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Australian Energy

Projections to 2049–50

December 2012Arif Syed

Arif Syed 2012, Australian energy projections to 2049-50, Canberra, December.

© Commonwealth of Australia 2012

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.978-1-922106-55-1 Australian Energy Projections (word)Postal address:Bureau of Resources and Energy EconomicsGPO Box 1564Canberra ACT 2601Phone: +61 2 6276 1000, or 61 2 6243 7504Email: [email protected], or [email protected]: www.bree.gov.au

Australian Energy Projections to 2050 • December 2012 • 3

AcknowledgementsThis report was undertaken under the guidance of Professor Quentin Grafton, Executive Director, Bureau of Resources and Energy Economics (BREE). The author appreciates the valuable contributions of the following people, who assisted with various aspects of the project: Bruce Wilson, Roger Rose, Allison Ball, Dr Nhu Che, Mark Stevens, Kate Penney and Clare Stark and all of BREE. The author is also grateful for the valuable input and comments provided by other colleagues from the Department of Resources, Energy and Tourism (DRET), Rob Jackson (the Australian Energy Market Operator, AEMO), Dr Alex Wonhas and Paul Graham (Commonwealth Scientific and Industrial Research Organisation, CSIRO), and colleagues from the Australian Treasury.


ForewordThis report, and indeed BREE’s other energy publications, data and analyses, provide the basis for informed decision making in the Australian energy sector. The 2012 release of Australian Energy Projections includes several important changes from 2011. First, the projections are extended out to 2049-50. Second, the projections take advantage of the levelised costs of electricity generation from the July 2012 release of the Australian Energy Technology Assessment. Third, the projections benefit from the latest volume and price data from the November 2012 release by the International Energy Agency of the World Energy Outlook.Key results worth highlighting in the latest projections are in terms of energy production. Electricity generation is projected to grow by 49 per cent over the period (1.1 per cent a year) to total 377 terawatt hours in 2049-50. Coal’s share (including with carbon capture and storage) of this production is projected to fall to 13 per cent in 2049-50, while gas (including with and without carbon capture and storage, and integrated solar-gas technologies) rises to 36 per cent. About half of Australia’s electricity is projected to be generated by renewable sources in 2049-50.Primary energy consumption is projected to grow by 21 per cent (0.5 per cent a year) to 7389 petajoules in 2049-50. This moderate growth projection is a result of a projected long-term fall in energy intensity, and the greater role of renewable technologies. Overall, the findings in this report suggest that Australia’s energy future will be markedly different to its current structure. Changes in energy use by fuel and by sector will alter consumption patterns, while a substitution away from carbon-intensive fuels to renewable energy sources will support a cleaner energy future.

Quentin GraftonExecutive Director / Chief EconomistBureau of Resources and Energy EconomicsDecember 2012


ContentsAcknowledgements 4Foreword 5Glossary 8Units 10Abbreviations 11BREE contacts 12Executive summary 13

1 Introduction 152 The Australian energy context 16

Energy resources 16Australian energy production 17Australian energy consumption 18Australia’s energy exports 19Energy policy 20

3 Methodology and key assumptions 23The E4cast model 23Key assumptions 27

4 Energy Consumption 35Total primary energy consumption 35Aggregate energy intensity trends 35Primary energy consumption, by energy type 35Primary energy consumption, by state and territory 36Primary energy consumption, by sector 37Electricity generation 38Final energy consumption, by energy type 43Final energy consumption, by sector 44

5 Energy production and trade 47Natural gas production and LNG exports 49Crude oil production and net imports 50

6 Conclusions 51References 52


BoxesBox 1: Key features of E4cast 24

MapsMap 1: Distribution of Australia’s energy resources 16Map 2: Advanced electricity generation projects, October 2012 41

FiguresFigure 1: Projected electricity generation mix 14Figure A: Australian energy production 17Figure B: Energy intensity trends 18Figure C: Australian primary energy consumption 19Figure D: Australian energy exports 20Figure E: Energy forecasting model 23Figure F: Index of real world energy prices, 2011 dollars 29Figure G: LCOE for Technologies (NSW), 2030 compared with 2012 31Figure H: LCOE for Technologies (NSW), 2040 32

TablesTable 1: Fuel coverage in E4cast 25Table 2: Industry coverage in E4cast 26Table 3: Australian population assumptions 27Table 4: Australian economic growth, by region 28Table 5: Carbon price assumptions, real, 2009–10 dollars 33Table 6: LRET renewable electricity generation target (excluding existing 34renewable generation)Table 7: Primary energy consumption, by energy type 36Table 8: Primary energy consumption, by state and territory 37Table 9: Primary energy consumption, by sector 38Table 10: Electricity generation, by state and territory (TWh) 39Table 11: Electricity generation, by energy type (TWh) 40Table 12: Australian electricity generation (total generation and roof-top estimates), TWh 43Table 13: Final energy consumption, by energy type (PJ) 44Table 14: Final energy consumption, by sector (PJ) 44Table 15: Final energy consumption, by manufacturing subsector (PJ) 46Table 16: Energy production, by source 47Table 17: Australian energy balance 48Table 18: Net trade in energy (PJ) 49Table 19: Australian gas production 49


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.

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 Australian Energy Projections to 2050 • December 2012 • 9

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 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. 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.

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 consumption

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

Wh 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. 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.


AbbreviationsAEMO Australian Energy Market OperatorAETA Australian Energy Technology Cost AssessmentBREE Bureau of Resources and Energy EconomicsCCS Carbon Capture and Storage/SequestrationCSG Coal Seam GasIEA International Energy AgencyLCOE Levelised Cost of ElectricityLNG Liquefied Natural GasLRET Large-scale Renewable Energy TargetNFEE National Framework for Energy EfficiencyNGER National Greenhouse and Energy ReportingNSEE National Strategy on Energy EfficiencyPV PhotovoltaicRET Renewable Energy TargetSRES Small-scale Renewable Energy Scheme


BREE contactsExecutive Director/Chief Economist – BREE Professor Quentin Grafton [email protected]

02 6276 1000Deputy Chief Economist/Research Director (A/g) Roger Rose [email protected]

02 6243 7583Modelling & Policy integration Program Leader Dr Arif Syed [email protected]

02 6243 7504Energy ProgramProgram Leader Dr Nhu Che [email protected]

02 6243 7539Data & Statistics ProgramProgram Leader Geoff Armitage [email protected]

02 6243 7510Resources ProgramProgram Leader (A/g) John Barber [email protected]

02 6243 7988


Executive summary This report presents the latest long-term projections of Australian energy consumption,

production and trade over the period to 2049-50. These projections are not intended as predictions or forecasts, but as a scenario of potential changes in Australian energy consumption, production and trade patterns given the assumptions used in the report.

The projections include existing government policies, including the Renewable Energy Target and carbon pricing. They also incorporate the latest estimates of electricity generation technology costs from the Australian Energy Technology Assessment (BREE 2012 d). The availability of these estimates has led to significant changes in the Australian energy landscape presented in this report compared to the BREE (2011) energy projections.

Energy consumption Total primary energy consumption is projected to grow by around 21 per cent (0.5 per

cent a year) over the period 2012-13 to 2049-50, to reach 7369 petajoules. 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 such as carbon pricing. Importantly, it also reflects the greater role of renewable technologies, which use less energy inputs to generate electricity than fossil fuels.

Large-scale changes are expected in Australia’s energy mix over the coming decades. The share of coal in total primary energy consumption is projected to fall sharply from 31 per cent in 2012-13 to just 6 per cent by 2049-50. Oil will remain an important energy source in Australia, while gas will be the fastest growing non-renewable energy source, with its share increasing to 34 per cent by 2049-50 (Figure 1a).

Renewable energy use is projected to nearly quadruple in volume terms over the period to 2049-50 (at 3.6 per cent a year). The share of renewables is projected to increase from 5 per cent of total primary energy consumption in 2012-13 to 14 per cent in 2049-50. The fastest growing energy sources are expected to be solar and wind.

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 resources and energy sectors and their high degree of export orientation.

The share of the electricity sector in Australia’s energy demand will fall substantially from 38 per cent in 2012-13 to 26 per cent in 2049-50, although it will still be the second largest user of primary energy in Australia. The key drivers of this change are the greater use of more efficient renewable technologies and the impact of higher energy prices.

The transport sector will become the largest user of primary energy in Australia, increasing its share slightly to one-third of primary energy consumption by 2049-50. The fastest growing consumer of primary energy will be the mining sector, with an average growth of 3.5 per cent a year expected over the projection period.

The projected outlook for energy consumption in this report differs substantially from previous BREE long term energy projections. This is because of the use of more up to date and lower projected costs for many renewable technologies. This is projected to result in a greater penetration of renewable energy in terms of the total energy mix. These renewable technologies use less energy in conversion to electricity than traditional fossil fuels and this is projected to lower the growth in demand for primary energy.

Electricity generation Gross electricity generation is projected to grow by around 49 per cent (1.1 per cent a

year) to reach 377 terawatt hours in 2049-50. This growth is expected to come from expansion of renewables and gas-fired electricity generation.

The projected rate of growth in electricity generation in this report is slightly less than 1.1 per cent a year, which is less than the 1.4 per cent reported in the previous BREE report (2011).

