Australian energy
projections to
2034–35
December 2011
Arif Syed and Kate Penney
© Commonwealth of Australia 2011
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BREE 2011, Australian energy projections to 2034–35, BREE report prepared for the Department of Resources, Energy and Tourism, Canberra,
December.
ISBN 978-1-921812-79-8 (Print)
ISBN 978-1-921812-78-1 (Online)
Postal address:
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GPO Box 1564
Canberra ACT 2601
Phone:
Email:
Web:
+61 2 6276 1000
info@bree.gov.au
www.bree.gov.au
From 1 July 2011, responsibility for resources and energy data and research was transferred from the Australian Bureau of Agr icultural and
Resource Economics and Sciences (ABARES) to the Bureau of Resources and Energy Economics (BREE).
Acknowledgements
This report was undertaken with the support of the Australian Government
Department of Resources, Energy and Tourism.
The valuable contribution of BREE colleagues; Trish Gleeson and Sally Thorpe of ABARES;
Bruce Wilson, Shane Bush and Sarah Hill from the Department of Resources, Energy and Tourism; Brendan
Mckenna and Sebastian Wende of the Australian Treasury; and colleagues at the Department of Climate Change
and Energy Efficiency is appreciated.
2
Foreword
In this report the Bureau of Resources and Energy Economics (BREE) presents its inaugural set of long -term
projections of Australian energy consumption, production and trade. The analysis covers the period from 2008–09
to 2034–35 and is prepared using BREE’s E4cast model. It is intended that this information will support decisionmaking by industry, government and the broader community. The results suggest that the Au stralian energy sector
is at an important crossroads as it adjusts to a carbon-constrained economy.
The dynamics of energy markets and uncertainties with respect to future energy costs make
long-term energy projections difficult. Nevertheless, projections are needed to guide decision makers about
investments and the impacts of energy policies and energy outcomes.
BREE’s projections provide this guidance and will assist decision-makers to deliver an efficient, secure and
sustainable energy future for Australia.
Quentin Grafton
Executive Director / Chief Economist
December 2011
3
Contents
Summary
1 Introduction
2 The Australian energy context
Energy resources and markets
Energy policy
Clean Energy Future Plan
Other initiatives
3 Methodology and key assumptions
The E4cast model
E4cast base year data
Key assumptions
4 Energy Consumption
Total primary energy consumption
Primary energy consumption, by energy type
Primary energy consumption, by state and territory
Primary energy consumption, by sector
Electricity generation
Final energy consumption, by energy type
Final energy consumption, by sector
5 Energy production and trade
Black coal production and exports
Natural gas production and LNG exports
Crude oil production and net imports
6 Conclusions
References
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Boxes
Box
Box
Box
Box
Box
Box
Box
1: Other Clean Energy Future initiatives
2: Key features of E4cast
3: Australian energy statistics
4: Carbon capture and storage
5: Uncertainty surrounding gas prices for electricity generation
6: Energy use in the Australian transport sector
7: Australian uranium outlook
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Figures
Figure A: Australian energy production
15
Figure B: Energy intensity trends
16
Figure C: Australian energy exports
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Figure D: Energy forecasting model
21
Figure E: Index of world real energy prices, 2008–09 dollars
27
Figure F: Index of real levelised cost of electricity generation technologies excluding
carbon costs
29
Figure G: Australian uranium production
46
Figure H: Australian energy balance
47
Figure I: Australian black coal balance
48
Figure J: Australian gas balance
49
Figure K: Australian oil and LPG balance
50
Tables
Table 1: Fuel coverage in E4cast
Table 2: Industry coverage of E4cast
Table 3: Australian population assumptions
Table 4: Australian economic growth, by region
Table 5: Carbon price assumptions, real, 2009–10 dollars
Table 6: LRET renewable electricity generation target (excluding existing
renewable generation)
Table 7: Primary energy consumption, by energy type
Table 8: Primary energy consumption, by state and territory
Table 9: Primary energy consumption, by sector
Table 10: Electricity generation, by state and territory
Table 11: Electricity generation, by energy type a
Table 12: Electricity generation, with alternative gas price assumptions,
by energy source
Table 13: Final energy consumption, by energy type
Table 14: Final energy consumption, by sector
Table 15: Final energy consumption, by manufacturing subsector
Table 16: Energy production, by source
Table 17: Net trade in energy
Table 18: Australian gas production
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Maps
Map 1: Distribution of Australia’s energy resources
Map 2: Advanced electricity generation projects, October 2011
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38
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 noncommercial 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
6
met to breakeven over the lifetime of a plant.
Lignite
Non-agglomerating coals with a gross calorific value
less than 17 435 kilojoules a kilogram, including
brown coal which is generally less than 11 000
kilojoules a kilogram.
Liquid fuels
All liquid hydrocarbons, including crude oil,
condensate, liquefied petroleum gas and other
refined petroleum products, and liquid biofuels.
Natural gas
Methane that has been processed to remove
impurities to a required standard for consumer use. It
may contain small amounts of ethane, propane,
carbon dioxide and inert gases such as nitrogen.
Landfill and sewage gas are some other potential
sources (also referred to as sales gas in some
sectors of the gas industry).
Petajoule
The joule is the standard unit of energy in electronics
and general scientific applications. One joule is the
equivalent of one watt of power radiated or dissipated
for one second. One petajoule, or 278 gigawatt
hours, is the heat energy content of about 43 000
tonnes of black coal or 29 million litres of petrol.
Petroleum
Crude oil and natural gas condensate used directly
as fuel, liquefied petroleum gas, refined products
used as fuels (aviation gasoline, automotive gasoline,
power kerosene, aviation turbine fuel, lighting
kerosene, heating oil, automotive diesel oil, industrial
diesel fuel, fuel oil, refinery fuel and naphtha) and
refined products used in nonfuel applications
(solvents, lubricants, bitumen, waxes, petroleum
coke for anode production and specialised
feedstocks).
In this report, all petroleum products are defined as
primary fuels even though most petroleum products
are transformed (refined). The distinction between
the consumption of petroleum at the primary and final
end use stages relates only to where the petroleum is
consumed, not to the mix of different petroleum
products consumed. The consumption of petroleum
at the primary energy use stage is referred to
collectively as oil, while the consumption of
petroleum at the final end use stage is referred to as
petroleum products.
The one exception to this is liquefied petroleum gas
(LPG). LPG is not included in the definition of end
use consumption of petroleum because it is modelled
separately.
7
Primary fuels
The forms of energy obtained directly from nature.
They include non-renewable fuels such as black coal,
brown coal, uranium, crude oil and condensate,
naturally occurring liquid petroleum gas, ethane and
gas, and renewable fuels such as wood, bagasse,
hydroelectricity, wind and solar energy.
Secondary fuels
Fuels produced from primary or other secondary (or
derived) fuels by conversion processes to provide the
energy forms commonly consumed. They include
refined petroleum products, thermal electricity, coke,
coke oven gas, blast furnace gas and briquettes.
Total final energy
consumption
The total amount of energy consumed in the final or
end use sectors. It is equal to total primary energy
consumption less energy consumed or lost in
conversion, transmission and distribution.
Total primary energy
The total of the consumption of each primary fuel (in
energy units) in both the conversion and end use
sectors. It includes the use of primary fuels in
conversion activities—notably the consumption of
fuels used to produce petroleum products and
electricity. It also includes own use and losses in the
conversion sector.
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.
8
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.
Abbreviations
ABARES
Australian Bureau of Agricultural and Resource Economics and Sciences
AEMO
Australian Energy Market Operator
BREE
Bureau of Resources and Energy Economics
CCS
Carbon Capture and Storage/Sequestration
COAG
Council of Australian Governments
CSG
Coal Seam Gas
GHG
Greenhouse Gas
IEA
International Energy Agency
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
OECD
Organisation for Economic Cooperation and Development
ORER
Office of the Renewable Energy Regulator
PV
Photovoltaic
RET
Renewable Energy Target
SRES
Small-scale Renewable Energy Scheme
9
BREE contacts
Executive Director/
Chief Economist – BREE
Quentin Grafton
quentin.grafton@bree.gov.au
02 6276 7483
General Manager
Jane Melanie
jane.melanie@bree.gov.au
02 6243 7502
Micro & Industry Performance Analysis
Theme Leader
Arif Syed
arif.syed@bree.gov.au
02 6243 7504
Macro & Markets Analysis
Theme Leader
Jin Liu
jin.liu@bree.gov.au
02 6243 7513
Resources Program
Program Leader
Alan Copeland
alan.copeland@bree.gov.au
02 6243 7501
Quantitative Economic Analysis
Theme Leader
Nhu Che
nhu.che@bree.gov.au
02 6243 7539
Energy Program
Program Leader
Allison Ball
allison.ball@bree.gov.au
02 6243 7500
Data & Statistics Program
Program Leader
Geoff Armitage
geoff.armitage@bree.gov.au
02 6243 7510
10
Summary

This report delivers BREE’s inaugural long-term projections of Australian energy consumption, production
and trade over the period to 2034–35. These projections are not intended as predictions or forecasts, but as
indicators of potential changes in Australian energy consumption, production and trade patterns given the
assumptions used in the report.

Relevant government policies that have been introduced or enacted have been incorporated into BREE’s
assumptions. This includes the Renewable Energy Target (RET) and the introduction of carbon pricing in
2012.
The assumptions around carbon emission reduction policies included in the E4cast model are based on the
Australian Treasury’s publication, Strong growth, low pollution: modelling a carbon price, released in 2011.
The transitional arrangements and targeted investment programs included in the Clean Energy Future plan
have not been included specifically in the modelling assumptions. Given the uncertainty surrounding future
domestic gas prices, a sensitivity analysis was undertaken to assess the effect of higher gas prices on the
electricity generation mix.

Energy consumption


Total primary energy consumption is projected to grow by around 29 per cent (1 per cent a year) over the
projection period (2008–09 to 2034–35). This moderate growth reflects a long-term decline in the energy
intensity of the Australian economy which has been accelerated by a number of policy drivers.
The share of coal in total primary energy consumption is projected to decline, with oil and gas projected to
be the dominant energy sources used.

Gas is expected to exhibit the fastest growth among non-renewable energy sources, increasing by an
average 3 per cent a year to 2611 petajoules in 2034–35.

The share of renewable energy is projected to increase from 5 per cent of total primary energy consumption
in 2008–09 to 9 per cent of total primary energy consumption in 2034–35. This implies an average annual
growth rate of 3.4 per cent, with the most significant growth occurring in wind energy.

Western Australia, the Northern Territory and Queensland are expected to exhibit the highest growth in
primary energy consumption. These regions are expected to achieve higher economic growth relative to
other states, based on the large contribution of the mining sector and the high degree of export orientation.
The electricity generation and transport sectors will remain the two main users of primary energy, together
accounting for 63 per cent of projected primary energy consumption in 2034 –35.


The share of primary energy consumed by the electricity generation sector is expected to decline over the
projection period as the effects of the RET and the implementation of carbon pricing are expected to
encourage a change in the energy mix.

The transport sector accounts for around one quarter of primary energy consumption, and this share is
projected to remain relatively constant out to 2034–35. Growth in transport is coupled with improving enduse efficiency, which is expected to have a moderating effect on energy consumption.

The fastest growing consumer of primary energy will be the mining sector, with average growth of 5.2 per
cent a year expected over the projection period.
Electricity generation



Gross electricity generation is projected to grow by around 42 per cent (1.4 per cent a year) from 245
terawatt hours in 2008–09 to 348 terawatt hours in 2034–35. This growth is expected to come from
expansion of gas-fired electricity generation and renewable sources.
A key change over the projection period is the expected shift from coal-fired to gas-fired generation. As the
proportion of coal-fired generation declines from 74 per cent to 38 per cent of electricity generation over the
projection period, the share of gas-fired generation is expected to more than double from 16 per cent to 36
per cent.
The use of renewable energy resources in electricity generation is expected to grow considerably at 6 per
cent a year over the projection period. Wind energy is projected to account for the majority of this growth,
representing 14 per cent of total electricity generation in 2034–35. Strong growth is also expected in other
renewable energy sources, including solar energy, geothermal energy and bioenergy, although from a
lower base.
11

Under assumed higher gas prices, total electricity generation is projected to grow at a slower rate of 1.3 per
cent a year to 340 terawatt hours in 2034–35. The share of gas in the generation mix is projected to be
lower under this scenario (22 per cent), accompanied by a relatively smaller fall in the share of coal, and a
slightly increased share for renewables
(25 per cent).
Energy production and trade

Australian energy production (excluding uranium) is projected to grow at an average annual rate of 3 per
cent over the projection period. At this rate, total production of energy is projected to more than double to
28 401 petajoules in 2034–35.

