The world has a huge appetite for energy. In its publication BP Energy Outlook 2030, BP projects global primary energy consumption to increase by 39% over the 20 year period to 2030. The vast majority of this expanded demand will continue to be met from fossil fuels. As our understanding of unconventional resources improves, and further advances are made in applicable technology, unconventional resources are destined to contribute a far greater share of future energy supplies.

The emergence of the coal seam gas to LNG projects in Australia (please see our Coal Bed Methane Briefing) and the development of shale projects in the United States and Canada and oil sands in Canada, are the clearest examples of how unconventional resources can change the energy landscape.  Until recently, Canada and the United States were expected to develop dozens of LNG regasification projects to import gas for domestic needs. The high gas price resulting from these market conditions, combined with the development of key technologies – especially horizontal drilling and hydraulic fracturing – has enabled huge shale gas reserves to be unlocked across North America. These two countries have now secured their own substantial domestic supplies, driving domestic gas prices down and creating the opportunity to instead start exporting LNG.  

The ability to now realize the commercial potential of shale gas on a large scale has caught the attention of national and international oil companies. 

Transactions in just the past few months include:

  • March 2011 – Sasol agreed to acquire 50% of Talisman's Cypress A acreage in Canada for over CA$1 billion
  • June 2011 - Petronas agreed to a $1 billion deal to buy into Progress Energy Resources Corp's Canadian shale gas assets
  • June 2011 – Mitsui Corporation agreed to buy a 12.5% interest in SM Energy Company's Eagle Ford shale assets, and to reimburse certain sunk costs and to carry 90% of SM Energy's costs up to US$680 million
  • July 2011 – BHP Billiton agreed to acquire Petrohawk for US$12 billion, following its US$4.75 billion acquisition in February 2011 of shale assets from Chesapeake

The prospects for shale gas are being looked at in various other countries.  For example, Poland has substantial recoverable shale gas resources and is leading the industry development in Europe, with companies such as ExxonMobil, Chevron, Total and Talisman all participating.   

In the past few weeks, Australia has suddenly come under the microscope, and some of the world's biggest international oil companies are moving in.

Australian shale gas

According to a June 2011 report commissioned by the U.S. Energy Information Agency, Australia has 396 trillion cubic feet of technically recoverable shale gas resources1. This is equivalent to about 20 per cent of the combined equivalent resources of Canada, Mexico and the United States.  It also exceeds the estimated recoverable reserves of coal seam gas in Australia, which underpin three LNG projects that have taken final investment decisions over the past 8 months with an aggregate capacity of more than 25 million tonnes per annum, with additional projects proposed.

The report only assessed four main basins in Australia, and so potential for additional resources exists across the country.  Those assessed basins, ranked on a composite play success / prospective area success basis, are the Cooper Basin in South Australia and Queensland, the Maryborough Basin in Queensland, and the Perth Basin and Canning Basin in Western Australia.  However it is the Canning Basin that has the highest technically recoverable resource of 229 tcf.  This is a substantial resource by any standards. The following table compares the four assessed Australian basins to the technically recoverable resources in the leading Canadian basins and US shale gas plays2:

Technically recoverable shale gas resources  

*Resources for the Horn River, Deep and Perth Basins are aggregates of resources in multiple formations

Current players: recent transactions

Although the assessed resource suggests there is huge potential for the shale gas industry in Australia, activity is still very much in its infancy.  There have been very few exploration wells drilled, no appraisal programs conducted, and no commercial production.

The Australian industry has been led by domestic players. Companies such as Santos, Beach Energy, Drillsearch Energy, Senex and Icon Energy have been assessing shale potential in the Cooper Basin.  AWE and Norwest Energy have been exploring the Perth Basin, while Buru Energy and New Standard Energy are active in the Canning Basin.  Other basins have also seen activity, such as the Beetaloo Basin in the Northern Territory, the Eromanga Basin in Queensland, the Georgina Basin across the Northern Territory and Queensland, and the Amadeus Basin straddling the Northern Territory and Western Australia.

Despite only limited exploration, results have been promising.  In July 2011, Beach Energy drilled its first shale gas well in the Cooper Basin producing up to 2 million standard cubic feet per day (mmscf/d), a result which was significantly greater than the company's expectations3. In early August 2011, Exoma Energy announced positive well results from its exploration activities in the Eromanga Basin.

The past 12 months, and in particular the past few weeks, have seen significant international interest emerge:

  • June 2010: Mitsubishi committed to fund an AU$152.4 million exploration & development program, to earn a 50 per cent. interest in the majority of Buru's exploration permits in the Canning Basin, with the additional right to acquire an interest in Buru's production permits in exchange for an additional cash payment.
  • September 2010: Bharat PetroResources agreed to acquire half of Norwest Energy's interests in two permits in the Perth Basin, committing up to AU$15 million for exploration and drilling.
  • December 2010: CNOOC executed a farmin agreement to acquire a 50% participating interest in Exoma's coal seam gas and shale gas permits located in the central Queensland Galilee Basin by contributing $50 million towards exploration and appraisal expenditure during the farmin period, expiring on 31 August 2013.
  • April 2011: Hess agreed a participation and evaluation deal with Falcon Oil and Gas in respect of the Beetalo Basin, pursuant to which Hess may acquire up to a 62.5 per cent. stake in three shale exploration permits and was granted warrants exercisable for 10 million common shares in the company.
  • July 2011: ConocoPhillips entered into a non-binding heads of agreement and exclusive negotiation period with New Standard Energy to farm-in to a 75 per cent. share of the Goldwyer shale project in the Canning Basin, for US$109.5 million funding obligations and a payment in respect of sunk costs.
  • July 2011: BG, through its wholly owned subsidiary QGC, agreed to acquire a 60 per cent. interest in one of Drillsearch's tenements in the Cooper Basin plus an option for shares representing 9.9 per cent. of the company.  In consideration, BG is to reimburse a share of sunk costs and commit to a five year $130 million three stage exploration and pilot production appraisal program (funding $90m of the first $100m). The venture also includes marketing provisions to sell gas for liquefaction through QGC's Queensland Curtis LNG project.

