Australia has the most active development of unconventional gas (concerning both shale gas as well as Coal Bed Methane) outside of North America, mostly in New South Wales (NSW), Queensland (Bowen and Surat Basins), and Victoria. This has already been taking place in NSW since the 1980s (for the generation of electricity), and in Queensland since 1996. Nevertheless it has been growing rapidly again since 2003: production has more than doubled in the period 2003-2006 from 538 mcm to 1,600 bcm. In 2008 this figure amounted to 3,700 mcm. Analysts believe CBM could provide up to 50 percent of the Australian east coast natural gas supply by 2020.

In 2010, Australia’s estimated TPEC amounted to 125.84 mtoe, a 4% decrease compared to 2009. Oil accounted for 40.32 mtoe, while coal and gas accounted for 52.91 mtoe and 26.01 mtoe respectively. Other sectors accounted for the remaining 6.6 mtoe.^[1]

*other: hydro, geothermal, solar, wind, electricity & heat, biofuels & waste ^[1]

*other: hydro, geothermal, solar, wind, electricity & heat, biofuels & waste ^[1]

• 1. Natural Gas Information © OECD/IEA, 2011

In 2010, Australia consumed a total of 32,322 mcm of natural gas, 3.1% more than in the previous year. In 2009, Australia consumed a total of 31,350 mcm of natural gas, which represented a 0.7% increase compared to 2008. Of the total demand in 2009, 9,795 mcm was used for transformation, 9,633 mcm for industry (excluding the energy industry itself, which used 5,912 mcm), 496 mcm for transport and 4,781 mcm was consumed by other sectors.*

Transformation includes the generation of electricity, while the demand from the ‘Industry’ refers to gas used for such things like the chemical-, iron and steel- and machinery industry. The demand from the ‘Energy Sector’ refers to gas used for the extraction of coal, oil, and gas and gas used in refineries, coke ovens and gas works.^[1]

*other: commerce and public, residential, agriculture, non-specified ^[1]

*other: commerce and public, residential, agriculture, non-specified ^[1]

• 1. Natural Gas Information © OECD/IEA, 2011

At the end of 2010, Australia holds around 1.76% of the world’s gas reserves, which is equivalent to 3,333 bcm of natural gas.^[1] Conventional gas is largely produced from the Carnarvon Basin offshore North Western Australia, the Cooper/Eromanga basin in central Australia, and Gippsland/Victoria. These 3 basins account for 96 percent of Australia's conventional natural gas production. Queensland and New South Wales are the main sources for coal bed methane, which accounted for 13 percent of gas production in 2010. Due to the remoteness of these reserves it is more economical to convert the gas into LNG for exports than it is to carry it inland by building a pipeline. About half of natural gas production is converted into LNG for export and the other half is consumed domestically.^[2]

The reserves-to-production (R/P) ratio* for Australia was 58 years at the end of 2010, which is significantly higher than, for example, the EU’s average R/P ratio of 14 years.^[3]

*Reserves-to-production (R/P) ratio – If the reserves remaining at the end of any year are divided by the production in that year, the result is the length of time that those remaining reserves would last if production were to continue at that rate.

• 1. Natural Gas Information © OECD/IEA, 2011
• 2. EIA Analysis Briefs 2011
• 3. BP Statistical Review of World Energy June 2011

In 2010, gas imports account for about 17% of the total volumes of consumed gas in Australia. All of Australia’s gas imports are being accomplished via pipeline, so far there are no LNG imports.^[1]

• 1. Natural Gas Information © OECD/IEA, 2011

It is estimated that, in 2010, Australia exported over 24 bcm. Its prime export market is Japan, with about 18.5 bcm. But also, China, South Korea, and Taiwan are destination markets. The distances between Australia and its key natural gas export markets in Asia discourage any pipeline trade; all exports are in the form of LNG.^[1]  

• 1. Natural Gas Information © OECD/IEA, 2011

Pipelines

Australia’s gas transmission network covers over 20.000 kilometres in length and transports natural gas from the production fields in the different territories to the major demand centres. No transit of gas takes place. The construction of Epic Energy’s QSN Link (stage 1 completed in 2009) has interconnected the Queensland transmission network with major pipelines in South Australia and New South Wales. Earlier projects included the Eastern Gas Pipeline (Longford to Sydney, completed in 2000), the Tasmanian Gas Pipeline (Longford to Hobart, 2002) and the South East Australia Gas (SEA Gas) Pipeline (Port Campbell to Adelaide, 2003). The VicHub in eastern Victoria was constructed in 2002 to physically interconnect the Victorian Transmission System with the Tasmanian Gas Pipeline and the Eastern Gas Pipeline. Transmission pipelines in Western Australia and the Northern Territory are not interconnected with other jurisdictions (yet).

