energy consumption, by manufacturing subsector

Level Share Average annual growth

2008–09 to

2008–09

2019–20 2034–35 2008–09 2034–35 2034–35

Subsector PJ PJ PJ % % %Wood, paper & printing

68 86 91 6 7 1.1

Basic chemicals 166 182 169 14 13 0.1Iron & steel 93 80 77 8 6 -0.8Non-ferrous metals 518 571 586 45 44 0.5Other manufacturing 307 384 410 27 31 1.1Total 1153 1304 1333 100 100 0.6Numbers in the table may not add up to their totals due to rounding.The figures for 2008–09 presented in this table may not be identical to actual historical data published in ABARES’ Australian Energy Statistics. This is a reflection of the different classification systems.

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5 Energy production and tradeThe major sources of energy produced in Australia on an energy content basis are coal and gas. In 2008–09, production of coal was 9651 petajoules (around 322 million tonnes) or 74 per cent of Australian energy production (excluding uranium). Gas accounted for 16 per cent of production, followed by crude oil and condensate and naturally occurring LPG (9 per cent) and renewable energy (hydroelectricity, wind energy, bioenergy and solar energy) at 2 per cent (Table 16). Although Australia is a major producer of uranium oxide, it is not accounted for in the projections as it is not consumed as a fuel domestically, and therefore, does not affect the energy balance. Details on the outlook for uranium are contained in Box 7.Table 16: Energy production, by source

Level Share

Average annual growth

2008–09 to

2008–09 2019–20 2034–35 2008–09 2034–35 2034–35

Energy type PJ PJ PJ % % %Non-renewables 12834 22649 27741 98 98 3.0Coal 9651 15832 18956 74 67 2.6

black coal 9004 15185 18676 69 66 2.8 brown coal 647 647 281 5 1 -3.2Oil 997 811 376 8 1 -3.7

LPG 104 116 135 1 <1 1.0

Gas 2082 5890 8274 16 29 5.5

Renewables 279 548 660 2 2 3.4Hydro 45 47 47 <1 <1 0.2

Wind 14 131 175 <1 1 10.1

Bioenergy 211 329 365 2 1 2.1

Solar 9 22 26 <1 <1 4.1

Geothermal 0 18 48 0 <1 -Total   13113 23197 28401 100 100 3.0Numbers in the table may not add up to their totals due to rounding.The figures for 2008–09 presented in this table may not be identical to actual historical data published in ABARES’ Australian Energy Statistics. This is a reflection of the different classification systems.

Australian energy production (excluding uranium) is projected to grow at an average annual rate of 3 per cent over the projection period. At this rate, total production of energy in Australia is forecast to more than double to 28 401 petajoules in 2034–35 (Table 16). Coal and gas are projected to account for 96 per cent of Australia’s energy

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production in 2034–35. Coal production is projected to increase by 96 per cent to 18 956 petajoules (632 million tonnes), while gas is projected to increase almost four-fold to 8274 petajoules (330 960 gigalitres).

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Box 7: Australian uranium outlookAs world uranium demand continues to grow, particularly in major consuming countries, new mines will be developed and existing production facilities expanded to increase Australia’s export capacity. According to BREE calculations (and outside the present modelling), Australia’s uranium production is projected to increase at an average annual rate of 4 per cent from 8700 tonnes uranium (U,4846 petajoules) in 2008–09 to around 26 200 tonnes U (14 500 petajoules) in 2034–35. This growth will be supported by the development of a number of new projects from 2014–15.

Figure G: Australian uranium production

Sources: BREE calculations, outside the E4cast model

Currently, there are three mines producing uranium in Australia: Ranger (4500 tonnes U a year), Olympic Dam (3800 t U) and Beverley (900 t U). Growth in uranium production is expected to come from the Honeymoon and Mullaquana projects in South Australia; the Yeelirrie, Kintyre, Mulga Rock, Lake Maitland and Wiluna projects in Western Australia, and the Bigrlyi project in the Northern Territory. In addition, plans are underway to expand production at the Olympic Dam mine, which will be the largest uranium development in Australia. The proposed expansion will increase production to around 19 000 tonnes of U3O8 (16 100 t U) a year.A number of these projects have not yet received final investment decisions. As a result, the eventual timing and output from these projects may differ from current plans.

