Australian
Energy
Projections
to 2049–50
December 2012
Arif Syed
Arif Syed 2012, Australian energy projections to 2049-50, Canberra, December.
© Commonwealth of Australia 2012
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978-1-922106-55-1 Australian Energy Projections (word)
Postal address:
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GPO Box 1564
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Email:
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Australian Energy Projections to 2050
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3
Acknowledgements
This 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.
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Foreword
This 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 fro m 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 t o
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 Grafton
Executive Director / Chief Economist
Bureau of Resources and Energy Economics
December 2012
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Contents
Acknowledgements
4
Foreword
5
Glossary
8
Units
10
Abbreviations
11
BREE contacts
12
Executive summary
13
1
Introduction
15
2
The Australian energy context
16
Energy resources
16
Australian energy production
17
Australian energy consumption
18
Australia’s energy exports
19
Energy policy
20
Methodology and key assumptions
23
3
The
4
5
6
E4cast
model
23
Key assumptions
27
Energy Consumption
35
Total primary energy consumption
35
Aggregate energy intensity trends
35
Primary energy consumption, by energy type
35
Primary energy consumption, by state and territory
36
Primary energy consumption, by sector
37
Electricity generation
38
Final energy consumption, by energy type
43
Final energy consumption, by sector
44
Energy production and trade
47
Natural gas production and LNG exports
49
Crude oil production and net imports
50
Conclusions
51
References
52
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Boxes
Box 1: Key features of E4cast
24
Maps
Map 1: Distribution of Australia’s energy resources
Map 2: Advanced electricity generation projects, October 2012
16
41
Figures
Figure 1: Projected electricity generation mix
Figure A: Australian energy production
Figure B: Energy intensity trends
Figure C: Australian primary energy consumption
Figure D: Australian energy exports
Figure E: Energy forecasting model
Figure F: Index of real world energy prices, 2011 dollars
Figure G: LCOE for Technologies (NSW), 2030 compared with 2012
Figure H: LCOE for Technologies (NSW), 2040
14
17
18
19
20
23
29
31
32
Tables
Table 1: Fuel coverage in E4cast
25
Table 2: Industry coverage in E4cast
26
Table 3: Australian population assumptions
27
Table 4: Australian economic growth, by region
28
Table 5: Carbon price assumptions, real, 2009–10 dollars
33
Table 6: LRET renewable electricity generation target (excluding existing
34
renewable generation)
Table 7: Primary energy consumption, by energy type
36
Table 8: Primary energy consumption, by state and territory
37
Table 9: Primary energy consumption, by sector
38
Table 10: Electricity generation, by state and territory (TWh)
39
Table 11: Electricity generation, by energy type (TWh)
40
Table 12: Australian electricity generation (total generation and roof -top estimates), TWh
Table 13: Final energy consumption, by energy type (PJ)
44
Table 14: Final energy consumption, by sector (PJ)
44
Table 15: Final energy consumption, by manufacturing subsector (PJ)
46
Table 16: Energy production, by source
47
Table 17: Australian energy balance
48
Table 18: Net trade in energy (PJ)
49
Table 19: Australian gas production
49
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7
Glossary
Bagasse
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 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
Australian Energy Projections to 2050
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8
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 us e 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.
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Units
Metric units
Standard metric prefixes
J
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 conversions
1 barrel = 158.987 L
1 mtoe (million tonnes of oil equivalent) = 41.868 PJ
1 kWh = 3600 kJ
1 MBTU (million British thermal units) = 1055 MJ
1 m 3 (cubic metre) = 35.515 f 3 (cubic feet)
1 L LPG (liquefied petroleum gas) = 0.254 m 3 natural gas
Conversion factors are at a temperature of 15°C and pressure of 1 atmosphere.
Indicative energy content conversion factors
Black coal production
30 GJ/t
Brown coal
9.8 GJ/t
Crude oil production
37 MJ/L
Naturally occurring LPG
26.5 MJ/L
LNG exports
54.4 GJ/t
Natural gas (gaseous production equivalent)
40 MJ/kL
Biomass
11.9 GJ/t
Hydroelectricity, wind and solar energy
3.6 TJ/GWh
Conventions used in tables
Small discrepancies in totals are generally the result of the rounding of components.
