Australian Energy Projections to 2049-50, BREE, Canberra, November.
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Australian Energy Projections to 2050
Postal address:
Bureau of Resources and Energy Economics
GPO Box 1564
Canberra ACT 2601
Phone:
Email:
Web:
+61 2 6276 1000, or 61 2 6243 7504
[email protected], or [email protected]
www.bree.gov.au
Acknowledgments
This report was prepared by Arif Syed. The author gratefully acknowledges the assistance
of BREE colleagues for their assistance in data provision and helpful comments on drafts
of this report. A special thanks goes to Peta Nicholson for her help in improving the
graphic design in the report. Valuable input and comments were also received from Rhys
Hunt, Richard Miles, and Dr Cally Brennan of the Department of Industry.
The preparation of this report also benefited from valuable insights and information
provided by a range of agencies that participated in the consultation program. These
included the Australian Treasury, the Clean Energy Regulator, the Australian Energy
Market Operator (AEMO), the Commonwealth Scientific and Industrial Research
organization (CSIRO), the New South Wales Department of Water and Energy, Bloomberg
and ACIL Allen consultancies, and the Department of Environment.
2
Foreword
The Australian Energy Projections to 2050 provides long-term projections of Australian
energy consumption, production and trade. This report assists in providing the basis for
informed decision making for the Australian energy sector by government, industry and the
community.
This report aims to encapsulate the recent developments such as the repeal of carbon
pricing and changes in electricity generation technology costs in providing long-term
projections of Australian energy consumption, production and trade.
Coal and oil are projected to continue to supply the bulk of Australia’s energy needs,
although their share in the energy mix is projected to decline. Electricity generation is
projected to grow at the rate of 0.8 per cent a year from 2014-15 to 2049-50, and black
coal is projected to remain Australia’s dominant energy export, while the liquid natural gas
exports are also projected to increase significantly.
Wayne Calder
Deputy Executive Director
Bureau of Resources and Energy Economics
November 2014
3
Contents
Acknowledgments
2
Foreword
3
Contents
4
Glossary
5
Units
7
Executive Summary
8
1 Introduction
11
2 The Australian energy context
12
Energy resources
12
Energy consumption
13
Energy production
15
Electricity generation
15
Energy trade
16
Energy policy
17
Renewable Energy Target
17
Energy efficiency
19
3 Methodology and key assumptions
20
E4cast overview
20
Key assumptions
25
4 Energy Consumption
28
Total primary energy consumption
28
Aggregate energy intensity trends
28
Primary energy consumption, by state
30
Primary energy consumption, by sector
31
Electricity generation
33
Final energy consumption, by sector
37
5 Energy Production and Trade
41
Black coal production and exports
42
Natural gas production and LNG exports
44
Crude oil production and net imports
45
6 Conclusions
48
References
49
4
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.
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
itself consumes energy. For example, some natural gas and liquefied petroleum gas is
consumed during gas manufacturing, some petroleum products are consumed
during petroleum refining, and various fuels, including electricity itself, 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.
Gas
Gases that include commercial quality sales gas, liquefied natural gas, ethane,
methane (including coal seam and mine-mouth methane and gas from garbage tips
and sewage plants) and plant and field use of non-commercial quality gas. In this
report, natural gas also includes town gas (including synthetic natural gas, reformed
gas, tempered liquid petroleum gas and tempered natural gas).
Gas pipeline operation Natural gas used in pipeline compressors, and losses, operation and leakage during
transmission.
Levelised cost
The total levelised cost of production represents the revenue per unit of electricity
generated that must be met to break even over the lifetime of a plant.
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 non-fuel applications (solvents, lubricants, bitumen, waxes, petroleum coke for
anode production and specialised feedstocks). The distinction between the
consumption of petroleum at the primary and final end use stages relates only to
where the petroleum is consumed, not to the mix of different petroleum products
consumed. The consumption of petroleum at the primary energy use stage is
referred to collectively as oil, while the consumption of petroleum at the final end
use stage is referred to as petroleum products. The one exception to this is
liquefied petroleum gas (LPG). LPG is not included in the definition of end use
consumption of petroleum because it is modelled separately.
Primary fuels
The forms of energy obtained directly from nature. They include nonrenewable fuels such as black coal, brown coal, uranium, crude oil and
condensate, naturally occurring liquid petroleum gas, ethane and natural gas,
and renewable fuels such as wood, bagasse, hydroelectricity, wind and solar
energy.
5
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, electricity, coke, coke oven gas, blast furnace gas and
briquettes.
Total final energy
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 Also known as total domestic availability. The total of the consumption of each 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.
6
Units
Metric units
Standard metric prefixes
J
Joules
K
kilo
103 (thousand)
L
Litres
M
mega
106 (million)
t
Tonnes
G
giga
109 (1000 million)
g
Grams
T
tera
1012
Wh
watt-hours
P
peta
1015
b
billion (or 1000 million)
E
exa
1018
Standard conversions
1 barrel = 158.987 L
1 kWh = 3600 kJ
Indicative energy content conversion factors
Black coal production
28.5 GJ/t
Brown coal
9.7 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.
7
Executive Summary
This report contains BREE’s long-term projections of Australian energy consumption,
production and trade for the period 2014-15 to 2049-50. 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.
In undertaking these projections, BREE has incorporated government policies already
enacted and those that can reasonably be expected to be adopted over the projection
timeframe. Noting that the Government policy is to introduce the direct action plan to
mitigate carbon emissions, there is no direct or indirect pricing of carbon emissions in the
projections. As the Renewable Energy Target (RET) review is in progress, the existing
RET target has been retained.
Energy consumption
• Total primary energy consumption is projected to grow by nearly 42 per cent (or
1 per cent a year) over the projection period. This compares with the average annual
growth in primary energy consumption in Australia of 1.5 per cent a year from 2001-02 to
2011-12.
• Coal and gas will continue to supply Australia’s energy needs, although their share in
the energy mix is expected to decline.
• The use of gas (conventional and unconventional natural gas) in industries is expected
to grow over the outlook period with projected falls in gas-fired electricity generation offset
by growth in the consumption of gas in LNG production.
• Renewable energy consumption is projected to increase moderately at the rate of
0.9 per cent a year over the projection period. The growth in renewable energy is mainly
driven by strong growth in wind and solar energy, at 2 and 1.7 per cent, respectively.
• The higher growth rates in energy consumption projected in Queensland, Northern
Territory, and Western Australia, compared with other states, are underpinned by relatively
higher gross state product assumptions, combined with the high share of mining in
economic output and the significant projected expansion of the gas sector, in particular
LNG.
• The electricity generation sector and the transport sector are expected to remain the
two main users of primary energy over the outlook period.
• While the mining sector accounts for 8.7 per cent of primary energy consumption in
2014-15, it is projected to have the highest energy consumption growth rate over the
outlook period. This reflects the expected ongoing moderate global demand for energy and
mineral commodities and the large number of mineral and energy projects (including LNG
and coal seam gas) assumed to come on stream over the next few years.
• Oil consumption in the transport sector is expected to grow steadily over the projection
period at an average rate of 1.3 per cent a year, driven largely by economic growth. Within
the transport sector, road transport is the largest contributor to energy consumption.
8
Energy use in the road transport sector is projected to grow by 0.65 per cent a year on
average over the period to 2049-50.
Electricity generation
• Gross electricity generation is projected to grow by nearly 30 per cent (or 0.8 per cent
a year) from 255 terawatt hours in 2014-15 to 332 terawatt hours in 2049-50. Coal is
expected to remain the dominant source of electricity generation. The share of coal in
electricity generation is projected to remain broadly constant (64 per cent in 2014-15 and
65 per cent in 2049-50), growing at 0.8 per cent a year.
• Due to the declining cost of renewable generation (mostly wind and solar) over the
projection period as shown in the latest BREE’s Australian Energy Technology
Assessment (BREE 2013a), electricity production from renewables is expected to grow by
1.5 per cent a year, with wind and solar growing at a rate of 2 and 3 per cent respectively
over the projection period. The share of renewables is expected to increase from
15.3 per cent in 2014-15 to 22 per cent in 2020, and then falling slightly to 20.1 per cent by
2049-50.
Energy production and trade
• Total production of non-uranium energy in Australia is projected to grow by 59 per cent
(or 1.3 per cent a year) over the projection period, driven by strong growth in gas, to reach
27 567 petajoules in 2049-50.
• While coal production is expected to continue to increase, with a projected growth of
1.2 per cent a year, its share in total energy production is expected to fall from the
75 per cent in 2014-15 to 71 per cent by the end of the projection period.
• The production of gas (conventional and unconventional natural gas) is expected to
grow at a rate of 2.5 per cent a year over the projection period, while its share in total
Australian energy production increases from 18 per cent to 27 per cent from the beginning
to the end of the projection period.
• Australia’s exports of energy are projected to grow over the projection period. In
2014-15, the ratio of Australia’s primary energy consumption to energy production
(excluding uranium) is estimated to be 35 per cent. By 2049-50, this ratio is projected to
fall to 31 per cent.
• Black coal, which includes both thermal and metallurgical coal, is projected to remain
Australia’s dominant energy export. The projected average annual growth rate of
1.2 per cent is based on expectations that global demand for coal will continue to increase
in the period to 2049-50 as a result of increased demand for electricity and steel-making
raw materials, particularly in emerging market economies in Asia.
