Challenges Faced by Australia's East Coast
August 2017
Australia’s east coast natural gas market has been irrevocably transformed over the past seven years. Facing an unprecedented demand surge from liquefied natural gas (LNG) export plants, producers and consumers have experienced a rapid break from the stable gas market that has ruled for decades. High gas exploration and production costs, and exposure to international markets have had the effect of doubling domestic gas prices from US$4/GJ in 2014 to around US$8/GJ in 2017.

The east coast gas market in Australia is being challenged by three factors that have important ramifications for the east coast; both residentially and for industrial gas users.  Firstly, the introduction of LNG is a significant factor, as it has changed gas flows and domestic prices. Secondly,  the fall of the oil price, both faster and further than some thought possible, is rapidly curtailing investment in gas exploration and development. And, thirdly, the complex petroleum policy, regulatory uncertainty and exploration moratorium in New South Wales, Victoria and Tasmania have significantly limited or delayed the potential for new gas supply from these states into the east coast market.  In Queensland, the state released 58sq km of exploration ground in the onshore Surat Basin with the “strict” condition that any gas produced must be used in Australia. At the Federal level, The Australian Domestic Gas Security Mechanism (ADGSM), came into effect in July 2017, which aims to ensure “adequate supply of gas for domestic markets” at prices that reflect international export prices. Doubt exists around the implementation and impact of the ADGSM, and it adds further uncertainty to a complex industry beset by government regulation.

  • The simultaneous commissioning of the six LNG trains in Queensland has caused significant disruption to the market and the demand-supply balance, with some LNG proponents having to supplement self-supply by contracting gas that would otherwise have been supplied into the domestic market.
  • Output from the region is expected to treble by the end of the decade, from the current 60Mcmpd to approximately 180Mcmpd. Nevertheless, the critical question for the gas industry was whether there would be sufficient supply over time to meet domestic and LNG market demand.
  • Most of the increase in output will come from more expensive unconventional reserves, such as coal seam gas (CSG) production in the Surat and Bowen Basins, (Figure 1).  These reserves had been identified by gas producers but still required extensive investment.  Australian gas producers are moving further up the cost curve as the most accessible reserves in mature plays, particularly from Cooper/Eromanga and the shallow Gippsland Basin, are depleting.
  • A large portion of future production in the market is coming from unconventional Coal Seam Gas (CSG) fields in Queensland, which are primarily being developed by the LNG projects. The need for continual reinvestment in CSG infrastructure creates commercial and technical uncertainty over the exact timing and volume of future gas from these reserves. Adding to this uncertainty is the lack of clear information about the likely timing and size of the Arrow project development, which still holds the most significant uncommitted gas reserves on the east coast.
  • Traditional conventional sources of supply, such as Gippsland, Otway and Cooper/Eromanga Basins continue to face increasing costs and challenging decisions about potential new field expansions in the prevailing economic conditions. In the absence of timely additional investment, there would likely be a significant reduction in supply from these traditional sources in the southern states.

Australian east coast gas projects have sufficient Proven plus Probable (2P) reserves—over 1.2Tcm—to meet both domestic demand and the forecast demand for the proposed LNG projects. Tripling of supply will however rely largely on developing non-established resource plays and improvements in unconventional technology to offset ageing conventional fields in the Gippsland and Cooper/Eromanga Basins. New capacity additions are focused mostly on CSG projects in Queensland.

Queensland’s CSG resources in the Surat and Bowen Basins are estimated to be 1,120Bcm, far exceeding conventional gas reserves in basins such as Gippsland (82Bcm), Cooper/Eromanga (43Bcm) and Otway (~18Bcm).

Production from the main producing CSG sites in the Bowen and Surat Basins has surged from 21Mcmpd in 2013/2014 to 71Mcmpd in 2015/2016, (Figure 2).   CSG accounts for well over 40% of the gas produced on the Australian east coast and 90% of 2P reserves.



CSG projects have high capital and ongoing operational costs, they require the drilling of several hundred wells and extensive surface infrastructure for water and gas processing, compared to the wells and facilities that would be used to extract gas from onshore conventional sandstone reservoir projects.  Approximately 7,000 CSG wells target coal seams in Queensland alone.

Forecasting CSG project cost direction relies on four principal risk considerations.