Australian Energy Projections to 2050
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Abbreviations
AEMO Australian Energy Market Operator
AETA Australian Energy Technology Cost Assessment
BREE Bureau of Resources and Energy Economics
CCS
Carbon Capture and Storage/Sequestration
CSG
Coal Seam Gas
IEA
International Energy Agency
LCOE Levelised Cost of Electricity
LNG
Liquefied Natural Gas
LRET
Large-scale Renewable Energy Target
NFEE National Framework for Energy Efficiency
NGER National Greenhouse and Energy Reporting
NSEE National Strategy on Energy Efficiency
PV
Photovoltaic
RET
Renewable Energy Target
SRES Small-scale Renewable Energy Scheme
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BREE contacts
Executive Director/
Chief Economist – BREE
Deputy Chief Economist/
Research Director (A/g)
Professor Quentin Grafton [email protected]
02 6276 1000
Roger Rose
Modelling & Policy integration
Program Leader
Dr Arif Syed
[email protected]
02 6243 7583
[email protected]
02 6243 7504
Energy Program
Program Leader
Dr Nhu Che
[email protected]
02 6243 7539
Data & Statistics Program
Program Leader
Geoff Armitage
[email protected]
02 6243 7510
Resources Program
Program Leader (A/g)
John Barber
[email protected]
02 6243 7988
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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 longterm 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 shar e 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 o f 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 efficie nt 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.
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

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 base d 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.
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Australian Energy Projections to 2050
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1 Introduction
The 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, w ith 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.
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2 The Australian energy context
Energy resources
Australia 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
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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 production
Australia 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.
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Australian energy consumption
Australia 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 o f 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).
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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.
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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 policy
Energy 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 wellregulated markets operating in the long-term interests of consumers and the nation (Australian
Government 2012).
Energy White Paper 2012
The 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 transf ormation in
the way it produces and uses energy.
The Energy White Paper identifies four priority action areas to support Australia’s energy transformation:
1.
2.
3.
4.
delivering better energy market outcomes for consumers;
accelerating our clean energy transformation;
developing Australia’s critical energy resources, particularly gas resources; and
strengthening the resilience of Australia’s energy policy framework.
Further details on specific areas of action around these priorities c an be found at:
www.ret.gov.au/energy/facts/white_paper/Pages/energy_white_paper.aspx
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Australian Energy Projections to 2050
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Clean Energy Future Plan
Through 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 th eir
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 sche me 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 Target
The 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), and
2. 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).
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Energy Efficiency
The 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 th rough 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).
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3 Methodology and key assumptions
The 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 model
The 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
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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.
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Table 1: Fuel coverage in E4cast
Black coal
Brown coal
Coal by-products
- coke oven gas
- blast furnace gas
Coke
Natural gas
Coal seam gas
Oil (crude oil and condensate)
Liquefied petroleum gas (LPG)
Other petroleum products
Electricity
Solar (solar hot water)
Solar electricity (solar photovoltaic and solar thermal)
Biomass (bagasse, wood and wood waste)
Biogas (sewage and landfill gas)
Hydroelectricity
Wind energy
Geothermal energy
Ocean energy
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Table 2: Industry coverage in E4cast
Sectors/sub-sectors
ANZSIC code
Conversion
Coke oven operations
2714
Blast furnace operations
2715
Petroleum refining
2510, 2512-2515
Petrochemicals
na
Electricity generation
361
End use
Agriculture
Division A
Mining
Division B
Manufacturing
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
Transport
na
Division I (excludes sectors 66 and 67)
Road transport
61
Passenger motor vehicles
na
Other road transport
na
Railway transport
62
Water transport
63
Domestic water transport
6301
International water transport
6302
Air transport
64
Domestic air transport
na
International air transport
na
Pipeline transport
Commercial and services
6501
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
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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 projection s as it is not
consumed in Australia and, therefore, does not affect the domestic energy balance.
E4cast base year data
The 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 Ener gy
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 assumptions
There 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 growth
Population 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
population
millions
2012-13
23.35
2034-35
31.19
2049-50
36.26
Source: Treasury (2011)
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Economic growth
The 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 b asic
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
2.4
Victoria
2.4
Queensland
2.9
South Australia
2
Western Australia
2.9
Tasmania
1.7
Northern Territory
2.6
Australia
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.
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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 co mpanies 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 price s, 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
Australian Energy Projections to 2050
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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 technologies
Australia 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;
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.
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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
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Source: BREE 2012d
Figure 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), 2040
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Source: BREE 2012d
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End use energy technologies
End 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 policies
The 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
21
2019–20
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).
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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 hou seholds 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
TWh
2011
10.4
2012
16.3
2013
18.2
2014
16.1
2015
18
2016
20.6
2017
25.2
2018
29.8
2019
34.4
2020 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.
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4 Energy Consumption
Under 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 consumption
Growth 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 pe riod. Each of these
factors affect energy consumption.