Gas Infrastructure Projects

Many infrastructure projects have been completed quite recently. Around $4 billion has been invested or committed to new transmission pipelines and expansions since 2000. Much of this investment has been in long haul interstate pipelines to introduce new supply sources and improve security of supply (see above). At the moment, besides some interconnection between existing pipelines, pipelines between the following areas are planned:

^[1], ^[2]

• 1. Australian Competition & Consumer Commission
• 2. Natural Gas Information © OECD/IEA, 2011

Currently, four LNG locations are operational with a combined annual capacity of at least 55.22 bcm of natural gas per annum: Whitnell Bay, Darwin, Pluto, and North West Shelf. Various installations are currently being proposed or under construction, mainly for Asian markets. Australia ranks fourth in terms of share in global production of LNG with 41.3 mcm in 2010 (after Qatar, Indonesia, and Malaysia). ^[1], ^[2]

Driving much of the recent CBM activity (see section 2), several major international companies have acquired stakes in Australia’s CBM industry with plans to convert CBM into liquid natural gas (LNG). The BG Group, Santos Ltd., (with Petronas), ConocoPhilips (with Origin Energy), and Royal Dutch Shell are planning four separate CBM-to-LNG projects in Queensland. ^[4]

• 1. GIIGNL 2010
• 2. Global LNG Info - World's LNG Liquefaction Plants and Regasification Terminals 2012
• 3. EIA Analysis Briefs 2011
• 4. Global Methane Initiative/U.S. Environmental Protection Agency - Coal Mine Methane Country Profiles 2010

In June 2011 there are 5 operational storage facilities in Australia with a combined technical storage capacity of 1,309 mcm. The storage facilities include 4 depleted gas fields and 1 LNG peak shaving facility. ^[1]

• 1. Natural Gas Information © OECD/IEA, 2011

The upstream sector is privately owned. The North West Shelf Venture (NWSV), a consortium of 6 energy companies led by Woodside Petroleum, dominates the Australian LNG market and produces around 8% of the world LNG supplies, mainly destined to Japan. Another large market player is ConocoPhilips. Exploration and production is undertaken by many private companies, including: BHP Billiton, BP, Chevron Texaco, ExxonMobil, OMV, Origin Energy, Santos, Shell and Woodside Energy. ^[1]

• 1. EIA Analysis Briefs 2011

All transmission pipelines are owned and operated by private companies. Third party access is arranged according to the National Gas Law (NGL) and National Gas Rules (NGR), introduced in July 2008. The transmission infrastructure is fragmented.

In Australia, a distinction is being made between ‘covered’ and ‘uncovered’ pipelines. Pipelines deemed to have undue market power by the national competition regulator, and approved by the relevant government minister, become covered pipelines under the NGL and NGR. This means that there is control over these covered pipelines by the energy regulator, mainly regarding tariffs. Pipelines that are not covered are free to set tariffs for transportation services, without regulator approval.

Two other relatively unique regulation features are:

• A ‘light regulation’ classification for pipelines under the NGL and NGR (after meeting a competition test), which ‘loosens’ some rules for access arrangement (no upfront approval by the regulator necessary, but afterward negotiated access with access seekers instead).

• The ‘greenfields pipeline incentives’ under which new pipelines can, subject to a competition test before commissioning, be granted a binding up-front exemption from regulation for the first 15 years of operation.

Local gas distribution has also been fully privatised in all states and territories, with the exception of the Australian Capital Territory (ACT), where the distribution network is 50 per cent owned by the ACT Government. The distribution pipelines are operated by 9 DSO’s under different states or territories regulation. Major distribution companies include: AGL, AlintaGas, Allgas Energy Ltd/ENERGEX, Envesta, Country Energy, TXU Networks and United Energy.

The National Gas Code (NGC) regulates the gas distribution and gas transmission access regime, but these sectors still retain a significant element of state of territory-based regulation (i.e. different regulated tariffs/access regimes). Local governments are expected to quickly adopt the NGC. ^[1], ^[2]

• 1. Natural Gas Information © OECD/IEA, 2011
• 2. International Energy Regulation Network 2006-2009

Also the downstream sector is privately owned. Most of Australia’s States and Territories are committed under the terms of the 1997 National Gas Pipelines Access Agreement (NGPAA) to implement full retail competition.

The eligibility level is different across States and Territories. In 1999 the New South Wales and South Australian gas markets became contestable for customers using between 1 and 10 terra joules per annum. In 2002 full gas retail contestability was introduced in New South Wales, the ACT and Victoria.

Main Gas retailers include: AGL Energy Sales & Marketing, AlintaGas, Allgas, Energy/ENERGEX, Country Energy, EnergyAustralia, Argon Energy Gas, Origin Energy, and TXU Retail. ^[1]

• 1. International Energy Regulation Network 2006-2009