• LNG exports are also projected to increase significantly. By 2049-50, LNG exports from
the western market have the potential to reach 44 million tonnes (2 838 petajoules), which
reflects an average annual growth rate over the projection period of 2.6 per cent. LNG
growth is higher in Eastern Gas Market and Northern Gas Market exports at 6.7 and
4 per cent a year, respectively, over the projection period. It may be noted that LNG
exports are included as exogenous variables, using the data to 2020 from BREE’s internal
9
database. IEA projections for growth in LNG supply in Australia are used (IEA 2012) as
well.
• With declining oil production and limited prospects for an expansion of refinery capacity,
coupled with recent refinery closures, Australia’s net trade position for crude oil and refined
petroleum products is expected to deteriorate over the outlook period. Australia’s net
imports of liquid fuels are projected to increase by 2.4 per cent a year on average.
10
1 Introduction
The current set of results provides an update to the Australian energy consumption,
production and trade projections published by BREE in December 2012 (BREE 2012a),
with the following amendments:
•
•
•
•
revisions to the base year data;
revisions to economic growth assumptions;
revisions to long-term energy price and electricity generation technology costs
assumptions; and
removing carbon pricing.
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 2014–15 to 2049–50. These projections are derived using the E4cast model, a
dynamic partial equilibrium model of the Australian energy sector.
In undertaking these projections, government policies that have already been enacted are
included, in particular, the Renewable Energy Target and the repeal of carbon pricing.
There is always some degree of uncertainty about technology, investment and also
government policies in the area of energy. The projections should only be considered as a
scenario of future energy use, and not a forecast of energy use. In this report, measures of
energy consumption, production and net trade are expressed in energy content terms
(typically petajoules or gigawatt hours for electricity) to allow for comparison across the
energy commodities.
The report is organised as follows. In section 2 the energy context in Australia is
described, with a view to highlighting the historical trends in the data and their likely effect
on the long-term energy trends in the next sections. Section 3 briefly presents the
modelling framework used, as well as the key underlying assumptions. Section 4 provides
the outlook for Australian energy consumption and electricity generation covering the
period 2014–15 to 2049–50, and Section 5 provides the long-term outlook for Australian
energy production and trade. Section 6 offers concluding remarks.
11
2 The Australian energy context
Energy resources
Australia is endowed with abundant, high quality and diverse energy resources (Map 1).
Australia has around 34 per cent of the world’s uranium resources, 14 per cent of the
world’s black coal resources, and almost 2 per cent of world gas resources. Australia has
only a small proportion of world resources of crude oil. Australia also has large, widely
distributed wind, solar, geothermal, hydroelectricity, ocean energy and bioenergy
resources.
Geoscience Australia (GA) and BREE published Australian Energy Resource Assessment
(AERA) in June 2014 (GA and BREE 2014), which has informed the present section of this
report. Australia's energy resources are a key contributor to Australia's economic
prosperity. Australia's estimated total demonstrated non-renewable energy resources, with
the exception of oil, have increased since 2010.
Australia’s diverse energy resource base includes substantial coal resources that support
domestic consumption and sizeable energy exports around the world.
Australia has substantial uranium resources that support world-leading exports. Gas
resources rank as Australia's third largest energy resource, supporting domestic
consumption and a growing export market. Australia has limited crude oil resources and is
increasingly reliant on imports for its transport fuels.
Australia is endowed with renewable energy resources (wind, solar, geothermal, ocean
and bioenergy). Wind and solar energy resources are being increasingly exploited, while
geothermal and ocean energy remain largely undeveloped.
Overall, it is expected that domestic and international demand for Australia's energy
resources will continue to rise over the next few decades; however the rate of this growth
is expected to slow, and the types of energy used are likely to change as new technologies
become more competitive.
The development of these resources has contributed to the competitiveness of energyintensive industries and provided considerable export income. Australia is one of the few
OECD economies that is a significant net exporter of energy commodities, with the major
exports being coal, liquefied natural gas (LNG), uranium and petroleum.
Since uranium is not consumed domestically, it is not included in the energy balance
projections presented in the following sections. In this section, uranium is included in
production and exports to provide a historical description of Australian energy. Therefore,
the numbers in this section are not strictly comparable to the numbers in the following
sections that exclude uranium.
12
Map 1: Distribution of Australia’s energy resources
Source: GA and BREE 2014
Energy consumption
Primary energy consumption measures the total amount of energy used within the
Australian economy. It is the total of the consumption of each fuel in both the conversion
and end-use sectors. Over the past three decades, growth in energy consumption has
generally remained below the rate of economic growth. This indicates a longer term
decline in the ratio of primary energy use to GDP, or energy intensity (Figure 1) in the
Australian economy. This can be attributed to two key factors: improvements in energy
efficiency associated with technological advancement; and a shift in industry structure
towards less energy-intensive sectors such as the commercial and services sectors.
13
Figure 1: Australian energy intensity
120
100
80
60
40
20
0
1991-92
1992-93
1993-94
1994-95
1995-96
1996-97
1997-98
1998-99
1999-00
2000-01
2001-02
2002-03
2003-04
2004-05
2005-06
2006-07
2007-08
2008-09
2009-10
2010-11
2011-12
2012-13
Index
Source: BREE 2014a, Table B
In 2012–13 black and brown coal together accounted for 33 per cent of total energy
consumption, its lowest share since the early 1970s. Coal consumption fell by 6 per cent in
2012–13, underpinned by falling coal use in the electricity generation and iron and steel
sectors.
Figure 2: Australian energy consumption, by fuel type
Source: BREE 2014a, Table C.
The share of natural gas in Australia’s energy mix has increased in recent years,
supported by greater uptake in the electricity generation sector and growth in industrial
use, particularly in the non-ferrous metals sector. Gas consumption rose by 2 per cent in
2012–13, supported by an expansion in alumina output and additional gas-fired electricity
generation capacity.
Hydro energy has been another significant contributor to energy consumption in Australia,
with other renewables (solar, wind, and bioenergy) representing a much lower proportion
of the total primary energy consumption.
14
Energy production
Primary production
Energy production is defined as the total amount of primary energy produced in the
Australian economy, as measured before consumption or transformation. Australia is the
world’s ninth largest energy producer, accounting for around 2.4 per cent of the world’s
energy production (IEA 2012a). The main fuels produced in Australia are coal, uranium
and gas (Figure 3). While Australia produces uranium, it is not consumed domestically and
all output is exported. Coal accounted for around 59.3 per cent of total energy production
in energy content terms in 2012-13, followed by uranium (22 per cent) and gas
(12.7 per cent). Crude oil, condensate and naturally occurring LPG represented
4.6 per cent of total energy production in that year, and renewable energy the remaining
1.7 per cent.
Australian production of renewable energy is dominated by bagasse, wood and wood
waste, and hydroelectricity, which together accounted for around 80 per cent of renewable
energy production in 2012-13. Wind and solar energy accounted for the remainder of
Australia’s renewable energy production, and their production has been increasing
strongly.
Figure 3: Australian energy production, by fuel type
Source: BREE 2014a, Table J.
Electricity generation
Electricity generation has grown at an average annual rate of 3.5 per cent a year from
1991-92 to 2001-02. However, there has been a gradual decline in generation over the
past few years (Figure 4), from 253 terawatt hours (around 911 petajoules) in 2010–11 to
249 terawatt hours (897 petajoules) in 2012–13. Electricity generation grew at an average
rate of 1.2 per cent from 2002-03 to 2012-13 (Figure 4).
Coal continues to be the major fuel source for electricity generation, although its share in
total production fell from 77 per cent 2003-04 to around 66 per cent in 2012-13. In
contrast, natural gas-fired generation continued to rise in 2012–13, supported by new
capacity coming on line in Victoria.
15
Figure 4: Australian electricity generation, by fuel type
300 000
250 000
200 000
150 000
100 000
50 000
1991-92
1992-93
1993-94
1994-95
1995-96
1996-97
1997-98
1998-99
1999-00
2000-01
2001-02
2002-03
2003-04
2004-05
2005-06
2006-07
2007-08
2008-09
2009-10
2010-11
2011-12
2012-13
0 000
GWh
Black coal
Brown coal
Natural gas
Oil
Renewables
Source: BREE 2014a, Table O.
The share of renewables in Australian electricity generation has risen from approximately
8 per cent in 2003–04 to around 13 per cent in 2012–13.
Energy trade
Australia’s energy exports grew by 14 per cent in 2012–13 in energy content terms, to
reach 15 504 petajoules, which is equal to around 80 per cent of total energy production.
This strong growth was led by Australia’s three largest energy exports: black coal, uranium
oxide and liquefied natural gas (LNG) (Figure 5).
Figure 5: Australian energy exports, by fuel type
Source: BREE 2014a, Table J.
Total export earnings for mineral and energy commodities for 2013-14 are forecast to be
around $196 billion, supported by robust growth in both mineral and energy commodity
export volumes. These predictions are in spite of tighter international commodity market
conditions and lower margins for domestic producers,
16
Black coal exports amounted to 9 485 petajoules (around 336 million tonnes) in 2012-13
(AES 2014), as production rebounded at existing mines and ramped up at a number of
new projects completed in 2012. Coal exports have grown at 5 per cent a year over the
past decade as strong global demand (particularly from China) has stimulated investment
in numerous expansions and new mine and infrastructure capacity.
