Note that this paper does not deal with debates around the environmental and social impacts of the gas industry.

This is the second of a series of companion briefing papers on utilities. The first related to electricity; the next two deal with water and renewable energy sources.

East Coast gas markets

The two predominant wholesale gas markets on the East Coast are the Declared Wholesale Gas Market (DWGM) in Victoria; and the Short Term Trading Market (STTM) which caters for the supply of gas into, or via, Adelaide, Brisbane or Sydney.

A new voluntary gas trading exchange was developed in early 2014 by the Australian Energy Market Operator (AEMO) in Wallumbilla, Queensland.

The primary purpose of these markets is to enable participants to trade gas supply imbalances that arise on a day because their actual demand for gas differs from their contracted supply. These markets may therefore be viewed as a market-based balancing mechanism that overlays the bilateral contracting arrangements. [2]

Wholesale gas prices

The capital-intensive nature of gas supply infrastructure, combined with a desire for long-term supply certainty from major gas users, has meant that the bilateral contract market has been the preferred vehicle to trade gas and manage long-term risks.

Until approximately 2010 new gas contracts were available in eastern Australia at price levels that had remained steady in real terms over the previous decade or longer.

A significant proportion of the long-term gas contracts in the eastern market have expired within the last five years, and more are due to expire in the next five years. The competition for gas supply from Queensland liquefied natural gas (LNG) developments creates an incentive for producers to seek to rollover contracts at higher short run prices rather than renegotiate them at long run prices. [3.1]

Gas spot prices (which respond in the short term to the balance of supply capacity) trended higher between the end of 2010 (from around $2-3 per gigajoule (GJ)) and mid-2013 (to around $6-7/GJ).

According to Jacobs SKM (2014), the upward trend in spot prices suggests that the spot markets are signalling future increases in the value of gas. While this may be the case, the signals have recently weakened, with spot prices falling back to average contract price levels. [3.2]

In the short to medium term, eastern market gas prices will be significantly influenced by the expansion of LNG exports out of Queensland, with the connection to export markets projected to increase demand and result in a convergence to the LNG netback price (which is the LNG sale price, less the costs incurred in producing and transporting the LNG to the point of sale).

Despite the general expectation of a price rise in the short term, followed by stabilisation in the medium to longer term, there is considerable uncertainty in the outlook because of variability in key price drivers such as oil prices, LNG export volumes and costs of gas production. [3.3]

Retail gas prices

At March 2014, the gas price index was highest for Adelaide (132.9) and Melbourne (127.2), followed by Sydney (125.8), Brisbane (121.8) and Perth (119.2). Perth has experienced the highest rate of growth in gas prices over the last decade, with the index more than doubling since June 2004 at an average quarterly rate of 2.2 per cent; compared to Sydney gas prices which grew at an average quarterly rate of 1.6 per cent. [4]

The Independent Pricing and Regulatory Tribunal (IPART) is responsible for regulating retail gas prices for around 28 per cent of residential and small business customers in New South Wales. On 1 July 2014, IPART published the latest review on regulated prices for 2014-15 and 2015-16 which determined that average regulated retail gas prices can increase by up to 17.7 per cent across NSW over the next 2 years. [4.1]

As at 30 June 2013, AGL Energy, Origin Energy and EnergyAustralia jointly supplied over 85 per cent of small gas customers in eastern Australia and account for around 95 per cent of such customers in New South Wales. [4.2]

IPART (2014) concluded that the competiveness of the retail gas market in NSW has continued to increase and suggested that the gas market is already transitioning towards a largely deregulated market, where few customers remain on regulated prices. [4.2.1]

Gas demand

New South Wales was the fourth highest consumer of natural gas in Australia in 2012-13 at 162 petajoules (PJ). Growth in natural gas consumption has remained relatively subdued in New South Wales, increasing by 13 per cent between 2002-03 and 2012-13.

On a per capita basis, New South Wales is the lowest consumer of natural gas (at 21.8 GJ/annum in 2012-13) when compared with the other States and the Northern Territory. Western Australia had the highest per capita consumption in 2012-13 at 289 GJ/annum. [5.1]

The manufacturing (50 per cent in 2012-13), electricity generation (25 per cent) and residential (16 per cent) sectors account for the majority of gas consumption in New South Wales; although consumption in the manufacturing sector, in absolute terms and as a proportion of State consumption, has been declining over the last decade. [5.2]

The influence of Queensland LNG developments on demand and supply conditions in the eastern market is expected to be significant because of the scale of the projects being developed which will demand around 1500 PJ annually; exceeding the combined capacity of existing LNG projects in other Australian markets. [5.4]

Eastern market annual gas demand is expected to increase from 745 PJ in 2014 to 2,182 PJ in 2033; at which point LNG exports are projected to account for 66 per cent of total annual gas demand.