The impact of lower cost renewable generation and carbon pricing is expected to lead to a dramatic decline in coal-fired generation (Figure 1). The share of coal in electricity generation is projected to fall from 60 per cent in 2012-13 to 13 per cent in 2049-50. The


remaining coal fired electricity generation capacity is projected to include carbon capture and storage technology.

Gas fired electricity generation is projected to double over the projection period, to account for 36 per cent of total generation in 2049-50. This also includes carbon capture and storage technologies, including integrated gas-solar technologies.

About half of Australia’s electricity is expected to be generated by renewables by 2049-50. The use of renewable energy resources in electricity generation is projected to rise by 4.8 per cent a year, from 13 per cent of total generation in 2012-13 to 51 per cent in 2049-50. Wind is expected to be the largest source of renewable electricity generation (21 per cent by 2049-50). Solar is projected to be the second largest contributor (16 per cent by 2049-50), and is the fastest growing of all sources over the projection period.

The strong growth in renewable electricity generation is a result of the increased competitiveness of renewable technologies under carbon pricing, as well as expected advances in technologies and a decline in their capital costs.

Figure 1: Projected electricity generation mix

Energy production and trade Australian energy production (excluding uranium) is projected to grow by 69 per cent (an

average annual rate of 1.4 per cent) over the projection period, to reach 27 803 petajoules in 2049-50. Coal and gas are projected to account for 96 per cent of Australia’s energy production in 2049-50.

Production of black coal, which includes thermal and metallurgical coal, is projected to grow at 1.2 per cent a year, to 17 973 petajoules (around 539 million tonnes) in 2049-50.

An increasing proportion of this production will be exported, with coal exports projected to increase by 1.4 per cent a year to 17 496 petajoules in 2049-50. World coal demand, particularly for metallurgical coal, is expected to continue to grow over the next four decades, albeit at a slower rate in the latter half of the projection period.

Strong growth in domestic and global demand for gas will continue to drive the development of new gas fields and LNG capacity in Australia. Australian gas production, including LNG, is projected to nearly triple (equal to growth of 2.9 per cent a year), to reach 8595 petajoules in 2049-50. The western market will remain the largest gas market in Australia, although its growth in output is expected to be slower than that of the eastern and northern markets.

LNG exports are projected to more than triple, to reach 6127 petajoules (around 113 million tonnes) in 2049-50. This includes new LNG projects in all markets, including projects based on coal seam gas and floating LNG technologies.

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 2.1 per cent a year.


1 IntroductionThe current set of results provides an update to the Australian energy consumption, production and trade projections published by BREE in December 2011, with the following amendments: Data updates to 2010-11; Extension of the projection period to 2049-50; Revisions to economic growth assumptions; Revisions to long term energy price and electricity generation technology costs

assumptions; and Inclusion of recently announced changes to 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 2012–13 to 2049–50. These projections are derived using the E4cast model, a dynamic partial equilibrium model of the Australian energy sector. This report provides more detailed energy projections than presented in the Energy White Paper (2012).In undertaking these projections, government policies that have already been enacted are included, in particular, the Renewable Energy Target and carbon pricing. There is always some degree of uncertainty about technology, investment and also government policies in the area of energy. The current projections should only be considered as a scenario of what the future could be given the assumptions used, and not a forecast of 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 report is organised as follows. In section 2 the energy policy context in Australia is described, with a focus on key policies that are likely to affect long-term energy trends. Section 3 briefly presents the modelling framework used, as well as the key underlying assumptions. Section 4 provides the outlook for Australian energy consumption and electricity generation covering the period 2012–13 to 2049–50, and Section 5 provides the long-term outlook for Australian energy production and trade. Section 6 offers concluding remarks.


2 The Australian energy contextEnergy resourcesAustralia is endowed with abundant, high quality and diverse energy resources (Map 1). Australia has around 34 per cent of the world’s uranium resources, 14 per cent of the world’s black coal resources, and almost 2 per cent of world conventional gas resources. Australia has only a small proportion of world resources of crude oil. Australia also has large, widely distributed wind, solar, geothermal, hydroelectricity, ocean energy and bioenergy resources.Map 1: Distribution of Australia’s energy resources

Source: BREE 2012a


The development of these resources has contributed to the competitiveness of energy-intensive industries and provided considerable export income. Australia is one of the few OECD economies that is a significant net exporter of energy commodities, with the major exports being coal, liquefied natural gas (LNG), uranium and petroleum. Since uranium is not consumed domestically, it is not included in the energy balance projections presented in the following sections. In this section, uranium is included in production and exports to provide a historical description of Australian energy. Therefore, the numbers in this section are not strictly comparable to the numbers in the following sections that exclude uranium.

Australian energy productionAustralia is the world’s ninth largest energy producer, accounting for around 2.4 per cent of the world’s energy production (IEA 2012a). Energy production in Australia has fallen over the past two years, to be 16 140 petajoules in 2010-11, mainly as a result of weather related supply disruptions (BREE 2012b).The main fuels produced in Australia are coal, uranium and gas (Figure A). While Australia produces uranium, it is not consumed domestically and all output is exported. Coal accounted for around 60 per cent of total energy production in energy content terms in 2010-11, followed by uranium (20 per cent) and gas (13 per cent). Crude oil, condensate and naturally occurring LPG represented 6 per cent of total energy production in that year, and renewable energy the remaining 2 per cent. Figure A: Australian energy production

Source: BREE 2012b

Australian production of renewable energy is dominated by bagasse, wood and wood waste, and hydroelectricity, which together accounted for around 80 per cent of renewable energy production in 2010-11. Wind and solar energy accounted for the remainder of Australia’s renewable energy production, and their production has been increasing strongly.Reserves to production ratios have generally been rising in recent years. This reflects the addition of new discoveries and the upgrading of resources meeting economic criteria. At current rates of production, Australia’s energy resources are expected to last for many more decades. In addition, many of Australia’s renewable energy resources are largely undeveloped.


Australian energy consumptionAustralia is the world’s twentieth largest primary energy consumer, and ranks eighteenth on a per person energy use basis (IEA 2012b). Since 2000-01, growth in energy consumption in Australia has averaged 2.0 per cent a year (BREE 2012b).Although Australia’s energy consumption is growing, the rate of growth has been declining over the past 50 years. Following annual growth of more than 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 and 1990s, the growth rate averaged around 2.3 per cent a year. Figure B shows the long term decline in energy intensity of the Australian economy (defined as total domestic energy consumption to GDP ratio). 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: BREE 2012b, ABS (2012)

Australian primary energy consumption consists mainly of coal, oil and gas (Figure C). In 2010-11, black and brown coal accounted for around one-third of the primary energy mix, its lowest contribution since the early 1970s, as a result of substitution away from coal toward other fuels in electricity generation. Oil accounted for a little under 40 per cent of primary energy consumption, followed by gas (about 25 per cent) and renewable energy sources (4 per cent).


Figure C: Australian primary energy consumption

Source: BREE 2012b

The main users of energy in Australia are the electricity generation, transport and manufacturing sectors. Together, these sectors accounted for more than 88 per cent of energy consumed in 2010-11. 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 2 per cent to Australian industry value added in 2010-11. 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.

Australia’s energy exports Australia is a net energy exporter, with domestic energy consumption representing only one-third of total energy production, including uranium. Australia’s energy exports were 13 312 petajoules in 2010–11 in energy content terms (Figure D). In value terms, energy exports accounted for 32 per cent of the total value of Australia’s commodity exports in 2010–11. Australia’s largest energy export earners are coal, crude oil and LNG. In 2010–11 exports were $43.7 billion for coal, $12.2 billion for crude oil and condensate and $10.4 billion for LNG.


Figure D: Australian energy exports

Source: BREE 2012b

Australia is a net importer of liquid hydrocarbons, including crude oil and most petroleum products. 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 sources into existing energy supply chains.

Energy policyEnergy related policy responsibilities are shared across the different levels of government in Australia. Much of Australia’s energy policy is developed and implemented through cooperative action between the Australian and state and territory governments.Australia’s national energy policy objective is to provide the settings to deliver secure, reliable, clean and competitively priced energy to consumers and build national wealth through the safe and sustainable development of Australia’s energy resources. Central to this is the commitment to competitive and well-regulated markets operating in the long-term interests of consumers and the nation (Australian Government 2012).Energy White Paper 2012The Energy White Paper 2012, Australia’s energy transformation, was released by the Australian Government in November 2012 (Australian Government 2012). It sets out a strategic policy framework to address the challenges in Australia’s energy sector and position Australia for a long term transformation in the way it produces and uses energy.The Energy White Paper identifies four priority action areas to support Australia’s energy transformation:1. delivering better energy market outcomes for consumers; 2. accelerating our clean energy transformation; 3. developing Australia’s critical energy resources, particularly gas resources; and 4. strengthening the resilience of Australia’s energy policy framework.