In 2013-14 LNG exports reached 1 303 petajoules (around 23.9 million tonnes). Over the
past decade, two new LNG trains built at NWS (in 2004 and 2008), and the start-up of
Darwin LNG in 2006 and Pluto in 2012 have been responsible for sustained LNG export
growth of 13 per cent a year (BREE 2014 a).
Australia is a net importer of liquid hydrocarbons, including crude oil and most petroleum
products.
Imports of crude oil and refined products have been growing strongly in recent years.
Expansion in international refining capacity, particularly in Singapore, combined with
growth in the mining and transport sectors has seen Australian imports of automotive
gasoline, diesel fuel and aviation turbine fuel all grow strongly. The ageing domestic
refineries are finding it difficult to compete with vast and more modern refineries in Asia
that hold significant technological and economies-of-scale benefits over Australian
refineries.
Any future expansion of Australia’s energy market, including access to new energy
resources, will require investment in energy infrastructure. Additional investment will be
required to replace ageing energy assets and also to allow for the integration of renewable
energy sources into existing energy supply chains.
Energy policy
Energy related policy responsibilities are shared across the different levels of government
in Australia. Much of Australia’s energy policy is developed and implemented through
cooperative action between the Australian and state and territory governments.
The Government has prioritised a new Energy White Paper to address the challenges
facing Australia’s energy sector and to provide industry and consumers with certainty in
government policy.
The Energy White Paper will articulate a coherent and integrated national energy policy,
addressing the issues of reliable and competitively priced energy supply, streamlining
regulation, and driving a commercially driven energy market that provides transparent
prices and investment signals across all sources of energy and proven energy
technologies.
Further information is available on the Energy White Paper website
www.ewp.industry.gov.au
Renewable Energy Target
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. The Renewable Energy Target legislation requires that the scheme is reviewed
every two years. The Australian Government released the Terms of Reference (ToR) for the
review and appointed an expert panel to undertake the review in February 2014. The ToR
17
specifies the examination of the operation and costs and benefits of the Renewable Energy
(Electricity) Act 2000 ("the Act") and related legislation and regulations, and the RET scheme
constituted by these instruments. This included considering:
•
the economic, environmental and social impacts of the RET scheme, in particular
the impacts on electricity prices, energy markets, the renewable energy sector, the
manufacturing sector and Australian households;
•
the extent to which the formal objects of the Act are being met; and
•
the interaction of the RET scheme with other Commonwealth and State/Territory
policies and regulations.
On 15 August 2014 the Expert Panel provided its report to the Australian Government. The
Government is currently considering the RET Review report.
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 at the time the RET was introduced. The RET brought existing
state based RETs, such as the Victorian Renewable Energy Target, into a single national
scheme.
Initially, retailers and large users of electricity were legally required to earn or obtain
Renewable Energy Certificates (RECs) equivalent to a set proportion of their electricity
purchases. Additionally, households and small businesses could earn RECs on a voluntary
basis through solar credits for small-scale renewable energy installations. RECs could then
be traded to ensure companies reached their legislated quota and to provide incentives for
the adoption of renewable energy sources.
From 1 January 2011, the RET has operated as two parts:
1. Large-scale Renewable Energy Target (LRET), and
2. Small-scale Renewable Energy Scheme (SRES).
The LRET encourages the deployment of large-scale renewable energy projects such as
wind farms, while the SRES supports the installation of small-scale systems, including
roof-top solar panels and solar water heaters. The LRET is set in annual gigawatt hour
targets, rising to 41 000 GWh in 2020. The LRET target remains at 41 000 GWh from 2021
to 2030.
Small businesses and households are anticipated to provide more than the additional
4000 gigawatt hours through the SRES. The Clean Energy Regulator (CER) oversees the
RET. The LRET targets are presented in Table 1 (CER 2014).
Table 1: LRET renewable electricity generation target (excluding existing renewable
generation)
Year ending
TWh
2014
16.9
2015
18.8
2016
21.4
2017
26.1
2018
30.6
2019
35.3
2020 and onwards
Source: CER (2014)
41
18
In E4cast, the renewable energy target is modelled as a constraint on electricity
generation—renewable energy must be greater than or equal to the interim target in any
given year. In the model, the large scale grid renewable generation is modelled by a subsidy
to renewables that is funded by a charge on non-renewable generators. This is
endogenously modelled so that total renewable generation meets the target.
The RET includes compulsory targets such as 41 TWh LRET by 2020 that is maintained to
2030, and 15 TWh existing renewable generation below baseline. Thus, the compulsory
RET target equates to a total of 56 TWh renewable electricity generation from large grid
based plants.
In addition, RET also includes 4 TWh by 2020 and maintained to 2030 under SRES,
greenpower and desalination plant demand (2.8 TWh), and the ACT renewable energy
target 91.5 TWh). However, all these latter requirements are voluntary, and expected to be
met through small-scale non-grid generation.
In E4cast, only grid generation is modelled (excluding roof-top solar, or non-grid small
generation plants).
Energy efficiency
Over the last two decades there has been a significant coordinated effort between
Australian Commonwealth and state and territory governments to ensure that energy
efficiency opportunities are recognised and realised. In particular, governments have
sought to act where market failures have limited the take up of cost-effective energy
efficiency activities. In 2009, Australian governments entered into a partnership agreement
and developed a National Strategy on Energy Efficiency (NSEE) to accelerate energy
efficiency efforts.
These activities – in particular, improved efficiency of refrigeration, air conditioning and
electronics, minimum performance standards for a range of common household appliances
and energy efficiency requirements in the Building Code – are beginning to show up in
Australia’s energy use trends. Together with the growth in rooftop solar PV and a decline
in some energy intensive industries, improved energy efficiency has reduced demand in
the national electricity market, although this trend may be reversing since the repeal of the
carbon price (Sadler 2014). In addition, energy efficiency measures can also reduce the
need for costly upgrades to electricity infrastructure, if they are targeted at reducing peak
demand.
19
3 Methodology and key
assumptions
E4cast overview
The energy sector projections presented in this report are derived using the E4cast model.
E4cast is a dynamic partial equilibrium model of the Australian energy sector. It is used to
project energy consumption by fuel type, by industry and by state or territory, on an annual
basis. Trends in economic growth and industry production, fuel prices and energy
efficiency improvements are some of the parameters used to approximate the principal
interdependencies between energy production, conversion and consumption.
E4cast modelling framework incorporates domestic as well as international trade in energy
sources. It provides a complete treatment of the Australian energy sector, representing
energy production, trade and consumption at a detailed level. As a result, the model can
be used to produce a full range of results, including Australian energy balance tables.
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 6.
Figure 6: Energy forecasting model
Activity variable and growth assumptions
Sector level energy demand within E4cast is
primarily determined by the value of the
4
‘activity’ variable used in each sector’s fuel demand equation, along with direct, cross
20
price, and income elasticities, as well as energy efficiency improvements. 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.
Energy efficiency
In the base year, the model uses empirically estimated energy efficiency parameters for
end use sectors of the Australian economy. In addition, the E4cast model incorporates
energy efficiency improvements over time. End-use energy efficiency improvements are
represented by a decline in the demand for each fuel in a sector per unit of its output. The
rate of end-use energy efficiency improvement is assumed to be 0.8 per cent a year
(consistent with the Treasury suggested autonomous efficiency improvement rate for the
RET Review in 2014) over the projection period for all fuels in non-energy intensive
sectors. In sectors containing energy intensive industries, the low capital stock turnover
relative to other sectors is expected to result in a lower rate of energy efficiency
improvement of 0.2 per cent a year.
Also, the rate of energy efficiency improvement is slightly different than mentioned above
in some sectors, based on the sector level information drawn from the results from the
previous Energy Efficiency Program, and other energy efficiency improvements in
residential and commercial sectors due to the specific efficiency programs in these sectors
(labelling, minimum standards, energy management system, capacity building and
demonstration programs, etc.). To incorporate such effects, a higher rate of energy
efficiency improvement is assumed for energy use.
E4cast also incorporates energy efficiency and cost efficiency improvements in the
electricity generation sector, reflecting expected technological developments over time
(BREE 2013a).
Energy production and trade
In E4cast, it is assumed
that Australia’s supply of black coal and oil will meet demand (for
4
net export and domestic use) at a given price level. The outlook for black coal and LNG
exports is based on BREE’s Resources and Energy Quarterly. In the case of oil and
naturally occurring LPG, domestic production is treated as exogenous, leaving the net
trade in crude oil to be determined endogenously in the model. The supply of brown coal
and non-traded black coal (that is, black coal produced in states other than New South
Wales and Queensland) is approximated using state-specific price assumptions and an
autonomous productivity improvement as the key determinants. Biogas and biomass
prices are taken from BREE’s publication (BREE 2013a).
The direction of interstate trade in natural gas and electricity is determined endogenously
in E4cast, accounting for variation in regional prices, transmission costs and capacities.
In E4cast, over the medium term, upper limits on interstate flows of electricity and natural
gas are imposed to reflect existing constraints. Beyond the medium term, it is assumed
that any interstate imbalances in gas supply and demand will be anticipated, which will
result in infrastructure investment in gas pipelines and electricity interconnector capacity
sufficient to meet trade requirements.
