Excluding uranium, which is not used domestically as an energy fuel, the main energy fuels produced in Australia are coal, oil, gas and renewables. With the exception of crude oil and refined petroleum products, Australia is a net exporter of energy commodities, notably of black coal. In 2004-05, in energy terms, production of black and brown coal was 8791 petajoules, or 74 per cent of total energy fuel production. In physical terms, black coal production was 284 million tonnes and brown coal production, 71 million tonnes. Natural gas accounted for 14 per cent of energy fuel production, followed by crude oil and naturally occurring LPG (10 per cent) and renewables (hydroelectricity, wind, biomass, biogas and solar) at 2 per cent.
Total production of energy fuels is projected to rise from 11 868 petajoules in 2004-05 to 22 350 petajoules in 2029-30 (table 16). This represents a rise of 88 per cent over the projection period and an average rate of increase of 2.6 per cent a year. The main projected change in production shares concerns gas, oil and coal. Gas production is projected to rise from 1685 petajoules (42 121 gigalitres) in 2004-05 to 5343 petajoules (133 578 gigalitres) in 2029-30, increasing its share in total energy fuels production to 24 per cent by 2029-30. At the same time, the relative share of crude oil and naturally occurring LPG is projected to fall to 6 per cent of total energy fuels production, and coal to 68 per cent.
table 16
energy production in Australia
production
average annual growth
2004-05
2010-11
2019-20
2029-30
2004-05 to
2004-05 to
2010-11
2029-30
PJ
PJ
PJ
PJ
%
%
black coal
8 105
10175
11 875
14 390
3.9
2.3
brown coal
686
708
754
796
0.5
0.6
crude oil a
1 011
1 074
1 139
1 078
1
0.3
LPG b
123
142
228
262
2.4
3.1
natural gas
1 685
2 458
4 480
5 343
6.5
4.7
hydro electricity
58
61
64
66
0.8
0.5
wind energy
5
13
15
24
19.2
7
biomass
187
227
303
349
3.3
2.5
biogas
7
39
38
37
34.1
7.1
solar energy
3
3
4
5
3
2.3
total
11 868
14 899
18 899
22 350
3.9
2.6
a Includes condensate. b Naturally occurring LPG.
As the projected increase in nonuranium energy fuels production exceeds the projected rise in primary energy consumption, Australia’s exportable surplus of energy fuels is projected to rise as a proportion of consumption to 2029-30. Conversely, Australia’s primary energy consumption represented 47 per cent of nonuranium energy fuel production in 2004-05, and this proportion is projected to fall to 37 per cent in 2029-30 (figure Q).
black coal production and exports
Black coal is projected to remain Australia’s dominant fossil fuel export over the projection period. In 2004-05, 81 per cent of Australian black coal (in terms of energy produced) was exported. Black coal exports are projected to rise by 88 per cent between 2004-05 and 2029-30, from 6591 petajoules (231 million tonnes) to 12 393 petajoules (435 million tonnes) (table 17; figure R). Australian thermal coal exports are forecast to increase by 7.4 million tonnes to 115 million tonnes by 2006-07, supported by a number of coal infrastructure developments currently under construction.
table 17
net trade in energy in Australia
net exports
other
net imports
petroleum
of crude oil
black coal
LPG
products
LNG
and ORF
PJ
PJ
PJ
PJ
PJ
2004–05
6 591
51
–304
576
397
2010–11
8 532
49
–293
1 061
523
2014–15
9 197
87
–261
1 948
495
2019–20
10 034
118
–313
2 856
667
2024–25
11 178
118
–376
3 204
814
2029–30
12 393
117
–450
3 650
919
annual growth rate
%
%
%
%
%
2004–05 to 2010–11
4.4
– 0.4
– 0.6
10.7
4.7
2004–05 to 2029–30
2.6
3.4
1.6
7.7
3.4
Australia’s metallurgical coal exports are forecast to grow by around 17 per cent to 146 million tonnes over the same period, driven by strong demand, particularly from China and India (Fairhead et al 2006).