Domestic demand (excluding LNG) is projected to grow slowly at approximately 0.9 per cent annually to approximately 750 PJ by 2033. On a State by State basis, average annual demand growth between 2014 and 2033 is projected by the AEMO to be highest in Tasmania (1.9 per cent), followed by Queensland (1.1 per cent) and Victoria (1.0 per cent). Annual demand in NSW is projected to grow by 0.8 per cent over this period. [5.5]

Gas production

Natural gas production in Australia has grown at a relatively high annual rate of 5.2 per cent over the last decade, increasing from 1,464 PJ in 2002-03 to 2,439 PJ in 2012-13. In absolute terms, production in New South Wales was estimated at 6.2 PJ in 2012-13 (or 0.25 per cent of Australian production), a decline of around 25 per cent since 2002-03.

Coal seam gas (CSG) developments in New South Wales have the potential to supply more than half of current New South Wales domestic demand within the next five years. The CSG industry is regulated by the Office of Coal Seam Gas and the Environment Protection Authority; recent regulatory reforms, including the Strategic Regional Land Use Policy, have slowed the expansion of the industry in New South Wales. [6.1]

Australia’s gas has historically been sourced largely from the Carnarvon, Cooper-Eromanga and Gippsland Basins. In recent years, production from unconventional resources (i.e. coal seam gas or shale gas) in the Surat-Bowen Basins and conventional (i.e. large underground chambers of trapped gas) offshore resources in the Bonaparte Basin and the Otway Basin has grown strongly.

In August 2013 Australia’s 2P gas reserves stood at around 141,000 PJ, comprising 97,000 PJ of conventional natural gas and 44,000 PJ of CSG. Eastern Australia contains 36 per cent of Australia’s gas reserves, of which the majority are CSG reserves in the Surat−Bowen Basin. [6.2]

The eastern gas market is highly concentrated and characterised by a relatively small number of players at each level of the supply chain. However, the growth of the CSG and LNG industries has led to considerable new entry in Queensland’s Surat−Bowen Basin over the past decade. The three largest gas retailers, AGL, Origin and EnergyAustralia, all have commercial interests in upstream reserves. [6.3]

The cost of new gas developments has increased in recent years, both domestically and worldwide. A number of market analysts have developed gas supply curves for the eastern market and a common characteristic is an increase in production costs as the quantity of gas supplied increases. This tends to occur because cheaper more accessible resources are the first to be extracted, leaving behind progressively more expensive sources of supply. [6.4]

Based on the analysis completed by the AEMO (2013), potential gas supply shortfalls may occur in Queensland in 2019 if facilities currently dedicated to domestic demand are prioritised to supply rising LNG export demand.

If production in Queensland and South Australia is prioritised for export, there will be flow-on effects to New South Wales with potential daily shortfalls of 50 to 100 TJ over winter peak demand days from 2018. BREE and the Department of Industry (2014) recommended that unnecessary impediments to supply be removed to overcome any potential shortfalls in the coming years. [6.5]

Analysis by the AEMO (2013) indicates that sufficient reserves are likely to be commercially viable to satisfy projected gas demand for at least the next 20 years. However, production and distribution capacity is the key source of uncertainty going forward for the eastern gas market. [6.6]

Gas transmission and distribution

Gas pipelines provide a transportation link between upstream gas producers and downstream energy customers.

Transmission pipelines enable gas to be transported under high pressure from production facilities to either the entry point of the distribution system or directly to users that are connected to the transmission pipeline. The ownership of gas transmission pipelines is highly concentrated. APA Group, a publicly listed company, has the most extensive portfolio of gas transmission assets in Australia. [7.1]

The distribution pipeline network delivers gas from demand hubs to industrial and residential customers and typically consists of high, medium and low pressure pipelines. The major gas distribution networks in southern and eastern Australia are privately owned by Envestra (which owns networks in Victoria, South Australia, Queensland and the Northern Territory) and Jemena (New South Wales). [7.2]

Investment in distribution networks in eastern Australia (including investment to augment capacity) is forecast at around $2.7 billion in the current access arrangement period (typically five years). [7.3]