The shale industry in Australia is very much in its infancy and the full extent of shale gas resource is far from being identified. However, both exploration and interest in Australia’s shale gas potential have increased significantly in the last few years. According to a report published by the US Energy Information Administration (EIA) in June 2013, Australia enjoys geological and industry conditions resembling those of the US and Canada, with an estimated technically recoverable shale gas resource of 437 TCF.1
Shale plays in Australia
Australia is ranked seventh of the 41 countries reviewed by the EIA for shale gas resources, following Mexico and ahead of South Africa. Western Australia alone is estimated to hold the fifth largest reserves of shale gas in the world, being 280 TCF (235 TCF in the Canning Basin and 45 TCF in the northern Perth Basin).2 Australia’s estimated technically recoverable shale gas resource exceeds its estimated recoverable reserves of coal seam gas (as coal bed methane is referred to in Australia). The shale gas reserves already underpin three liquefied natural gas (LNG) projects now being developed, with an aggregate capacity of more than 25 million tonnes per annum, and additional projects have been proposed.
The EIA report assessed 11 formations within six basins in Australia: the Cooper Basin in South Australia and Queensland; the Maryborough Basin in Queensland; the Perth Basin and Canning Basin in Western Australia; and the Georgina Basin and Beetaloo Basin in the Northern Territory. Ranking these six basins in terms of composite play success and prospective area success, the Canning Basin is estimated to have the highest technically recoverable resource of 235 TCF. This is a substantial resource by any standards.
Unassessed shale resources
As the map on page 27 shows, there are several more basins in Australia that have not been assessed. Potential for significant additional resources therefore exists across the country. While some basins are currently the subject of exploration programmes, most remain substantially underexplored.
To help understand the shale potential in Australia, the Onshore Hydrocarbons Section at Geoscience Australia, in collaboration with state and territory geological surveys and energy departments, has begun an assessment of the unconventional hydrocarbon potential of Australian basins.
For those basins with very poor geological control (many of Australia’s basins fall into this category), a detailed prospectivity assessment will first be conducted. This will give a better understanding of the petroleum system(s) in the basin and identify zones that are likely to host unconventional hydrocarbons.
For those basins where there has already been significant exploration, such as the Cooper Basin, a resource assessment will be carried out in cooperation with the US Geological Survey. This will utilise existing data and apply probabilistic methodology to estimate recoverable resources. The results will be released on a basin-by-basin basis.
To date, the initial results from early core sampling analysis show that the Georgina Basin has some promise, less so the Amadeus Basin3. To help assess the unconventional petroleum resource potential in the Georgina Basin, Geoscience Australia has generated a new mineralogical dataset. However, it is not clear when a prospectivity assessment for the Georgina Basin will be finalised and published.
History of Australia’s shale business
There have been very few wells drilled that specifically target shale gas formations. This is partly because of Australia’s plentiful supply of conventional and coal seam gas, as well as a lack of land rigs capable of drilling deep enough.
The first two vertical wells specifically targeting shale gas were drilled in 2011 in the Cooper Basin by Beach Energy. Australia’s first, and so far only, commercial shale gas production commenced in October 2012 in the Cooper Basin. The vertical test well was drilled only 350m from existing pipeline infrastructure and 8km from a gas processing plant, which enabled it to be brought online quickly. Not all basins are endowed with existing infrastructure of this nature. Those basins in the north of Western Australia and in the Northern Territory are particularly remote and are likely to require substantial capital commitments to develop infrastructure to deliver gas to market.
The Australian industry was initially led by domestic players and nimble international companies with shale gas experience in North America. These companies acquired permits over large areas considered to be the most prospective for shale gas. There has been a steady increase in international interest in Australian acreage, and a number of large global players gained interests in acreage by funding exploration operations and forming joint ventures.
The following is a brief summary of the state of play in some of the more significant basins, although it should be noted that activity and opportunities also exist in several other basins.