Further details on specific areas of action around these priorities can be found at: www.ret.gov.au/energy/facts/white_paper/Pages/energy_white_paper.aspx


Clean Energy Future PlanThrough its Clean Energy Future Plan, legislated in late 2011, the Australian Government has implemented reforms aimed at driving a long-term transformation to a clean energy economy. The central elements most relevant to energy policy are carbon pricing, renewable energy and energy efficiency.A carbon price was introduced on 1 July 2012, making large emitters of carbon financially liable for their carbon emissions. It will be fixed for the first three years before transitioning to an emissions trading scheme. 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 price in 2012-13 is $23 a tonne of carbon dioxide equivalent (CO2-e), increasing by 2.5 per cent in real terms until 30 June 2015. From 1 July 2015, the carbon price will transition to an emissions trading scheme where the number of available permits will be capped and the permit price will be determined in the marketplace (Australian Government 2011).Carbon pollution from the following sources will be covered by a carbon price: stationary energy, waste, rail, domestic aviation and shipping, industrial processes and fugitive emissions. The Government also intends to expand the coverage of the carbon price to include heavy on-road vehicles from 1 July 2014. Households and light commercial vehicles will not face a carbon price on the fuel they use for transport. In addition, the agriculture, forestry and fishing industries will not face a carbon price on their off-road fuel use (Australian Government 2011).In August 2012, it was announced that Australia and Europe will be linking their emissions trading systems, with businesses will be allowed to use carbon units from the Australian emissions trading scheme or the European Union Emissions Trading System (EU ETS) for compliance under either system by no later than 1 July 2018. As part of this arrangement, an Australian carbon price floor will no longer be implemented (Combet 2012).Other initiatives to support clean energy technology development include the establishment of the commercially oriented Clean Energy Finance Corporation, with funding of $10 billion to invest in renewable energy, low emissions and energy efficiency projects and technologies, as well as in manufacturing businesses that supply inputs to those technologies. The government has also established the Australian Renewable Energy Agency (ARENA) as an independent statutory body managing $3.2 billion of funding to support renewable energy R&D, demonstration, commercialisation and deployment. The government has provided $1.2 billion in the Clean Technology Program to support the development and early stage commercialisation of clean technologies across industry. The government is also providing around $2 billion in support for the research, development and demonstration of CCS technology, including the CCS Flagships program (Australian Government 2012).Renewable Energy TargetThe Renewable Energy Target complements the carbon price by providing additional support for renewable energy investment and industry development in the transition period to more mature carbon prices and technology costs. The RET scheme is designed to deliver on the Australian Government’s commitment that the equivalent of at least 20 per cent of Australia’s electricity comes from renewable sources by 2020. The RET, which commenced in 2010, expands on the previous Mandatory Renewable Energy Target (MRET) which began in 2001. The RET places a legal obligation on entities that purchase wholesale electricity (mainly electricity retailers) to surrender a certain number of renewable energy certificates to the Clean Energy Regulator each year. Each certificate represents one megawatt-hour of additional renewable energy for compliance purposes. Certificates are generated by accredited renewable energy power stations and eligible small-scale renewable technology systems. The sale of certificates supports additional renewable energy deployment. Certificates are tradeable and may be banked (Climate Change Authority 2012).From 1 January 2011, the RET has operated as two parts:1. Large-scale Renewable Energy Target (LRET), and2. Small-scale Renewable Energy Scheme (SRES).


The LRET encourages the deployment of large-scale renewable energy projects such as wind farms, while the SRES supports the installation of small-scale systems, including solar panels and solar water heaters. The LRET is set in annual gigawatt hour targets, rising to 41 850 GWh in 2020. The LRET target remains at 41 000 GWh from 2021 to 2030. The SRES is an uncapped scheme but has an implicit target of 4000 GWh. The RET is currently scheduled to end in 2030 (Clean Energy Regulator 2012).


Energy EfficiencyThe National Strategy on Energy Efficiency (NSEE) is the main mechanism by which all governments in Australia coordinate national action on energy efficiency. Through this collaborative approach, the NSEE delivers a range of policy measures, with a focus on increasing energy efficiency among energy users in the residential, commercial and industrial sectors. The Ministerial Council on Energy is responsible for the delivery of several important measures in the NSEE. These measures are delivered through the National Framework for Energy Efficiency.The Australian Government is also investigating the merits of a possible national Energy Savings Initiative (ESI), to encourage the identification and take-up of energy efficient technologies. Schemes currently operate in New South Wales, Victoria and South Australia, and the Australian Capital Territory scheme will commence in January 2013 (RET 2012).


3 Methodology and key assumptionsThe energy sector projections presented in this report are derived using the E4cast model. E4cast is a dynamic partial equilibrium model of the Australian energy sector that approximates the principal interdependencies between energy production, conversion and consumption in Australia. It is used to project, on an annual basis, energy consumption, by fuel type, by industry and by state or territory, explicitly taking into account real incomes and industry production trends, fuel prices and technical change (or energy efficiency improvements). Regional coverage of the model comprises: New South Wales, including the Australian Capital Territory; Victoria; Queensland; South Australia; Western Australia; Tasmania; and the Northern Territory.The E4cast modelling framework incorporates domestic as well as international trade in energy sources. It provides a complete treatment of the Australian energy sector, representing energy production, trade and consumption at a detailed level. As a result, the model can be used to produce a full range of results, including Australian energy balance tables.

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 E.

Figure E: Energy forecasting model


E4cast incorporates long-term macroeconomic forecasts from the Australian Treasury and current assumptions on the costs and characteristics of energy conversion technologies. A brief overview of the key features of the current version of E4cast is provided in Box 1. 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). Box 1: Key features of E4cast The first version of the model was documented in Dickson et al. (2001). Since its inception, the

model has been enhanced and refined in a number of ways to provide a sound platform for the development and analysis of medium and long term energy projections. Key features of the 2012 version of E4cast include:

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 projects over the period from 2012–13 to 2049–50; Demand parameters are established econometrically using historical Australian energy data from

BREE’s Australian Energy Statistics; 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 45 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 carbon pricing and the Australian Government Renewable Energy Target;

All fuel quantities are in petajoules; Supply of gas is modelled at the state level; and All prices in the model are real, in constant dollars of the base year, and are expressed in dollars

per gigajoule.

The model includes 19 energy sources, 45 electricity generation technologies, 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


Table 2: Industry coverage in 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 23-24

Basic chemicals 2520-2599

Nonmetallic mineral products 26

Iron and steel (excludes coke ovens and blast furnaces)

2700-2713, 2716-2719

Basic nonferrous metals 272-273

Aluminium smelting 2722

Other basic nonferrous metals 2720-2721, 2723-2729

Other manufacturing and construction na

Transport Division I (excludes sectors 66 and 67)Road transport 61

Passenger motor vehicles na

Other road transport na

Railway transport 62Water transport 63

Domestic water transport 6301

International water transport 6302

Air transport 64Domestic air transport na

International air transport na

Pipeline transport 6501

Commercial and services Sectors 37, 66 and 67; Divisions F, G, H, J, K, L, M, N, O, P and Q

Residential na

In E4cast, prices for energy sources used in electricity generation can be 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 all simulations, exogenous fuel 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 and LPG production, and LNG and black coal of exports, information is exogenous to the model and is drawn from BREE’s commodity forecasting capability as well from external sources, including the International Energy Agency. 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.

E4cast base year dataThe underlying year in the model is 2010-11, however the base year for projections is 2012-13, as provided in the Energy White Paper 2012. The data are drawn from BREE’s Australian Energy Statistics (BREE 2012b). These statistics are largely derived from the National Greenhouse and Energy Reporting (NGER) data, sourced from the Australian Government Department of Climate Change and Energy Efficiency. Information from other Australian Government agencies, state based agencies, industry associations and publicly available company reports are also used to supplement and/or validate NGER data. These sources include the Australian Bureau of Statistics, BREE’s commodity database and the Australian Petroleum Statistics.

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; and Government policies.The assumptions relating to these key drivers are presented below.Population growthPopulation growth affects the size and pattern of energy demand. Projections for the Australian population are drawn from the Australian Treasury carbon price modelling (Treasury 2011) and are presented in Table 3.Table 3: Australian population assumptions

year populationmillions

2012-13 23.352034-35 31.192049-50 36.26

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 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 long-term projections of the GDP and GSP assumptions (Table 4) are drawn from the assumptions used by the Australian Treasury carbon price modelling (Treasury 2011), supplemented in the short term by BREE’s GDP assumptions. In 2010–11, Australia’s real GDP increased by 1.8 per cent, following growth of 2.3 per cent in 2009-10. Over the projection period, Australia’s real GDP is expected to grow at an average annual growth rate of 2.5 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 2049–50, as a result of 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 2012-13 to 2049-50 %New South Wales 2.4Victoria 2.4Queensland 2.9South Australia 2Western Australia 2.9Tasmania 1.7Northern Territory 2.6Australia 2.5

Sources: BREE assumptions are drawn from Treasury (2011).