E4cast incorporates long-term macroeconomic forecasts from the Australian Treasury and
current assumptions on the costs and characteristics of electricity generation technologies
from BREE's Australian Energy Technology Assessment publication (BREE 2013a). A
brief overview of the key features of the current version of E4cast is provided in Box 1. The
model provides an outlook for the Australian energy sector that is feasible (where all
quantity constraints are satisfied) and satisfies the economic competitive price conditions
21
(a competitive equilibrium is achieved).
Box 1: Key features of E4cast
•
•
•
•
•
•
•
•
•
•
The first version of the model was documented in ABARE (2001). Since its inception,
the model has been enhanced and refined in a number of ways to provide a sound
platform for the development and analysis of medium and long term energy
projections. Key features of the 2014 version of E4cast include:
E4cast is a dynamic partial equilibrium framework that provides a detailed treatment of
the Australian energy sector focusing on domestic energy use and supply;
the Australian energy system is divided into 24 conversion and end use sectors;
fuel coverage comprises 19 primary and secondary fuels;
all states and territories (the Australian Capital Territory is included with New South
Wales) are represented;
detailed representation of energy demand is provided. The demand for each fuel is
modelled as a function of income or activity, fuel prices (own and cross) and efficiency
improvements;
primary energy consumption is distinguished from final (or end use) energy
consumption. This convention is consistent with the approach used by the International
Energy Agency;
the current version of E4cast projects over the period from 2014–15 to 2049–50;
demand parameters are established econometrically using historical Australian energy
data from BREE’s Australian Energy Statistics;
business activity is generally represented by gross state product (GSP);
energy intensive industries are modelled explicitly, taking into account large and lumpy
capacity expansions. The industries modelled in this way are:
– Aluminium;
– Other basic nonferrous metals (mainly alumina); and
– Iron and steel.
•
•
•
•
•
the electricity generation module includes 45 generation technologies. Investment
plans in the power generation sector are forward looking, taking into account current
and likely future conditions affecting prices and costs of production;
key policy measure modelled explicitly is the Australian Government Renewable
Energy Target;
all fuel quantities are in petajoules;
supply of gas is modelled at the state level; and
all prices in the model are real, in constant dollars of the base year, and are expressed
in dollars per gigajoule.
The model includes 19 energy sources, 45 electricity generation technologies, 5 conversion
sectors, 19 end-use sectors (Tables 2 and 3), and covers all Australian states (Australian
Capital Territory is included in New South Wales). 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.
22
Table 2: 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 3: Industry coverage in E4cast
Sectors/sub-sectors
ANZSIC code
Conversion industries
Coke oven operations
2714
Blast furnace operations
2715
Petroleum refining
2510, 2512-2515
Petrochemicals
na
Electricity generation
361
End use industries
Agriculture
Division A
Mining
Division B (includes LNG)
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
na
Transport
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
6501
Commercial and services
Sectors 37, 66 and 67; Divisions F, G, H,
J, K, L, M, N, O, P and Q
Residential
na
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.
24
E4cast base year data
The underlying year in the model is 2012-13 which is drawn from BREE’s Australian
Energy Statistics (AES) (BREE 2013b and BREE 2014a). These statistics are largely
derived from the National Greenhouse and Energy Reporting (NGER) data, sourced from
the Australian Government Department of Environment. Information from other Australian
Government agencies, state based agencies, industry associations and publicly available
company reports is also used to supplement and/or validate NGER data. These sources
include the Australian Bureau of Statistics, BREE’s commodity database and the
Australian Petroleum Statistics.
The industry classifications in the AES may be slightly different to the classifications used
in this report.
Key assumptions
There are a number of economic drivers that will shape the Australian energy sector over
the next two decades. These include:
•
•
•
•
•
•
Population growth;
Economic growth;
Energy prices;
Electricity generation technologies;
End use energy technologies; and
Government policies.
The assumptions relating to these key drivers are presented below.
Population growth
Population growth affects the size and pattern of energy demand. Projections for the
Australian population are taken from the Australian Bureau of Statistics publication (ABS
2013) and are presented in Table 4.
Table 4: Australian population assumptions
year
population millions
2015
23.94
2020
26.03
2030
30.11
2040
33.92
2050
Source: ABS (2013)
37.59
Economic growth
The energy projections are highly sensitive to underlying assumptions about GDP growth –
the main driver of energy demand. Sector level energy demand within E4cast is primarily
determined by the value of the ‘activity’ variable used in each sector’s fuel demand
equation, along with fuel prices; that is, direct and cross price, and income elasticities, as
well as energy efficiency improvements.
Since E4cast is a bottom up model, 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.
25
The long-term projections of the GDP and GSP assumptions (Table 5) are provided by the
Australian Treasury.
In 2012–13, Australia’s real GDP increased by 2.6 per cent, following growth of
3.6 per cent in 2011-12. Over the projection period, Australia’s real GDP is expected to
grow at an average annual growth rate of 2.7 per cent. A moderation in Australia’s
population and labour supply growth will contribute to a gradual reduction in GDP growth in
the latter part of the projection period.
Queensland and Western Australia are expected to have the highest GSP growth rates
over the period to 2049–50, as a result of their substantial minerals and energy resource
base, relatively high degree of export orientation, and higher relative population growth
rates.
Table 5: Australian economic growth, by region
Annual growth rate 2014-15 to 2049-50
Per cent
New South Wales
2.6
Victoria
2.5
Queensland
3.2
South Australia
1.5
Western Australia
3.3
Tasmania
1.8
Northern Territory
2.6
Australia
2.7
Sources: Australian Treasury provided assumptions on GSP and GDP
Real energy prices
Energy prices affect the demand for, and supply of, energy. The long term world energy
price assumptions incorporated in E4cast are presented in Figure 7, and are drawn from
the International Energy Agency (IEA) 2013 World Energy Outlook New Policies Scenario
(IEA 2013), extended to 2050. Long-term energy price profiles will depend 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.
Domestic fuel costs, such as gas, black and brown coal, biomass and biogas are based on
the fuel price projections to 2050 used in BREE 2013a. These fuel prices were provided by
Acil Allen consulting.
26
Figure 7: Index of real world energy prices, 2012 dollars
140
120
Price Index
100
80
60
40
20
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
0
Crude oil
LNG
Coal
Source: IEA 2013
Electricity generation technologies
The Australian Energy Technology Assessment (AETA) provides insights on
40 market-ready and prospective electricity generation technologies in Australia (BREE
2012c). AETA provides latest levelised cost of energy (LCOE) estimates and projections to
2050. While other similar cost estimates have been conducted internationally, these
studies are not directly applicable to Australian conditions due to differences in domestic
costs (e.g. labour), differences in the quality of domestic energy resources, technology
performance, and other local conditions. The LCOE estimates provided in BREE 2013a
were used in the present projections.
Government policies
The key policies that have been modelled explicitly in E4cast included the repeal of carbon
tax and the Minerals Resource Rent. Noting that the Government policy is to introduce the
direct action plan to mitigate carbon emissions, there is no direct or indirect pricing of
carbon emissions in the projections. Since the Renewable Energy Target (RET) review is
in progress, the existing RET target has been retained. Direct action plan was not
modelled directly given the capacity of the model.
27
4 Energy Consumption
This chapter presents the outlook for Australian energy consumption for the period 2014-15
to 2049-50 under the economic 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
Total primary energy consumption growth has shown a downward trend since the 1970s,
reflecting changes to Australia’s economic structure and the effect of technological
developments and government policies on energy efficiency in energy conversion and
end-use sectors. In the 1990s, energy consumption grew by an average annual rate of
2.3 per cent, followed by growth of 1.5 per cent a year in the 10 years to 2011-12.
Over the outlook period, growth in energy consumption is expected to continue to be
moderate, with an average annual growth rate of 1 per cent from 6 016 petajoules in
2014-15 to 8 541 petajoules in 2049-50 (table 6).
The decline in the growth rate of energy consumption reflects the net outcome of
countervailing downward and upward pressures on energy consumption growth.
Assumptions about energy demand management, weak manufacturing energy demand, a
shift away from more energy-intensive sectors in the economy, and existence of the RET
target are some of the factors expected to provide a dampening effect on energy demand.
Partly offsetting this trend are the increased energy demand in LNG production and mining,
as well as economic growth in Australia returning to its long-term potential as world
economic performance improves.
A decline in the cost of renewable electricity generation technologies also dampens energy
consumption by enhancing the share of renewable electricity generation in total generation.
This is because the fossil fuels (black and brown coal, gas and oil) use about three times
more energy in producing one unit of electricity generation compared with renewable fuels
(wind, solar, geothermal and water). Hence as renewable electricity generation increases
from 15 per cent in 2015 to above 20 per cent in 2050, less overall energy is used in the
economy.
Aggregate energy intensity trends
Australia’s aggregate energy intensity (measured as total domestic energy consumption
per dollar of GDP) declined at an average rate of 1.3 per cent a year between 1989–90 and
2009–10 (BREE 2012b). Over the study period, the primary energy consumption is expected
to grow at the rate of 1 per cent a year, and GDP is expected to grow at 2.7 per cent a year.