Over the medium term, Australia’s total coal exports are projected to grow at an average rate of 4.4 per cent a year, reaching 300 million tonnes by 2010-11. Beyond the medium term (between 2011-12 and 2029-30), coal exports are projected to increase by a further 50 per cent to 438 million tonnes in 2029-30.
This coal outlook incorporates new developments proposed for both the metallurgical and thermal coal sectors that are expected to expand production considerably over the projection period. Major thermal coal projects include Rio Tinto’s 12 million tonne a year Clermont project in Queensland, Centennial Coal’s 10.5 million tonne a year Anvil Hill mine in New South Wales and Ensham Resources’ 8 million tonne a year Ensham Central project in Queensland. Metallurgical coal projects include the Belvedere coking coal mine in Queensland, with a capacity of 12 million tonnes a year, and the BHP Mitusi Alliance (BMA) Goonyella project in Queensland, with a capacity of 7 million tonnes a year (Haine et al. 2006).
Major additions to Australian coal export infrastructure are under way to support the planned increase in mine output. The most significant of these developments is expected at the Newcastle port coal terminal, where capacity is being expanded from 89 million tonnes a year to 105 million tonnes a year by early 2007. In Queensland the port of Gladstone coal terminal is being expanded to around 78 million tonnes a year by late 2007. The Blackwater and Goonyella rail systems will be upgraded to support increased coal exports through Gladstone. Capacity at the BMA Hay Point coal terminal in Queensland is also expected to increase to 44 million tonnes a year by early 2007. Capacity at the Dalrymple Bay coal terminal near Mackay in Queensland will increase to 68 million tonnes, in late 2007, in the project’s first phase, and to 85 million tonnes by late 2008 in phases 2 and 3 of the project (Haine et al. 2006).
The positive outlook for exports is projected to drive an increase in black coal production of 78 per cent over the outlook period, reaching 14390 petajoules by 2029-30 (table 16). Black coal will continue to dominate Australia’s energy exports (in energy content terms, excluding uranium), although LNG exports are also projected to increase strongly, as is discussed below.
natural gas production and LNG exports
In 2004-05, total gross output of natural gas in Australia was 1685 petajoules (table 16. Of this, 701 petajoules or 42 per cent was sourced from basins in the eastern states. The two largest producing basins in the eastern states, Gippsland and Cooper Eromanga, provided a total of 544 petajoules of gas or 78 per cent of the eastern gas supply. Production from Gippsland basin, which was the largest in 2004-05 with 290 petajoules, is projected to peak in 2021-22 with 392 petajoules and decline thereafter by an average 4.7 per cent a year (figure S). Production from the Cooper Eromanga basin was 254 petajoules in 2004-05 and is projected to decline to 183 petajoules in 2011-12. After this, production from Cooper Eromanga is projected to decline sharply for the rest of the outlook period, averaging a rate of decline of over 17 per cent a year.
The decline in the two largest producing basins in the eastern states is partially compensated for by growing supplies from the Otway basin and coal seam gas (CSG). Gas production from Otway, a relatively new and promising gas province, is projected to increase from 42 petajoules in 2004-05 to a peak of 160 petajoules in 2011-12 and settle around 110 petajoules from 2011-12 to 2019-20. After this, production from Otway is projected to fall to around 40 petajoules by the end of the projection period. With current production of about 49 petajoules, CSG already accounts for more than 60 per cent of the Queensland gas market. Reflecting in part major supply contracts, the production of CSG in Queensland and New South Wales is projected to increase from 58 petajoules in 2004-05 to 146 petajoules by 2010-11, accounting for about 18 per cent of the entire eastern Australian gas market. Over the entire outlook period, CSG production is projected to reach 339 petajoules by 2029-30.
Total gas supply in the eastern Australian market is projected to increase more modestly than CSG production, by around 60 per cent over the 25 year projection period. This is a result of the offsetting effect of falling gas supplies from the mature Cooper–Eromanga basin and eventually from Bass Strait. Indeed, from 2012-13, gas demand in the eastern market is projected to outstrip local supply, providing an opportunity for supplies from outside the region to enter the market. By 2029-30, this market is projected to have grown to around 1124 petajoules.