Identified by the EIA report as having the greatest likely resource in Australia, it is no surprise that the Canning Basin has seen a significant amount of activity, led by Buru Energy and New Standard Energy. The EIA report identified the basin as having in excess of 225 TCF of recoverable shale gas, based on the Goldwyer formation alone. The Australian Council of Learned Academies confirmed this assessment and calculated a further 38 TCF of recoverable shale gas in the Laurel formation.
Buru Energy has announced very large gas resources in its petroleum titles. It was the first company to farm out interests to larger foreign investors when it struck a deal with Mitsubishi in June 2010. In November 2013, Apache Energy joined Buru Energy and Mitsubishi’s joint venture. On June 20, 2014, Western Australia’s Department of Mines and Petroleum approved Buru Energy’s Laurel Formation Tight Gas Pilot Exploration programme, which was developed to identify the potential environmental impacts and risks associated with exploration activity. This programme will involve stimulation of tight gas zones in existing vertical exploration wells to assess their commercial potential. Buru Energy intends to drill five firm wells, and up to seven in total, in a continuous drilling programme set to commence mid-May 2015.
ConocoPhillips also joined the action, striking a deal with New Standard Energy in 2011, with PetroChina subsequently acquiring part of that stake from ConocoPhillips in 2013.
Hess also acquired Canning Basin interests in 2012. Other active participants include Key Petroleum and Oilex.
There are challenges to developing a commercial resource in the Canning Basin due to its remote location and lack of existing pipelines, roads and water sources.
The Cooper Basin may enjoy the greatest viability for commercial development of shale gas. This results from the size of its expected resource (92.9 TCF of technically recoverable resource according to the EIA report) and its close proximity to pipeline networks already in place following decades of conventional oil and gas production in the region.
Companies such as Santos, Beach Energy, Drillsearch Energy, Senex Energy, Strike Energy and Icon Energy have been assessing shale potential in the Cooper Basin. Santos operates the well, boasting the first commercial production of shale gas in Australia in 2012, and other positive drilling results have been enjoyed in the basin. BG Group acquired shale interests from Drillsearch in 2011, and in February 2013 Chevron entered Australia’s shale industry by agreeing to fund exploration operations to gain a stake in petroleum titles from Beach Energy.
There has been significant interest in the Perth Basin because of its close proximity to the Perth city region, its existing pipeline infrastructure and tightening gas markets. Western Australia’s Department of Mines and Petroleum estimates a technically recoverable resource of 60 TCF in two formations, excluding additional tight gas resources.
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Source: © Commonwealth of Australia (Geoscience Australia) 2013. This product is released under the Creative Commons Attribution 3.0 Australia Licence.
Exploration in the Perth Basin has been revitalised in recent years and several fields that may potentially include shale gas have been identified. AWE, Norwest Energy and Origin Energy have been exploring the Perth Basin for shale and tight sandstone gas opportunities. In September 2010, Bharat PetroResources agreed to acquire half of Norwest Energy’s interests in two permits in the Perth Basin. AWE drilled the first well with shale gas as the target in 2010. The initial results were favourable and the formation was high-graded for further evaluation. In 2012, three shale gas wells were hydraulically fractured in the northern Perth Basin and the results identified three prospective formations.
The Beetaloo Basin is more than 3,000m thick and there is evidence that both unconventional and conventional hydrocarbons are present. However, the basin is remote, with very limited access and infrastructure in place and there has been very little exploration for conventional or shale resources. Any discoveries are likely to require a new pipeline to Darwin, which in itself has limited gas demand, and so would need to be commercialised through liquefaction and export as LNG.
Falcon Oil & Gas acquired petroleum titles covering a large area in the Beetaloo Basin in 2008, since then it has drilled 11 wells. On August 21, 2014, Falcon Oil & Gas Australia farmed out 35 per cent of its interest in the petroleum titles to each of Origin Energy and Sasol Petroleum.
Other companies such as Paltar Petroleum, Sweetpea Petroleum and Tamboran also hold petroleum titles in the Beetaloo Basin.