Over the period to 2049-50, Australia’s aggregate energy intensity is projected to decline by
around 1.7 per cent a year. Compared to the past trends, this indicates a considerable
de-coupling of energy-GDP nexus, and a shift in Australia’s economic structure over this
period. The major drivers of this trend are a growth in renewable electricity generation costs
and electricity generation over the projection period, and strong growth in less
28
energy-intensive sectors, such as the 'commercial and services sector' relative to
energy-intensive sectors like manufacturing. Improved efficiency in other sectors through
technological development and fuel switching will also contribute to this trend.
Primary energy consumption, by energy type
For the period from 2014-15 to 2049-50, primary energy consumption is projected to grow at
an average rate of 1 per cent a year to reach 8 541 petajoules in 2049-50 (Table 6). This
represents an increase of 42 per cent over the projection period.
At the primary energy level, fossil fuels contribution in 2014-15 is around 94 per cent and
renewables around 6 per cent of the energy consumed in Australia. Black and brown coals
provide 27 per cent, oil 40 per cent, and gas 27 per cent of primary energy consumption,
respectively. Over the long term, the shares of black and brown coal fall to 23 per cent,
and the share of gas falls to 26 per cent, whereas the share of oil is projected to marginally
rise to account for 45 per cent of total primary energy consumption. The share of
renewables in total primary energy consumption is expected to fall from 6 per cent in
2014-15 to 5 per cent by 2049-50. Wind energy has the fastest growth of all fuels in
Table 6, at the rate of 2 per cent a year. Overall renewables grow at the rate of
0.9 per cent over the projection period to 2049-50.
In contrast, consumption of coal (both black and brown) is projected to rise relatively
modestly over the outlook period — at an average rate of 0.5 per cent a year to
1945 petajoules by 2049-50.
Australia’s primary energy consumption of oil is projected to increase by around
1448 petajoules to 3879 petajoules by 2049-50, or at an average rate of 1.3 per cent a year
(Table 6). Demand for products derived from oil for road, rail, air and sea transport is
projected to be the main source of growth in oil consumption.
29
Table 6: Primary energy consumption, by energy type
2014-15
(PJ)
2034-35
(PJ)
2049-50
(PJ)
% share
2014-15
% share
2049-50
Average
annual
growth
2014-15 to
2049-50
5675
7220
8078
94
95
1.0
1635
1871
1945
27
23
0.5
black coal
1171
1407
1436
19
17
0.6
brown coal
464
464
509
8
6
0.3
Oil
2431
3304
3879
40
45
1.3
Gas
1610
2045
2253
27
26
1.0
341
441
463
6
5
0.9
Hydro
68
68
66
1
1
-0.1
Wind
59
116
118
1
1
2.0
195
220
231
3
3
0.5
19
23
34
<1
<1
1.7
0
14
14
0
<1
6016
7661
8541
100
100
Non-renewables
Coal
Renewables
Bioenergy
Solar
Geothermal
Total a
1.0
a numbers in the table may not add up to their totals due to rounding
Primary energy consumption, by state
Primary energy consumption is projected to increase across all states over the next two
decades. However, in line with assumptions about economic activity, energy resource
endowments, economic structure and the significance of mining in the economic base,
growth in primary energy consumption is expected to vary across states (Table 7).
Relatively higher gross state product assumptions, together with relatively high shares of
mining in economic output and relatively high degrees of export orientation, are key factors
underpinning the relatively higher energy consumption growth rates in Queensland, Northern
Territory, and Western Australia (Table 7).
30
Table 7: Primary energy consumption, by state and territory
2014-15
(PJ)
2034-35
(PJ)
2049-50
(PJ)
% share
2014-15
% share
2049-50
% average
annual
growth
2014-15 to
2049-50
New South Wales
1540
1869
2051
26
24
0.8
Victoria
1310
1488
1677
22
20
0.7
Queensland
1447
2136
2445
24
29
1.5
363
382
384
6
4
0.2
1038
1384
1526
17
18
1.1
Tasmania
121
125
134
2
2
0.3
Northern Territory
197
277
324
3
4
1.4
6016
7661
8541
100
100
1.0
State/territory
South Australia
Western Australia
Australia a
New South Wales includes the Australian Capital Territory.
a Numbers in the table may not add up to their totals due to rounding.
Reflecting the expansion of energy intensive industries, primary energy consumption in
Western Australia is projected to rise from 1 038 petajoules in 2014-15 to 1 526 petajoules in
2049-50 (or by 1.1 per cent a year over the projection period). In Queensland, primary
energy consumption is projected to rise from 1 447 petajoules to 2 445 petajoules, growing
at a rate of 1.5 per cent a year (Table 7). Currently the second largest primary energy
consuming state, Queensland is projected to lead Australian states in terms of total primary
energy consumption by 2049-50.
Energy consumption in the Northern Territory is projected to grow at an average rate of
1.4 per cent a year to 324 petajoules by 2049-50. This high growth reflects the large
contribution of the mining sector output and expected expansion in the region’s LNG export
sector.
Growth in primary energy consumption in the other states is projected to be relatively low.
This is particularly the case for South Australia and Tasmania. Reflecting the modest
economic growth outlook, primary energy consumption in South Australia is projected to
grow by just 21 petajoules, or 6 per cent, over the entire outlook period. In Tasmania, energy
consumption is projected to grow at an average rate of 0.3 per cent a year. In Victoria
energy consumption over the outlook period is projected to grow at a slightly higher rate of
0.7 per cent a year.
Growth in energy consumption is projected to be more moderate in South Australia and
Tasmania driven by assumed lower economic growth. Despite the slower growth, New
South Wales is projected to remain the second largest consumer of energy after
Queensland. Its energy consumption is projected to increase at around 0.8 per cent a year
and increase from 1 540 petajoules in 2014–15 to 2 051 petajoules in 2049–50 (Table 7).
Primary energy consumption, by sector
At the sectoral level, the main drivers of primary energy consumption are the electricity
generation sector, the transport sector and the manufacturing sector. These sectors are
projected to account for 64 per cent of the increase in primary energy consumption from
2014-15 to 2049-50 (Table 8).
31
The electricity generation sector accounted for the largest share (34 per cent) of primary
energy consumption in 2014-15. Total primary energy consumption in the power generation
sector is projected to grow at the rate of only 0.3 per cent a year, to increase from
2 054 petajoules in 2014-15 to 2 278 petajoules in 2049-50 (Table 8). Further details about
the electricity generation sector projections are provided below.
Table 8: Primary energy consumption, by sector
% average
annual
growth
% share 2014-15 to
2049-50
2049-50
2014-15
(PJ)
2034-35
(PJ)
2049-50
(PJ)
% share
2014-15
2054
2268
2278
34
27
0.3
Agriculture
103
133
157
2
2
1.2
Mining
523
1051
1211
9
14
2.4
Manufacturing
1244
1456
1618
21
19
0.8
Transport
1752
2325
2723
29
32
1.3
339
427
554
6
6
1.4
6016
7661
8541
100
100
1.0
Sector
Electricity generation
Commercial &
Residential
Australia a
a Numbers in the table may not add up to their totals due to rounding.
The transport sector (excluding electricity used in rail transport) is expected to account for
29 per cent of primary energy consumption in 2014-15 and continues to rely heavily on oil.
Consumption of oil and petroleum products in the transport sector is expected to grow
steadily over the projection period at an average rate of 1.3 per cent a year driven largely by
economic growth (Table 8). Also, the share of the transport sector in primary energy
consumption is projected to increase marginally from 29 per cent to 32 per cent over the
period to 2049-50. This effect is evident due to the slow growth in two main fuel consuming
sectors in the economy, electricity generation and manufacturing.
The manufacturing sector is the third largest user of primary energy in Australia, accounting
for a share of 21 per cent in 2014-15. This sector covers a number of relatively
energy-intensive sub-sectors such as petroleum refining, iron and steel, aluminium smelting
and minerals processing. While energy consumption in the manufacturing sector is projected
to increase at an average annual rate of 0.8 per cent over the outlook period, the share of
the sector in total primary energy consumption is expected to decline, which reflects a
progressive structural shift toward less energy-intensive sectors.
The mining sector, while contributing only 9 per cent of primary energy consumption in
2014-15, is projected to have the highest energy consumption growth rate (2.4 per cent
a year) over the outlook period. This reflects the continuation of global demand for energy
and mineral commodities and the large number of mineral and energy projects (including
LNG and coal seam gas) assumed to come on stream over the outlook 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 2049–50, the sector is
projected to account for 14 per cent of Australian primary energy consumption.
32
Electricity generation
Gross electricity generation in Australia is projected to grow over the outlook period by an
average of 0.8 per cent a year, from 255 terawatt hours (918 petajoules) in 2014-15 to 332
terawatt hours (1 196 petajoules) in 2049-50 (Table 9).
The projected growth in electricity generation varies across regions, reflecting a number of
factors including available technology, primary energy input availability and prices, capital
cost and interregional transmission capacity. For states that are within the integrated
National Electricity Market (New South Wales, Queensland, Victoria, South Australia and
Tasmania), the figures provided in table 9 reflect electricity consumed as well as market
determined electricity flows across regions.