In 2012-13, production from such an external supply source is assumed to commence with 56 petajoules and is projected to grow by at least 13 per cent a year over the subsequent decade to reach 190 petajoules in 2022-23. Production is projected to continue at least at this level for the rest of the projection period. For the period after 2022-23, the gas supply sourced externally and that sourced from CSG are considered minimum levels. These two combined minimum levels of supply are insufficient to meet the gas demand gap in the eastern region. There is a further 17 petajoules in 2023-24, growing to 187 petajoules in 2029-30, which would be required in order to fully meet demand (as indicated by the grey area in figure S). This additional demand could conceivably be sourced from either the external supply or from CSG.
Production of gas in Western Australia and the Northern Territory is projected to increase from 984 petajoules in 2004-05 to 4280 petajoules by 2029-30, growing at an average rate of 6.4 per cent a year. About 93 per cent of the additional gas production in the two regions is accounted for by assumed developments in the LNG sector.
LNG exports
Australian LNG exports are expected to increase significantly in the short to medium term, supported by growth in existing markets and new regional markets, such as China and the north American west coast. Australia currently has two LNG export projects, the North West Shelf, with annual supply capacity of around 11.7 million tonnes from four trains and the Darwin LNG project with a capacity of 3.24 million tonnes a year. The Darwin project and a fifth train in the North West Shelf are expected to be the main contributors to LNG export growth over the medium term. LNG exports are forecast to rise to around 20 million tonnes by 2010-11.
The Darwin LNG plant began production in February 2006 and will supply LNG to Japan for the next seventeen years. Site work on the 4.2 million tonne a year North West Shelf fifth train started in July 2005 and exports from the project are scheduled to commence in late 2008.
LNG is projected to be Australia’s fastest growing energy export over the outlook period, growing at an average rate of 7.7 per cent a year (table 17). By 2029-30, LNG exports are projected to reach 67 million tones (figure T). Several projects that are currently in the planning phase have been included in these projections. The Gorgon LNG, Pluto, Pilbara LNG and Browse projects are assumed to go ahead, as well as possible additional trains at the North West Shelf and Gorgon.
The Gorgon LNG project on Barrow Island in Western Australia moved to the front end engineering development (FEED) phase in July 2005 and a final investment decision on the $11 to $15 billion project is expected in early 2007. Production is planned to commence in 2010, with a capacity of 10 million tonnes a year.
Total domestic gas production is projected to grow strongly, at an average rate of 4.7 per cent a year. Nevertheless, LNG production is projected to increase its share in total domestic gas production, from 34 per cent in 2004-05 to 68 per cent by 2029-30. The mining sector’s use of natural gas will be largely driven by the strong projected growth in LNG production. Consumption of natural gas in the mining sector is projected to increase from 133 petajoules in 2004-05 to 363 petajoules by 2029-30, growing at an average rate of 4.1 per cent a year. The great majority of this increase is projected to occur in Western Australia, with a share of 73 per cent, and another 18 per cent of the increase is projected to occur in the Northern Territory.
petroleum refining and oil production
The outlook for domestic oil production and the outlook for the end use consumption of petroleum products are key drivers of Australia’s demand for imported liquid fuels. Domestic oil production is largely driven by world oil prices and the impact these have on exploration activity, in addition to geological factors.
ABARE currently forecasts real oil prices in the short term to remain at around the high levels experienced in 2005-06. In 2005-06, real oil prices (in world trade weighted terms) averaged US$55 a barrel, up from US$41 a barrel in 2004-05. The world trade weighted oil price is forecast to be US$52 a barrel (in 2004-05 US dollars) in 2006-07 (Penm et al. 2006). Beyond the medium term, ABARE projects oil prices to fall to below US$40 a barrel and to remain at around this level for the rest of the projection period.
In 2004-05, domestic production of oil and naturally occurring LPG represented 59 per cent of Australia’s total liquid fuels consumption (figure U). This is forecast to increase to nearly 66 per cent in 2007-08, as new projects reach full production, including Woodside’s Enfield project, which began production in July 2006 and is expected to produce an extra 100 000 barrels a day at full capacity. The majority of Enfield’s production is expected to be exported, however, since the development is located in the Carnarvon Basin, close to Asian markets and remote from the regions of high demand in Australia.