Real energy prices Energy prices affect the demand for, and supply of, energy. The long term world energy price assumptions incorporated in E4cast are presented in figure F, and are based on the International Energy Agency (IEA) 2012 World Energy Outlook New Policies Scenario (IEA 2012b). 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 F: Index of real world energy prices, 2011 dollars

Source: IEA 2012b

Thermal coal spot prices averaged around US$122 a tonne in 2011. Real thermal coal prices are projected to decline over the medium term, but are expected to remain relatively high in historical terms. The expected price decline is a result of strong growth in exports from Australia, Indonesia and Colombia and emerging exporters such as Mongolia and Mozambique. The decline in prices is expected to be limited by production costs, which have increased significantly over the past decade, as companies extract coal deposits that are deeper underground and further away from existing infrastructure. In addition, the costs of many inputs such as diesel, labour, explosives and machinery are expected to increase (BREE 2012c). The IEA average OECD thermal coal import price is used as a general proxy for international prices. It is assumed to rise slowly from around US$110 a tonne (2011 dollars) in 2015 to about US$115 a tonne in 2035. Coal prices increase less in percentage terms than oil and gas prices, partly because coal production costs are expected to rise less rapidly and because coal demand levels off by around 2025 (IEA 2012b). The WTI crude oil price averaged US$95 a barrel in 2011, an increase of 20 per cent from 2010. Higher 2011 prices were a result of supply disruptions in both the Oil and Petroleum Exporting Countries (OPEC) and non-OPEC regions and strong consumption growth in non-OECD countries (BREE 2012c). The IEA assumes that the average IEA crude oil import price – a proxy for international oil prices – rises to US$120 per barrel (in 2011 dollars) in 2020 and $125 a barrel in 2035. This rising price trend reflects the higher costs of producing oil from new sources, as existing fields are depleted (IEA 2012b).LNG prices in Asia Pacific markets are assumed to broadly follow a similar trajectory to oil prices. Increased reliance on local supplies of unconventional gas, notably in China, and on spot purchases of LNG are expected to exert some downward pressure on imported LNG prices (IEA 2012b). While oil indexation is likely to remain the dominant LNG pricing mechanism in Asia Pacific markets, there is considerable uncertainty about how international gas pricing will evolve. The share of spot and short-term trade in global LNG supply has been rising rapidly, and there are indications that spot trade is likely to continue its rise in the longer term. An expansion of spot trade in Asia would help to address one barrier to the adoption of hub-based pricing, as it would provide a sounder basis for a reliable benchmark spot price. Rising LNG supplies, increased short-term trading and greater operational flexibility are likely to


lead to increased price linkages between regions and, probably, a degree of price convergence. Opportunities to take advantage of regional price differentials will probably spur more trade between the Atlantic basin and Asia-Pacific markets, which traditionally have been largely distinct from each other. The construction of LNG liquefaction plants in North America, which would open up the possibility of exports to Asia, would help to connect prices between the two regions and accelerate the process of globalisation of natural gas markets (IEA 2012b).Domestic fuel costs, such as gas, black and brown coal, biomass and biogas are based on the fuel price projections to 2050 used in BREE’s Australian Energy Technology Assessment 2012 report (BREE 2012d). These fuel prices were provided by Acil Tasman.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 Australian Energy Technology Assessment (AETA) 2012 was released by BREE in July 2012. AETA 2012 provides the best available and most up-to-date cost estimates for 40 electricity generation technologies under Australian conditions, taking into consideration the impact of carbon pricing. These technologies encompass a diverse range of energy sources including renewable energy (such as wind, solar, geothermal, biomass and wave power), fossil fuels (such as coal and gas), and nuclear power. The cost estimates were generated on a ‘bottom up’ basis that accounted for the component costs that determine overall long-run marginal cost of electricity generation (LCOE) from a utility-scale and an Nth kind plant. The methods used to build up the cost estimates were applied consistently across all technologies and all the key assumptions used to generate the costs are fully detailed in the report and/or the accompanying AETA model.An integral component of the AETA that complements the AETA report is the AETA model that was developed to generate LCOE by state, by year and by technology. The AETA model, which is available from BREE, allows users to change many of the principal model parameters such as the capacity factor, the carbon price and discount rate.Key findings of the AETA 2012 include: Estimated costs of large-scale solar photovoltaic technologies have dropped dramatically

in the past two to three years, and by mid-2030s, it is the cheapest technology; Differences in the cost of generating electricity, especially between fossil fuel and

renewable electricity generation technologies, are expected to diminish over time; Biogas and biomass electricity generation technologies in 2012 are some of the most cost

competitive forms of electricity generation and are projected to remain cost competitive out to 2050;

From 2030 some renewable technologies, such as solar photovoltaic and wind on-shore, are expected to have the lowest LCOE of all of the evaluated technologies;

Among the non-renewable technologies, combined cycle gas (and in later years combined with carbon capture and storage) and nuclear power, offer the lowest LCOE over most of the projection period and they both remain cost competitive with the lower cost renewable technologies out to 2050; and

For some technologies, LCOE is projected to increase over time. This is because of a projected weakening of the Australian-dollar exchange rate from its current historic highs that will increase the cost of imported power plant components in Australian dollar terms and also because of projected increases in labour costs in excess of the consumer price index. In addition, for fossil-fuel technologies that generate CO2 emissions, increased costs are projected from assumed increases in the carbon price out to 2050.

Technology Comparisons of LCOE In AETA (2012) LCOE costs are provided for the years 2012, 2020, 2025, 2030, 2040, and

2050; Australian Energy Projections to 2050 • December 2012 • 36

Cost ranges are provided for each technology that accounts for differences in fuel prices, and state-based variations; and

LCOE costs vary substantially across the technologies from $91/MWh to $366/MWh in 2012 and $86/MWh to $288/MWh in 2050.

The AETA results are depicted in the figures below. Figure G compares LCOEs at 2030 with the 2012 LCOEs for each technology, for NSW (AETA developed LCOEs by each Australian state). The black line represents the LCOE in 2012 for currently available technologies while the bars represent the projected range of LCOEs in 2030. The red diamond are the carbon dioxide equivalent emissions per MWh of electricity for each technology. Differences are explained by a multiplicity of factors including the technical developments, learning rates or cost reductions, carbon prices, exchange rate effects, and fuel prices. The inter-technology LCOE comparisons figures (see Figures G and H) reveal changes in relative costs of technologies over time. Key results include: carbon capture and storage technologies become commercially available from 2030; between 2012 and 2020, except for biogas (land fill) and on-shore wind technologies, renewable technologies have higher LCOEs than the lowest cost non-renewable technologies; and the relative LCOE rankings significantly change post 2030. LCOEs of several renewable technologies become lower than the non-renewables, including CCS technologies, from mid 2030 onwards, and after the mid 2030s, several CCS and renewable technologies such as solar PV, on-shore wind, bioenergy, and CCS retrofit technologies become lower cost than non-renewable fossil fuel technologies without CCS under the assumed carbon price.

Figure G: LCOE for Technologies (NSW), 2030 compared with 2012


Source: BREE 2012dFigure H provides a relative ranking of technology LCOEs in 2040 for NSW. The figure illustrates how the LCOEs of various technologies rank against each other in 2040. The figure shows by 2040 large-scale solar PV is the lowest electricity generation cost technology.

Figure H: LCOE for Technologies (NSW), 2040Australian Energy Projections to 2050 • December 2012 • 38

Source: BREE 2012d


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 National Strategy on Energy Efficiency (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. In addition, some individual sectors such as transport are assigned a higher efficiency assumption than 0.5 per cent per year. Many of these individual assumptions are drawn from the Treasury (2011).Government policiesThe key policies that have been modelled explicitly in E4cast included the carbon price, and the Australian Government Renewable Energy Target (RET).The carbon price assumptions are set in reference to the Treasury modelling report (2011) . Table 5 shows the values provided by the Treasury modelling (2011) at 2009-10 prices. These prices were updated for 2012-13 dollars in the E4cast model. In 2012–13, the nominal carbon price is $23 a tonne, growing at 5 per cent a year in nominal terms. After three years, 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 2015, 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. Table 5: Carbon price assumptions, real, 2009–10 dollars

2012–13 212019–20 29.4

2029–30 52.6

2034–35 69.9

2049-50 131

Source: BREE calculations based on Treasury (2011)

The assumptions on global climate change policies are drawn from Treasury carbon price modelling (2011), where all developed countries simultaneously adopt carbon emission policies over the projection period, with developing countries joining in the long-term.

Renewable Energy Target (RET)The RET is designed to deliver on the Government’s commitment that the equivalent of 20 per cent of Australia’s electricity will come from renewable sources by 2020. The RET creates a guaranteed market for renewable energy deployment, using a mechanism of tradable certificates created by large-scale renewable energy generators and owners of small-scale solar panel, wind, and hydro systems. Demand for these certificates is created by placing a legal obligation on entities that buy wholesale electricity (mainly electricity retailers), to source and surrender certificates to the Clean Renewable Energy Regulator.The certificates are created by: The installation of solar water heaters, solar panels and small-scale wind and hydro

systems under the Small-scale Renewable Energy Scheme (SRES). These are known as Small-scale Technology Certificates (STCs); and

Renewable energy power stations under the Large-scale Renewable Energy Target (LRET). These are known as Large-scale Generation Certificates (LGCs).


Certificates are traded directly between power stations, RET liable entities, small-scale system owners, and other traders, through a self-regulated open market, where the daily price is set by market supply and demand.STCs may also be traded for a Government-guaranteed $40/STC via the STC Clearing House. The Clean Energy Regulator does not set the price of certificates (unless they are purchased through the STC Clearing House), nor does the Clean Energy Regulator receive any money from certificate sale, purchase, or surrender. The RET commenced in 2010 and requires 45 000 gigawatt hours of electricity be sourced from renewable energy sources by 2020. 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 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 182016 20.62017 25.22018 29.82019 34.42020 and onwards 41

Source: ORER (2011)

In E4cast, the renewable energy target 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.