New South Wales, with generation growth rate of 0.9 per cent a year, is expected to grow its
relative share of electricity generation from 27 per cent in 2014-15 to 28 per cent by
2049-50. Similarly, Queensland is expected to grow its share from 25 per cent in 2014-15 to
26 per cent by 2049-50. South Australia grows its share in generation from 8 per cent to
9 per cent over the outlook period, while growing at the rate of 0.9 per cent a year. The
dominant contributor to this growth is renewable energy, which is projected to grow at an
average rate of 2.5 per cent a year.
Table 9: Electricity generation, by state and territory (TWh)
% average
annual
growth
% share 2014-15 to
2049-50
2049-50
2014-15
2034-35
2049-50
% share
2014-15
New South Wales a
69
91
94
27
28
0.9
Victoria
51
51
56
20
17
0.3
Queensland
64
82
85
25
26
0.8
South Australia
21
28
28
8
9
0.9
Western Australia
32
42
46
12
14
1.1
Tasmania
14
14
17
5
5
0.5
4
6
7
2
2
1.4
255
315
332
100
100
0.8
State/territory
Northern Territory
Australia b
a includes Australian Capital Territory
b numbers in the table may not add up to their totals due to rounding
In Western Australia, gross electricity output is projected to increase by 44 per cent over
the projection period, from 32 terawatt hours in 2014-15 to 46 terawatt hours in 2049-50
(Table 9). Much of this expansion is driven by renewables and black coal fired electricity
generation, which are projected to grow at an average rate of 1.8 and 1.6 per cent a year,
respectively.
In comparison, electricity generation in Victoria is projected to grow at a rate below the
national average. Electricity in this state is based mainly on brown coal and some gas
fired generation. At a low growth rate of 0.3 per cent a year, it is projected to become
more dependent on imports from other regions to meet its electricity needs.
33
Table 10: Electricity generation, by energy type (TWh)
2014-15
2034-35
2049-50
% share
2014-15
% share
2049-50
% average
annual
growth
2014-15 to
2049-50
Non-renewables
216
252
265
85
80
0.6
Coal
163
200
214
64
65
0.8
black coal
117
153
163
46
49
1.0
brown coal
47
47
51
18
15
0.3
50
49
48
19
14
-0.1
3
3
3
1
1
0.0
Renewables
39
63
67
15
20
1.5
Hydro
19
19
18
7
6
-0.1
Wind
16
32
33
6
10
2.0
Bioenergy
2
5
6
1
2
3.7
Solar
2
3
6
1
2
3.0
Geothermal
0
4
4
0
1
255
315
332
100
100
Energy type
Gas
Oil
Total a
0.8
In the absence of potential new policy initiatives, the relative shares of fossil fuels and
renewables in electricity generation are not likely to change significantly over the projection
period. In Table 10, in 2014-15, 85 per cent of electricity is generated from fossil fuels (coal,
oil and gas), and 15 per cent from renewables such as hydro, wind, biomass, biogas and
solar. Within the category of fossil fuels, the key changes projected over the outlook period
are the substitution away from gas-fired generation towards coal and renewables. The share
of electricity generated from coal (both black and brown) is expected to increase from
64 per cent in 2014-15 to 65 per cent in 2049-50, and the share of renewables reaches
20 per cent in 2049-50 from 15 per cent in 2014-15.
Given the higher prices of gas, and the absence of carbon pricing, the share of gas in
electricity generation is projected to fall from 19 per cent in 2014-15 to 14 per cent in
2049-50. Renewables generation does not grow to higher levels beyond a point, unlike
constantly rising share of renewables as previously projected in BREE’s previous energy
projections report (BREE 2012a). This is mainly because of the assumption of no carbon
pricing in this set of projections. Due to the RET target assumed in the report, and in the
later years due to the declining renewable generation technology costs (BREE 2013a),
renewable generation does reach 22 per cent by 2020, and then marginally declines to
20 per cent of total generation by 2050. More precisely, after 2019-20, renewable
electricity generation continues to increase in absolute terms but not in relative terms
(Table 10). This will be underpinned by the development of new renewable electricity
generation capacity over the projection period (Map 2) (BREE 2013d).
There are 18 renewable electricity generation projects at the Committed Stage, accounting
for around 78 per cent (2 101 megawatts) of disclosed new capacity. Fourteen of these
projects are wind powered, representing 69 per cent of the disclosed new capacity for
renewable electricity projects at the Committed Stage. Three solar powered projects
account for around 7 per cent of disclosed new renewable capacity. There is also
34
one hydroelectric plant at the Committed Stage proposed for development with planned
capacity of 40 megawatts.
The timing for the deployment of carbon capture and storage (CCS) technologies hinges on
the economic viability of this technology. In the modelling, the deployment of CCS
technologies for new plants is not projected to occur in large scale over the projection period
given the high costs of this technology. (However, the significant global support to overcome
technical and financing hurdles faced by CCS technologies has the potential to bring forward
the large-scale, commercial deployment of CCS technologies for electricity generation and
other energy- intensive industries through accelerated cost reductions associated with
learning by doing).
Map 2: Electricity generation - major development projects
Source: BREE 2013d
Wind energy is a proven and mature technology, and the output of both individual turbines
and wind farms has increased considerably over the past five years. Wind energy is
currently relatively cost competitive, notwithstanding site-specific factors. Like solar energy,
the competitiveness of wind energy will be enhanced by a reduction in the cost of turbines
and further efficiency gains through turbine technology development (BREE 2013a).
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 2014–15, bioenergy
accounts for 1 per cent of total electricity generation (Table 10). 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
35
be constrained by competition for inputs used in the production of bioenergy, such as water
availability and logistical issues associated with handling, transport and storage.
Nonetheless, the use of bioenergy for electricity generation is projected to increase by
3.7 per cent a year over the projection period, but will still account for only 2 per cent of total
generation by 2049–50 (Table 10).
Australia has large geothermal energy potential. However, these resources are currently
considered sub-economic because geothermal technologies for electricity generation have
not yet been demonstrated to be commercially viable in Australia. Electricity generation from
geothermal energy is currently limited to pilot projects that generate small volumes of
electricity. Technological breakthroughs in assessment and well digging technologies are
likely to make this technology more viable in the latter part of the projections period, and its
share in total generation is likely to grow to 1 per cent by 2049-50 (Table 10).
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.
Integration costs for variable renewables
The cost of integrating intermittent energy sources into electricity grids is heavily dependent
on their share of overall electricity supply and the overall mix of generation technologies. At
low penetration levels (less than 5 per cent), integration costs are negligible. However, at
wind penetration levels of 20 per cent, wind integration costs associated with balancing
could increase the overall cost of electricity by $9/MWh (BREE 2014b).
This study (Table 10) shows only 20 per cent of renewable generation by 2049-50, hence
the integration cost is not a significant issue. In addition, BREE's Asia-Pacific Renewable
Energy Assessment study (BREE 2014b) has identified a range of opportunities to reduce
integration costs through the use of ‘flexible resources’. These flexible resources - which
already exist in electricity grids to varying degrees - include quickly dispatchable
conventional power plants (e.g. hydro power, OCGT), storage facilities (e.g. pumped hydro),
demand side management and response, strengthened grid interconnection, wind
forecasting and market design (e.g. intra-hour trading). Several of these flexible resources
(e.g. increased OCGT capacity, improved wind forecasts, intra-hour trading) are already
being utilised in Australian electricity markets.
This study does not model the roof top solar PV generation, or other small scale non-grid
renewables such as oil or wind, etc.
36
Final energy consumption, by energy type
Total final energy consumption in Australia is projected to increase from 4 399 petajoules in
2014-15 to 6 582 petajoules in 2049-50, a rise of 50 per cent over the projection period and
an average annual rate of increase of 1.2 per cent (Table 11).
This compares with an average annual growth rate of 1.7 per cent in the 10 years to
2014-15. Electricity is projected to continue to grow strongly to meet energy demand in
end-use sectors. This will reduce the relative share of gas in final energy consumption by
2050, although the amount of gas consumption is projected to increase by 35 per cent
between 2014-15 and 2049-50. Petroleum products are projected to have the fastest growth
rate, with an average rate of 1.4 per cent a year over the projection period. Since the share
of petroleum products in total final energy consumption increases from 53 per cent to
57 per cent from the beginning to the end of the outlook period, the shares of gas, electricity
and coal fall accordingly. The decline in gas share is predominantly because of rising prices
to 2049–50. The demand for petroleum products increases from growing mining and
residential sectors. The consumption of renewables grows moderately at the rate of
0.7 per cent a year in the absence of carbon pricing.
Table 11: Final energy consumption, by energy type
2014-15
(PJ)
2034-35
(PJ)
2049-50
(PJ)
% share
2014-15
% share
2049-50
% average
annual
growth
2014-15 to
2049-50
119
139
152
3
2
0.7
2312
3169
3734
53
57
1.4
Gas
999
1159
1346
23
20
0.9
Renewables
186
220
240
4
4
0.7
Electricity
784
1037
1111
18
17
1.0
4399
5725
6582
100
100
1.2
Energy type
Coal
Petroleum
products
Total a
a numbers in the table may not add up to their totals due to rounding
Final energy consumption, by sector
The main drivers of final energy consumption in the Australian economy are the transport
and manufacturing sectors. In 2014-15 these sectors account for 40 per cent and
29 per cent of final energy consumption, respectively (Table 12).