With the exception of crude oil and refined petroleum products, Australia is a net exporter of energy commodities. As the projected growth in energy production exceeds that of primary energy consumption, Australia’s exportable surplus of energy is expected to increase over the period to 2034–35. Demand for Australia’s energy resources is expected to remain robust over the projection period, particularly in China and other developing economies. This will be supported by growth in economic activity and industrial production which is expected to provide a solid platform for growth in energy consumption. In 2008–09, the ratio of Australia’s primary energy consumption to non-uranium energy production was 44 per cent. This is projected to decline to 26 per cent in 2034–35 (Figure H).

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Figure H: Australian energy balance

Black coal production and exportsProduction of black coal, which includes thermal and metallurgical coal, is projected to grow at 2.8 per cent a year to 18 676 petajoules (623 million tonnes) in 2034–35. Despite this growth, the share of black coal in total energy production is projected to decline from 69 per cent in 2008–09 to 66 per cent in 2034–35 (Table 16). Growth in black coal will be supported by the development of a number of new mines and expansions at existing mines in New South Wales and Queensland over the projection period. New thermal capacity will come from BHP Billiton’s RX1 thermal coal development in the Hunter Valley region of New South Wales (4 million tonnes a year) which is scheduled for completion in 2013 and Xstrata Coal’s Ravensworth North development, also in New South Wales, which is expected to have an annual capacity of 8 million tonnes when completed in 2012. New metallurgical coal production will be supported by the development of BHP Billiton Mitsubishi Alliance’s Daunia mine in Queensland (4.5 million tonnes a year) in 2013 and an expansion at Jellinbah Resources’ Lake Vermont mine (additional 4 million tonnes a year) in 2013.Black coal is an important energy export for Australia, with coal projected to account for almost three-quarters of the growth in exports over the period to 2034–35. The projected growth of 3.3 per cent a year is based on the expectation that global demand for coal will continue to increase over the projection period, particularly in emerging market economies in Asia, in line with growing demand for electricity and steel-making raw materials. Australia, with its abundant reserves of high-quality coal, is well positioned to make a substantial contribution to meeting this increased

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demand. The development of infrastructure in New South Wales and Queensland will support coal exports growing to 17 415 petajoules (581 million tonnes) in 2034–35 (Table 17, and Figure I). There are a number of port expansions at Newcastle, including the second stage of the Newcastle Coal Infrastructure Group (NCIG) terminal, which will lift capacity by 23 million tonnes annually, and two stages of expansion at Port Waratah Coal Services’ Kooragang Island Coal Terminal, which will collectively increase annual capacity by 32 million tonnes to a total of 145 million tonnes a year. In Queensland, BHP Billiton’s Hay Point coal terminal is scheduled for completion in 2014 and will increase the port’s capacity by 11 million tonnes annually to 55 million tonnes a year.

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Table 17: Net trade in energy

Level Average

annual growth

2008–09 2019–20 2034–35 %

Subsector PJ PJ PJ 2008–09 to 2034–35

Coal 7411 13725 17415 3.3Liquid fuelsa -920 -1513 -2159 3.1LNG 838 4006 5663 7.6Total 7329 16218 20919 4.1a Includes crude oil, other refinery feedstock, petroleum products and LPG.