Coal and gas are projected to account for 96 per cent of Australia’s energy production in 2034 –35. Coal
production is projected to increase by 96 per cent to 18 956 petajoules
(632 million tonnes), while gas is projected to increase fourfold to 8274 petajoules
(330 960 gigalitres).
Production of black coal, which includes thermal and metallurgical coal, is projected to grow at 2.8 per cent
a year to 18 676 petajoules (623 million tonnes) in 2034–35. Despite this growth, the share of black and
brown coal in total energy production is projected to decline from 74 per cent in 2008 –09 to 67 per cent in
2034–35.


Strong growth in domestic and global demand for gas has been driving the development of new gas fields
and LNG capacity in Australia. Gas production in the western market is projected to grow at an average
annual rate of 5.5 per cent to 4771 petajoules in 2034–35. In the eastern market, production is projected to
grow at 5.0 per cent a year to
2492 petajoules.

Production of coal seam gas (CSG) is expected to maintain its strong growth trajectory over the projection
period, supported by the development of new projects and demand for CSG -fired electricity generation.

The exportable surplus of Australia’s energy production is expected to increase over the projection period,
rising by approximately 4.1 per cent a year. The fastest growth is expected in LNG exports, growing at 7.6
per cent a year.
Projections of declining oil production and constraints around petroleum refining suggest Australia’s net
trade position for crude oil and refined petroleum products will weaken over the projection period, with net
imports projected to increase at an average rate of
3.1 per cent a year.

12
1 Introduction
This report presents the results of BREE’s inaugural energy projections for Australia. The release of these results
will be part of an ongoing commitment by BREE to publish regular long-range projections of Australian energy
consumption, production and trade, with the support of the Australian Government Department of Resources,
Energy and Tourism. The current set of results provides an update to the projections published by ABARE in March
2010, with the following amendments:








Updated base year to 2008–09;
Extension of the projection period to 2034–35;
Revisions to economic growth assumptions;
Revisions to carbon price assumptions;
Revisions to long term energy price assumptions;
Changes to the Renewable Energy Target policy;
An analysis of the effect of different gas prices on the electricity generation mix; and
Inclusion of recently announced changes to Australian steel making and petroleum refining capacity.
The report aims to encapsulate these recent developments by providing an assessment of long-term projections of
Australian energy consumption, production and trade for the period 2008 –09 to 2034–35. These projections are
derived using BREE’s E4cast model, which is a dynamic partial equilibrium model of the Australian energy sector.
In undertaking these projections, BREE has included policies that have already been enacted. As such, these
projections incorporate the Renewable Energy Target and the introduction of carbon pricing in 2012. This scenario
does not pre-empt any Australian Government decisions that may affect the final target and policy design, or any
specific outcomes that may be achieved by a global commitment to reduce emissions. Given the uncertainty
surrounding future gas prices, a sensitivity analysis was conducted to assess the effect of gas prices on growth in
energy use.
The evolving dynamics of energy markets over the past few years have increased the complexity of long -term
energy projections. There is significant uncertainty about technology, investment and government policies in the
current environment. The current projections should only be considered as indications of what the future could be
given the assumptions used, and not a forecast and what energy use will be into the future.
In this report, measures of energy consumption, production and net trade are expressed in energy content terms
(typically petajoules or gigawatt hours for electricity) to allow for comparison across the energy commodities. The
significance of a commodity in energy content terms may differ to physical production units (such as tonnes, litres
and barrels) and value.
The report is structured as follows. In chapter 2 the changing energy policy context in Australia is described, with a
focus on key policies that are likely to affect long-term energy trends. Chapter 3 presents the modelling framework
used, as well as the key underlying assumptions. Chapter 4 provides the outlook for Australian energy consumption
and electricity generation covering the period 2008–09 to 2034–35, and chapter 5 provides the long-term outlook
for Australian energy production and trade. Chapter 6 offers concluding remarks.
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2 The Australian energy context
Energy resources and markets
Australia is endowed with abundant, high quality and diverse energy resources (Map 1). Australia holds an
estimated 47 per cent of world uranium resources, 10 per cent of world coal resources, and almost 2 per cent of
world natural gas resources. In addition, Australia has large, widely distributed wind, s olar, geothermal,
hydroelectricity, ocean energy and bioenergy resources.
Map 1: Distribution of Australia’s energy resources
Source: Geoscience Australia and ABARE (2010)
The development of these resources has contributed to low-cost energy, underpinned the competitiveness of
energy-intensive industries and provided considerable export income. Australia is one of the few OECD economies
that is a significant exporter of energy commodities, with the major exports being coal, liquefied natural gas (LNG),
uranium and petroleum.
Australian energy production
Australia is the world’s ninth largest energy producer, accounting for around 2.5 per cent of the world’s energy
production (IEA 2011). Energy production in Australia has been increasing over the past decade, growing at an
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average annual rate of 3.2 per cent since 1999–00.
The main fuels produced in Australia are coal, uranium and gas (Figure A). Of these, coal accounted for around 57
per cent of total energy production in energy content terms in
2009–10, followed by uranium (20 per cent) and gas (12 per cent). Crude oil and LPG represented 6 per cent of
total production, and renewable energy 2 per cent.
Figure A: Australian energy production
Sources: BREE calculations, and ABARES (2011)
Australian production of renewable energy has been dominated by bagasse, wood and wood waste, and
hydroelectricity, which together accounted for 83 per cent of renewable energy production in 2009–10. Wind energy,
solar energy and biofuels accounted for the remainder of Australia’s renewable energy production.
Although energy production has been increasing over the past 10 years, reserves to production ratios have
followed a rising trend. This reflects the addition of new discoveries and the upgrading of resources meeting
economic criteria. At current rates of production, Australia’s energy resources are expected to last for many more
decades.
Australian energy consumption
Australia is the world’s nineteenth largest primary energy consumer, and ranks fourteenth on a per person energy
use basis (IEA 2011). Since 2000, growth in energy consumption has averaged 1.6 per cent a year.
Although Australia’s energy consumption is growing, the rate of growth has been declining over the past 50 years.
Following annual growth of around 5 per cent during the 1960s, growth in energy consumption fell during the 1970s
to an average of around 4 per cent a year, largely as a result of the two major oil price shocks. During the 1980s,
economic recession and sharply rising energy prices resulted in the annual growth in energy consumption falling to
an average of 2.3 per cent. In the early 1990s, falling real energy prices and robust economic growth contributed to
rising energy consumption. Despite this, growth in energy consumption for the decade as a whole also averaged
around 2.3 per cent.
Figure B shows the long term decline in energy intensity of the Australian economy. This can be attributed to two
main factors. First, greater efficiency has been achieved through technological improvement and fuel switching.
Second, rapid growth has occurred in less energy-intensive sectors, such as the commercial and services sector,
15
relative to the more moderate growth of the energy-intensive manufacturing and processing sectors.
Figure B: Energy intensity trends
Sources: ABARE-BRS (2010), ABS (2010a)
Australian primary energy consumption consists mainly of coal, petroleum and gas. In 2008 –09 black and brown
coal accounted for around 39 per cent of the primary energy mix, followed by petroleum products (35 per cent), gas
(22 per cent) and renewable energy sources (5 per cent).
The main users of energy in Australia are the electricity generation, transport and manufacturing se ctors. Together,
these sectors accounted for more than 80 per cent of energy consumed in 2008 –09. The mining, residential and
commercial and services sectors were the next largest energy consuming sectors.
The electricity industry is one of Australia’s largest industries, contributing 1.1 per cent to Australian industry value
added in 2008–09 and generated 245 terawatt hours of electricity.
Most of Australia’s electricity is produced using coal, reflecting its abundance along the eastern seaboard where the
majority of electricity is generated and consumed. In 2008–09, coal-fired electricity generation accounted for 74 per
cent of total electricity generation and gas 16 per cent.
Over the past 20 years, domestic energy consumption has increased at a slower rate than energy production.
Rapid growth in global demand for Australian energy resources has driven this growth in energy production.
Consequently, the share of Australian energy production that is exported has continued to increase.
Australia’s energy exports
Australia is a net energy exporter, with domestic energy consumption representing only one -third of total energy
production, including uranium.
Since 1990–91, the value of Australia’s energy exports (in 2011–12 Australian dollars) has increased at an average
rate of 9.3 per cent a year. In 2010–11, energy export earnings increased by 16 per cent to $71 billion (in 2011 –12
dollars), reflecting increased export volumes and higher export prices (Figure C). Energy exports accounted for 32
per cent of Australia’s total commodity exports in 2010–11.
Australia’s largest energy export earners are coal, crude oil and LNG. These exports are significant contr ibutors to
the economy, and in 2010–11 export values (in 2011–12 Australian dollars) were estimated at $44 billion for coal,
$12 billion for crude oil and condensate and $11 billion for LNG, respectively.
16
Figure C: Australian energy exports
Source: BREE (2011)
While Australia is a net energy exporter, it is a net importer of crude oil and refined petroleum. In 2010 –11,
Australia’s imports of crude oil and refined products were valued at $33 billion
(in 2011–12 Australian dollars).
Any future expansion of Australia’s energy market, including access to new energy resources, will require
investment in energy infrastructure. Additional investment will be required to replace ageing energy assets and also
to allow for the integration of renewable energy into existing energy supply chains.
Energy policy
Australia’s energy policy aims to balance the growing demand for energy with the promotion of a lower carbon
economy, incorporating international commitments regarding climate change. The policy also seeks the p rovision of
a stable economic environment to encourage investment in the energy sector, particularly renewable energy.
Australian Government policies that will shape the energy market over the next 25 years are the Renewable Energy
Target (RET) and the introduction of carbon pricing. The RET and carbon pricing are aimed at creating a
fundamental shift in consumption, in addition to investment incentives in the energy sector, to induce Australian
companies and households to internalise the costs of climate change. These strategies are complemented by
targeted initiatives, such as the Energy Efficiency Initiative.
Renewable Energy Target
Introduced in 2010, the RET requires 45 000 gigawatt hours of electricity to be supplied from renewable energy
sources by 2020. This target corresponds to around 20 per cent of total electricity generation and is a substantial
increase from the previous Mandatory Renewable Energy Target (MRET) of 9500 gigawatt hours by 2020. The RET
brought existing state based RETs, such as the Victorian Renewable Energy Target, into a single national scheme.
Initially, retailers and large users of electricity were legally required to earn or obtain Renewable Energy Certificates
(RECs) equivalent to a set proportion of their electricity purchases. Additionally, households and small businesses
could earn RECs on a voluntary basis through solar credits for small-scale renewable energy installations. RECs
17
could then be traded to ensure companies reached their legislated quota and to provide incent ives for the adoption
of renewable energy sources.
From January 2011, the RET has been split into the voluntary Small-scale Renewable Energy Scheme (SRES) and
the mandatory Large-scale Renewable Energy Target (LRET) to improve certainty for all involved and to provide
incentives targeted at each group. The LRET consists of legislated annual targets for the amount of electricity to be
sourced from renewable energy to ensure that 41 000 gigawatt hours is achieved by 2020. Because of the large
number of RECs generated by the end of 2010, the annual LRET targets for 2012 and 2013 were increased to
support advances in the adoption of renewable energy sources (ORER 2011). Households and small businesses
are anticipated to provide, and potentially exceed, the additional 4000 gigawatt hours required to meet the RET
through the SRES. Accordingly, RECs have been separated into Large-scale Generation Certificates (LGCs) and
Small-scale Technology Certificates (STCs).
The Office of the Renewable Energy Regulator oversees the implementation of the RET and the registration of
subsequent LGCs and STCs (ORER 2011).
The objective of the RET is to advance the development and employment of renewable energy resources over the
medium term and to assist in moving Australia to a lower carbon economy (Combet 2009).
Clean Energy Future Plan
The Australian Government passed its Clean Energy Future plan through the Senate on
8 November 2011. The plan reflects the considerations of the Multi-Party Climate Change Committee (MPCCC)
that determined that a carbon price and a package of complementary measures would be the most cost -effective
and economically responsible way of reducing Australia’s carbon emissions. The emissions reduction targets that
have been previously agreed to and were extended under the Clean Energy Future plan are:


To reduce emissions to 5 per cent below 2000 levels by 2020, which will require cutting net expected
emissions by at least 23 per cent in 2020
A long-term reduction in emissions to 80 per cent below 2000 levels by 2050.
The carbon price is to be introduced on 1 July 2012. It will be fixed for the first three years before transitioning to an
emissions trading scheme. From 1 July 2012, the carbon price will be a nominal $23 a tonne of carbon dioxide
equivalent (CO2-e), increasing at a rate of 5 per cent a year until 30 June 2015. From 2015, the carbon price will
transition to a ‘cap and trade’ emissions trading scheme, open to the international market.
Introducing carbon pricing makes large emitters of carbon financially liable for their carbon emissions. During the
fixed price period, an unlimited number of permits will be available at a fixed price, and these must be purchased
and surrendered for each tonne of reported emissions.
The carbon price will transition to an emissions trading scheme in 2015, where the number of available permits will
be capped and the permit price will be determined in the marketplace. However, there will be a price cap set at $20
above the expected international price for an equivalent tonne of CO 2-e, and a price floor of $15 a tonne CO2-e. At
this point the carbon market may also be opened up to international carbon trading.
The Government’s Clean Energy Future plan, comprises of a number of institutional arrangements. These inclu de
household and industry assistance, innovation and investment programs and transitional measures. Some of the
arrangements relevant to the Australian energy projections are discussed in Box 1.
18
Box 1: Other Clean Energy Future initiatives
A range of government initiatives and support programs are included in the Clean Energy Future plan:
Energy Security and Transformation
An Energy Security Council that will collaborate with the Australian Energy Market Operator will be established. Signif icant work
occurring in this area will include the:
Negotiation and potential payment for closure of up to 2000 megawatts of emissions -intensive generation capacity before 2020;
Free permit allocations and cash payments to emissions-intensive coal-fired electricity generators, in return for adopting clean
energy investment plans; and
Short-term loans to generators to help finance the purchase of carbon permits.
Clean Energy Finance Corporation
The Government intends to encourage investment in renewable energy, energy efficiency and low emissions technologies by
providing financial support. The Government will invest $10 billion over 5 years beginning 2013 –14 through loans, loan
guarantees and equity investments.
Australian Renewable Energy Agency
The Australian Renewable Energy Agency (ARENA) will provide grant funding to support research, development and
demonstration of new renewable technologies, investing $3.2 billion over 9 years beginning 2011 –12. It will also oversee
existing government renewable energy programs.
The Jobs and Competitiveness Program
The Jobs and Competitiveness Program will assist emissions-intensive trade-exposed industries with $9.2 billion transitional
assistance between 2011–12 and 2014–15. These industries will receive assistance to cover 94.5 per cent of industry average
carbon costs in the first year of the carbon price. Less emission-intensive trade-exposed industries will receive assistance to
cover 66 per cent of average industry carbon costs. Assistance will be reduced by 1.3 per cent each year.
Other programs
The Clean Technology Program will target energy efficiency in manufacturing industries and support research and development
in low emissions technologies. It will provide $1.2 billion over 7 years from 2011–12. There will also be funding to support jobs in
food processing, metal forging and foundry industries ($200 million) and funding for the Steel Transformation Plan ($300
million). There will be $1.3 billion directed to the Coal Sector Jobs Package over 6 years fr om 2011–12, which will provide
transitional assistance to the coal industry to assist in the implementation of carbon abatement technologies.
Other initiatives
A wide range of policies exist at both the Australian and State Government levels that will assist with creating a
lower carbon economy. These include the National Strategy on Energy Efficiency and other related energy
efficiency initiatives, the New South Wales Greenhouse Gas Reduction Scheme, and the Queensland Gas Scheme.
Energy Efficiency
The National Framework for Energy Efficiency (NFEE) is a multi-level government policy announced by the
Ministerial Council on Energy in 2004. The NFEE promotes improvements in energy efficiency through encouraging
a shift in households’ and companies’ consumption behaviour by improving public information, providing financial
incentives, and enforcing standards for the energy efficiency of goods such as light bulbs and air conditioners. To
reinforce this desired behavioural shift or ‘step change’, the Prime Minister’s Task Group on Energy Efficiency has
recommended establishing a national energy efficiency target of improving energy intensity by 30 per cent by 2020
(PMTGEE 2010).
In 2009, the Council of Australian Governments (COAG) agreed on the 10 year National Strategy on Energy
Efficiency (NSEE). The NSEE seeks to support the NFEE in providing information regarding methods of reducing
energy use and improving efficiency, generating public awareness, and facilitating innovations in energy efficient
technologies and practices (COAG 2009). The NSEE also strives to remove regulatory obstacles which may
prevent improvements in energy efficiency, such as duplication of processes and inconsistent standards.
A number of NFEE and NSEE programs are already in place or currently in the process of development in order to
address energy efficiency opportunities (DCC 2010).
19
New South Wales Greenhouse Gas Reduction Scheme
The New South Wales (NSW) Greenhouse Gas Reduction Scheme (GGAS) commenced in NSW on 1 January
2003. On 1 January 2005, the Australian Capital Territory Government introduced a corresponding scheme utilising
the same regulatory bodies and structures. GGAS aims to reduce the emissions associated with the production and
use of electricity through imposing mandatory emission reduction targets.
The GGAS targets maintaining greenhouse gas emissions (from 2007 until the scheme concludes) at a benchmark
of 7.27 tonnes of carbon dioxide equivalent (CO 2-e) per person, which is equivalent to 5 per cent below the KyotoProtocol baseline year of 1989–90.
The NSW government has committed to maintaining the program until the introduction of carbon pricing. The
proportion of the greenhouse gas reduction benchmark imposed on each participant is equivalent to their share of
electricity sales in NSW (Greenhouse Gas Reduction Scheme Administrator 2007).
On 1 July 2009, the NSW Government introduced the Energy Savings Scheme (ESS) to replace the demand side
abatement component of GGAS. Companies that supply electricity in NSW are required to meet energy savings
targets equivalent to their share of electricity sales in NSW. Participants may trade the Energy Savings Certificates
(ESCs) generated through their activities. This provides an incentive for companies to increase their energy savings
and rewards companies that exceed their benchmark.
Queensland Gas Scheme
The Queensland Gas Scheme was implemented on 1 January 2005. The scheme requires electricity retailers and
other liable parties to source a minimum percentage of their electricity from eligible gas -fired generation. The initial
requirement was set at 13 per cent and increased to 15 per cent in 2010. There is the potential to increase the
required percentage to 18 per cent by 2020 (DME 2011). The objective is to diversify the energy mix, provide
support for the state’s gas industry and reduce greenhouse gas emissions. The Queensland Gas Scheme will
conclude when carbon pricing is introduced.
Data Collection
Recently, emphasis has been placed on the role that quality data collection plays in ensuring effective development
and evaluation of energy policy. Improving the accuracy of the data collected and distributed also helps
governments and companies understand the effect of energy policies on supply and demand so that they can adapt
their behaviour accordingly. In the NSEE, COAG includes measures for advancing the collection of energy
efficiency data and identifying those measures as critical to the effective implementation of energy efficiency policy
(COAG 2009). The development and distribution of data collection in Australia is supported by existing legislation
such as the National Greenhouse and Energy Reporting Act, as well as organisations such as the Australian
Bureau of Statistics (ABS) and the Bureau of Resources and Energy Economics (BREE).
20
3 Methodology and key assumptions
The energy sector projections presented in this report were derived using the E4cast model. E4cast is a dynamic
partial equilibrium model of the Australian energy sector that can project energy consumption by fuel type, by
industry and by state or territory, on a financial year (July–June) basis. The model includes a large number of
variables and parameters that are used to approximate the interdependencies between production, conversion and
consumption of energy.
The E4cast 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 D.
Figure D: Energy forecasting model
E4cast incorporates long-term macroeconomic forecasts from the Australian Treasury and ABARES and current
assumptions on the costs and characteristics of energy conversion technologies. A brief overview of the key
features of the current version of E4cast is provided in Box 2. The model provides an outlook for the Australian
energy sector that is feasible (where all quantity constraints are satisfied) and satisfies the economic competitive
price conditions (a competitive equilibrium is achieved).
21
Box 2: Key features of E4cast
The first version of the model was documented in Dickson et al. (2001). Since then, the model has been enhanced and refined
in a number of directions, providing a sound platform for the development and analysis of medium and long term energy
projections. Key features of the 2011 version of E4cast are outlined below.

E4cast is a dynamic partial equilibrium framework that provides a detailed treatment of the Australian energy sector
focusing on domestic energy use and supply.

The Australian energy system is divided into 24 conversion and end use sectors.

Fuel coverage comprises 19 primary and secondary fuels.

All states and territories (the Australian Capital Territory is included with New South Wales) are represented.

Detailed representation of energy demand is provided. The demand for each fuel is modelled as a function of income or
activity, fuel prices (own and cross) and efficiency improvements.

Primary energy consumption is distinguished from final (or end use) energy consumption.
This convention is consistent with the approach used by the International Energy Agency.

The current version of E4cast covers the period from 2008–09 to 2034–35.

Demand parameters are established econometrically using historical Australian energy data.

Business activity is generally represented by gross state product (GSP).

Energy intensive industries are modelled explicitly, taking into account large and lumpy capacity expansions. The
industries modelled in this way are:

Aluminium;

Other basic nonferrous metals (mainly alumina); and

Iron and steel.

The electricity generation module includes 17 generation technologies. Investment plans in the power generation sector
are forward looking, taking into account current and likely future conditions affecting prices and costs of product ion.

Key policy measures modelled explicitly are:

The introduction of carbon pricing;

The Australian Government’s Renewable Energy Target;

The New South Wales Government’s Greenhouse Gas Reduction Scheme;

The Queensland Government’s Gas Scheme; and

The Victorian Government Renewable Energy Target.

All fuel quantities are in petajoules.

Supply of gas is modelled at the state level.

All prices in the model are real, in constant dollars of the base year, and are expressed in dollars per gigajoule. The base
year is 2008–09.
22
The model includes 19 energy sources, five conversion sectors, 19 end use sectors and seven regions (Table 1
and Table 2). The demand functions for each of the main types of fuel (such as electricity, gas, coal and petroleum
products) have been estimated econometrically and incorporate own price, cross price, income or activity, and
technical change effects.
Table 1: Fuel coverage in E4cast
Black 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
23
Table 2: Industry coverage of 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
24
In E4cast, prices for energy sources used in electricity generation are determined within the model based on
demand and supply factors, with the exception of oil and coal where prices are determined on the world market. In
some simulations, exogenous gas prices have been used.
The direction of interstate trade in gas and electricity is determined endogenously in E4cast, accounting for variation
in regional prices, transmission costs and capacities.
In E4cast, upper limits on interstate flows of electricity and gas are imposed over the medium term to reflect existing
constraints and known expansions that are at an advanced stage of development. Beyond the medium term, it is
assumed that any interstate imbalances in gas supply and demand will be anticipated, resultin g in infrastructure
investment in gas pipelines and electricity interconnector capacity sufficient to meet trade requirements.
For internationally traded energy commodities, crude oil, LNG and black coal of export quality, production is
exogenous to the model and is drawn from BREE’s (previously ABARES’) commodity forecasting capability.
Although Australia is a significant producer of uranium oxide, it is not included in the projections as it is not
consumed in Australia and, therefore, does not affect the domestic energy balance. A detailed assessment of
Australia’s uranium resources is provided in the Australian Energy Resource Assessment (Geoscience Australia
and ABARE 2010).
E4cast base year data
The base year (2008–09) data in the model are drawn from ABARES’ Australian Energy Statistics (ABARE –BRS
2010). These statistics are largely derived from ABARES’ former fuel and electricity survey (FES). The 2008 –09
data, as reported in the projections report, and the published data (ABARE–BRS 2010) may be classified differently.
As a result, there may be differences in the figures published. A brief description of the survey and ABARES’
energy balance data is provided in Box 3.
From 2010, National Greenhouse and Energy Reporting (NGER) data, sourced from the Australian Government
Department of Climate Change and Energy Efficiency, has been adopted as the main energy consumption data
source for the Australian Energy Statistics. With the introduction of NGER, survey year 2008–09 became the final
year that the FES was conducted. Australian energy statistics using NGER data will be used in the next set of
energy projections.
Box 3: Australian energy statistics
The Australian energy statistics for 2008–09 are based on ABARES’ fuel and electricity survey (FES), which was a nationwide
survey of around 1400 large energy users and producers. The energy users surveyed accounted for around 60 per cent of total
Australian energy consumption. Each year, in around October/November, respondents were sent paper-based surveys,
requesting information on the quantity of fuels they produced and consumed as well as the electricity they generated. These
detailed energy statistics were integrated and reconciled with other databases and information sources. Supplementary data
were also collected from various sources, including:

Australian Bureau of Statistics’ international trade data;

ABARES’ farm surveys database for the broadacre and dairy farm sectors;

Department of Resources, Energy and Tourism’s Australian Petroleum Statistics;

Energy Supply Association of Australia;

Geoscience Australia;

state government departments; and

Australian Customs and Border Protection Service.
The detailed FES data on energy consumption provides a platform for estimating energy consumption by region, industry and
energy source. The consumption data are reconciled with readily available production statistics to provide a national energy
balance.
Key assumptions
There are a number of economic drivers that will shape the Australian energy sector over the next two decades.
These include:
Population growth;
25
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 Australian population is drawn
from the Australian Treasury carbon price modelling and presented in Table 3.
Table 3: Australian population assumptions
year
population
million
2009
21.97
2020
25.83
2035
31.19
Source: Treasury (2011)
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 basic nonferrous metals, and iron and steel
manufacturing) projected industry output is considered as a more relevant indicator of activity than GSP because of
the lumpy nature of investment.
The GDP and GSP assumptions (Table 4) are drawn from the assumptions used by the Australian Treasury carbon
price modelling (Treasury 2011).
In 2008–09, Australia’s real GDP increased by 1.4 per cent, following growth of 3.8 per cent in 2007–08. Over the
projection period, Australia’s real GDP is expected to grow at an average annual growth rate of 2.8 per cent. A
moderation in Australia’s population and labour supply growth will contribute to a gradual reduction in GDP growth in
the latter part of the projection period.
Queensland and Western Australia are expected to have the highest GSP growth rates over the period to 2034–35,
reflecting to a large extent their substantial minerals and energy resource base, relatively high degree of export
orientation, and higher relative population growth rates.
Table 4: Australian economic growth, by region
Average annual growth 2008–09 to 2034–35
%
New South Wales (and ACT)
2.5
Victoria
2.6
Queensland
2.9
South Australia
2.0
Western Australia
3.7
Tasmania
1.7
Northern Territory
2.5
Australia
2.8
Sources: BREE assumptions based on Treasury (2011).
26
Real energy prices
Energy prices affect the demand for, and supply of, energy. The long term energy price assumptions of BREE
incorporated in E4cast are presented in Figure E. Long-term energy price profiles will hinge on a number of factors,
including demand, investment in new supply capacity, costs of production, and technology. Although the long -run
price paths follow smooth trends, in reality, prices are likely to fluctuate in response to short -term market
developments.
Figure E: Index of world real energy prices, 2008–09 dollars
Sources: BREE assumptions
Coal
In early 2011, coal prices for both thermal and metallurgical coal increased significantly following heavy rain and
flooding in Queensland. In the medium term, thermal coal prices are expected to remain significantly above the long
term average of the past two decades, although decline in real terms relative to 2010–11. This reflects rising supply
costs in China, the world’s largest producer of thermal coal, and also in Australia and Indonesia, the largest
exporters, as they develop coal deposits that are deeper underground and/or further away from existing
infrastructure.
Beyond the medium term, global thermal coal prices are expected to stabilise above the long -term historical
average. The higher costs associated with developing new mines and infrastructu re is expected to be offset to
some extent by the adoption of more advanced technology.
Oil
In 2010, oil prices in WTI terms averaged around US$79 a barrel. World oil prices are projected to remain around
real US$90–95 a barrel over the medium term, as oil demand increases in line with assumed stronger economic
growth. The availability of spare production capacity and stocks in OPEC are expected to limit significant increases
in oil prices over the medium term.
The long-term prospect for oil prices is much less certain. Key factors that are expected to drive long-term oil prices
are the cost of developing remaining oil reserves, the volume and timing of investment in production and refining
capacity, and technological development in relation to alternative liquid fuels. The estimated capital and production
costs for conventional oil sources have increased in recent years because of rising materials, equipment and labour
costs. While a rise in the marginal cost of oil production is expected over time, technol ogical developments
associated with non-conventional liquids, such as gas-to-liquids and second generation biofuels, have the potential
to play a major role in anchoring oil prices below what would have been the case without these new technologies.
However, it is not expected that these technologies will be developed in Australia. The assumed development and
27
entry of these technologies underpins the long-term price assumptions used in this report.
LNG
In the long term, international LNG prices are assumed to follow a similar trajectory to oil prices, reflecting an
assumed continuation of the established relationship between oil prices and long -term gas supply contracts through
indexation in the Asia Pacific market, and substitution possibilities in electric ity generation and end use sectors.
While in recent years gas prices have decoupled from oil prices in some markets (reflecting relatively abundant
supplies of unconventional gas in North America and increased availability of spot supplies of cheaper LNG i n
Europe and the Asia Pacific), there is considerable uncertainty about whether this will also apply to the Asia Pacific
market. Indexation is likely to remain the dominant pricing mechanism in the Asia Pacific region, unless there is a
significant convergence of the Atlantic and Pacific markets through LNG exports from North America to the Asian
region.
Domestic prices for coal and gas are drawn from ABARES’/BREE’s assumptions.
Electricity generation 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 Electric Power Research Institute (EPRI 2009) assessed the status of different electricity technologies in 2015
and 2030. The EPRI technology status data enables the comparison of technologies at varying levels of maturity.
However, market and system factors will have a significant impact on the technology mix and electricity prices in an
energy system. For this reason, electricity market prices cannot be extrapolated from technology cost analysis.
Market modelling is required to project potential electricity prices arising from market and investment outcomes.
The levelised cost of technologies represents the revenue per unit of electricity generated that must be met to break
even over the lifetime of a plant.
While EPRI cost estimates were developed on the basis of generic plant configurations rather than on detailed plant
designs or equipment and material costs—and are subject to uncertainty in relation to a number of factors—they
provide valuable and comprehensive information on the relative costs of different electricity generation technologies
in an Australian setting, and how these costs might change over time. Importantly, these costs do not include the
effects of any carbon price.
The relative costs of different technologies are more important than the abs olute magnitude of these costs in
determining their relative prospects in the electricity generation sector (merit order). The EPRI results show that, in
the medium term, coal and gas without CCS will remain among the lowest technology cost options. Of the
renewable energy technologies, wind is one of the lowest cost options. Despite a significant decline in the costs of
solar technologies expected in the future, the costs of these technologies are expected to remain relatively high
over the coming years. The costs of geothermal electricity are shown to be competitive with those of other baseload
technologies, although this technology is still at a demonstration stage.
For technologies that are not covered in detail by the EPRI data (ocean energy, bioenergy and the retrofitting of
existing fossil-fuel plants with CCS technology), BREE has drawn on a range of other sources (IEA 2008; Specker,
Phillips and Dillon 2009; National Energy Technology Laboratory 2009). There is considerable uncertainty
regarding the absolute costs of these technologies. Further, not all units of existing power plants are amenable to
be retrofitted with CCS technology. Key considerations include the unit’s age and size, available space and access
to geological storage.
In 2011, the Australian Treasury modified EPRI technology costs to account for exchange rate movements since
the 2009 EPRI report. In E4cast, the assumptions regarding the cost of electricity generation technologies in
Australia are drawn from the modified EPRI technology costs, and are presented in Figure F. In addition, there are
exogenous and endogenous factors that can contribute to changing electricity generation costs over time. These
include carbon prices, and thermal efficiencies, including assumptions regarding fu ture technological changes and
learning rates.
28
Figure F: Index of real levelised cost of electricity generation technologies excluding carbon costs
Sources: BREE calculations based on modified EPRI technology costs
End use energy 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 NSEE can also be expected to address
non-market barriers to the uptake of energy efficiency opportunities.
The rate of end use energy efficiency improvement is assumed to be 0.5 per cent a year over the projection period
for most fuels in non-energy intensive end-use sectors. For energy intensive industries, the low capital stock
turnover relative to other sectors is assumed to result in a lower rate of energy efficiency improvement of 0.2 per
cent a year.
Government policies
In this set of projections, the following key policies have been modelled explicitly in E4cast:





The clean energy future carbon price;
The Australian Government Renewable Energy Target (RET);
The New South Wales Greenhouse Gas Reduction Scheme;
The Queensland Gas Scheme; and
The Victorian Government Renewable Energy Target.
Emissions Reduction Target
The carbon price assumptions are set in reference to the Treasury modelling, Strong growth, low pollution:
modelling a carbon price released in 2011. In 2012–13, a nominal carbon price of $23 a tonne is used, growing at 5
per cent a year. From 2015, the carbon price will transition to an emissions trading scheme, open to the
international market. The price trajectory for the scheme is estimated to start at $29 a tonne in 2016, in nominal
terms, growing at a rate of
5 per cent a year. In practice, the carbon price path post 2015 will be determined by the world’s carbon market,
within which Australia will trade permits. The projection path for the carbon price assumptions (in real terms) is
shown in Table 5.
29
Table 5: Carbon price assumptions, real, 2009–10 dollars
2012–13
21.05
2019–20
29.40
2029–30
52.60
2034–35
69.90
Source: BREE calculations based on Treasury (2011)
Renewable Energy Target (RET)
The Renewable Energy Target (RET) requires 45 000 gigawatt hours of electricity be sourced from renewable
energy sources by 2020. Legislation to implement the Renewable Energy Target (RET) scheme was passed by the
Parliament on 24 June 2010.
In January 2011, the RET was split into the voluntary Small-scale Renewable Energy Scheme (SRES) and the
mandatory Large-scale Renewable Energy Target (LRET). The LRET consists of legislated annual targets for the
amount of electricity to be sourced from renewable sources to ensure 41 000 gigawatt hours is achieved by 2020.
Small businesses and households are anticipated to provide more than the additional 4000 gigawatt hours through
the SRES. The Office of the Renewable Energy Regulator (ORER) oversees the RET. The LRE T 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
18.0
2016
20.6
2017
25.2
2018
29.8
2019
34.4
2020 and onwards
41.0
Source: ORER (2011)
In E4cast, this policy intervention is modelled as a constraint on electricity generation —renewable energy must be
greater than or equal to the interim target in any given year. In the model, the LRET target is met by a subsidy to
renewables that is funded by a tax on non-renewable generators. This is endogenously modelled so that total
renewable generation meets the target.
New South Wales Greenhouse Gas Reduction Scheme
The New South Wales Greenhouse Gas Reduction Scheme requires electricity retailers and other liable parties to
meet mandatory greenhouse gas reduction benchmarks. The scheme is implemented in the model by requiring
total emissions from state electricity generation to be less than or equal to the product of targeted per person
emissions and state population. In effect, the price of carbon is internalised in state electricity supply decisions.
However, it is assumed that the scheme will cease in 2012–13 upon the implementation of carbon pricing.
Queensland Gas Scheme
The Queensland Gas Scheme requires electricity retailers and other liable parties to source at least 13 per cent of
their electricity from natural gas-fired generation. On 1 July 2008, the requirement was increased to 15 per ce nt in
30
2010 and up to 18 per cent thereafter. The scheme has been approximated in the model by requiring the share of
natural gas-fired electricity generation in Queensland to be greater than or equal to 13 per cent in 2009 and 15 per
cent in 2010. In effect, producers of gas-fired electricity receive a subsidy which is funded by all other generators. In
the model, this scheme is terminated from 2012–13 with the implementation of carbon pricing.
Victorian Renewable Energy Target
The Victorian Government’s Renewable Energy Target (VRET), which requires that 10 per cent of total electricity
generation be sourced from renewable energy sources by 2016, was implemented in the model from 2007 –08 to
2009–10 before the legislated transition in 2010 into the RET. In the model, generators of renewable electricity
under the RET receive a subsidy which is funded by all other non-renewable sources of power.
31
4 Energy Consumption
This chapter presents the outlook for Australian energy consumption over the period to 2034 –35 under the
assumptions and policy settings outlined in chapter 3. The projections cover primary energy consumption by energy
type and sector; final energy consumption by energy type and end-use activity; and electricity generation. While the
discussion focuses on Australian trends, key trends at a state and territory level are also highlighted.
Total primary energy 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. Growth in Australia’s total primary energy consumption
declined from 5 per cent a year in the 1960s to 2.3 per cent a year in the 1990s.
This trend is expected to continue, with growth in energy consumption moderating over the projection period.
Australia’s primary energy consumption is projected to increase at an average annual rate of 1 per cent from 5784
petajoules in 2008–09 to 7481 petajoules in 2034–35 (Table 7).
The moderate growth in energy consumption is largely driven by the implementation of new policies. Between
2008–09 and 2034–35, the Australian Government will introduce a number of measures, including the RET and
carbon pricing, that are expected to increase energy prices and dampen the demand for energy. This will be partly
offset by assumed strong economic growth over the projection period.
The largest decline in consumption growth is expected to occur in the last decade of the projection period. This
reflects the assumption of increasing carbon prices.
Aggregate intensity trends
Australia’s aggregate energy intensity (measured as total domestic energy consumption per dollar of GDP) declined
at an average rate of 1.2 per cent a year between 1989–90 and 2007–08 (Petchey 2010). Over the period to 2034–
35, Australia’s aggregate energy intensity is projected to decline by around 1.7 per cent a year. This indicates a
considerable shift in Australia’s economic structure over this period. The major driver of this trend is strong growth
in less energy-intensive sectors, such as the commercial and services sector relative to energy-intensive sectors,
such as manufacturing. Improved efficiency through technological development and fuel switching will also
contribute to this trend.
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
the changing policy environment.
Non-renewable energy accounted for around 95 per cent of the primary energy consumed in Australia in 2008–09. Of
this, coal accounted for 39 per cent of the primary energy consumed; oil 35 per cent; and gas (including conventional
and coal seam gas) 22 per cent. Over the projection period, the share of coal in total primary energy consumption is
projected to decline to 21 per cent (Table 7). By contrast, the share of gas is projected to increase to 35 per cent.
Gas is expected to exhibit the fastest growth among non-renewable energy sources over the projection period,
increasing by around 3 per cent a year to 2611 petajoules in 2034 –35 (Table 7). This growth is driven by increased
use in electricity generation and in the mining sector, and reflects the shift to less carbon-intensive energy sources.
The majority of this growth is at the expense of coal. The growth in gas consumption is expected to be greater in
the period to 2020, after which the uptake of technologies that are less carbon -intensive is expected to accelerate.
32
Table 7: Primary energy consumption, by energy type
Level
Average
annual
growth
Share
2008–09 to
Energy type
2008–09
2019–20
2034–35
2008–09
2034–35
2034–35
PJ
PJ
PJ
%
%
%
Non-renewables
5505
6431
6822
95
91
0.8
Coal
2240
2106
1541
39
21
-1.4
black coal
1593
1460
1260
28
17
-0.9
brown coal
647
647
281
11
4
-3.2
Oil
2021
2441
2670
35
36
1.1
Gas
1244
1884
2611
22
35
2.9
279
548
660
5
9
3.4
Hydro
45
47
47
1
1
0.2
Wind
14
131
175
<1
2
10.1
211
329
365
4
5
2.1
Solar
9
22
26
<1
<1
4.1
Geothermal
0
18
48
0
1
-
5784
6979
7481
100
100
1.0
Renewables
Bioenergy
Total
Numbers in the table may not add up to their totals due to rounding.
The figures for 2008–09 presented in this table may not be identical to actual historical data published in
ABARES’ Australian Energy Statistics. This is a reflection of the different classification systems.
In 2008–09, around 5 per cent of Australia’s primary energy consumption was sourced from renewable energy . The
share of renewable energy is projected to increase by 3.4 per cent a year following the introduction of the RET to
account for around 9 per cent of primary energy consumption in 2034–35 (Table 7). The bulk of this increase is
expected to come from bioenergy (mainly biomass) and wind energy. Growth is also expected to be strong in
geothermal and solar energy, albeit from a lower base.
Primary energy consumption, by state and territory
Primary energy consumption is projected to increase in all states and the Northern Territory over the period to
2034–35. However, there is variation in the rates of growth reflecting economic growth assumptions, energy
resource endowments, economic structure and state-specific policy settings (Table 8).
The highest growth in primary energy consumption is projected to occur in Western Australia, the Northern Territory
and Queensland. This is underpinned by higher assumed economic growth compared with the other states, the
large contribution of the mining sector to economic output and the high degree of export orientation. The strongest
growth in primary energy consumption is expected to occur in Western Australia, increasing at a rate of 2 per cent a
year, with its share of total primary energy consumption increasing from 16 per cent in 2008–09 to 21 per cent in
2034–35 (Table 8).
33
Growth in energy consumption is projected to be more moderate in South Australia and New South Wales driven by
assumed lower economic growth. Despite the slower growth, New South Wales is projected to remain the largest
consumer of energy. Its energy consumption is projected to increase at around 0.6 per cent a year and increase
from 1569 petajoules in 2008–09 to 1851 petajoules in 2034–35 (Table 8).
Table 8: Primary energy consumption, by state and territory
Level
Average
annual
growth
Share
2008–09
to
State/territory
2008–09
2019–20
2034–35
2008–09
2034–35
2034–35
PJ
PJ
PJ
%
%
%
New South Wales a
1569
1758
1851
27
25
0.6
Victoria
1388
1608
1491
24
20
0.3
Queensland
1291
1626
1770
22
24
1.2
South Australia
344
394
420
6
6
0.8
Western Australia
953
1323
1607
16
21
2.0
Tasmania
113
120
135
2
2
0.7
Northern Territory
127
150
207
2
3
1.9
5784
6979
7481
100
100
1.0
Australia
a includes the Australian Capital Territory.
Numbers in the table may not add up to their totals due to rounding.
The figures for 2008–09 presented in this table may not be identical to actual historical data published
in ABARES’ Australian Energy Statistics. This is a reflection of the different classification systems.
Victoria is projected to exhibit the lowest growth in primary energy consumption. The effect of government policies
on brown coal-fired electricity generation and other emission-intensive industries such as petroleum refining and
chemicals will contribute to the moderate growth. Energy consumption in Victoria is projected to increase by 0.3 per
cent a year from 1388 petajoules in 2008–09 to 1491 petajoules in 2034–35 (Table 8).
Primary energy consumption, by sector
Electricity generation, transportation and manufacturing accounted for 89 pe r cent of Australia’s total primary
energy consumption in 2008–09. These sectors are projected to account for 81 per cent of projected primary
energy consumption in 2034–35 (Table 9).
The electricity generation sector accounted for the largest share (44 per cent) of primary energy consumption in
2008–09. Total primary energy consumption in electricity generation is projected to increase from 2557 petajoules
in 2008–09 to 2803 petajoules in 2034–35 (Table 9). The combined effect of the RET and the implementation of
carbon pricing on the relative competitiveness of generation technologies is expected to encourage a change in the
energy mix, with a gradual shift away from coal to gas and renewable energy.
In 2008–09, the transport sector (excluding electricity used in rail transport) accounted for one-quarter of primary
energy consumption, with a heavy reliance on oil and petroleum products. Consumption in the transportation sector
is projected to grow steadily over the projection period, increasing at an averag e annual rate of 1.2 per cent. Growth
in transport energy consumption will be offset by improved end-use efficiency in the sector and high fuel prices
such that the share of primary energy consumption is estimated to remain relatively constant at around 2 6 per cent
in 2035 (Table 9).
34
Table 9: Primary energy consumption, by sector
Level
Average
annual
growth
Share
2008–09
to
Sector
Electricity generation
2008–09
2019–20
2034–35
2008–09
2034–35
2034–35
PJ
PJ
PJ
%
%
%
2557
2827
2803
44
37
0.4
90
124
143
2
2
1.8
235
633
885
4
12
5.2
Manufacturing
1164
1277
1312
20
18
0.5
Transport
1437
1769
1960
25
26
1.2
302
349
379
5
5
0.9
5784
6979
7481
100
100
1.0
Agriculture
Mining
Commercial & residential
Total
Numbers in the table may not add up to their totals due to rounding.
The figures for 2008–09 presented in this table may not be identical to actual historical data published
in ABARES’ Australian Energy Statistics. This is a reflection of the different classification systems.
The manufacturing sector is the third largest user of primary energy in Australia, accounting for 20 per cent of the
total in 2008–09. This sector includes a number of relatively energy-intensive sub-sectors such as petroleum
refining, iron and steel, aluminium smelting and minerals processing. While primary energy consumption in the
sector is projected to increase by 0.5 per cent a year over the projection period, the relative share of the sector is
expected to decline to 18 per cent (Table 9). This reflects an ongoing structural shift away from energy-intensive
manufacturing, encouraged further by the implementation of carbon pricing.
Despite accounting for a relatively small proportion of total primary energy consumption
(4 per cent in 2008–09), the mining sector is projected to exhibit the fastest energy consumption growth to 2034 –35.
This growth will be supported by a large number of energy and mineral projects scheduled for development over the
projection period. The considerable volume of investment is a major driver of the expected expansion in the mining
sector and the associated growth in primary energy consumption. In 2034–35, the sector is projected to account for
12 per cent of Australian primary energy consumption (Table 9).
Electricity generation
Gross electricity generation in Australia is projected to increase at an average annual rate of
1.4 per cent from 245 terawatt hours (883 petajoules) in 2008–09 to 348 terawatt hours
(1253 petajoules) in 2034–35 (Table 10).
Reflecting differences in the availability of technologies and primary energy inputs, primary input prices, capital
costs and interregional transmission capacity, the projected growth in electricity generation varies across the states
and the Northern Territory. For states that are part of the integrated National Electricity Market (New South Wales
and the Australian Capital Territory, Queensland, Victoria, South Australia and Tasmania), the figures in Table 10
reflect electricity consumed and market determined electricity flows across regions.
35
New South Wales is likely to remain the largest producer of electricity, accounting for
31 per cent of total generation in 2034–35 and adding 35 terawatt hours to annual generation in 2034–35. South
Australia is a small electricity generator in absolute terms. However, it is expected to exhibit the strongest growth in