Transport
With an average rate of growth of 1.3 per cent a year between 2014-15 and 2049-50, the
transport sector is expected to account for 55 per cent (or 972 petajoules) of the total
projected increase in final energy consumption. Also, the share of the transport sector in
total energy consumption is projected to increase slightly over the period, from 40 per cent in
2014-15 to 42 per cent by 2049-50 (Table 12). Energy use in the transport sector is the main
driver of the outlook for oil and oil-based products, which is projected to increase at an
average annual rate of 1.4 per cent (Table 11).
37
Within the transport sector, the road transport segment is the largest contributor to energy
consumption. In 2014-15, road transport accounted for around three-quarters of the energy
used in the sector, which in turn was dominated by passenger transport. Energy use in the
road transport sector is projected to grow by 0.7 per cent a year over the projection period,
driven largely by the freight transport industry.
Energy use in the air transport sector (both domestic and international) is projected to grow
firmly over the projection period, reflecting rapid growth in private passenger demand for air
transport. With a long-term growth rate of 3 per cent a year, energy use in the air transport
sector is projected to increase to more than 800 petajoules in 2049-50. As a result, the air
transport sector is projected to account for almost 30 per cent of the transport sector’s
energy use in 2049-50.
The transport sector is highly dependent on oil-based petroleum products and this
dependence is expected to continue over the projection period. There are a range of
alternative 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 2049-50.
Table 12: Final energy consumption, by sector
2014-15
(PJ)
2034-35
(PJ)
2049-50
(PJ)
% share
2014-15
% share
2049-50
% average
annual
growth
2014-15 to
2049-50
Agriculture
112
143
167
3
3
1.1
Mining
462
752
868
11
13
1.8
Manufacturing
1295
1510
1650
29
25
0.7
Transport
1761
2335
2733
40
42
1.3
769
986
1165
17
18
1.2
4399
5725
6582
100
100
1.2
Sector
Commercial &
Residential
Total a
Manufacturing
The manufacturing sector is the second largest energy end user in Australia, with minerals
processing—mainly iron and steel making, alumina refining and aluminium smelting —
contributing to the relatively high energy intensity of the sector. Over the past 10 years, the
manufacturing sector has grown relatively slowly such that its share of total final energy
consumption remained largely constant at around 30 per cent. In these projections, the
manufacturing sector as a whole is projected to grow at 0.7 per cent a year in the period to
2049-50 supported by growth in the economy and ongoing global demand for resource
based energy-intensive output. However, the projected growth rate is well below the average
for all sectors (1.2 per cent). This reflects the continuing long-term structural shift in the
Australian economy toward the commercial and services sector. Economic growth in the
38
manufacturing sector has been slow over the last several years in Australia, this has been
further re-enforced by aluminium establishments closures. As such, the share of
manufacturing in final energy consumption is projected to decline to 25 per cent by 2049-50.
Within the manufacturing sector, lower growth in energy consumption is expected for the
relatively energy-intensive sub-sectors.
Final energy consumption in the iron and steel industry is projected to grow at an average
rate of 0.8 per cent a year over the projection period, to 61 petajoules by 2049-50 (Table 13).
Energy consumption in the non-ferrous metal industries is expected to increase by
1.1 per cent a year over the period to 2049-50.
Mining
Reflecting the development of a large number of mineral and energy mining projects
assumed to take place over the projection period, mining is projected to increase its share of
total final energy consumption. The mining sector’s share of total final energy consumption is
projected to rise from 11 per cent in 2014-15 to more than 13 per cent in 2049-50 (Table 12),
growing at an average annual rate of 1.8 per cent. This growth is slower than the rapid
growth experienced in recent years, reflecting, in part, an assumed 0.8 per cent a year
reduction in the energy intensity of mining industries, and slow growth in mining compared to
the previous years (BREE 2012a).
Nonetheless, the projected growth in energy consumption in the mining sector is the highest
in comparison with projected growth in other sectors. This is driven by the substantial
increase in the relatively energy-intensive production of liquefied natural gas (LNG). Over the
period 2014-15 to 2049-50, the production of LNG is set to grow at an average rate of
around 3.6 per cent a year. The outlook for the LNG sector is discussed in more detail
below.
Table 13: Final energy consumption, by manufacturing subsector
2014-15
(PJ)
2034-35
(PJ)
2049-50
(PJ)
% share
2014-15
% share
2049-50
% average
annual
growth
2014-15 to
2049-50
Wood and paper
printing
88
83
90
7
5
0.1
Basic chemicals
285
308
306
22
19
0.2
Iron & steel
46
53
61
4
4
0.8
Non-ferrous
metals
594
759
866
46
53
1.1
Other
manufacturing
282
307
327
22
20
0.4
1295
1510
1650
100
100
0.7
Subsector
Total a
a numbers in the table may not add up to their totals due to rounding
Commercial and residential
The commercial and residential sector comprises wholesale and retail trade,
communications, finance, government, community services, recreational industries and
39
households. In 2014-15, the commercial and residential sector accounted for around
17 per cent of total final energy consumption and is projected to grow to 18 per cent by
2049-50. The sector is particularly electricity-intensive and is expected to be a major source
of growth in electricity consumption over the medium to longer term. Over the projection
period, energy use in this sector is projected to grow by 1.2 per cent a year (Table 12).
Given population growth assumptions, household income, energy prices and lifestyle
choices are the main variables affecting energy consumption in the residential sector.
Energy is a relatively small component of household expenditure. Further, current pricing
arrangements, particularly for electricity, still do not provide strong time and cost-reflective
price signals to residential energy consumers. For these reasons, a high degree of
responsiveness to prices has not generally been observed.
Agriculture
Agriculture holds a minor share of final energy consumption with a share of 3 per cent in
2014-15. Over the outlook period, agricultural energy use is projected to increase by
1.1 per cent a year (Table 12), which reflects, in part, an assumed reduction in the energy
intensity of agriculture of 0.8 per cent a year. Petroleum products are the main fuel used on
farms, accounting for more than 90 per cent of the total fuel mix.
40
5 Energy Production and Trade
The main sources of energy produced in Australia on an energy content basis are coal,
uranium and gas. With the exception of crude oil and refined petroleum products, Australia
is a net exporter of energy commodities. In 2014-15, production of coal is expected to be
13 021 petajoules, or 75 per cent of total energy production (excluding uranium). In
physical terms, total coal production is expected to be 570 million tonnes. Gas is expected
to account for 18 per cent of total energy production, followed by crude oil and condensate
and naturally occurring LPG (5 per cent) and renewables (hydroelectricity, wind energy,
bioenergy and solar energy) at 2 per cent. Although Australia is a significant producer of
uranium oxide, it is not included in the projections as it is not consumed as a fuel in
Australia and, therefore, does not affect the domestic energy balance.
Total production of energy in Australia (excluding uranium) is projected to grow at an
average rate of 1.3 per cent a year to 2049-50. At this rate, Australian production of
energy is projected to increase by 59 per cent to reach 27 567 petajoules in 2049-50
(Table 14). Gas production is projected to increase from 3 109 petajoules
(57 million tonnes) in 2014-15 to 7 398 petajoules (136 million tonnes) in 2049-50, or
27 per cent of total energy production. At the same time, the combined share of crude oil
and naturally occurring LPG is projected to be around 1 per cent of total energy production
(at 265 petajoules) in 2049-50. The share of coal in total energy production is projected to
slightly fall from 75 per cent in 2014-15 to 71 per cent by 2049-50.
Table 14: Energy production, by source
2014-15
(PJ)
2034-35
(PJ)
2049-50
(PJ)
% share
2014-15
% share
2049-50
% average
annual
growth
2014-15 to
2049-50
17009
26492
27104
98
98
1.3
13021
19299
19441
75
71
1.2
12557
18834
18932
72
69
1.2
464
464
509
3
2
0.3
786
348
161
5
1
-4.4
LPG
93
98
104
1
0
0.3
Gas
3109
6748
7398
18
27
2.5
341
441
463
2
2
0.9
Hydro
68
68
66
0
0
-0.1
Wind
59
116
118
0
0
2.0
195
220
231
1
1
0.5
19
23
34
<1
<1
1.7
0
14
14
0
<1
17350
26933
27567
100
100
Non-renewables
Coal
black coal
brown coal
Oil
Renewables
Bioenergy
Solar
Geothermal
Total
1.3
Note: Numbers in the table may not add up to their totals due to rounding.
As the projected growth in non-uranium energy production exceeds that of primary energy
41
consumption, Australia’s exportable surplus of energy is projected to increase as a
proportion of consumption over the projection period. In 2014-15, the ratio of Australia’s
primary energy consumption to non-uranium energy production is estimated to be
35 per cent. By 2049-50, the ratio of Australia’s primary energy consumption to
non-uranium energy production is projected to fall to 31 per cent (Figure 8).
Figure 8: Australian energy balance (PJ)
30000
25000
20000
15000
10000
5000
0
Energy consumption
Energy production
Energy exports
Source: BREE estimation
Black coal production and exports
Black coal, which includes both thermal and metallurgical coal, is projected to remain
Australia’s dominant energy export, increasing by around 54 per cent from 2014-15 to
2049-50. The projected annual growth rate of 1.2 per cent is built on expectations that
global demand for coal will continue to increase in the period to 2049-50 as a result of
increased demand for electricity and steel-making raw materials, particularly in emerging
market economies in Asia. Australia, with its abundant reserves of high-quality coal, has
the potential to contribute significantly to meeting this increased demand, subject to
adequate investment in mine and related infrastructure development. By 2049-50,
Australian black coal exports are projected to reach 17 496 petajoules, equivalent to
around 650 million tonnes (Table 15 and Figure 9).