4 Energy ConsumptionUnder the assumptions and policy settings outlined in section 3, the projections for Australian energy consumption over the period to 2049-50 are presented in this section. 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. This trend is expected to continue, with growth in energy consumption severely moderating over the projection period. Australia’s primary energy consumption is projected to increase at an average annual rate of 0.5 per cent from 6069 petajoules in 2012–13 to 7369 petajoules in 2049–50 (Table 7). The moderate growth in energy consumption is largely driven by two main factors. The first is the decline in the cost of renewable electricity generation technologies, and a substantial growth in the share of renewable electricity generation projected in this report. About 40 per cent of total primary energy is consumed in Australia to generate electricity. Fossil fuels (black and brown coal, gas and oil) use about three times more energy in producing one unit of electricity generation compared with renewable fuels (wind, solar, geothermal and water). The second factor behind the moderate growth in energy consumption is the effect of government policies. In particular, the RET and carbon pricing 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. Other reasons for the moderate growth in energy consumption in the current projections, compared to the previous projections (BREE 2011) included a slightly lower assumed GDP growth, lower electricity demand and hence generation growth, refinery capacity reduction, and lower LNG and coal export growth over the projection period. Each of these factors affect energy consumption.

Aggregate energy intensity trendsAustralia’s aggregate energy intensity (measured as total domestic energy consumption per dollar of GDP) declined at an average rate of 1.3 per cent a year between 1989–90 and 2009–10 (Che and Pham 2012). Over the period to 2049-50, Australia’s aggregate energy intensity is projected to decline by around 2.0 per cent a year. This indicates a considerable de-coupling of energy-GDP nexus, and a shift in Australia’s economic structure over this period. The major drivers of this trend are a step-change in renewable electricity generation costs over the projection period, and strong growth in less energy-intensive sectors, such as the commercial and services sector relative to energy-intensive sectors like manufacturing. Improved efficiency in other sectors through technological development and fuel switching will also contribute to this trend.

Primary energy consumption, by energy typeOver the projection period, the relative share of each energy type is expected to change significantly in response to changing electricity generation technology costs and changeable policy environment. Non-renewable energy is projected to fall from 95 per cent of the primary energy consumed in Australia in 2012–13 to 86 per cent by 2049-50. Over the projection period to 2049-50, the share of coal in total primary energy consumption is projected to sharply decline to 6 per cent from 31 per cent in 2012-13 (Table 7). By contrast, the share of gas is projected to increase to 34 per cent from 26 per cent in 2012-13. The share of renewables is also projected to significantly increase from 5 per cent of total primary energy use in 2012-13 to 14 per cent In 2049-50. Renewables are expected to exhibit the fastest growth among over the projection period, increasing by around 3.6 per cent a year to 1032 petajoules in 2049-50. This growth is driven


by increased use of renewables in electricity generation. Gas is expected to grow at the second highest rate of 1.3 per cent a year over the projection period to 2049-50. In previously published projections (eg. BREE 2011), gas had the highest projected growth rate among all fuels over the projections period. The fast growth in renewables is in sharp contrast to all previous projections, and reflects a marked shift to less carbon-intensive energy sources. The majority of this growth is at the expense of coal. With the cost of renewable electricity generation technologies declining over the projection period to 2050, much more renewable electricity (around 54 per cent, including roof-top electricity, by 2050, Table 12) is projected to be generated over the projection period than predicted in the earlier BREE energy projections studies (which was around 23 per cent by 2035). Given the higher thermal efficiencies of renewables (100 per cent) compared to fossil fuels (28 to 40 per cent), total energy consumption is commensurately reduced in electricity generation, and hence in the economy.

Table 7: Primary energy consumption, by energy type

Level Share

Average annual growth 2012-13

to2012-13 2034–35 2049-50 2012-13 2049–50 2049-50

Energy type PJ PJ PJ % % %Non-renewables

5 793 5 980 6 337 95 86 0.2

Coal 1 882 1 036 478 31 6 -3.6 black coal 1 212 962 478 20 6 -2.5 brown coal 670 74 0 11 0 -21.7Oil 2 359 2 888 3 391 39 46 1.0Gas 1 552 2 056 2 469 26 34 1.3Renewables 276 755 1 032 5 14 3.6Hydro 62 62 62 1 1 0.0Wind 51 231 282 1 4 4.7Bioenergy 149 299 346 2 5 2.3Solar 14 104 236 <1 3 7.8Geothermal 0 59 106 0 1

Total a 6 069 6 735 7 369 100 100 0.5a numbers in the table may not add up to their totals due to rounding

The bulk of the increase in renewables is expected to come from electricity generation using solar energy, wind energy, bioenergy (mainly biomass) and geothermal energy. Details regarding electricity generation are discussed in another sub-section.

Primary energy consumption, by state and territoryPrimary energy consumption is projected to increase in states and the Northern Territory over the period to 2049–50. 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 Northern Territory followed by Queensland, Western Australia and other states. State level energy consumption growth rates are underpinned by assumed economic growth, fuels used in the electricity generation in the state, the large contribution of the mining sector to economic output and the high degree of export orientation. Despite 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 1557 petajoules in 2012–13 to 1922 petajoules in 2049-50. Energy consumption in Victoria is projected to decline from 1498 petajoules in 2012–13 to 1263 petajoules in 2049–50. This is primarily due to the decline of the share of brown coal in Victoria to zero over the projection period. Growth in energy consumption is projected to be more moderate in South Australia and Tasmania driven by assumed lower economic growth.


Table 8: Primary energy consumption, by state and territory

Level Share

Average annual growth

2012-13 to

2012-13 2034-35 2049-50 2012-13 2049-50 2049-50

State/territory PJ PJ PJ % % %New South Wales a 1 557 1 726 1 922 26 26 0.6

Victoria 1 498 1 148 1 263 25 17 -0.5Queensland 1 322 1 787 1 988 22 27 1.1South Australia 373 389 422 6 6 0.3Western Australia 1 039 1 301 1 387 17 19 0.8Tasmania 164 186 189 3 3 0.4Northern Territory 117 195 198 2 3 1.4Australia b 6 069 6 735 7 369 100 100 0.5

a includes the Australian Capital Territory. b Numbers in the table may not add up to their totals due to rounding.

The effect of government policies on brown coal-fired electricity generation and other emission-intensive industries such as petroleum refining and chemicals will further contribute to the moderate growth in energy consumption.

Primary energy consumption, by sectorElectricity generation, transportation and manufacturing are estimated to account for 88 per cent of Australia’s total primary energy consumption in 2012–13. These sectors combined are projected to account for 77 per cent of projected primary energy consumption in 2049–50 (Table 9).The electricity generation sector accounts for the largest share (38 per cent) of primary energy consumption in 2012–13. Total primary energy consumption in electricity generation is projected to decline from 2293 petajoules in 2012–13 to 1927 petajoules in 2049–50. The combined effect of the RET, carbon pricing, and importantly the growth in renewables electricity generation are expected to encourage a change in the energy mix, with a significant shift away from coal to renewable energy. A shift away from fossil fuel electricity generation to renewable generation reduces fuel requirements by about one-third on average, because the thermal efficiency of renewable electricity generation is higher than for fossil fuels.In 2012–13, the transport sector (excluding electricity used in rail transport) accounted for 29 per cent 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 0.9 per cent. Growth in transport energy consumption will be offset by improved end-use efficiency in the sector, but still remain strong to 2049-50 and increase its share of primary energy consumption to 33 per cent by the end of the projection period.


Table 9: Primary energy consumption, by sector

Level Share


2012-13 to

2012-13 2034-35 2049-50 2012-13 2049-50 2049-50

Sector PJ PJ PJ % % %Electricity generation 2 293 1 996 1 927 38 26 -0.5

Agriculture 105 145 171 2 2 1.3Mining 310 899 1 089 5 15 3.5Manufacturing 1 268 1 256 1 332 21 18 0.1Transport 1 760 2 095 2 467 29 33 0.9Commercial & residential 333 344 385 5 5 0.4Australia a 6 069 6 735 7 369 100 100 0.5

a Numbers in the table may not add up to their totals due to rounding.

The manufacturing sector is the third largest user of primary energy in Australia and accounts for 21 per cent of the total in 2012–13. 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 0.1 per cent a year over the projection period, the relative share of the sector is expected to decline to 18 per cent. This reflects an ongoing structural shift away from energy-intensive manufacturing.Despite accounting for a relatively small proportion of total primary energy consumption (5 per cent in 2012–13), the mining sector is projected to exhibit the fastest energy consumption growth of 3.5 per cent a year to 2049–50. 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 (BREE 2012e) and the associated growth in primary energy consumption. In 2049–50, the sector is projected to account for 15 per cent of Australian primary energy consumption.