The Georgina Basin is a region of proven oil potential. The Southern Georgina Basin is considered to be one of the most prospective onshore basins in Australia, with potential for very large conventional and unconventional gas deposits. However, it is virtually unexplored. Since 2012, there has been a greater interest in the basin from global energy giants, which adds credibility and confidence to the basin’s potential.
PetroFrontier has been leading the activity in this remote location, targeting primarily oil-mature source beds, but also dry gas mature rocks. PetroFrontier was joined by Baraka in April 2010 and by Statoil in June 2012.
Central Petroleum also holds petroleum titles in the Georgina Basin and in November 2012 was joined by Total SA.
Ownership of petroleum and the role of government
In Australia, all rights to petroleum and petroleum resources existing at or below the surface of any land or the seabed are vested in the Crown. The Commonwealth government (i.e. federal government) and state and territory governments grant rights to private persons to explore for or produce petroleum through a legislative licensing regime. The licences granted for petroleum exploration or production are commonly referred to as ‘petroleum titles’. Petroleum exploration and production activities may only be carried out under the authority of an appropriate petroleum title. When petroleum is produced, property in that petroleum generally passes from the Crown to the petroleum title holder at the wellhead.
The government does not directly engage in commercial petroleum exploration and production via, for example, a national oil company. However, it does provide an orderly and equitable system by which the private sector can undertake such activities. The government’s main roles in relation to the petroleum sector are the establishment of broad economic policy, provision of a regulatory framework for petroleum operations, collection and dissemination of geoscientific information with a view to reducing commercial risk in petroleum exploration, and the promotion of petroleum industry competitiveness.
Regulation of onshore petroleum activities
Australia is a federation comprising six states and two territories. Each state and the Northern Territory has its own legislative power to govern onshore petroleum exploration and production activities within its boundaries. Offshore petroleum activities (activities in coastal waters further than three nautical miles from the coastal baseline) are governed under a joint commonwealth–state legislative scheme that provides for a uniform legislative framework. State legislation regulates onshore activities and activities within coastal waters extending up to 3 nautical miles from the coastal baseline.
This guide focuses on the onshore regime. The onshore petroleum regimes in each state are broadly similar but not identical. Western Australia in particular has made recent regulatory changes specifically directed at the shale gas industry, as discussed below.
The onshore petroleum regimes in Australia start from a fundamental position of treating shale resources in the same manner as conventional petroleum resources. For example, the Petroleum and Geothermal Energy Resources Act 1967 of Western Australia defines ‘petroleum’ to include any naturally occurring hydrocarbon or mixture of hydrocarbons, whether in a gaseous, liquid or solid state. It specifically only excludes oil shale (i.e. hydrocarbons contained in rocks that can only be recovered by mining those rocks as oil shale), and does not exclude oil or gas recovered from shale or other source rock.
Other relevant laws
In addition to the petroleum-specific legislation, there is other legislation that applies to petroleum exploration and production activities. This includes environment and heritage protection legislation (at state, territory and commonwealth level), legislation governing the allocation of onshore water rights, native title and Aboriginal heritage protection legislation, legislation governing industrial relations and workplace health and safety, planning legislation and general land tenure legislation.
Direct agreements may also be entered into between a state government and the proponents of major petroleum projects (known as State Agreements). Such agreements supplement, and in some cases modify, existing state legislation in order to facilitate a large-scale project. The State Agreements are passed as an Act of state government and given legislative force.
State Agreements generally specify the rights, obligations, terms and conditions for the development of a major resource project and can be for a period of up to 50 years. State Agreements provide projects with long-term certainty and establish a framework for ongoing relations and cooperation between the state and the project proponents.