A major proportion of Australia’s black coal production is destined for export. Australia
accounts for 27 per cent of world black coal exports — 51 per cent of metallurgical coal
exports and 18 per cent of thermal coal exports. Growth in Australia’s thermal coal exports
will be supported by infrastructure upgrades at the Newcastle Coal Infrastructure Group
terminal and the Kooragang Island Coal Terminal. Upgrades to rail infrastructure at
Goonyella in Queensland (among other projects) have also increased metallurgical coal
export capacity. Another key factor increasing export capacity has been increasing
efficiency in the use of existing resources (in Newcastle in particular) (BREE 2013c).
Currently lower coal prices have affected the profitability of many producers who have
been forced to explore options for cutting costs or suspend production. Since some of
these producers are locked into long-term take-or-pay contracts for infrastructure services,
particularly in Australia, they have been reluctant to close facilities. As the largest importer
and exporter of thermal coal, respectively, developments in China and Indonesia’s coal
42
markets will continue to have an important bearing on world coal trade. The Chinese
Government continued to announce a series of policy and legislative measures aimed at
improving air quality in early 2014. While this has been widely expected to depress China’s
coal use, early indications suggest that China’s coal imports will continue to register robust
growth in 2014-15 (BREE 2014c).
The coal production and trade will be supported by the commissioning of new mines, rail
networks and ports in Queensland and New South Wales, output from new capacity and
producers seeking to reduce unit costs.
Increased production is also expected due to a number of operations including Ulan,
Beltana and Ravensworth North Opencut, completion of new capacity including Caval
Ridge, Daunia, Maules Creek, Metropolitan, North Goonyella and Middlemount. However,
offsetting some of these increases will be the announced closure of capacity that is no
longer considered economically viable such as Glencore Xstrata’s Ravensworth
underground mine in Queensland and Vale’s Integra complex in New South Wales (BREE
2014d).
Table 15: Net trade in energy (PJ)
% average
annual growth
2049-50 2014-15 to 2049(PJ)
50
2014-15
(PJ)
2034-35
(PJ)
Black coal
11386
17428
17496
1.2
Oil a
-1576
-2810
-3608
2.4
LPG
24
-48
-7
LNG
1500
4703
5144
3.6
Total
11334
19272
19026
1.5
a Includes crude oil, other refinery feedstock and petroleum products
Source: BREE estimates
Figure 9: Australian Coal balance (PJ)
43
25000
20000
15000
10000
5000
Coal consu mption
Coal productio n
2048-49
2046-47
2044-45
2042-43
2040-41
2038-39
2036-37
2034-35
2032-33
2030-31
2028-29
2026-27
2024-25
2022-23
2020-21
2018-19
2016-17
2014-15
0
Coal exports
Source: BREE estimation
Natural gas production and LNG exports
Australia has considerable resources of gas that are increasingly being developed for
domestic use and export (Figure 10). The significant gas resource base is capable of
meeting domestic and export demand over the projection period. Gas production in
Australia, including LNG, is projected to grow from 3 109 petajoules in 2014-15 to
7 398 petajoules in 2049-50, at an annual average rate of 2.5 per cent over the outlook
period (Table 14). 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 is 1 729 petajoules in
2014–15 or 56 per cent of total production (Table 16). In the western market, gross gas
production, including LNG, is projected to grow at an average annual rate of around
2.2 per cent from 2014-15 petajoules to 3 735 petajoules in 2049-50 (Table 16). Strong
growth in domestic and global demand for gas has been driving the development of new
projects and LNG capacity. There are a number of LNG projects that are expected to be
completed in the western market over the projection period. These include Chevron, Shell
and ExxonMobil’s Gorgon LNG project (15 million tonnes a year) in 2015; and Chevron,
Apache, KUFPEK and Tokyo Electric’s Wheatstone (8.9 million tonnes a year initially) in
2016.
Gas production in the eastern market is projected to grow at 2.7 per cent a year from
1 052 petajoules in 2014-15 to 2 703 petajoules in 2049-50 (Table 16). A prominent
feature of the eastern gas market is the increasing contribution of CSG to total production.
Production of CSG in Queensland is expected to maintain its strong growth trajectory over
the projection period supported by the development of a number of new projects.
Table 16: Australian gas production
2014-15
2034-35
2049-50 % average annual
44
(PJ)
(PJ)
(PJ)
growth 2014-15
to 2049-50
Eastern market
1052
2459
2703
2.7
Western market
1729
3408
3735
2.2
Northern market
328
881
960
3.1
3109
6748
7398
2.5
Total
Production is forecast to constantly grow as Australia’s LNG projects currently under
construction are slated to begin operations. Queensland Curtis LNG (QCLNG), Gladstone
(GLNG) and Gorgon LNG, are all expected to be fully operational by 2015. There are other
projects under construction as well and will continue to boost Australia's gas supply (BREE
2014).
Figure 10: Australian Natural gas balance (PJ)
8000
7000
6000
5000
4000
3000
2000
1000
0
Gas consumption
Gas production
LNG exports
Source: BREE estimation
Gas production in the northern gas market (including imports from the Joint Petroleum
Development Area in the Timor Sea for processing in Darwin) is projected to grow from
328 petajoules in 2014-15 to 960 petajoules in 2049-50, at an average rate of 3.1 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 for 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. Australia's recoverable oil resources are largely located in the Gippsland and
Carnarvon basins. 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.
Australia’s crude oil and natural gas liquids production is projected to decline by 4.4 per cent
45
a year from 786 petajoules in 2014–15 to 161 petajoules in 2049–50 (Table 14). 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 0.3 per cent to 104 petajoules in 2049–50.
Australia is a net importer of crude oil and condensate. In volume terms, Australia’s crude
oil and condensate production was equivalent to 58 per cent of refinery feedstock in
2011-12. However, Australia exports 78 per cent of its crude oil and condensate
production to refineries in Asia, with the majority being sourced from the north-west coast
of Australia.
Figure 11: Australian Liquid fuel balance (PJ)
1600
1400
1200
1000
800
600
400
200
0
Imports
Production
Consumption
Source: BREE estimation
Australian consumption of liquid fuels (excluding petroleum products) is projected to
increase from 1 104 petajoules in 2014–15 to 1 427 petajoules in 2049–50 (Figure 11). Over
the projection period, the gap between supply and demand will be exacerbated by the
significant proportion of growth in crude oil and naturally occurring LPG production being
concentrated in the Carnarvon and Browse basins in north-western Australia, which are
closer to Asian refineries than the east coast of Australia. As a result, it is reasonable to
assume that the bulk of the supply of crude oil and naturally occurring LPG will be exported
for further processing rather than directed to the domestic market. Reflecting this
assumption, the ability to meet domestic demand with domestic production is likely to be
lower than implied by the simple comparison of production and consumption.
The demand for petroleum product imports is determined by domestic oil production,
end-use consumption of petroleum products, and domestic petroleum refining capacity.
Australia’s refining capacity is not expected to expand considerably over the projection
period given increasing competitive pressure, particularly from large South-East Asian
refineries. In the year 2000, Australia had seven refineries. By the year 2016, Australia will
have only four: Caltex, Mobil, BP and Vitol — the new owners of the Shell refinery in
Geelong — are the four owners.
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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 2.4 per cent a year to 2049–50 (Table 15).
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6 Conclusions
The energy sector projections presented in this report are derived using the E4cast model.
E4cast is a dynamic partial equilibrium model of the Australian energy sector. This model
is used to project energy consumption by fuel type, by industry and by state and territory to
2050, on an annual basis.
The current projections show that Australian energy consumption will continue to grow
over the next forty years, albeit at a much lower rate than experienced in the past twenty
years. This is because of the substitution of renewables for fossil fuels in electricity
generation – which require much less energy use to generate electricity – and because of
expected energy efficiency improvements, and higher energy prices.
Gross electricity generation is projected to grow at the rate of 0.8 per cent a year over the
outlook period. This growth is dominated by coal-fired electricity generation. Coal and oil
will continue to supply the bulk of Australia’s energy needs, although their share in the
energy mix is expected to decline. The use of gas (natural gas and coal seam gas) in
industries is expected to grow by 1 per cent a year over the outlook period. This moderate
growth is driven primarily by negative gas-fired electricity generation growth, but positive
consumption of gas in liquefied natural gas (LNG) production. Black coal is projected to
remain Australia’s dominant energy export. LNG exports are also projected to increase
significantly.
The share of renewable energy is projected to increase moderately at the rate of
0.9 per cent a year over the projection period. The growth in renewable energy is mainly
driven by strong growth in wind and solar energy. Transition to a low carbon economy will
require long term structural adjustment in the Australian energy sector. While Australia has
an abundance of energy resources, this transformation will need to be underpinned by
significant investment in energy supply chains to allow for better integration of renewable
energy sources and emerging technologies into our energy systems. It will be critical to
ensure that the broader energy policy framework continues to support cost-effective
investment in Australia’s energy future, and timely adjustments to market settings in
response to emerging pressures, and market developments.
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