A large part of current Australian oil production is sourced from mature oil and gas provinces. The latest available estimates of oil reserves for the Bonaparte, Browse, Carnarvon and Gippsland basins are 587 gigalitres at the 95 per cent level of probability (Geoscience Australia 2005). However, many prospective areas offshore are yet to be fully explored. Australia has about 40 offshore basins that exhibit signs of hydrocarbon potential and around half of them have not been explored (Australian Government 2004).
ABARE bases its estimate of Australia’s long term undiscovered resources partly on a 2000 study by the US Geological Survey (USGS) of world long term ultimate undiscovered potential oil resources. Using a 1995 data set, the USGS assessed potential undiscovered oil resources in the Bonaparte, Browse, Carnarvon and Gippsland Basins to be 1758 gigalitres at a 50 per cent level of probability, and 530 gigalitres at a 95 per cent level of probability.
Taking account of the resources that have been discovered in these basins since the US study, the ultimate undiscovered potential in these four basins is reduced to 1423 gigalitres at a 50 per cent level of probability, and 195 gigalitres at a 95 per cent level of probability. At the 95 per cent level of probability, the ultimate remaining oil resources (identified, inferred and undiscovered) for the four basins are estimated by ABARE to be 782 gigalitres. In E4cast, suppliers develop a small proportion of this resource base every year in response to price signals, and bring that production to the market, resulting in a projected long term level of indigenous production of crude oil and condensate of around 1078 petajoules by 2029-30 (table 16).
Reflecting the current estimates of reserves, after reaching a peak in 2007-08, Australian oil production is projected to fall by 0.3 per cent a year over the rest of the projection period. Domestic production of naturally occurring LPG is projected to increase at a rate of 3.1 per cent a year, reaching 142 petajoules by 2010-11 and 262 petajoules by 2029-30 (table 16).
The combined production of oil and naturally occurring LPG in Australia is forecast to increase only modestly over the outlook period, from 1133 petajoules in 2004-05 to 1340 petajoules in 2029-30. Consumption of liquid fuels, on the other hand, is projected to grow more strongly from 1908 petajoules in 2004-05 to 2709 petajoules by 2029-30. As a result, Australia’s self sufficiency in oil and naturally occurring LPG is projected to fall from 59 per cent to 49 per cent over the outlook period (figure U).
The demand for liquid fuel imports is not only determined by domestic production and end use consumption of petroleum products, but also by domestic petroleum refining capacity. For a given domestic production and consumption outlook, petroleum refining capacity constraints will result in lower oil imports and, simultaneously, higher imports of refined products.
The refining industry also uses petroleum products as an energy input to convert oil feedstock into a range of petroleum products. Around 6.0 per cent of gross refinery output is used on site in the conversion process, in addition to small quantities of natural gas and electricity.
Gross refinery output in Australia, including that of petrochemicals, is projected to increase from 1482 petajoules in 2004-05 to 1670 petajoules in 2010-11, growing at an average rate of 2.0 per cent a year.
To achieve this increase, new investment in refining capacity will need to occur in the medium term, reflecting a consistent increase in the domestic consumption of petroleum products and an improvement in the economics of petroleum refining in Australia. In the projections, this new investment is assumed to occur around the period 2010-11 to 2012-13, when a 5 per cent increase in capacity is assumed. Combined with an assumed 1.0 per cent a year growth in overall refinery output through efficiency improvements, this would result in a projected average rate of growth in refinery output of 2.0 per cent a year over the whole projection period, together with a temporary fall in imports of refined petroleum products as the new capacity comes on stream.
Refining capacity and refinery output are assumed to continue to increase by about 1.0 per cent a year beyond 2012-13. Refinery output is projected to increase to 2066 petajoules by 2029-30, representing a 39 per cent increase over the projection period. However, this increase in output is outstripped by the increase in petroleum consumption, which is projected to be 42 per cent over the same period. Consequently, the share of domestic production of refined petroleum products in liquid fuels consumption is projected to decrease from 78 per cent to 76 per cent over the outlook period (figure V). If it were assumed that new refinery capacity did not come on stream in the medium term, Australia’s self sufficiency in refined petroleum products could fall to around 70 per cent by 2029-30.