In late June 2013, the Natural Gas (Canning Basin Joint Venture) Agreement Act 2013 (WA) was passed by the Western Australia parliament. The Act ratifies an agreement between the State of Western Australia, Buru Energy, Mitsubishi and the Mitsubishi subsidiaries, Diamond Resources (Fitzroy) and Diamond Resources (Canning). The agreement seeks to facilitate the development of domestic gas supply and LNG projects (together with associated onshore pipelines), underpinned by shale gas from the Canning Basin.
The agreement provides for a structured process for the grant of the necessary petroleum titles to support the proposed project development. While each phase of the development is subject to approval by the relevant minister, the agreement indicates an overall commitment by the Western Australia government to support the development. In return, the proponents agree (among other things) to supply a minimum amount of gas to the domestic market, support local industry and provide other social and community benefits. The agreement is for an initial term of 25 years with an option to extend for a further 25 years. The proponents must notify the Minister for State Development between December 31, 2015 and March 31, 2016 if they do not intend to proceed with the domestic gas project.
Changes to regulatory regime
There have been recent changes to the regulatory regime, particularly in relation to disclosure of the hydraulic fracturing process. Given that the shale gas industry in Australia is in its infancy, over time we are likely to see more changes to the environment regulations applicable to shale gas.
National Harmonised Regulatory Framework
The Standing Council on Energy and Resources, comprising Australia’s energy and resources ministers, has endorsed and implemented a harmonised framework for the regulation of coal seam gas. The National Harmonised Regulatory Framework provides a suite of leading-practice principles to be used as a guidance and reference tool for Australian federal, state and territory government regulators for the coal seam gas industry.
The framework focuses on four key areas of operations, covering the life cycle of the development of natural gas from coal seams: well integrity, water management and monitoring, hydraulic fracturing and chemical use. The framework acknowledges that, although shale gas and coal seam gas have some common exploration and development procedures, the geological and hydrological issues that apply to different forms of unconventional gas are also significant.
There is no expectation that the harmonised regulatory framework developed for coal seam gas will be extended to apply to shale gas. However, it would be reasonable to expect that a similar harmonisation process may subsequently be implemented for the shale gas industry, and that some of the recommendations in the coal seam gas framework could inform that process.
Potential state reform
At present, the potential of onshore conventional gas in Victoria is unknown. In response to community concerns, a moratorium has been in place in Victoria since August 2012 on approvals of new coal seam gas exploration licences and hydraulic fracturing approvals for all existing mineral and petroleum titles. The moratorium on hydraulic fracturing will remain in place until at least July 2015 while a community consultation process and a series of scientific studies on the environmental impact of the industry are conducted. It is anticipated that a report on the consultation process will be made publicly available in July 2015.
The Victoria government is also currently reviewing its regulatory arrangements against the leading principles in the National Harmonised Regulatory Framework. It has noted that the current framework does not fully meet the 18 leadingpractice principles and is in the process of considering what actions must be taken before the moratorium can be lifted.
With the increased investment by companies in developing and exploring shale gas potential, there has been an increase in community concern about the environmental impact. The Western Australia government commissioned an independent review of regulations dealing with petroleum and geothermal exploration with a focus on the impact of developments in the shale, coal seam and tight gas activities.4 The report made 15 recommendations for changes to the regulatory framework. The Western Australia government is in the process of reviewing and improving its regulatory framework for onshore gas projects to ensure they are carried out in accordance with best industry practice, and to provide a more robust, enforceable and transparent regulatory framework.
To date there has been no hydraulic fracturing activity in Tasmania. In March 2014, the Tasmanian government introduced a 12-month moratorium on hydraulic fracturing to enable a review of the potential impacts of hydraulic fracturing in Tasmania. The Department of Primary Industries, Parks, Water and Environment of Tasmania provided its final report to the Minister for Primary industry and Water in February 2015. As a result, the Tasmanian government has extended the moratorium on the use of hydraulic fracturing activity for the purposes of hydrocarbon resource extraction in Tasmania to March 2020. A further review on the practice of hydraulic fracturing will be conducted before the moratorium expires.