electricity generation, increasing at 2.5 per cent a year over the projection period (Table 10). This growth is being
driven by the development of renewable energy generation in the state, which is projected to grow at an average
annual rate of 7.4 per cent. Strong growth is also expected in gas -fired electricity generation, increasing at a
projected rate of 2.5 per cent a year.
In Western Australia, electricity generation is projected to increase by 64 per cent from
28 terawatt hours in 2008–09 to 46 terawatt hours in 2034–35 (Table 10). Much of this expansion will come from
growth in gas-fired electricity generation, which is projected to increase at an annual average rate of 2 .5 per cent.
Gas will account for 72 per cent of the projected expansion in Western Australia’s electricity generation between
2008–09 and 2034–35.
By contrast, electricity generation in Victoria is projected to grow at a rate much lower than the national average.
Electricity generation in Victoria is largely based on brown coal. The competitiveness of this energy source relative
to other technologies is expected to be diminished following the introduction of carbon pricing. Unless Victoria
invests in the development of its own low emission electricity generation capacity, it is projected to become more
dependent on the importation of electricity from other states.
Table 10: Electricity generation, by state and territory
Level
Average
annual
growth
Share
2008–09
to
State/territory
2008–09
2019–20
2034–35
2008–09
2034–35
2034–35
TWh
TWh
TWh
%
%
%
New South Wales a
75
96
110
30
31
1.5
Victoria
59
77
69
24
20
0.6
Queensland
56
65
76
23
22
1.2
South Australia
14
20
27
6
8
2.5
Western Australia
28
35
46
12
13
1.9
Tasmania
9
13
15
4
4
1.9
Northern Territory
4
4
5
1
2
1.6
245
310
348
100
100
1.4
Australia
a Includes the Australian Capital Territory.
Numbers in the table may not add up to their totals due to rounding.
The figures for 2008–09 presented in this table may not be identical to actual historical data published
in ABARES’ Australian Energy Statistics. This is a reflection of the different classification systems.
Under a policy setting that includes the RET and the introduction of c arbon pricing, the relative shares of nonrenewable and renewable energy in total electricity generation are expected to change considerably over the
projection period. In 2008–09, 93 per cent of electricity was generated from non-renewable sources (coal, oil and
gas) with the balance coming from renewable energy sources (Table 11). The incentives provided to generators
under the RET are expected to be the major driver of the accelerated uptake of renewable technologies in the
period to 2020. After 2019–20, renewable electricity generation is projected to continue to increase, albeit at a
slower rate.
Within non-renewable energy, the key change over the projection period will be the expected shift from coal -fired
generation to gas-fired generation. While coal is projected to continue to dominate the energy mix, the introduction
of carbon pricing will encourage a switch toward lower-emission energy sources. Black coal-fired generation and
36
brown coal-fired generation are projected to decline by 0.5 per cent a year and 3.7 per cent a year over the
projection period, respectively. Reflecting this, the share of coal in the energy mix is projected to decline from 74
per cent in 2008–09 to 38 per cent in 2034–35.
While these results imply the partial or full closure of coal-fired capacity over the projection period, there are a
number of factors that may reduce the effect of the implementation of carbon pricing on these plants, at least over
the medium term. For example, hedging contracts and other financial consider ations can be expected to provide
some degree of cost insulation to these plants. The longer term role of coal will be heavily dependent on
technological developments related to carbon capture and storage (CCS). The timing for deployment of CCS
technologies relies on the economic viability of this technology given carbon pricing (see Box 4 for further
discussion). In the modelling, the deployment of CCS technologies for new plants will be limited in the short to
medium term because of the current relatively high costs compared with other technologies. Nevertheless, some
coal-fired electricity generation with CCS may emerge by the end of the projection period, supported the
development of subsidised projects.
Table 11: Electricity generation, by energy type
a
Level
Average
annual
growth
Share
2008–09
to
Energy type
2008–09
2019–20
2034–35
2008–09
2034–35
2034–35
TWh
TWh
TWh
%
%
%
Non-renewables
227
248
265
93
76
0.6
Coal
182
178
134
74
38
-1.2
black coal
129
125
114
53
33
-0.5
brown coal
53
53
20
21
6
-3.7
40
64
126
16
36
4.5
5
5
5
2
2
0.0
Renewables
18
63
84
7
24
6.0
Hydro
12
13
13
5
4
0.2
Wind
4
36
49
2
14
10.1
Bioenergy
2
4
4
<1
1
3.5
<1
4
5
<1
1
13.6
0
5
13
0
4
-
245
310
348
100
100
1.4
Gas
Oil
Solar
Geothermal
Total
a These figures represent total gross electricity generation output, covering both on-grid and off-grid
principal generators, small generators, and non-scheduled generators. Numbers in the table may not
add up to their totals due to rounding.
The figures for 2008–09 presented in this table may not be identical to actual historical data published in
ABARES’ Australian Energy Statistics. This is a reflection of the different classification systems.
37
Box 4: Carbon capture and storage
Carbon capture and storage (CCS) is one of the key technologies being developed to help reduce global greenhouse gas
emissions (GHG) and the only technology available for mitigating carbon dioxide (CO 2) emissions from large scale nonrenewable energy usage. The underlying concept is for CO2 to be collected from point sources or industries with major CO 2
emissions and stored in such a way that it does not enter the atmosphere. The three distinct stages comprising the CCS
procedure consist of capture, transportation and long-term storage.
Technologies already exist for each of these stages and have been in commercial use for many years. CO 2 capture
technologies have long been used for high-concentration, high-pressure CO2 sources such as natural gas extraction. CO 2
transport has been used for decades as part of enhanced oil recovery techniques. Geologic CO 2 storage is being employed at a
growing number of sites worldwide. The issue is not whether technologies exist for CCS, but whether the incentives exist for
developing them for use on the commercial scale.
Many of the proposed CCS technologies are embryonic in nature and have not yet reached a level consistent with long -term,
least cost stages of development. This has resulted in a financial gap existing between CCS technologie s and current methods
of accommodating CO2 emissions. As long as this gap exists, it will slow the widespread adoption of CCS technologies.
The uptake of CCS is of particular relevance to Australia given the proportion of electricity generated from coal -fired power
plants. Not only does the implementation of CCS require additional capital expenditure, it also imposes additional costs thro ugh
a loss in thermal efficiency as a greater volume of fuel is used to generate each kilowatt hour of electricity. In order for CCS to
be commercially viable it is necessary for the market price of carbon to rise significantly such that it exceeds the cost of the CO2
avoided. Recent estimates put the average cost of CCS to avoid CO 2 emissions at around $75 a tonne at 2008 prices
(Bukhteeva et al. 2009).
The bulk of the decline in coal-fired electricity generation is expected to be taken up by gas-fired generation, with
the share of gas in electricity generation projected to increase from 16 per cent in 2008 –09 to 36 per cent in 2034–
35 (Table 11). This will be underpinned by the development of new gas-fired electricity generation capacity over the
projection period (Map 2). As of October 2011, gas accounted for 37 per cent of advanced electricity generation
projects in Australia (Stark et al. 2011).
38
Map 2: Advanced electricity generation projects, October 2011
Source: Stark et al. (2011)
Gas-fired generation is based on mature technologies that are more cost competitive compared with renewable
energy technologies. Consequently, gas is expected to play a major role in the transition period until lower emission
technologies become more cost viable. However, the cost competitiveness of gas -fired generation relies heavily on
gas prices. The modelling of gas prices for this set of projections suggests that domestic gas prices are likely to
moderately increase over the period to 2034–35.
The uptake of gas-fired electricity generation is expected to be substantial in all states. Growth is expected to be
particularly strong in New South Wales and Victoria. This will be underpinned by a number of gas -fired generation
projects under development or planned. The largest project at an advanced stage of development is the first stage
of the Mortlake Power Station Project in Victoria. This project has an announced capacity of 550 megawatts and is
scheduled for completion in late 2011 at a capital cost of $735 million (Stark et al. 2011).
Electricity generation from gas in Queensland is projected to more than double over the projection peri od,
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 2008–09 and 2034–35. Wind energy is projected to account for the majority of the
increase in generation from renewable energy sources over this period, growing at an average annual rate of 10.1
per cent to 2034–35 (Table 11). Wind energy is projected to account for 14 per cent of electricity generation in
2034–35. Wind energy is a proven and mature technology, and the output of both individual turbines and wind
farms has increased considerably over the past five years. Wind energy is relatively cost competitive,
39
notwithstanding site specific factors. The competitiveness of wind energy will be enhanced by a reduction i n the
cost of turbines and further efficiency gains through turbine technology development (Geoscience Australia and
ABARE 2010).
Australia has large bioenergy resource potential. Currently, Australia’s bioenergy resources are dominated by
bagasse (sugar cane residue), wood waste, and capture of gas from landfill and sewage facilities for generating
heat and electricity. In 2008–09, bioenergy accounted for less than 1 per cent of total electricity generation (Table
11). The combination of the RET and the potential commercialisation of second generation technologies using a
range of non-edible biomass feedstocks indicate that bioenergy has the potential to make a growing contribution to
renewable electricity generation in Australia. However, this growth is likely to be constrained to some extent by
competition for inputs used in the production of bioenergy, such as water availability and logistical issues
associated with handling, transport and storage. Nonetheless, the use of bioenergy for electricity generat ion is
projected to increase by 3.5 per cent a year over the projection period, but will still account for only 1 per cent of
total generation by 2034–35 (Table 11).
Australia is a world leader in developing solar technologies; however the uptake has been low because of their
relatively high investment cost (Geoscience Australia and ABARE 2010). Electricity generation from solar energy in
Australia is largely sourced from photovoltaic (PV) installations. Electricity generation from solar thermal systems
are currently limited to small-scale pilot projects. Solar energy is projected to grow at 13.6 per cent a year over the
period to 2034–35, but from a very low base (Table 11). The cost of installing solar capacity has generally been
declining over time and there is potential for the cost of solar technologies to continue to decline over the projection
period given the substantial research and development funds allocated toward these technologies. This will
contribute to its competitiveness over the period to 2034–35. In addition, the Australian Government has
implemented a number of policies that are expected to increase the uptake of solar technologies, including the
Solar Flagships Program and the establishment of the Australian Solar Institute.
Australia has large geothermal energy potential. However, these resources are currently considered sub -economic
because geothermal technologies for electricity generation have not been demonstrated to be commercially viable
in Australia. Electricity generation from geothermal energy is currently limited to pilot projects that generate small
volumes of electricity. It is important to note that the development of the geothermal industry in Australia is not
dependent on a major technological breakthrough; all the technology required already exists. The challenge lies in
adapting the technology to make it more commercially viable (Geoscience Australia and ABARE 2010). Given the
time expected to achieve commercial viability and the long lead time to bring a new geothermal pow er plant into
operation, geothermal energy is not expected to play a major role in electricity generation over the projection period,
although it will grow to 4 per cent of total electricity generation by 2034-35 (Table 11).
Hydroelectricity generation is projected to remain broadly unchanged in volume terms over the projection period
because of the limited availability of suitable locations for the expansion of capacity and water supply constraints.
Over the projection period, most of the expected expansion in capacity is assumed to be associated with the
upgrading of existing equipment and small-scale schemes.
40
Box 5: Uncertainty surrounding gas prices for electricity generation
There are a range of perspectives on future gas prices in Australia. The modelling undertaken in this report assumes that gas
prices are likely to gradually increase over the next two decades as a result of interactions between demand and supply.
However, there are a number of factors that could affect the projected price path, including the renegotiation of existing longterm contracts, timeframes for new projects, the pace of development of coal seam gas (CSG), the extent and pace of
convergence in gas prices in the eastern gas market and global LNG markets and international d evelopments.
The dynamics of the western and eastern gas markets are quite different. As a result, there will be differences in the price paths
in these markets over the projection period.
In the western gas market, production directed to the domestic market is dominated by only a few suppliers. Other production
capacity is limited by reserves or the timing of production is closely linked to LNG projects. Consequently, there can be tim es
when there is a domestic supply shortage and domestic prices are higher than export prices (net of shipping and liquefaction
costs) and vice versa. Domestic prices in the western market have increased considerably since early 2007 and are now close
to export parity. Tight demand–supply conditions to 2017 are expected to contribute to relatively high domestic gas prices in the
western market over this period. Beyond 2017, some production from large LNG projects is planned to be directed to the
domestic market, such as Wheatstone and Pluto 2, which will place downward pressure on domestic prices.
In the eastern gas market, there are a number of domestic suppliers from both conventional and unconventional sources. Four
major LNG projects using CSG are planned to start production in Queensland from 2014. Once operational, these pr ojects have
the potential to divert gas from the domestic market, which will support prices increasing towards export parity over the lon ger
term. However, there are a number of factors that may reduce the upward pressure on gas prices. In particular, the gas fields
being developed in the eastern market are onshore and are expected to be developed rapidly over the medium to longer term.