  • The first consideration, relies on how fast efficiency gains will be made as CSG operators move further along the learning curve and increase production scale.
  • The second consideration, is dependent upon defining subsurface risk and its impact on production costs. Given the current scale of CSG production required to meet LNG demand, operators will be required to develop non-proven acreage. This increases geological risk since coal seams are notoriously heterogenic. The effects of poorer quality CSG reservoirs on well performance can be significant. As an example, the CSG projects analysed by AME— most of them focused around proven CSG acreage—have a wide range of production costs, from US$2.7–6.8/MBtu.
  • The third consideration, hinges upon the level of project investment. The drilling intensity and the high levels of associated water production require large capital investments on treatment plants, gathering lines, pipelines and access infrastructure. The footprint of such projects is significant and the impact on water resources has put CSG producers and local communities at odds.
  • Finally, the fourth consideration, rests upon state and federal petroleum regulation. The specific challenge is the political environment in the states of New South Wales and Victoria, where drilling moratoria and resistance from local communities has cast doubts over several proposed and developing CSG projects.  AGL’s Camden and Narrabri CSG projects have ceased and the Santos Narrabri CSG project EIS is under intense scrutiny.  The lack of additional local supply from these states will require increased flows of gas transportation to these southern states—instead of east towards Gladstone—and increase the burden on the local pipeline network.

With respect to traditional onshore conventional gas reservoir projects, recent years have seen a marginal improvement in recovery; this will continue to be critical to maintain the smooth supply ramp-up to meet demand from the Queensland LNG facilities. Australia’s established conventional low-cost gas fields in the Gippsland, Otway and Cooper/Eromanga Basins are mature and declining. In the Cooper/Eromanga Basin in central Australia, Santos, the lead operator in the area, announced over half a billion US dollars in proposed investments to revive production from the basin, including an expansion of Moomba’s gas processing capacity. The basin has slightly increased output and this is expected to be maintained until the end of the decade. Santos is focusing heavily on reducing unit well and production costs. The cash cost of production in the basin is increasing from an estimated average of US$3.5/MBtu in 2015.


Driving investment and addressing the challenges of the Australian east coast gas market also relies on arresting the decline of established offshore reserves from the Bass/Otway/Gippsland Basin’s. However, major conventional gas projects, such as ExxonMobil’s Kipper-Tuna-Turrum project and Cooper Energy Sole project, will only help maintain and potentially marginally increase output for some years yet.

The US$5.5Bn Exxon-operated Kipper-Tuna-Turrum project is currently the largest offshore development.  In early 2017 ExxonMobil flagged a major phase of new investment to arrest the decline in these three large offshore Victorian gas fields it owns with BHP Billiton. The Kipper-Tuna-Turrum project paves the way for “Bass Strait 2.0” amid surging east coast domestic gas demand. The Operator believes it can produce another 7Tcf of gas; it has two other significant discoveries in Bass Strait it has been considering developing for more than a decade: South East Remora and East Pilchard.

In early 2017, Cooper Energy announced the Sole Gas Project had advanced to the finalization of the field development plan, signing of heads of agreement with APA to own and operate the Orbost Gas Plant and achievement of gas contracting targets enabling the final financing process to commence with a view to project sanction in March 2017.   The project involves the development of the estimated 6.6Bcm Sole field in the Gippsland Basin, offshore Victoria to supply approximately 25PJ of gas per annum from 2019.  AME estimates that the single-well project could deliver up to 1.2–1.5Mcmpd during peak, but will feature very low liquids yields of about 40bpd of condensates. The gas will also require treatment for its high H2S content. Preliminary economic analysis points to full production costs over US$5/MBtu.

The Northern Gas Pipeline project has been granted a construction licence. The 622km pipeline connecting the Northern Territory to Mt Isa in Western Queensland could open a new supply route for natural gas assets in the Amadeus and Beetaloo Basins. The expected start-up date is late 2017 and final capacity could reach 700TJ of gas per day. This pipeline could potentially provide access for the lower-cost Palm Valley and Mereenie gas fields. Operator Central Petroleum has announced that it seeks monetisation options to fully develop the fields, and this pipeline link would allow it to deliver to Mt Isa at around US$3/MBtu. The decision by the Northern Territory government to connect the Northern Territory with the east coast gas market would potentially bring new gas supply into the Australian east coast market.