In Australia, there is a general principle of multiple land use, which means that different parties may have coexisting rights or interests with respect to the same area of land. The types of land interests that may coexist with onshore petroleum titles include private land, leases from the government for pastoral, agricultural or other commercial purposes, mining (i.e. hard rock mineral) tenements, as well as native title rights and interests.
Where a petroleum title coexists with private land, operations cannot begin on the private land unless an agreement has been reached with the private land owner as to compensation or the compensation has been otherwise determined by a court. For other types of land interest, the petroleum title holder is generally not prevented from proceeding with operations, but is required to pay compensation to other lawful occupiers of the land who are adversely affected by the petroleum operations. Where there is conflict between onshore petroleum titles and mining tenements, the Minister for Mines and Petroleum makes a decision as to the priority of operations.
Australian law recognises native title rights of Aboriginal people to land and waters that arise from traditional laws and customs. Registered native title claimants and holders have procedural rights in respect of the grant of new petroleum titles within their native title claim areas.
The main native title process that applies is the ‘right to negotiate’ procedure. This requires the native title parties to be notified of an application for a new petroleum title, be given the opportunity to make submissions with respect to the grant of the title, and negotiate in good faith the conditions on which the title may be granted. This process usually results in the parties also negotiating an appropriate compensation package for the native title party. If agreement cannot be reached, the matter can be determined by a regulatory tribunal.
Sites or objects of cultural significance to Aboriginal people are also protected and maintained under legislation. Consent is usually required before Aboriginal heritage sites or objects can be disturbed. Compliance with heritage protection protocols is usually a requirement of most negotiated native title agreements.
Types of petroleum and related titles
The petroleum titles required in order to explore for and produce petroleum, including for shale oil and gas, are broadly similar for each Australian jurisdiction, although there are some important differences.
Different petroleum titles are required for each stage in the development of a petroleum project. Generally, titles fall into four main categories: exploration titles, retention titles, production titles and infrastructure titles. The terminology varies between Australian jurisdictions, but the most common terms are exploration permit, retention lease, production licence, pipeline licence and infrastructure licence.
An exploration title gives the holder the exclusive right to explore for petroleum within the title area. Exploration titles are usually granted for a term of between five and seven years. In most cases they can be renewed, but there is often a requirement to relinquish portions of the title on renewal. Exploration titles usually have minimum work conditions attached to them. Typically, these require a combination of technical, geological and marketing studies, seismic acquisition and the drilling of at least one exploration or appraisal well during the term of the title (and each renewal).
For onshore areas, the release and award system for petroleum exploration acreage differs between jurisdictions. There is either an invitation and competitive tender process, an open application system or a combination of both. Broadly speaking, for areas where there is significant commercial interest, a competitive tender process is likely to apply.
In some jurisdictions, a retention title can be obtained over areas where petroleum discoveries are not currently commercially viable but are likely to become commercially viable in the future. In Western Australia, for example, the title holder must demonstrate that the discovery is likely to become commercially viable within the next 15 years. The initial term of a retention title is generally five years and may be renewed. When the petroleum discovery is deemed to be commercially viable, the retention title must be converted into a production title.
The holder of an exploration title containing a declared discovery is entitled ‘as of right’ to a production licence over the area containing the discovery. A production title gives the holder an exclusive right to carry out operations (e.g. drilling of developmental wells) for the recovery of petroleum within the relevant licence area.
In Western Australia (for production titles granted after May 25, 2011), South Australia and Victoria, onshore production titles are granted on a ‘life of field’ basis. In the remaining jurisdictions (and for Western Australia production titles granted prior to May 25, 2011) the term of a production title can vary from 20 to 30 years, and can be renewed at the discretion of the regulator.
Pipeline and infrastructure licences
The holder of a pipeline licence has the authority to construct and operate a petroleum pipeline and ancillary storage tanks and facilities. The key difference between onshore pipeline licences and exploration and production titles is that a pipeline licence is usually only a licence to operate the pipeline infrastructure, and appropriate land tenure – for example, an easement over the pipeline corridor land (although separate access rights may need to be obtained). Infrastructure licences are used for the construction and operation of facilities and services outside a production title area.