Relatively low barriers to entry in the eastern market and the large number of suppliers will ensure greater competition w ithin the
domestic market and exert some downward pressure on prices. In addition, the extensive gas transmission network linking
basins and markets on the east coast should ensure the efficient transfer of supply from lower to higher demand segments of
the eastern market, which is expected to further slow LNG demand driven price rises.
Given the uncertainty surrounding future gas prices, extra analysis was conducted to assess the effect of a change to the
assumptions used on the electricity generation mix. In this analysis, gas prices were increased by around 40 per cent (in the
latter part of the projection period) relative to base case assumptions.
Under higher assumed gas prices, total electricity generation is projected to grow at a slower rate of 1.3 per cent a year to 340
terawatt hours in 2034–35 (Table 12). The share of gas is projected to be lower under this scenario, at 22 percent, with a
relatively smaller fall in the share of coal relative to the main scenario in Table 11. The share of renewable s rises marginally to
25 per cent (Table 12).
41
Table 12: Electricity generation, with alternative gas price assumptions, by energy source
Level
Average
annual
Share
growth
Energy
Source
2008–09
TWh
2019–20
TWh
2034–35
TWh
2008–09
%
2034–35
%
2008–09 to
2034–35 %
Nonrenewables
227
225
256
93
75
0.5
Coal
182
181
176
74
52
-0.1
black coal
129
129
137
53
40
0.2
brown coal
53
53
40
21
12
-1.1
40
39
74
16
22
2.4
5
5
5
2
2
0.0
Renewables
18
63
84
7
25
6.0
Hydro
12
13
13
5
4
0.2
Wind
4
37
49
2
14
10.1
Bioenergy
2
4
4
1
1
3.3
<1
4
4
<1
1
13.5
0
5
14
0
4
-
245
288
340
100
100
1.3
Gas
Oil
Solar
Geothermal
Total
Numbers in the table may not add up to their totals due to rounding.
The figures for 2008–09 presented in this table may not be identical to actual historical data published in
ABARES’ Australian Energy Statistics. This is a reflection of the different classification systems.
Final energy consumption, by energy type
Total final energy consumption, the amount of energy used in end-use applications, is projected to increase from
3645 petajoules in 2008–09 to 4978 petajoules in 2034–35, a rise of 37 per cent over the projection period and an
average annual rate of increase of 1.2 per cent (Table 13). Electricity and renewable energy are projected to
continue to grow strongly to meet energy demand in end-use sectors over the projection period. This will contribute
to the declining relative share of petroleum products in final energy consumption by 2034–35. Nonetheless, in
absolute terms, the consumption of petroleum products is projected to increase by 36 per cent between 2008 –09
and 2034–35.
42
Table 13: Final energy consumption, by energy type
Level
Average
annual
growth
Share
2008–09
to
Energy type
Coal
2008–09
2019–20
2034–35
2008–09
2034–35
2034–35
PJ
PJ
PJ
%
%
%
162
151
147
4
3
-0.4
1738
2143
2359
48
47
1.2
Gas
749
909
1025
21
21
1.2
Renewables
171
232
265
5
5
1.7
Electricity
826
1042
1182
23
24
1.4
3645
4478
4978
100
100
1.2
Petroleum products
Total
Numbers in the table may not add up to their totals due to rounding.
The figures for 2008–09 presented in this table may not be identical to actual historical data published in
ABARES’ Australian Energy Statistics. This is a reflection of the different classification systems.
Final energy consumption, by sector
The transport and manufacturing sectors are the major drivers of Australia’s final energy consumption, accounting
for 40 per cent and 32 per cent of final energy consumption in 2008–09, respectively (Table 14). Growth in final
energy consumption will tend to be greater in less energy intensive sectors such as the commercial and residential
sectors. This is the continuation of a long term trend in the Australian economy that is expected to be accelerated
by the introduction of carbon pricing.
Transport
Final energy consumption in the transportation sector is projected to grow at an average rate of 1.2 per cent a year
between 2008–09 and 2034–35 (Table 14). While the sector is expected to account for 40 per cent of the increase
in final energy consumption over the projection period, the relative share of transportation in total final energy
consumption is projected to remain unchanged in 2034–35. These projections reinforce the downward trend in road
transport fuel consumption over the past 30 years.
Within the transport sector, the road transport segment is the largest contributor to final energy consumption. In
2008–09, road transport accounted for more than three-quarters of the energy used in the sector, with the bulk of
this coming from passenger transport. Energy use in the road transport sector is projected to increase by 1.2 per
cent a year to 2034–35, driven by passenger and rail transportation.
Energy use in the air transport sector (domestic and international) is projected to grow at
2.2 per cent a year to 406 petajoules in 2034–35. This reflects rapid growth in passenger demand for air transport.
As a result, the share of air transport in the transportation sector is projected to increase from 16 per cent in 2008 –
09 to 21 per cent in 2034–35.
The transport sector is highly dependent on oil-based petroleum products and this trend is expected to continue
over the projection period. There are a range of alternative low-carbon fuels that have the potential to complement
or replace conventional oil in the longer term such as coal-to-liquids, gas-to-liquids, and second generation biofuels.
However, significant further research, development and demonstration would be required to allow these fuels to
make a substantial contribution to meeting transport energy needs. Similarly, electric vehicles and hybrid electric
cars are not expected to make a significant contribution to the road transport fuel mix by 2034 –35 (Box 6).
43
Table 14: Final energy consumption, by sector
Level
Average annual
growth
Share
2008–09 to
2008–09
2019–20
2034–35
2008–09
2034–35
2034–35
Sector
PJ
PJ
PJ
%
%
%
Agriculture
96
131
150
3
3
1.7
231
345
480
6
10
2.9
Manufacturing
1153
1304
1333
32
27
0.6
Transport
1445
1780
1972
40
40
1.2
720
918
1043
20
21
1.4
3645
4478
4978
100
100
1.2
Mining
Commercial &
residential
Total
The figures for 2008–09 presented in this table may not be identical to actual historical data published in
ABARES’ Australian Energy Statistics. This is due to different classification systems.
Box 6: Energy use in the Australian transport sector
The transport sector is the largest final energy consumer in Australia, accounting for 40 per cent of final energy consumptio n.
Over the period to 2034–35, consumption in this sector is projected to grow at an average annual rate of 1.2 per cent reflecting
assumed on-going economic and population growth that will stimulate demand for freight transport and increase rates of vehicle
ownership.
Given the demand for oil and petroleum products for transport fuels is relatively unresponsive to changes in prices, there is not
expected to be a dramatic change from the transport modes, consumption patterns and fuels currently used. However, rising
fuel costs and increasing discernment in the market may result in small changes to transport energy consumption, including
improved energy efficiency, an increased uptake of alternative fuels and the development of alternative transport modes.
In the short term, the major driver of changes in consumption is likely to be energy efficiency, which will be achieved through
tightening fuel efficiency standards, tyre efficiency and eco driving. Commercial incentives faced by freight operators may
encourage significantly more efficiency investment, although uncertainty about future oil prices and high investment costs could
limit the uptake of available opportunities. Efficiency gains are likely to drive small changes within transport energy consu mption,
but an overall increase in consumption may absorb these changes.
The environmental performance of the sector in the long term will be influenced by the small, but growing role of alternative
fuels and other technological breakthroughs. As barriers to use are reduced and technology improvements continue, alternative
fuels may have an increasing market presence in Australia. Currently, the most viable alternative fuels are biofuels and LPG,
although the usage rates are low, with biofuels accounting for 0.5 per cent of the Australian transport fuel supply in 2007–08.
With policy assistance, electric vehicles may become commercially viable within the projection period, although at low levels of
market penetration.
Future changes in the quantum and patterns of transport fuel consumption will be influenced by the policy environment. The
introduction of carbon pricing, fuel excise arrangements, targeted alternative fuels strategies or other efficiency measures could
all affect future demand.
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 so that the share of the sector
as a proportion of total final energy consumption has remained around 32 per cent (Table 14). Over the period to
2034–35, the sector is projected to grow at 0.6 per cent a year, supported by gr owth in the economy and ongoing
global demand for energy intensive, resource based output. However, the growth in the sector is well below the
growth in final energy consumption projected across all sectors (1.2 per cent). This reflects the continuation of a
long-term structural shift toward the commercial and services sector in the Australian economy. This is further
44
reinforced by the introduction of carbon pricing as the rising cost of energy provides incentives to reduce the energy
intensity of the economy. As a result, the share of manufacturing in final energy consumption is projected to decline
to 27 per cent in 2034–35 (Table 14).
Final energy consumption in non-ferrous metals is projected to grow at 0.5 per cent a year from 518 petajoules in
2008–09 to 586 petajoules in 2034–35 (Table 15). This growth will be supported by the planned expansion of
alumina refining capacity over the projection period. BHP Billiton’s Worsley refinery Efficiency and Growth project in
Western Australia will increase the refinery’s annual production capacity by 1.1 million tonnes once completed in
2012 while the expansion at Rio Tinto Alcan’s Yarwun refinery in Queensland will increase capacity by 2 million
tonnes from 2012. The implementation of carbon pricing will increase the cost of energy inputs for minerals
processing. As a result, growth in energy-intensive minerals processing is expected to be relatively subdued over
the projection period. In addition, Xstrata announced in May 2011 that it intends to phase out its cop per smelting
and refining activities in Australia by the end of 2016.
In the iron and steel industry, final energy consumption is projected to decline at an average annual rate of 0.8 per
cent over the projection period to 77 petajoules in 2034–35. This, in part, reflects BlueScope Steel’s closure of
capacity in New South Wales. In August 2011, BlueScope announced that it would close its number six blast
furnaces at Port Kembla and Western Port hot strip mill as part of a restructure aimed at returning it t o a profitable
generation level.
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 2008–09 to 10 per cent in 2034–35 (Table 14). The growth of 2.9 per cent a year is slower than in
previous years, which is driven, in part, by an assumed 0.5 per cent a year reduction in the energy intensity of
mining industries.
Commercial and 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 20 per cent of total final
energy consumption in 2008–09, and is projected to increase to 21 per cent in 2034–35. Energy use in the sector is
projected to increase by
1.4 per cent a year to 1043 petajoules in 2034–35 (Table 14).
The commercial and residential sector relies heavily on electricity and is expected to remain the major driver of
growth in electricity consumption over the projection period. In the residential sector, energy consumption is
influenced by population growth, household income, energy prices and lifestyle choices. Energy is a relatively small
component of household expenditure (ABS 2010b). In addition, current pricing arrangements, particularly for
electricity, do not provide strong price signals to residential energy consumers. As a result, households have not
tended to be highly responsive to changes in prices. However, the Council of Australian Governments (COAG) is
committed to a national rollout of smart meters (meters that allow energy users to observe the real time cost of their
energy consumption) where benefits are considered to outweigh the costs. Such developments should drive an
increased demand response to prices.
Agriculture
Agriculture accounts for a small proportion of final energy consumption, with a share of 3 per cent in 2008–09 that
is projected to remain unchanged to 2034–35. Petroleum products are the major fuel used on farms. Energy use in
the agriculture sector is projected to increase by 1.7 per cent a year to 203 4–35 (Table 14).
45
Table 15: Final energy consumption, by manufacturing subsector
Level
Average annual growth
Share
2008–09 to
Subsector
Wood, paper & printing
2008
–09
2019–20
2034–35
2008–09
2034–35
2034–35
PJ
PJ
PJ
%
%
%
68
86
91
6
7
1.1
166
182
169
14
13
0.1
93
80
77
8
6
-0.8
Non-ferrous metals
518
571
586
45
44
0.5
Other manufacturing
307
384
410
27
31
1.1
1153
1304
1333
100
100
0.6
Basic chemicals
Iron & steel
Total
Numbers in the table may not add up to their totals due to rounding.
The figures for 2008–09 presented in this table may not be identical to actual historical data published in ABARES’
Australian Energy Statistics. This is a reflection of the different classification systems.
46
5 Energy production and trade
The major sources of energy produced in Australia on an energy content basis are coal and gas. In 2008 –09,
production of coal was 9651 petajoules (around 322 million tonnes) or 74 per cent of Australian energy production
(excluding uranium). Gas accounted for 16 per cent of production, followed by crude oil and condensate and
naturally occurring LPG (9 per cent) and renewable energy (hydroelectricity, wind energy, bioenergy and solar
energy) at 2 per cent (Table 16). Although Australia is a major producer of ur anium oxide, it is not accounted for in
the projections as it is not consumed as a fuel domestically, and therefore, does not affect the energy balance.
Details on the outlook for uranium are contained in Box 7.
Table 16: Energy production, by source
Level
Average
annual
growth
Share
2008–09
to
Energy type
Non-renewables
2008–09
2019–20
2034–35
2008–09
2034–35
2034–35
PJ
PJ
PJ
%
%
%
12834
22649
27741
98
98
3.0
9651
15832
18956
74
67
2.6
black coal
9004
15185
18676
69
66
2.8
brown coal
647
647
281
5
1
-3.2
Oil
997
811
376
8
1
-3.7
LPG
104
116
135
1
<1
1.0
Gas
2082
5890
8274
16
29
5.5
279
548
660
2
2
3.4
Hydro
45
47
47
<1
<1
0.2
Wind
14
131
175
<1
1
10.1
211
329
365
2
1
2.1
Solar
9
22
26
<1
<1
4.1
Geothermal
0
18
48
0
<1
-
13113
23197
28401
100
100
3.0
Coal
Renewables
Bioenergy
Total
Numbers in the table may not add up to their totals due to rounding.
The figures for 2008–09 presented in this table may not be identical to actual historical data
published in ABARES’ Australian Energy Statistics. This is a reflection of the different classification
systems.
Australian energy production (excluding uranium) is projected to grow at an average annual rate of 3 per cent over
the projection period. At this rate, total production of energy in Australia is forecast to more than double to 28 401
petajoules in 2034–35 (Table 16). Coal and gas are projected to account for 96 per cent of Australia’s energy
production in 2034–35. Coal production is projected to increase by 96 per cent to 18 956 petajoules (632 million
tonnes), while gas is projected to increase almost four-fold to 8274 petajoules (330 960 gigalitres).