Aggregate energy intensity trends
Australia’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 type
Over 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 o f 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 carbonintensive 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
Australian Energy Projections to 2050
•
December 2012 •
38
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
Average annual
growth 2012-13
to
Share
2012-13
2034–35
2049-50
2012-13
2049–50
2049-50
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
1 212
962
478
20
6
-2.5
670
74
0
11
0
-21.7
Oil
2 359
2 888
3 391
39
46
1.0
Gas
1 552
2 056
2 469
26
34
1.3
276
755
1 032
5
14
3.6
Hydro
62
62
62
1
1
0.0
Wind
51
231
282
1
4
4.7
149
299
346
2
5
2.3
14
104
236
<1
3
7.8
0
59
106
0
1
6 069
6 735
7 369
100
100
Energy type
black coal
brown coal
Renewables
Bioenergy
Solar
Geothermal
Total a
0.5
a 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 territory
Primary 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.
Australian Energy Projections to 2050
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December 2012 •
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Australian Energy Projections to 2050
•
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40
Table 8: Primary energy consumption, by state and territory
Level
Average
annual
growth
2012-13
to
Share
2012-13
2034-35
2049-50
2012-13
2049-50
2049-50
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
-0.5
Queensland
1 322
1 787
1 988
22
27
1.1
373
389
422
6
6
0.3
1 039
1 301
1 387
17
19
0.8
Tasmania
164
186
189
3
3
0.4
Northern Territory
117
195
198
2
3
1.4
6 069
6 735
7 369
100
100
0.5
State/territory
South Australia
Western Australia
Australia b
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 sector
Electricity 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.
Australian Energy Projections to 2050
•
December 2012 •
41
Table 9: Primary energy consumption, by sector
Level
Average
annual
growth
2012-13
to
Share
2012-13
2034-35
2049-50
2012-13
2049-50
2049-50
PJ
PJ
PJ
%
%
%
2 293
1 996
1 927
38
26
-0.5
Agriculture
105
145
171
2
2
1.3
Mining
310
899
1 089
5
15
3.5
Manufacturing
1 268
1 256
1 332
21
18
0.1
Transport
1 760
2 095
2 467
29
33
0.9
333
344
385
5
5
0.4
6 069
6 735
7 369
100
100
0.5
Sector
Electricity generation
Commercial & residential
Australia a
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 ong oing 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 growt h 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 generation
Gross 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.
Australian Energy Projections to 2050
•
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42
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
2012-13
Average
annual
growth
2012-13
to
Share
2034-35
2049-50
2012-13
2049-50
2049-50
%
%
%
State/territory
New South Wales a
72
110
139
29
37
1.8
Victoria
49
40
44
20
12
-0.3
Queensland
67
82
85
26
22
0.7
South Australia
18
26
30
7
8
1.5
Western Australia
30
41
50
12
13
1.3
Tasmania
14
22
25
5
7
1.6
3
4
4
1
1
1.1
253
324
377
100
100
1.1
Northern Territory
Australia b
a includes Australian Capital Territory
b 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
Australian Energy Projections to 2050
•
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43
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
2012-13
Average
annual
growth
2012-13
to
Share
2034-35
2049-50
2012-13
2049-50
2049-50
%
%
%
Energy type
Non-renewables
219
194
183
87
49
-0.5
Coal
153
104
48
60
13
-3.1
black coal
109
100
48
43
13
-2.2
brown coal
44
5
0
17
0
62
85
136
25
36
2.1
4
4
0
2
0
-8.6
Renewables
34
130
194
13
51
4.8
Hydro
17
17
17
7
5
0.0
Wind
14
64
78
6
21
4.7
Bioenergy
2
7
7
1
2
3.9
Solar
1
25
62
<1
16
12.3
Geothermal
0
17
29
0
8
253
324
377
100
100
Gas
Oil
Total a
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).
Australian Energy Projections to 2050
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44
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
Australian Energy Projections to 2050
•
December 2012 •
45
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 gener ation 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 renewables
The 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 Costs
The 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 intercon nection, 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 rese rve 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
Australian Energy Projections to 2050
•
December 2012 •
46
some locations.
Electricity generation with roof-top PV systems
One 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
Average
annual growth
Level
2012-13 to
2034-35
2049-50
Level
2012-13
Level
2034-35
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 type
Total 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 stro ngly 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.
Australian Energy Projections to 2050
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Table 13: Final energy consumption, by energy type
Level
Average
annual
growth
2012-13 to
Share
2012-13
2034-35
2049-50
2012-13
2049-50
2049-50
PJ
PJ
PJ
%
%
%
134
119
124
3
2
-0.2
2 180
2 709
3 241
52
55
1.1
Gas
908
912
1 006
22
17
0.3
Renewables
134
185
224
3
4
1.4
Electricity
851
1 091
1 272
20
22
1.1
4 207
5 016
5 868
100
100
0.9
Energy type
Coal
Petroleum
products
Total a
a numbers in the table may not add up to their totals due to rounding
Final energy consumption, by sector
The 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
Average
annual
growth
2012-13
to
Share
2012-13
2034-35
2049-50
2012-13
2049-50
2049-50
PJ
PJ
PJ
%
%
%
Agriculture
113
154
180
3
3
1.3
Mining
257
456
663
6
11
2.6
Manufacturing
1 252
1 302
1 397
30
24
0.3
Transport
1 768
2 106
2 478
42
42
0.9
817
999
1 150
19
20
0.9
4 207
5 016
5 868
100
100
0.9
Sector
Commercial &
residential
Total a
Australian Energy Projections to 2050
•
December 2012 •
48
Transport
Final 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 c ent 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-toliquids, 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.