Other petroleum authorities
There are also other types of petroleum authorities, such as access authorities and special prospecting authorities. Broadly speaking, these authorities allow for the carrying out of certain approved petroleum activities (e.g. seismic surveys) but not the drilling of wells.
Access authorities generally only allow exploration survey work to be conducted in areas adjacent to an existing petroleum title.
Special prospecting authorities are designed to encourage exploration in areas where little or no exploration has been undertaken. In Western Australia, a special prospecting authority permits a person to undertake exploration work (other than drilling a well) in areas that are the subject of competing applications, areas that have been identified for future acreage release or areas that are not currently under title. Special prospecting authorities may be applied for with an ‘acreage option’, which enables the holder to apply for an exploration permit within six months of the expiry of the authority. However, the option does not impose any obligation on the government to grant a title, as title is only granted on the merits of the proposed work programme and on satisfying the assessment criteria.
With increased petroleum activity in Australia and increased concern about its potential environmental impacts, there is a firm emphasis on strengthening regulation to ensure the environment is protected. There is a framework of state and commonwealth legislation applicable to petroleum activities. As onshore petroleum activity has the potential to impact significantly on the environment, the state or territory governments will probably require stringent environmental approval processes to be followed.
A number of states have introduced environmental and safety management regulations that are specifically directed at the unconventional gas industry, or primarily impact on it. For example, additional notification and reporting obligations are required for activities involving hydraulic fracturing. This includes disclosure of chemical compounds added to the water injected in fracturing operations. The Western Australia government, for example, requires ‘full public disclosure and transparency for any products, additives, chemicals and substances used in drilling, hydraulic fracturing activities and related petroleum activities’. In September 2014, the Victoria government enacted legislation prohibiting the use of BTEX chemicals (benzene, toluene, ethylbenzene and xylene) in hydraulic fracturing.
State environmental approvals
The environmental regulation of onshore petroleum activity varies between the states and territories, although there are some common features. Most petroleum exploration and production operations require environmental approval under the state or territory petroleum legislation, which is usually issued on the approval of a satisfactory environment management plan. This plan must outline the potential environmental impacts, their significance and how those impacts are to be managed. For hydraulic fracturing activities, it should address, among other things: transport of equipment; fuel, chemical and hazardous materials handling; and management of produced water and flow-back fluid.
Where onshore petroleum activities are likely to have significant environmental impact, a more comprehensive and detailed assessment is required under the relevant state or territory environmental protection legislation. There are various levels of environmental impact assessment, depending on the environmental significance and complexity of the proposed project. A public consultation process may be required for some projects.
Commonwealth environmental approvals
Actions that will have a significant impact on a matter of national environmental significance require approval under the commonwealth environment legislation (i.e. the Environment Protection and Biodiversity Conservation Act 1999 (Cth)) in addition to state or territory environmental approval. Matters of national environmental significance include listed threatened species and ecological communities, migratory species and areas of high conservation value.
Access to water will be an important consideration for the recovery of shale gas. State and territory governments regulate and manage water resources with the aim of protecting them and promoting sustainable and efficient use of water. Licences and permits are issued for water use under specific water rights legislation. Water generally cannot be taken from a watercourse or groundwater aquifer without a licence. Separate licences are required for the operation of artesian wells.
Foreign investment regulation
Investment proposals by foreign persons are regulated by the Foreign Acquisitions and Takeovers Act 1975 (Cth) and applicable policy guidelines issued by the commonwealth government. The foreign investment law and policy is administered by the Foreign Investment Review Board (FIRB) on behalf of the Treasurer. Certain proposals must be reviewed by FIRB and considered by the Treasurer before they can be implemented, and so FIRB should be notified in advance. These include an acquisition:
- of an interest in a petroleum title, irrespective of value5
- of shares in a corporation (or its parent) where more than 50 per cent of that company’s assets comprise petroleum titles
- that results in the acquirer obtaining 15 per cent or more of the shares in a ‘prescribed corporation’ (or that results in foreign persons together holding more than 40 per cent of the shares in the corporation), where the proposal values the company at more than A$252 million
- of the assets of an Australian business (which includes a petroleum project or joint venture) valued in excess of A$252 million, which results in foreign control of that business.