47
Box 7: Australian uranium outlook
As world uranium demand continues to grow, particularly in major consuming countries, new mines will be developed and
existing production facilities expanded to increase Australia’s export capacity.
According to BREE calculations (and outside the present modelling), Australia’s uranium production is projected to incr ease at
an average annual rate of 4 per cent from 8700 tonnes uranium (U,4846 petajoules) in 2008–09 to around 26 200 tonnes U
(14 500 petajoules) in 2034–35. This growth will be supported by the development of a number of new projects from 2014–15.
Figure G: Australian uranium production
Sources: BREE calculations, outside the E4cast model
Currently, there are three mines producing uranium in Australia: Ranger (4500 tonnes U a year), Olympic Dam (3800 t U) and
Beverley (900 t U). Growth in uranium production is expected to come from the Honeymoon and Mullaquana projects in South
Australia; the Yeelirrie, Kintyre, Mulga Rock, Lake Maitland and Wiluna projects in Western Australia, and the Bigrlyi project in
the Northern Territory.
In addition, plans are underway to expand production at the Olympic Dam mine, which will be the largest uranium d evelopment
in Australia. The proposed expansion will increase production to around 19 000 tonnes of U 3O8 (16 100 t U) a year.
A number of these projects have not yet received final investment decisions. As a result, the eventual timing and output from
these projects may differ from current plans.
With the exception of crude oil and refined petroleum products, Australia is a net exporter of energy commodities.
As the projected growth in energy production exceeds that of primary energy consumption, Australia’s exportable
surplus of energy is expected to increase over the period to 2034–35. Demand for Australia’s energy resources is
expected to remain robust over the projection period, particularly in China and other developing economies. This
will be supported by growth in economic activity and industrial production which is expected to provide a solid
platform for growth in energy consumption. In 2008–09, the ratio of Australia’s primary energy consumption to nonuranium energy production was 44 per cent. This is projected to decline to 26 per cent in 2034–35 (Figure H).
48
Figure H: Australian energy balance
Black coal production and exports
Production of black coal, which includes thermal and metallurgical coal, is projected to grow at 2.8 per ce nt a year
to 18 676 petajoules (623 million tonnes) in 2034–35. Despite this growth, the share of black coal in total energy
production is projected to decline from 69 per cent in 2008–09 to 66 per cent in 2034–35 (Table 16).
Growth in black coal will be supported by the development of a number of new mines and expansions at existing
mines in New South Wales and Queensland over the projection period. New thermal capacity will come from BHP
Billiton’s RX1 thermal coal development in the Hunter Valley region of New South Wales (4 million tonnes a year)
which is scheduled for completion in 2013 and Xstrata Coal’s Ravensworth North development, also in New South
Wales, which is expected to have an annual capacity of 8 million tonnes when completed in 2012. New
metallurgical coal production will be supported by the development of BHP Billiton Mitsubishi Alliance’s Daunia
mine in Queensland (4.5 million tonnes a year) in 2013 and an expansion at Jellinbah Resources’ Lake Vermont
mine (additional 4 million tonnes a year) in 2013.
Black coal is an important energy export for Australia, with coal projected to account for almost three -quarters of the
growth in exports over the period to 2034–35. The projected growth of 3.3 per cent a year is based on the
expectation that global demand for coal will continue to increase over the projection period, particularly in emerging
market economies in Asia, in line with growing demand for electricity and steel-making raw materials. Australia, with
its abundant reserves of high-quality coal, is well positioned to make a substantial contribution to meeting this
increased demand.
The development of infrastructure in New South Wales and Queensland will support coal exports growing to 17 415
petajoules (581 million tonnes) in 2034–35 (Table 17, and Figure I). There are a number of port expansions at
Newcastle, including the second stage of the Newcastle Coal Infrastructure Group (NCIG) terminal, which will lift
capacity by 23 million tonnes annually, and two stages of expansion at Port Waratah Coal Services’ Kooragang
Island Coal Terminal, which will collectively increase annual capacity by 32 million tonnes to a total of 145 million
tonnes a year. In Queensland, BHP Billiton’s Hay Point coal terminal is scheduled for completion in 2014 and will
increase the port’s capacity by 11 million tonnes annually to
55 million tonnes a year.
49
Table 17: Net trade in energy
Level
Average
annual growth
Subsector
2008–09
2019–20
2034–35
%
PJ
PJ
PJ
2008–09 to 2034–
35
Coal
7411
13725
17415
3.3
Liquid fuels a
-920
-1513
-2159
3.1
LNG
838
4006
5663
7.6
Total
7329
16218
20919
4.1
a Includes crude oil, other refinery feedstock, petroleum products and LPG.
Figure I: Australian black coal balance
Natural gas production and LNG exports
Australia has considerable resources of gas that are increasingly being developed for domestic use and export
(Figure J). The significant gas resource base is capable of meeting domestic and export demand over the
projection period. In 2008–09, Australian gas output was 2082 petajoules (around 38 million tonnes), including LNG
(Table 18). The majority of Australia’s conventional gas resources are located off the north -west coast of Western
Australia. Reflecting this, the western market is the largest producing region in Australia. Gas production in the
western market was 1199 petajoules in 2008–09 or 58 per cent of total production.
Gas production in the eastern and northern markets was 688 petajoules and
195 petajoules, respectively, in 2008–09 (Table 18).
In the western market, gross gas production, including LNG, is projected to grow at an average annual rate of 5.5
per cent to 4771 petajoules in 2034–35 (Table 18). Strong growth in domestic and global demand for gas has been
driving the development of new projects and LNG capacity. There are a number of LNG projects that are expected
to be completed in the western market over the projection period. These include Chevron, Shell and ExxonMobil’s
Gorgon LNG project (15 million tonnes a year) in 2015; and Chevron, Apache, KUFPEK and Tokyo Electric’s
Wheatstone (8.9 million tonnes a year initially) in 2016.
50
Gas production in the eastern market is projected to grow at 5 per cent a year to 2492 petajoules in 2034 –35. A
prominent feature of the eastern gas market is the increasing contribution of CSG to total production. In 2008 –09,
CSG accounted for 8 per cent of Australian production and around 89 per cent of production in Queensland.
Production of CSG in Queensland and New South Wales is expected to maintain its strong growth trajectory over
the projection period supported by the development of a number of new projects.
A large proportion of this CSG will be consumed domestically, supporting growth in CSG -fired electricity generation,
particularly in Queensland and New South Wales. The rapid growth in CSG production in Queensland suggests that
there may also be some changes in gas flow patterns, with relatively less gas flowing from Victoria and more
flowing from Queensland (AEMO 2010).
Table 18: Australian gas production
Level
Average
Annual
Growth
Share
2008–09
to
2008–09
2019–20
2034–35
PJ
PJ
PJ
2008–09 2019–20
%
%
2034–
35
2034–35
%
%
Eastern market
688
1893
2492
33
32
30
5.0
Western market
1199
3626
4771
58
62
58
5.5
195
371
1011
9
6
12
6.5
2082
5890
8274
100
100
100
5.5
Northern
market
Total
It is expected that CSG will be also be converted to LNG over the projection period, with a number of projects being
planned around Gladstone. BG Group’s Queensland Curtis LNG project received approval in October 2010. The
facility will have a capacity of 8.5 million tonnes of LNG a year once completed in 2014. It will be the first facility in
the world to use CSG as a feedstock in the production of LNG. The Gladstone LNG development (7.8 million tonnes
a year) was approved in early 2011 and is scheduled to be completed in 2015. There are a numbe r of other LNG
projects using CSG as a feedstock planned for development. However, some of these projects may not proceed for
several years as they face changes in market conditions or are targeting the same market opportunities. The
development of CSG-LNG is likely to have implications for gas prices on the east coast.
51
Figure J: Australian gas balance
Production in the northern gas market (including imports from the Joint Petroleum Development Area in the Timor
Sea for processing in Darwin) was 195 petajoules in 2008–09. Production is projected to be 1011 petajoules in
2034–35, growing at an average rate of 6.5 per cent a year. Gas production in the northern market is projected to
be more than sufficient to meet domestic demand. Domestic gas consumption growth will be underpinned by the
increased volumes of gas required for the conversion of gas to LNG at the Ichthys processing plant and the
increased uptake of gas-fired electricity generation.
Crude oil production and net imports
Australia’s oil production is influenced by the geology of oil deposits, exploration activity and world prices. The
latest available estimates of recoverable oil resources are around 8624 petajoules (1466 million barrels), largely
located in the Gippsland and Carnarvon basins (Geoscience Australia 2011). A major proportion of Australia’s oil
production is sourced from mature fields with declining oil reserves. However, there are many prospective offshore
areas that have not been explored. In addition, Australia has substantial res ources of condensate (16 295
petajoules) and LPG (6281 petajoules) associated with the major gas fields on the North West Shelf in the Browse
and Bonaparte basins (Geoscience Australia 2011).
Australia’s crude oil and natural gas liquids production is projected to decline by 2.9 per cent a year from 1101
petajoules in 2008–09 to 511 petajoules in 2034–35 (Table 16). It is assumed that producers will develop a small
proportion of the resource base each year in response to price signals. However, the reserves in existing and
subsequently developed oil fields are assumed to deplete as the oil is extracted that will result in lower production
over the projection period. Production of naturally occurring LPG is projected to increase at an average annual rate
of 1 per cent to 135 petajoules in 2034–35.
In 2008–09, Australia’s crude oil production was equivalent to around 76 per cent of refinery feedstock. As a result,
Australia was a net importer of crude oil. However, around 60 per cent of Australia’s crude oil a nd condensate
production was exported, primarily to oil refineries in Asia.
52
Figure K: Australian oil and LPG balance
Australian consumption of liquid fuels (excluding petroleum products) is projected to increase from 1784 petajoules
in 2008–09 to 1991 petajoules in 2034–35 (Figure K). Over the projection period, the gap between supply and
demand will be exacerbated by the significant proportion of growth in crude oil and naturally occurring LPG
production being concentrated in the Carnarvon and Browse basins in north-western Australia, which are closer to
Asian refineries than the east coast of Australia. As a result, it is reasonable to assume that the bulk of the supply
of crude oil and naturally occurring LPG will be exported for further processing rath er than directed to the domestic
market. Reflecting this assumption, the ability to meet domestic demand with domestic production is likely to be
lower than implied by the simple comparison of production and consumption.
The demand for petroleum product imports is determined by domestic oil production, end use consumption of
petroleum products, and domestic petroleum refining capacity. Australia’s refining capacity is not expected to
expand considerably over the projection period given increasing competitive pressure, particularly from large SouthEast Asian refineries. For example, in April 2011, Shell announced plans to convert its Clyde refinery and Gore Bay
Terminal in Sydney into a fuel import terminal. This would result in the end of its refining ope rations. The Clyde
refinery supplies around 40 per cent of Sydney’s and 50 per cent of New South Wales’ petroleum requirements,
respectively (Shell 2011). For a given domestic consumption and production projection, petroleum refining
constraints may result in lower crude oil imports and higher imports of refined products.
The refining industry also uses petroleum products as an input to convert oil feedstock into a range of petroleum
products. Around 7 per cent of gross refinery output is used on-site in the conversion process, as well as small
quantities of natural gas and electricity.
With declining oil production, Australia’s net trade position for liquid fuels is set to decline, with net imports
increasing by 3.1 per cent a year to 2034–35 (Table 17).
53
6 Conclusions
Australian energy consumption will continue to grow over the next 26 years, albeit at a slower rate than witnessed
over the past few decades. This represents an ongoing trend that has been accelerated by a number of policy
drivers and market factors.
The projections in this report point towards a major change in the Australian energy landscape. The change is most
prominent in the energy mix. BREE modelling indicates a shift to low emission technologies, driven by policies that
promote a less emission intensive economy. The Renewable Energy Target and the introduction of carbon pricing
will drive the uptake of renewable technologies, which are projected to account for 9 per cent of primary energy
consumption in 2034–35, up from 5 per cent in 2008–09.
Within non-renewables, there is projected to be a strong increase in the use of gas, particularly in electricity
generation, which is one of the largest components of primary energy consumption, and LNG production. Gas -fired
electricity generation is based on mature technologies with competitive cost structures. As such, it is expected to
play a transitional role in the Australian energy mix until lower emission technologies become more cost competitive.
Renewable energy is projected to have the strongest growth prospects, driven largely by the RET and other policies
promoting the uptake of these technologies. Within the renewables, the largest expansion is projected to occur in
wind energy which is a more mature technology in Australia and has a lower cost-structure relative to other
renewable technology options. In addition, solar energy and geothermal energy are expected to play a small, but
growing role in the energy mix.
The transition to a lower carbon economy will rely on long-term structural adjustment of the Australian energy
sector. While Australia has diverse and abundant energy resources, the transformation will require considerable
investment in energy supply chains to allow for the larger-scale integration of renewable energy sources and other
emerging technologies. Changes to market settings within the energy market framework will further help to support
this transition. A shift to a cleaner energy future will require a broad energy policy framework that supports
investment in Australia’s energy future along with timely adjustments in response to emerging pressures and
market developments.
54
References
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BREE 2011, Resources and Energy Statistics Annual, Canberra, November.
Bukhteeva, O., P. Neal and G. Allinson (2009), “Optimisation economics for CO 2 Capture and Storage in Central
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