Manufacturing
The 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 sector s (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
Australian Energy Projections to 2050
•
December 2012 •
49
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 restr ucture
aimed at returning it to a profitable generation level.
Table 15: Final energy consumption, by manufacturing subsector
Level
Average
annual
growth
2012-13 to
Share
2012-13
2034-35
2049-50
2012-13
2049-50
2049-50
Subsector
PJ
PJ
PJ
%
%
%
Wood, paper &
printing
Basic chemicals
75
85
99
6
7
0.7
266
282
285
21
20
0.2
81
55
58
6
4
-0.9
Non-ferrous metals
572
600
633
46
45
0.3
Other manufacturing
257
280
322
21
23
0.6
1 252
1 302
1 397
100
100
0.3
Iron & steel
Total a
a numbers in the table may not add up to their totals due to rounding
Mining
While 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 residential
The 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 residentia l 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 enc ourage 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).
Agriculture
Australian Energy Projections to 2050
•
December 2012 •
50
Agriculture 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 trade
Coal 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
Average
annual
growth
2012-13 to
Share
2012-13
2034-35
2049-50
2012-13
2049-50
2049-50
Energy type
PJ
PJ
PJ
%
%
%
Nonrenewables
16 221
26 906
26 771
98
96
1.4
Coal
12 333
18 463
17 973
75
65
1.0
11 664
18 390
17 973
71
65
1.2
670
74
0
4
0
-21.7
775
252
98
5
<1
-5.4
LPG
89
98
104
1
<1
0.4
Gas
3 023
8 092
8 595
18
31
2.9
276
755
1 032
2
4
3.6
Hydro
62
62
62
<1
<1
0.0
Wind
51
231
282
<1
1
4.7
149
299
346
1
1
2.3
14
104
236
0
1
7.8
0
59
106
0
<1
16 497
27 660
27 803
100
100
black coal
brown coal
Oil
Renewables
Bioenergy
Solar
Geothermal
Total
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).
Australian Energy Projections to 2050
•
December 2012 •
51
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, whic h 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).
Australian Energy Projections to 2050
•
December 2012 •
52
Table 17: Australian energy balance
Average annual
growth
2012-13 to 2049-50
2012-13
2034-35
2049-50
PJ
PJ
PJ
1 212
962
478
-2.5
Black coal
Consumption
balance
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
1.3
balance
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
0.5
balance
Exports
10 428
20 926
20 434
1.8
Production
16 497
27 660
27 803
1.4
Black coal production and exports
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 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 It ochu
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 milli on 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
Australian Energy Projections to 2050
•
December 2012 •
53
million tonnes annually (BREE 2012e).
Australian Energy Projections to 2050
•
December 2012 •
54
Table 18: Net trade in energy
Average annual growth
2012-13 to
Level
2012-13
2034-35
2049-50
2049-50
PJ
PJ
PJ
%
Coal
10 451
17 428
17496
1.4
Liquid fuels a
-1 495
-2 537
-3189
2.1
LNG
1 472
6 035
6127
3.9
Total
10 428
20 926
20434
1.8
Subsector
a Includes crude oil, other refinery feedstock, petroleum products and LPG.
Natural gas production and LNG exports
Australia 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 wil l be
consumed domestically, supporting growth in CSG-fired electricity generation, particularly in Queensland
and New South Wales.
Table 19: Australian gas production
Level
Average
annual growth
2012-13 to
Share
2012-13
2034-35
2049-50
2012-13
2049-50
2049-50
PJ
PJ
PJ
%
%
%
Eastern market
1 006
2 836
3 267
33
38
3.2
Western market
1 777
3 982
4 036
59
47
2.2
Northern market
240
1 274
1 293
8
15
4.7
3 023
8 092
8 595
100
100
2.9
Total
a includes imports from the Joint Petroleum Development Area, East Timor, JPDA
There are also several CSG to LNG export projects committed and under construction, around Gladstone.
Australian Energy Projections to 2050
•
December 2012 •
55
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 imports
Australia’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 resourc es, 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 p eriod. 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 consump tion.
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.
Australian Energy Projections to 2050
•
December 2012 •
56
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 de cline, with
net imports increasing by 2.1 per cent a year to 2049–50 (Table 18).
6 Conclusions
The 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 f uel until loweremission 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.
Australian Energy Projections to 2050
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December 2012 •
57
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Australian Energy Projections to 2050
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