The monetary threshold is higher than A$252 million for acquisitions involving certain investors. For private Chilean, Japanese, South Korean, New Zealand and US investors, the monetary threshold is A$1,094 million.6 In November 2014, China and Australia completed negotiations for a China- Australia Free Trade Agreement and signed a Declaration of Intent. It is anticipated that the China-Australia Free Trade Agreement will be signed and come into effect in late 2015. This will then increase the monetary threshold for private Chinese investors from A$252 million to A$1,094 million.
The vast majority of Australian companies will be prescribed corporations. In addition, if the value of the Australian part of an international group is more than the monetary threshold or comprises more than 50 per cent of the total value of that group, the group’s ultimate parent will be a prescribed corporation.
Likelihood of acceptance of investment proposals
The only basis on which the Treasurer can object to an investment proposal by a foreign interest is if the proposal is contrary to the ‘national interest’. From a foreign investor’s perspective, this compares favourably with, for example, the ‘net benefit’ test applied under the Investment Canada Act. Foreign investors in Australia’s petroleum industry can expect that approval will not be withheld from a proposal on national interest grounds, other than in unusual circumstances affecting Australia’s vital interests and development.
Greater scrutiny will be directed towards investments by state-owned entities to ensure they act commercially. They will also be subject to additional approvals. However, stateowned investors could still largely expect that approval will only be withheld in unusual circumstances. This expectation is subject to any changes in relevant FIRB policy guidelines.
For many years, the Australian government has publicised that it welcomes foreign investment and recognises the contribution that foreign investment is able to make to the development of Australia. Access to new technology, management skills and overseas markets, as well as scope for higher economic activity and employment, are all positive attributes claimed by the Australian government to derive from foreign investment.
Taxes, duties, royalties and incentives
The Petroleum Resource Rent Tax (PRRT) levied by the federal government currently applies to all petroleum projects in Australia. The PRRT is levied at a rate of 40 per cent of a petroleum project’s taxable profits.
There are also royalties imposed by state governments that are payable on petroleum produced from onshore projects. These apply concurrently with the PRRT. The royalty payable is based on the value at the wellhead of petroleum recovered and is levied at a rate of between 10 per cent and 12.5 per cent of the gross wellhead value, less costs incurred. Deductible costs are normally confined to the processing, storage and transport of the petroleum recovered by the producer to the point of sale.
For example, in Western Australia, there are three types of cost that can be deducted against the gross value: the post-wellhead operating costs, depreciation on commissioned post-wellhead assets, and costs of borrowing on commissioned post-wellhead assets. There are deduction limits, which can vary depending on the predominant nature of the project. The royalty payments will be creditable against current and future PRRT liabilities of a petroleum project.
Company tax and several other taxes and fees (including on registration of transactions relating to interests in petroleum titles and carbon tax) will also apply. Specific concessions apply for petroleum production in Australian income tax law. Specific provisions also allow certain expenditures to be deducted or written off. For example, income tax deductions apply to certain exploration and operating costs, such as prospecting right costs, provision of housing and services facilities for employees at, or adjacent to, the production site, royalty payments and depreciation of plant and equipment.
The rates of applicable tax, the nature of costs that are eligible for deduction and the timing of their deductibility are regularly reviewed and are subject to change.
A foreign company will be required either to register in Australia as a registered foreign body or set up an Australian subsidiary company before it can carry on business in Australia (which would include acquiring an interest in a petroleum title or a company holding such an interest). An Australian subsidiary will usually need to have at least one Australian resident director.