Electricity generationGross electricity generation in Australia is projected to increase at an average annual rate of 1.1 per cent from 253 terawatt hours (911 petajoules) in 2012–13 to 377 terawatt hours (1357 petajoules) in 2049–50 (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 are the electricity generation and market determined electricity flows across regions.New South Wales is likely to remain the largest producer of electricity, accounting for 37 per cent of total generation in 2049–50 and adding 67 terawatt hours to annual generation in 2049–50. It is also projected to export electricity to Victoria. South Australia is a small electricity generator in absolute terms. However, it is expected to exhibit strong growth in electricity generation, increasing at 1.5 per cent a year over the projection period. This growth is projected to be driven by the development of renewable energy generation in the


state, which is projected to grow at an average annual rate of 5 per cent. Strong growth is also expected in South Australia gas-fired electricity generation, increasing at a projected rate of 2.1 per cent a year.In Western Australia, electricity generation is projected to increase by 66 per cent from 30 terawatt hours in 2012–13 to 50 terawatt hours in 2049-50 (Table 10). Much of this expansion will come from growth in renewable and gas-fired electricity generation, which are projected to increase at an annual average rate of 4.8 per cent and 0.6 per cent, respectively. By contrast, electricity generation in Victoria is projected to decline at a rate of 0.3 per cent a year over the projection period to 2049–50. Electricity generation in Victoria is largely based on brown coal. The competitiveness of this energy source relative to other technologies is expected to diminish following the introduction of carbon pricing, and importantly due to a fall in the price of renewable electricity generation technologies, specifically solar energy. 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 (TWh)

Level Share


2012-13 to

2012-13 2034-35 2049-50 2012-13 2049-50 2049-50

State/territory % % %

New South Wales a 72 110 139 29 37 1.8Victoria 49 40 44 20 12 -0.3Queensland 67 82 85 26 22 0.7South Australia 18 26 30 7 8 1.5Western Australia 30 41 50 12 13 1.3Tasmania 14 22 25 5 7 1.6Northern Territory 3 4 4 1 1 1.1Australia b 253 324 377 100 100 1.1

a includes Australian Capital Territoryb numbers in the table may not add up to their totals due to rounding

Given the rapidly declining costs of renewable electricity generation technologies, and under a policy setting that includes the RET and 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 2012–13, 87 per cent of electricity is estimated to be generated from non-renewable sources (coal, oil and gas) with the balance coming from renewable energy sources (Table 11). Significant reductions in the cost of renewables electricity generation technologies in the long-run, and the incentives provided to generators under the RET are expected to be the major driver of the accelerated uptake of renewable technologies in the short term. 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 2050 in the energy mix, the introduction of carbon pricing will encourage a switch toward lower-emission energy sources. Black coal-fired generation is projected to decline by 2.2 per cent a year over the projection period. As a result, the share of coal in the energy mix is projected to decline from 60 per cent in 2012–13 to 13 per cent in 2049–50.While these results imply the partial or full closure of coal-fired capacity over the projection period, particularly for brown coal, there are a number of factors that may reduce this effect,


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. 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, coal and gas-fired electricity generation with CCS are projected to come online from mid 2030s (23 per cent by 2050) under the assumed carbon price modelled by Treasury.A significant development in the current set of projections is the huge growth in renewables generation from 34 TWh in 2012-13 to 194 TWh, or a shift in the share of renewable generation in the total electricity generation from 13 per cent in 2012-13 to 51 per cent in 2049–50 (excluding roof-top electricity). The latest set of electricity generation technology cost assessment by BREE (2012d) projects a rapid reduction in solar technology costs. The report finds that by mid 2030s, large scale solar PV technology will be the lowest cost electricity generation technology out of the 40 technologies assessed in the AETA 2012 report. AETA 2012 technology costs are the basis of current projections and explain the substantial growth in renewable energy electricity generation. Table 11: Electricity generation, by energy type (TWh)

Level Share


2012-13 to

2012-13 2034-35 2049-50 2012-13 2049-50 2049-50

Energy type % % %Non-renewables 219 194 183 87 49 -0.5Coal 153 104 48 60 13 -3.1 black coal 109 100 48 43 13 -2.2 brown coal 44 5 0 17 0

Gas 62 85 136 25 36 2.1Oil 4 4 0 2 0 -8.6Renewables 34 130 194 13 51 4.8Hydro 17 17 17 7 5 0.0Wind 14 64 78 6 21 4.7Bioenergy 2 7 7 1 2 3.9Solar 1 25 62 <1 16 12.3Geothermal 0 17 29 0 8

Total a 253 324 377 100 100 1.1

The share of renewable generation in total generation in 2019-20 is 22 per cent, above the target set by the RET scheme.As of October 2012, there were 170 major electricity projects around Australia at various stages of development, with a planned total capacity of around 39 281 MW. As of October 2012, there were 20 projects under construction or committed, with a total capacity of more than 3 017 MW and capital cost of $6.5 billion. This is equal to around 6 per cent of Australia’s existing generating capacity. There were fourteen advanced renewable energy projects, including 12 wind projects, one hydro upgrade project and one solar thermal project. The six non-renewable projects at an advanced stage included four gas-fired and two black coal-fired generation projects (Stanwix 2012).


Map 2: Advanced electricity generation projects, October 2012

Source: Stanwix (2012)

Gas-fired generation is based on mature technologies that are currently 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, particularly large-scale solar PV, become more cost effective by the 2030s. However, the cost competitiveness of gas-fired generation relies heavily on gas prices. The modelling of gas prices for this set of projections (based on AETA 2012 gas price assumptions) suggests that domestic gas prices are likely to increase over the period to 2049-50. 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 Queensland. This will be underpinned by a number of gas-fired generation projects under development or planned. Electricity generation from gas in Queensland is projected to significantly increase 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 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 2012–13 and 2049–50. Large-scale solar 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 12.3 per cent to 2049–50 (Table 11). Solar electricity generation is projected to account for 16 per cent of electricity


generation in 2049-50. The cost of large-scale solar PV technology has been declining rapidly over time and there is potential for the cost of solar technologies to continue to decline over the projection period because of the substantial research and development funds allocated toward these technologies, but particularly due to the advent of Chinese solar turbines production. This will contribute to enhanced solar electricity generation competitiveness over the period to 2020, and after 2030. In addition, the Australian Government has implemented a number of policies that are expected to increase the uptake of solar technologies.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 currently relatively cost competitive, notwithstanding site specific factors. Like solar energy, the competitiveness of wind energy will be enhanced by a reduction in the cost of turbines and further efficiency gains through turbine technology development (BREE 2012d).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 2012–13, bioenergy accounted for 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 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 3.9 per cent a year over the projection period, but will still account for only 2 per cent of total generation by 2049–50 (Table 11).Australia has large geothermal energy potential. However, these resources are currently considered sub-economic because geothermal technologies for electricity generation have not yet 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. Technological breakthroughs in assessment and well digging technologies are likely to make this technology more viable in the latter part of the projections period, and its share in total generation is likely to grow to 8 per cent by 2049-50 (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.Integration costs for variable renewablesThe cost of integrating intermittent energy sources into electricity grids is heavily dependent on their share of overall electricity supply and the overall mix of generation technologies. At low penetration levels (less than 5 per cent), integration costs are negligible. However, at wind penetration levels of 20 per cent, wind integration costs associated with balancing could increase the overall cost of electricity by $9/MWh (Denholm 2010). Table 11 shows that total renewable electricity generation amounts to 51 per cent of the grid generation. Out of these renewable sources, wind and solar PV constitute a total of 36 per cent of the total generation by 2049-50. The rest of the renewable sources such as hydro, geothermal and bioenergy are not intermittent generation.Reducing Integration CostsThe IEA (2011) work has identified a range of opportunities to reduce integration costs through the use of ‘flexible resources’. These flexible resources - which already exist in electricity grids to varying degrees - include quickly dispatchable conventional power plants (e.g. hydro power, OCGT), storage facilities (e.g. pumped hydro), demand side management and response, strengthened grid interconnection, wind forecasting and market design (e.g. intra-hour trading). Several of these flexible resources (e.g. increased OCGT capacity, improved wind forecasts, intra-hour trading) are already being utilised in Australian electricity markets.Several US studies (Denholm 2010, EPRI 2004) have concluded that the use of Compressed


Air Energy Storage (CAES) in conjunction with wind power could represent a cost effective option, particularly in situations where there is a significant carbon price and a large reliance (i.e. greater than 20 per cent) on wind power. Another US study (Mason 2008) has drawn similar conclusions in relation to the use of CAES with PV plants. In addition to maintaining system reliability by reducing load levelling and planning reserve requirements, CAES could also reduce transmission costs if these storage facilities were co-located with the wind power plants. Several studies (e.g. Denholm 2009) conclude that co-located wind-CAES plants could function as baseload power plants, achieving capacity factors of 90 per cent with less than 4 days of energy storage in some locations.Electricity generation with roof-top PV systemsOne of the factors influencing the growth in electricity demand in the NEM has been an increase in electricity generation by rooftop photovoltaic PV systems. As input to improved forecasting of electricity demand, AEMO has recently released forecasts of the installation of rooftop PV systems over the next 20 years to 2032. AEMO notes that these forecasts are based on moderate reductions in rooftop PV prices, moderate increases in retail electricity prices and moderate levels of government incentive.Several reports have concluded that rooftop PV will not defer network investment, which comprises approximately 50 per cent of retail electricity costs. Available evidence (NERA 2009, Ausgrid 2011) suggests that, in the majority of circumstances, distributed photovoltaic systems will not defer network investment. While photovoltaic output generally correlates with peak periods, the degree of correlation does not appear to be sufficient to avoid network augmentation and its associated costs. IPART concludes that any benefits are likely to be small and location- and time-specific (NSW Independent Pricing and Regulatory tribunal, IPART 2012).Solar roof-top PV was not included as a separate technology in the current projections which are confined to network generation. Nonetheless, following AEMO (2012), roof-top estimates are explicitly added to the electricity generation projections presented in Table 11. Table 12 presents total generation, and also Australia level solar roof-top generation.Table 12: Australian electricity generation (total generation and roof-top estimates), TWh

Level2012-13

Level2034-35

Level2034-35


2012-13 to 2049-50

Total generation (as in Table 11) Australian generation

253 324 377 1.1

including roof-top 256 342 398 1.2

AEMO (2012) published projections of solar roof-top generation up to 2031-32 for the NEM region. In Table 12, roof-top projections are obtained by extending NEM roof-top estimates to all Australia. Roof-top generation estimates between 2031-32 to 2049-50 were obtained by extending AEMO based projections for Australia in 2031-32 to 2049-50 at the rate of total generation growth to 2049-50 (1.1 per cent a year, Table 11).The share of renewable generation as a proportion of total generation is 51 per cent in 2049-50 (Table 11), but, rises to 54 per cent in 2049-50 in total Australian generation, including roof-top electricity estimates.

