8 minute read

East-coast gas market – where to now?

Tim Nelson
Tim Nelson
06 September 2018

Many homes and businesses on Australia’s east-coast are reliant upon natural gas for cooking, heating and producing many different products. We use these products, such as glass and bricks, every day for building our homes, running our businesses and going about our daily lives.

This reliance on gas, coupled with high wholesale gas prices is prompting the questions, how did we get here? And what are some solutions that may place downward pressure on prices?

In my new paper published in the journal Economic Analysis and Policy, I take a look at the issues facing the market today, and where to from here.

What’s the problem?

The development of new drilling technologies had two main impacts:

  • large resources of coal-seam gas being unlocked, and
  • 2P reserves increasing substantially (from 3,400 PJ in 2005) to approximately 49,300 PJ.

Expressed simply, 2P is an indicator that the gas can be produced commercially. And as the Table below shows, there is no shortage of gas ‘resources’ on Australia’s east-coast.


But with only ~ 600 PJ per annum of domestic demand (for households, businesses and power generation), three large LNG export facilities were developed at Gladstone in Queensland. These facilities can consume around 1,500 PJ per annum.

There is more than enough gas to ‘physically’ satisfy domestic demand and current LNG export contracts for at least twenty years.

There are around 50,000 PJ of 2P reserves with both domestic and LNG consumption summing to around 45,000 PJ. But the estimated marginal cost of production for these resources is at least $6/Gigajoule (GJ).

Beyond this point there is a significant step-change in estimated costs with a range of at least between $7/GJ and $9/GJ. This is an important observation as it represents a material deviation from historical pricing of closer to $3/GJ.

And while all this was happening, gas prices globally fell substantially. Given east-coast gas resources are now ‘linked’ to the global gas market through the LNG export facilities, it is this global price that guides new investment in domestic gas production. A subdued global gas price means gas producers have little incentive (and cash flow and balance sheet strength) to finance expansion of production. The result of a slowdown in gas production activity is a gap between what is being produced and what is required to satisfy both domestic consumption and the LNG export facilities. This is shown in the Figure below.


So, what are the options for fixing this problem?

Four options for addressing the lack of supply relative to demand are considered in the paper. There are:

  • the Commonwealth Government’s Australian Domestic Gas Security Mechanism;
  • expanding domestic supply;
  • importing LNG; and
  • expanding pipeline infrastructure to connect interstate gas reserves to the east-coast.

The paper presents simplified partial equilibrium analysis (i.e. demand and supply curves) to demonstrate how each of the options would impact on the market.

  • Expanding domestic supply: Expanding supply is a logical solution to the problem. But in a world of low global LNG pricing, supply cannot expand when it is a function of the expected future stream of diminishing revenue from global gas pricing. As a price taker, Australian LNG producers face little incentive to expand production domestically when there is a subdued outlook for global gas pricing. If global LNG prices are high, expanded domestic supply may in fact be the best option. A paper by Paul Simshauser and I came to this conclusion a few years ago.
  • Importing LNG: In an environment with comparatively high international gas pricing, it would be improbable for gas import infrastructure to be utilised. However, in an environment of relatively low international gas pricing, import infrastructure of considerable capacity (relative to domestic gas consumption) may play a critical role in eliminating price differentials between Australian and international markets. The ‘price floor’ becomes the ‘price cap’.
  • Expanding interstate pipeline capacity: Some preliminary estimates of the cost of building a pipeline from Western Australia indicate it would be uneconomic when compared to importation infrastructure. Credit Suisse have estimated that transporting Western Australian gas to Victoria would result in pipeline tariffs of approximately $7.50 per GJ (around $6 per GJ for transportation to Moomba and a further $1.50 per GJ from Moomba to Melbourne). Assuming shipping and liquefaction costs of around $1.70 per GJ and $1.50 per GJ for life cycle import terminal costs, Credit Suisse estimate the ‘equivalent’ tariff for importing gas would be around $3.20 per GJ.


There have been significant unintended negative consequences due to the ‘lumpiness of capital allocation’ (i.e. the development of the LNG export industry) and the ‘temporal instability’ caused by a shift in global oil and gas pricing. The economic detriment being caused by these issues, manifesting through domestic gas supply shortfalls and comparatively high domestic gas prices, is only now being understood by policy makers. A recent paper by other Australian economists is worth reading in this context.

In my view, the most efficient and ‘no regrets’ economic solution at this point in time would be to allow market participants to develop gas import infrastructure. Such a development would ensure that the market price floor (created by LNG export capability) is also the market price cap.

Most importantly, development of gas import infrastructure would not involve government intervention and could therefore limit perceptions of sovereign risk. In the event that international oil and gas prices markedly increased, the economic risk associated with a stranded asset would sit with proponents of gas import infrastructure and not domestic gas users and producers (or the government).