The choice of structure will largely be driven by tax considerations such as the deductibility of the Australian branch’s expenses from the foreign company’s income or, conversely, the deductibility of interest on loans used to capitalise the Australian subsidiary. Other factors that may influence the choice of structure include providing additional limited liability with respect to the foreign company’s operations in Australia, providing a vehicle by which the operations could be sold at a future time and, potentially, giving greater commerciality to the operations by the registration of an Australian subsidiary.
Enforcement regime in judicial and arbitral alternatives
The enforcement of foreign judgments in Australia is governed by both statutory regimes – the Foreign Judgments Act 1991 (Cth) and Foreign Judgments Regulations 1992 (Cth) – and principles of common law and equity. The statutory regime is restricted to specified countries and courts, and requires certain conditions to be met.
Australia is not party to the Hague Convention on Recognition and Enforcement of Foreign Judgments in Civil and Commercial Matters 1971. The principles of common law (for recognition of money judgments) and of equity need to be relied upon where there is no international or statutory agreement under which the foreign judgment can be enforced.
Foreign arbitral awards
Foreign arbitral awards are enforced in Australia under the International Arbitration Act 1974 (Cth). This implements Australia’s obligations under the United Nations Convention on the Recognition and Enforcement of Foreign Arbitral Awards 1958 (known as the New York Convention) and gives force to the United Nations Commission on International Trade Law (UNCITRAL) Model Law. Arbitral awards from countries that are signatories to the New York Convention will be binding in Australia as if the award had been made in Australia.
Section 8(2) of the International Arbitration Act 1974 (Cth) provides that a foreign award ‘may be enforced in a court of a State or Territory or in the Federal Court of Australia as if the award were a judgment or an order of that court’. The effect of this section is to equate a foreign award with a domestic award for the purposes of enforcement.
In Australia, Sydney has been promoted as a regional centre for arbitration on the foundation of its stable, supportive and trusted legal system and competitive costs. For cross-border contracts, many arbitration agreements select Singapore as the arbitral venue.
There is little doubt that Australia has substantial shale gas resources, although just how much gas is in place, and how much of that will be recoverable, remains to be seen. There is certainly enough prospectivity to have experienced shale gas players such as Chevron and ConocoPhillips commit to large investments. Others, such as BHP Billiton and Shell, express more than a passing interest.
However, a number of challenges will need to be overcome before large-scale commercial development is possible. Unless production wells are close to existing and underutilised pipeline infrastructure and domestic gas markets, as is the case with the Cooper Basin, substantial capital commitments will be required to develop the pipeline, processing and other infrastructure needed to commercialise recoverable reserves.
The cost of developing projects in Australia is extremely high by global standards, not least because the recent and ongoing parallel development of several world-class LNG projects in the country has driven up the cost of most inputs. Shale gas developments in the remote regions may struggle to be commercially viable on the back of domestic gas prices, and would need to secure LNG export markets in order to reach a favourable final investment decision. The Canning Basin in Western Australia and the various basins in the Northern Territory are attracting significant exploration interest, notwithstanding their remote location and absence of nearby gas demand centres. Success in those locations could lead to the expansion or back-filling of existing liquefaction facilities in the north of Australia.
Mirroring the US
Australia’s shale gas industry has been described by some as being a decade or so behind that of the US. In 2006, shale gas production in the US reached a sufficient volume to separate Henry Hub prices from West Texas Intermediate (WTI) spot crude oil prices. It was only in late 2008 that increased production caused US gas prices to trend away from crude oil linked gas prices in Asia. The mega-shale transactions in the US came in earnest in 2009 when ExxonMobil acquired XTO Energy for US$40 billion. Global gas markets have changed since then, and Australian domestic conditions are very different from those in the US.
However, if Australia’s geological and industry conditions resemble those of the US, as the EIA report states, and if Australia follows the trend of the US shale industry even to a reduced degree, there are great opportunities for those who enter the Australian shale industry while it is still in its relative infancy.