Final energy consumption, by energy typeTotal final energy consumption, the amount of energy used in end-use applications, is projected to increase from 4 207 petajoules in 2012–13 to 5 868 petajoules in 2049–50, a rise of 39 per cent over the projection period and an average annual rate of increase of 0.9 per cent (Table 13). Electricity (1.1 per cent) and renewable energy (1.4 per cent) 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 coal and gas in final energy


consumption by 2049–50 (from 3 per cent to 2 per cent, and from 22 per cent to 17 per cent, respectively). The decline in gas consumption is predominantly because of rising prices to 2049–50. The demand for petroleum products increases from growing mining and residential sectors. The consumption of renewables grows strongly at the rate of 1.4 per cent a year.


Table 13: Final energy consumption, by energy type

Level Share


2012-13 to

2012-13 2034-35 2049-50 2012-13 2049-50 2049-50

Energy type PJ PJ PJ % % %Coal 134 119 124 3 2 -0.2Petroleum products

2 180 2 709 3 241 52 55 1.1

Gas 908 912 1 006 22 17 0.3Renewables 134 185 224 3 4 1.4Electricity 851 1 091 1 272 20 22 1.1Total a 4 207 5 016 5 868 100 100 0.9

a numbers in the table may not add up to their totals due to rounding

Final energy consumption, by sectorThe transport and manufacturing sectors are the major drivers of Australia’s final energy consumption, accounting for 42 per cent and 30 per cent of final energy consumption in 2012–13, 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. However, the mining sector is projected to grow the strongest at 2.6 per cent a year over the projection period from 2012–13 to 2049–50.Table 14: Final energy consumption, by sector (PJ)

Level Share


2012-13 to

2012-13 2034-35 2049-50 2012-13 2049-50 2049-50

Sector PJ PJ PJ % % %Agriculture 113 154 180 3 3 1.3

Mining 257 456 663 6 11 2.6Manufacturing 1 252 1 302 1 397 30 24 0.3Transport 1 768 2 106 2 478 42 42 0.9Commercial & 817 999 1 150 19 20 0.9Total a 4 207 5 016 5 868 100 100 0.9


TransportFinal energy consumption in the transportation sector is projected to grow at an average rate of 0.9 per cent a year between 2012–13 and 2049-50. While the sector is expected to account for 43 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 2049–50 at 42 per cent. 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 2012–13, 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 per cent a year to 2049–50, driven by passenger and rail transportation. Energy use in the air transport sector (domestic and international) is projected to grow at 1.5 per cent a year to 380 petajoules in 2049–50. This is due to 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 2012–13 to 21 per cent in 2049–50.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 before 2030.

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. As 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 0.6 per cent of the Australian transport fuel supply in 2010–11. Electric vehicles may become commercially viable within the projection period, and at significant 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 with the share of the sector as a proportion of total final energy consumption at 30 per cent in 2012–13 (Table 14). Over the period to 2049-50, the sector is projected to grow at 0.3 per cent a year, supported by growth in the economy and on-going 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 (0.92 per cent a year). 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 24 per cent in 2049–50.Final energy consumption in non-ferrous metals is projected to grow at 0.3 per cent a year from 572 petajoules in 2012–13 to 633 petajoules in 2049-50 (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 increased the refinery’s annual production capacity by 1.1 million tonnes in 2012, while the expansion at Rio Tinto Alcan’s Yarwun refinery in Queensland increased capacity by 2 million tonnes in 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 0.9 per cent over the projection period to 58 petajoules in 2049–50. This, in part, reflects BlueScope Steel’s closure of capacity in New South Wales 2013. 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.Table 15: Final energy consumption, by manufacturing subsector

Level Share


2012-13 to

2012-13 2034-35 2049-50 2012-13 2049-50 2049-50Subsector PJ PJ PJ % % %Wood, paper & 75 85 99 6 7 0.7Basic chemicals 266 282 285 21 20 0.2Iron & steel 81 55 58 6 4 -0.9Non-ferrous metals 572 600 633 46 45 0.3Other 257 280 322 21 23 0.6Total a 1 252 1 302 1 397 100 100 0.3

a numbers in the table may not add up to their totals due to rounding

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 2012–13 to 11 per cent in 2049–50 (Table 13). The growth of 2.6 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 the mining industry.

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 19 per cent of total final energy consumption in 2012–13, and is projected to increase to 20 per cent in 2049–50. Energy use in the sector is projected to increase by 0.9 per cent a year to 1150 petajoules in 2049–50 (Table 13).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. However, there have been significant improvements in the energy efficiency standards and energy saving devices in buildings and appliances under various state and Federal government initiatives. Currently, the Australian Government is also investigating the merits of a possible national Energy Savings Initiative (ESI), to encourage the identification and take-up of energy efficient technologies. Schemes currently operate in New South Wales, Victoria and South Australia, and the Australian Capital Territory scheme will commence in January 2013 (RET 2012). AgricultureAgriculture accounts for a small proportion of final energy consumption, with a share of 3 per cent in 2012–13 that is projected to remain unchanged to 2049–50. Petroleum products are the major fuel used on farms. Energy use in the agriculture sector is projected to increase by 1.3 per cent a year to 2049–50 (Table 14).

5 Energy production and tradeCoal and gas are the major energy products in Australia on an energy content basis. In 2012-13 production of black and brown coal generated 12 333 petajoules (around 370 million tonnes) or 75 per cent of Australian energy production (excluding uranium). Gas accounts for 18 per cent of production, followed by crude oil, condensate and naturally occurring LPG (6 per cent) and renewable energy (hydro, wind, solar and bioenergy) 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. Table 16: Energy production, by source

Level Share


2012-13 to

2012-13 2034-35 2049-50 2012-13 2049-50 2049-50

Energy type PJ PJ PJ % % %Non-renewables

16 221 26 906 26 771 98 96 1.4

Coal 12 333 18 463 17 973 75 65 1.0 black coal 11 664 18 390 17 973 71 65 1.2 brown coal 670 74 0 4 0 -21.7Oil 775 252 98 5 <1 -5.4LPG 89 98 104 1 <1 0.4Gas 3 023 8 092 8 595 18 31 2.9Renewables 276 755 1 032 2 4 3.6Hydro 62 62 62 <1 <1 0.0Wind 51 231 282 <1 1 4.7Bioenergy 149 299 346 1 1 2.3Solar 14 104 236 0 1 7.8Geothermal 0 59 106 0 <1

Total 16 497 27 660 27 803 100 100 1.4


Australian energy production (excluding uranium) is projected to grow at an average annual rate of 1.4 per cent over the projection period. At this rate, total production of energy in Australia is forecast to grow from 16 497 petajoules in 2012–13 to 27 803 petajoules in 2049–50 (Table 16). Coal and gas are projected to account for 96 per cent of Australia’s energy production in 2049–50, supported by growth in export volumes. Coal production is projected to increase by 46 per cent to 17 973 petajoules (around 539 million tonnes), while gas production is projected to nearly triple to 8 595 petajoules (343 800 gigalitres).

With the exception of crude oil and refined petroleum products, Australia will remain a net exporter of energy commodities over the period to 2049-50. Demand for Australia’s energy resources is expected to remain robust over the projection period, particularly in China, India 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 their energy consumption. The ratio of Australia’s primary energy consumption to non-uranium energy production is projected to decline from 37 per cent in 2012-13 to 26 per cent in 2049–50 (Table 17).