Figure I: Australian black coal balance

Natural gas production and LNG exportsAustralia has considerable resources of gas that are increasingly being developed for domestic use and export (Figure J). The significant gas resource base is capable of meeting domestic and export demand over the projection period. In 2008–09, Australian gas output was 2082 petajoules (around 38 million tonnes), including LNG (Table 18). The majority of Australia’s conventional gas resources are located off the north-west coast of Western Australia. Reflecting this, the western market is the largest producing region in Australia. Gas production in the western market was 1199 petajoules in 2008–09 or 58 per cent of total production. Gas production in the eastern and northern markets was 688 petajoules and 195 petajoules, respectively, in 2008–09 (Table 18).In the western market, gross gas production, including LNG, is projected to grow at an

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average annual rate of 5.5 per cent to 4771 petajoules in 2034–35 (Table 18). Strong growth in domestic and global demand for gas has been driving the development of new projects and LNG capacity. There are a number of LNG projects that are expected to be completed in the western market over the projection period. These include Chevron, Shell and ExxonMobil’s Gorgon LNG project (15 million tonnes a year) in 2015; and Chevron, Apache, KUFPEK and Tokyo Electric’s Wheatstone (8.9 million tonnes a year initially) in 2016.

Gas production in the eastern market is projected to grow at 5 per cent a year to 2492 petajoules in 2034–35. A prominent feature of the eastern gas market is the increasing contribution of CSG to total production. In 2008–09, CSG accounted for 8 per cent of Australian production and around 89 per cent of production in Queensland. Production of CSG in Queensland and New South Wales is expected to maintain its strong growth trajectory over the projection period supported by the development of a number of new projects. A large proportion of this CSG will be consumed domestically, supporting growth in CSG-fired electricity generation, particularly in Queensland and New South Wales. The rapid growth in CSG production in Queensland suggests that there may also be some changes in gas flow patterns, with relatively less gas flowing from Victoria and more flowing from Queensland (AEMO 2010). Table 18: Australian gas production

Level Share

Average Annual Growth

2008–09 to

2008–09 2019–20 2034–35 2008–09

2019–20

2034–35

2034–35

PJ PJ PJ % % % %

Eastern market

688 1893 2492 33 32 30 5.0

Western market

1199 3626 4771 58 62 58 5.5

Northern market

195 371 1011 9 6 12 6.5

Total 2082 5890 8274 100 100 100 5.5

It is expected that CSG will be also be converted to LNG over the projection period, with a number of projects being planned around Gladstone. BG Group’s Queensland Curtis LNG project received approval in October 2010. The facility will have a capacity of 8.5 million tonnes of LNG a year once completed in 2014. It will be the first facility in the world to use CSG as a feedstock in the production of LNG. The Gladstone LNG development (7.8 million tonnes a year) was approved in early 2011 and is scheduled to be completed in 2015. There are a number of other LNG projects using CSG as a feedstock planned for development. However, some of these projects may not

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proceed for several years as they face changes in market conditions or are targeting the same market opportunities. The development of CSG-LNG is likely to have implications for gas prices on the east coast.Figure J: Australian gas balance

Production in the northern gas market (including imports from the Joint Petroleum Development Area in the Timor Sea for processing in Darwin) was 195 petajoules in 2008–09. Production is projected to be 1011 petajoules in 2034–35, growing at an average rate of 6.5 per cent a year. Gas production in the northern market is projected to be more than sufficient to meet domestic demand. Domestic gas consumption growth will be underpinned by the increased volumes of gas required for the conversion of gas to LNG at the Ichthys processing plant and the increased uptake of gas-fired electricity generation.

Crude oil production and net importsAustralia’s oil production is influenced by the geology of oil deposits, exploration activity and world prices. The latest available estimates of recoverable oil resources are around 8624 petajoules (1466 million barrels), largely located in the Gippsland and Carnarvon basins (Geoscience Australia 2011). A major proportion of Australia’s oil production is sourced from mature fields with declining oil reserves. However, there are many prospective offshore areas that have not been explored. In addition, Australia has substantial resources of condensate (16 295 petajoules) and LPG (6281 petajoules) associated with the major gas fields on the North West Shelf in the Browse and Bonaparte basins (Geoscience Australia 2011).Australia’s crude oil and natural gas liquids production is projected to decline by 2.9 per cent a year from 1101 petajoules in 2008–09 to 511 petajoules in 2034–35 (Table 16). It is assumed that producers will develop a small proportion of the resource base each year in response to price signals. However, the reserves in existing and