These transactions pale in comparison to the multi-billion dollar deals in Canada and the United States that have been making the global headlines.  However, in many ways Australia is in a similar emerging position to where the North American shale industry was several years ago.  As the resource in Australia becomes better defined and clear routes to market identified, then the transaction values could increase significantly

Issues to consider

Shale operations are governed under the umbrella of laws and regulations that govern conventional onshore gas production.  Although largely similar, there are some differences in the regulatory framework applicable across the various States and Territories in Australia, and in the way they are applied. Some of the key legal and commercial issues that companies should consider when assessing the Australian shale gas industry include:

  • Hydraulic fracturing:  As with coal seam gas operations, there has been significant public debate over possible environmental risks associated with hydraulic fracturing (fracking), particularly on the potential contamination of aquifers by chemicals used in fracking fluids.  Irrespective of the degree of risk actually created by these activities, this remains a sensitive area.  In May 2011 the New South Wales government imposed a temporary moratorium on fracking activities in the State, and in July 2011 the ban was extended until the end of the year.  Investigation into the environment, economic and social impacts associated with fracking, and their management, should be expedited in order to provide certainty for all stakeholders.  For investors, the risk of a moratorium being introduced after investment has been sunk will be of significant concern.  
  • Water use and production:  The drilling and fracking process also requires a substantial supply of water - especially the slickwater fracturing process which appears more cost effective for high pressure formations - and so competition for water supplies may be an issue.  Some shale formations will produce water, in much the same way as occurs for coal seam gas wells. The substantial quantities of saline fracking waste water pumped back to the surface will typically contain a high level of total dissolved solids and contaminants and, together with any produced water volumes, will need to be treated and disposed of.  As re-fracking the shale is often required over time to maximise recovery, water management will be an ongoing and expensive operation.  These are emerging issues and the regulatory environment is constantly evolving.
  • Competing land use:  Development of shale resources gives rise to similar competing land use issues as have been encountered with coal seam gas developments.  The development and operation of shale projects requires a large number of wells, rigs and collection and transmission pipeline networks.  Projects will be competing for land, water and infrastructure with other resource development projects, agricultural uses and communities.   
  • Labour and equipment:  Successful development of shale gas assets requires specialized horizontal drilling and hydraulic fracturing techniques, and skilled personnel and specialized equipment to perform them.  As a relatively new industry to Australia, these are not in abundant supply, and there are many coal seam gas and tight gas projects competing for the same pool of supply.  Conventional petroleum projects and mining projects will also compete for skilled labour.  This could result in significantly higher drilling and production costs compared to equivalent activity in North America.
  • Markets:  Australia produces substantially more gas than is required for domestic use.  Shale gas will compete with conventional and other unconventional resources to meet the gradual increments in demand for gas and to displace existing feedstock.  New markets might be created by virtue of the proposed carbon pricing mechanism, which should act to promote cleaner fuels such as natural gas.  However, acting contrary to this is the risk of market collapse.  Unconventional plays are present across Asia, particularly in China, India and Indonesia.  As large quantities of coal seam gas, shale gas and tight gas become commercially recoverable in Australia and the region, this has the potential to reduce domestic and regional gas prices.  Achieving long term export market pricing for shale gas is sensitive to this regional supply picture (although this risk is common to the conventional LNG business).
  • Reserves certainty: Developers, and their lenders and offtakers, will need to get comfortable with the greater uncertainties surrounding reserves estimation for shale gas. The shale gas industry is relatively new and, as with coal seams, each shale formation is unique and can respond differently to artificial stimulation.  It might be misleading to rely on the short term performance history of shale wells in one formation to estimate recoverable reserves in another.  A multitude of wells will need to be drilled over the life of a shale gas project, and production rates will be affected by the well completion and cannot be predicted in advance with a great deal of certainty.  Additionally, traditional decline curve analysis requires constant well pressure, however performance to date indicates a quick drop in pressure and flow rates. This needs to be taken into account when structuring the project, including for reserves dedication to offtakers, reserves tails for financing, and allocating consequences in the event reserves are less than expected.

Australia certainly has sufficient recoverable reserves to underpin a successful shale gas industry.  However it won't be without its challenges.  It will need robust demand and strong gas prices to underpin the projects, and so will primarily need to look to export markets.  In January 2011, the National Energy Administration predicted that in 2011 alone, China's natural gas consumption will have a year on-year rise of 20 per cent.  The key question is whether continued strong demand in north Asia and emerging demand centers will be enough to absorb all of the unconventional gas reserves that are emerging in the region.  


1 World Shale Gas Resources: An Initial Assessment of 14 Regions Outside the United States, prepared by Advanced Resources International for the U.S. Energy Information Administration, April 2011
2 US shale play figures taken from Review of Emerging Resources: US Shale Gas and Shale Oil Plays, prepared by INTEK, Inc. for the U.S. Energy Information Administration, December 2010

The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.