Table 17: Australian energy balance

2012-13 2034-35 2049-50


2012-13 to 2049-50

PJ PJ PJ

Black coal Consumption 1 212 962 478 -2.5balance Exports 10 451 17 428 17 496 1.4

Production 11 664 18 390 17 973 1.2

Gas Consumption 1 552 2 056 2 469 1.3balance Exports 1 472 6 035 6 127 3.9

Production 3 023 8 092 8 595 2.9

Energy Consumption 6 069 6 735 7 369 0.5balance Exports 10 428 20 926 20 434 1.8

Production 16 497 27 660 27 803 1.4

Black coal production and exportsProduction of black coal, which includes thermal and metallurgical coal, is projected to grow at 1.2 per cent a year to 17 973 petajoules (around 538 million tonnes) in 2049-50. Despite this growth, the share of black coal in total energy production is projected to decline from 75 per cent in 2012–13 to 65 per cent in 2049-50 (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. As of October 2012, there were more than 60 million tonnes of additional coal production capacity committed, due to come on line over the next few years. Significant additional thermal coal capacity includes the Xstrata and Itochu Ravensworth North development, in New South Wales, which is expected to have an annual capacity of 8 million tonnes when completed in 2013; and the Xstrata and Mitsubishi Ulan West project in New South Wales (6.7 million tonnes a year) from 2014. Major new metallurgical coal production capacity includes the BHP Billiton Mitsubishi Alliance Daunia mine (4.5 million tonnes a year) in 2013 and Caval Ridge mine (8 million tonnes a year) in 2014; and the Anglo American Grosvenor underground project (5 million tonnes a year) in 2013, all in Queensland (BREE 2012e).Black coal will continue to be an important energy export for Australia, with coal projected to account for around two-thirds of the growth in net exports over the period to 2049-50, to reach 17 496 petajoules (around 585 million tonnes) (Table 18). The projected growth of 1.4 per cent a year is based on the expectation that the global demand for coal will continue to grow over the projection period, particularly in emerging market economies in Asia, driven by growing demand for electricity and steel-making raw materials. However, the rate of growth is expected to slow in the latter half of the projection period, as China’s coal demand plateaus (IEA 2012b). Australia, with its abundant reserves of high-quality coal, is well positioned to make a substantial contribution to meeting this increased demand. In particular, growth in global demand for metallurgical coal remains robust, as there is less scope for its replacement by other less carbon intensive fuels in steel making.The development of further infrastructure in New South Wales and Queensland will be required to support continued growth in coal exports. There are a number of port expansions committed and under construction. In Newcastle (New South Wales), these include the second and third stages of the Newcastle Coal Infrastructure Group (NCIG) terminal, which will lift capacity by 36 million tonnes annually by 2014. In Queensland, the Wiggins Island


Coal Export Terminal is scheduled for completion in 2014, which will increase export capacity by 27 million tonnes a year, while the BHP Billiton Mitsubishi Alliance Hay Point coal terminal is scheduled for completion in 2014 and will increase the port’s capacity by 11 million tonnes annually (BREE 2012e).


Table 18: Net trade in energy

LevelAverage annual

growth 2012-13 to2012-13 2034-35 2049-50 2049-50

Subsector PJ PJ PJ %Coal 10 451 17 428 17496 1.4Liquid fuelsa -1 495 -2 537 -3189 2.1LNG 1 472 6 035 6127 3.9Total 10 428 20 926 20434 1.8

a Includes crude oil, other refinery feedstock, petroleum products and LPG.

Natural gas production and LNG exportsAustralia has considerable resources of gas – both conventional and unconventional – that are increasingly being developed for domestic use and export. The significant gas resource base is capable of meeting domestic and export demand over the projection period. Australian gas production is projected to nearly triple from 3 023 petajoules in 2012-13 to 8 595 petajoules in 2049-50 (Table 19). The majority of Australia’s conventional gas resources are located off the north-west coast of Western Australia. As a result, the western market is the largest producing region in Australia and is expected to remain so over the next four decades. Gas production in the western market, including LNG, is projected to rise by 2.2 per cent a year from 1 777 petajoules in 2012–13 to 4 036 petajoules in 2049–50 (Table 19). 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. Those currently committed and under construction include Chevron, Shell and ExxonMobil’s Gorgon LNG project (15 million tonnes a year) from 2015; and Chevron, Apache, KUFPEK and Tokyo Electric’s Wheatstone (8.9 million tonnes a year initially) from 2016. The Shell Prelude Floating LNG project (3.6 million tonnes a year) in the Browse Basin is also due on line from 2016 (BREE 2012e).Gas production in the eastern market is projected to grow at 3.2 per cent a year to 3267 petajoules in 2049-50. A prominent feature of the eastern gas market is the increasing contribution of CSG to total production. In 2011–12, CSG accounted for 23 per cent of Australian gas production and around 80 per cent of production in Queensland (Energy Quest 2012; DNRM 2012). 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 significant proportion of this CSG will be consumed domestically, supporting growth in CSG-fired electricity generation, particularly in Queensland and New South Wales. Table 19: Australian gas production

Level Share


2012-13 to2012-13 2034-35 2049-50 2012-13 2049-50 2049-50

PJ PJ PJ % % %Eastern 1 006 2 836 3 267 33 38 3.2Western 1 777 3 982 4 036 59 47 2.2Northern 240 1 274 1 293 8 15 4.7Total 3 023 8 092 8 595 100 100 2.9

a includes imports from the Joint Petroleum Development Area, East Timor, JPDAAustralian Energy Projections to 2050 • December 2012 • 60

There are also several CSG to LNG export projects committed and under construction, around Gladstone. BG Group’s Queensland Curtis LNG project 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 (Santos, Petronas, Total, Kogas) is due on line in 2015, with capacity of 7.8 million tonnes a year. The Australia Pacific LNG project, being developed by Origin, ConocoPhillips and Sinopec, will have a capacity of 9 million tonnes a year from 2016 (BREE 2012e). Production in the northern gas market (including imports from the Joint Petroleum Development Area in the Timor Sea for processing in Darwin) is projected to increase from 240 petajoules in 2012–13 to reach 1293 petajoules in 2049-50, growing at an average rate of 4.7 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 new Ichthys processing plant (8.7 million tonnes a year from 2017) 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. At the beginning of January 2011, recoverable oil resources were around 7436 petajoules (1264 million barrels), largely located in the Carnarvon, Gippsland and Bonaparte basins (Geoscience Australia 2012). A significant proportion of Australia’s oil production is sourced from matured fields with declining oil reserves. However, there are many prospective offshore areas that have not been explored. In addition, there are technical developments taking place in oil exploration and drilling, which may enhance Australian oil production in hitherto unexplored or abandoned oil fields. In the United States, production of unconventional or light tight oil (oil produced from shale, or other very low permeability rocks, with technologies similar to those used to produce shale gas) has increased strongly in recent years (IEA 2012b). Australia also has significant unconventional oil resources, although there is no production currently occurring from these resources (Geoscience Australia and ABARE 2010). Given the uncertainty around the economics and potential development of Australia’s unconventional oil resources, they have not been included in these projections.Australia also has substantial resources of condensate (16 074 petajoules) and naturally occurring LPG (5654 petajoules) associated with the major gas fields on the North West Shelf in the Browse and Bonaparte basins (Geoscience Australia 2012).Australia’s crude oil and natural gas liquids production is projected to decline at an average rate of 3.8 per cent a year, from 864 petajoules in 2012–13 to 202 petajoules in 2049–50 (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 resources in existing and subsequently developed oil fields are assumed to deplete as the oil is extracted, which will result in lower production over the projection period. Production of naturally occurring LPG is projected to increase at an average annual rate of 0.4 per cent to 104 petajoules in 2049–50.

In 2011–12, Australia’s crude oil production was equivalent to around 60 per cent of refinery input. As a result, Australia was a net importer of crude oil. However, around 84 per cent of Australia’s crude oil and condensate production was exported, primarily to oil refineries in Asia (BREE 2012f).Australian consumption of liquid fuels is projected to increase slowly, from 1599 petajoules in 2012–13 to 1665 petajoules in 2049-50. 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 over the projection period given increasing competitive pressure, particularly from large South-East Asian refineries as evidenced by the announcements to curtail refining capacity in Australia in 2012-13 (Shell) and 2013-14 (Caltex). 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 consumes petroleum products as an input to convert oil feedstock into a range of petroleum products. Around 7 per cent of gross refinery output is consumed on-site in the conversion process, as well as small quantities of natural gas and electricity are also consumed.With assumed declining oil production, Australia’s net trade position for liquid fuels is set to decline, with net imports increasing by 2.1 per cent a year to 2049–50 (Table 18).

6 ConclusionsThe outlook presented in this report represents a significant structural change in Australia’s future energy landscape. The current projections show that Australian energy consumption will continue to grow over the next forty years, albeit at a much lower rate than experienced in the past twenty years. This is because of the substitution of renewables for fossil fuels in electricity generation – which require much less energy use to generate electricity – and because of expected energy efficiency improvements, as well as the global response to climate change and higher energy prices. The report also projects significant energy efficiency gains in the Australian energy sector.It is expected that the share of fossil fuels will decline from 87 per cent in 2012-13 to 49 per cent (including CCS fossil fuel technologies) of total electricity generation in 2049-50 (excluding AEMO based roof-top predictions). The share of fossil fuels in total primary consumption is projected to decline from 95 per cent in 2012-13 to 86 per cent in 2049-50. By 2049-50, three-quarter of electricity generation in Australia is projected to come from renewables and carbon capture and storage technologies.Within the non-renewables category, the share of gas is projected to increase in energy use and production. There is a significant increase in the use of gas (natural gas and coal seam gas), primarily for electricity generation – the largest user of primary energy, and LNG production. Gas-fired electricity generation is based on mature technologies with competitive cost structures relative to many renewable energy technologies. Thus, it has the potential to play a major role as a transitional fuel until lower-emission technologies become more cost effective in the short to medium term. Renewable energy is projected to have the strongest growth prospects. The highest growth trajectory is expected to apply to the lowest cost renewable energy sources – namely large-scale solar PV and wind energy and, to a lesser extent, geothermal energy. Transition to a low carbon economy will require long term structural adjustment in the Australian energy sector. While Australia has an abundance of energy resources, this transformation will need to be underpinned by significant investment in energy supply chains to allow for better integration of renewable energy sources and emerging technologies into our energy systems. It will be critical to ensure that the broader energy policy framework continues to support cost-effective investment in Australia’s energy future, and timely adjustments to market settings in response to emerging pressures, and market developments.


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