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subsequently developed oil fields are assumed to deplete as the oil is extracted that will result in lower production over the projection period. Production of naturally occurring LPG is projected to increase at an average annual rate of 1 per cent to 135 petajoules in 2034–35. In 2008–09, Australia’s crude oil production was equivalent to around 76 per cent of refinery feedstock. As a result, Australia was a net importer of crude oil. However, around 60 per cent of Australia’s crude oil and condensate production was exported, primarily to oil refineries in Asia.Figure K: Australian oil and LPG balance

Australian consumption of liquid fuels (excluding petroleum products) is projected to increase from 1784 petajoules in 2008–09 to 1991 petajoules in 2034–35 (Figure K). Over the projection period, the gap between supply and demand will be exacerbated by the significant proportion of growth in crude oil and naturally occurring LPG production being concentrated in the Carnarvon and Browse basins in north-western Australia, which are closer to Asian refineries than the east coast of Australia. As a result, it is reasonable to assume that the bulk of the supply of crude oil and naturally occurring LPG will be exported for further processing rather than directed to the domestic market. Reflecting this assumption, the ability to meet domestic demand with domestic production is likely to be lower than implied by the simple comparison of production and consumption.The demand for petroleum product imports is determined by domestic oil production, end use consumption of petroleum products, and domestic petroleum refining capacity. Australia’s refining capacity is not expected to expand considerably over the projection period given increasing competitive pressure, particularly from large South-

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East Asian refineries. For example, in April 2011, Shell announced plans to convert its Clyde refinery and Gore Bay Terminal in Sydney into a fuel import terminal. This would result in the end of its refining operations. The Clyde refinery supplies around 40 per cent of Sydney’s and 50 per cent of New South Wales’ petroleum requirements, respectively (Shell 2011). For a given domestic consumption and production projection, petroleum refining constraints may result in lower crude oil imports and higher imports of refined products.The refining industry also uses petroleum products as an input to convert oil feedstock into a range of petroleum products. Around 7 per cent of gross refinery output is used on-site in the conversion process, as well as small quantities of natural gas and electricity.With declining oil production, Australia’s net trade position for liquid fuels is set to decline, with net imports increasing by 3.1 per cent a year to 2034–35 (Table 17).

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6 ConclusionsAustralian energy consumption will continue to grow over the next 26 years, albeit at a slower rate than witnessed over the past few decades. This represents an ongoing trend that has been accelerated by a number of policy drivers and market factors.The projections in this report point towards a major change in the Australian energy landscape. The change is most prominent in the energy mix. BREE modelling indicates a shift to low emission technologies, driven by policies that promote a less emission intensive economy. The Renewable Energy Target and the introduction of carbon pricing will drive the uptake of renewable technologies, which are projected to account for 9 per cent of primary energy consumption in 2034–35, up from 5 per cent in 2008–09.Within non-renewables, there is projected to be a strong increase in the use of gas, particularly in electricity generation, which is one of the largest components of primary energy consumption, and LNG production. Gas-fired electricity generation is based on mature technologies with competitive cost structures. As such, it is expected to play a transitional role in the Australian energy mix until lower emission technologies become more cost competitive.Renewable energy is projected to have the strongest growth prospects, driven largely by the RET and other policies promoting the uptake of these technologies. Within the renewables, the largest expansion is projected to occur in wind energy which is a more mature technology in Australia and has a lower cost-structure relative to other renewable technology options. In addition, solar energy and geothermal energy are expected to play a small, but growing role in the energy mix.The transition to a lower carbon economy will rely on long-term structural adjustment of the Australian energy sector. While Australia has diverse and abundant energy resources, the transformation will require considerable investment in energy supply chains to allow for the larger-scale integration of renewable energy sources and other emerging technologies. Changes to market settings within the energy market framework will further help to support this transition. A shift to a cleaner energy future will require a broad energy policy framework that supports investment in Australia’s energy future along with timely adjustments in response to emerging pressures and market developments.

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