1. Carbon Pricing
The Carbon Price Mechanism
On 1 July 2012, the government implemented the Carbon Price Mechanism to incentivise business to cut carbon pollution and invest in clean technologies such as wind, solar, tidal and geothermal energy, with the intention of achieving the emission reductions set out in the Clean Energy Future Plan.
In February 2013, the Department of Climate Change and Renewable Energy advised a Senate Committee meeting that there has been a 9% drop in emissions from electricity generators during the first six months of carbon pricing. While industry analysts agree that the carbon price is playing a role in this reduction, they note that other factors (such as changing fuel costs, falling power demand and flooding at the Yallourn brown-coal plant) have also contributed to the figure and should not be disregarded.
From 1 July 2012, a fixed carbon price of $23 a tonne was implemented with an annual increase of 2.5% until 2015 (i.e. up to $25.40). From 1 July 2015 the carbon price will move to a flexible price period, set by the market, under a global trading scheme. In May 2013, the Government said international markets had severely impacted the carbon price and lowered expectations for carbon pricing revenue for financial year 2015/16 when the scheme is linked internationally. European carbon permits are currently trading at approximately $6 per tonne. Recent media speculation suggest that this date may be moved forward by Kevin Rudd.
The industry response to the carbon price has been widely reported in the media, with major operators being openly critical of the tax. Although some electricity generators have praised the scheme, those with significant brown-coal assets (such as TRUenergy and International Power) have been critical of the impact that the carbon price will have on life expectancies of their facilities. The closure of South Australia’s Playford B brown-coal plant and 86% generation drop at Victoria’s Morwell plant indicate that this is a real threat which should be actively managed by brown-coal generators.
The carbon scheme is a key issue for the upcoming Federal election. Should the Coalition win the 2013 Federal election it says it will repeal the carbon scheme and introduce its Direct Action policy. Under the Direction Action policy, the Coalition plans to pay emitters for polluting less rather than charging them for the emissions that they release.
Though the Coalition have maintained that they will implement the change in policy immediately, such a move would be difficult. Given the current Senate composition and the indicative Parliamentary sitting schedule, it is possible that any such replacement could take up to 2 or 3 years in practice. By this time, the global trading scheme will have begun and the appetite for significant change may well have passed.
2. Coal Seam Gas
The past 12 months have seen increased scrutiny of unconventional exploration and production activities in Australia. In response to community concerns, particularly those of environmental groups and land owners, Governments have responded with legislative changes or the introduction of best-practice framework.
CSG is regulated at State and Territory level as well as by the Federal Government under the Environment Protection and Biodiversity Act1999 (Cth) (EPBC Act).
Recently, legislative changes include changes to the EPBC Act to include ‘water resources’ as a new matter of national environmental significance for large coal mining and coal seam gas. The amendments require CSG and ‘large coal mining’ developments which are likely to have a significant impact on a ‘water resource’ to be referred to the Minister for a determination as to whether they are a controlled action.
APPEA have been critical of the decision, saying the changes are ‘anti-business’, and guided by political and not environmental objectives.
The NSW Government is introducing ‘coal seam gas exclusion zones’ which will prohibit CSG development within and under 2km of residential zones or future residential growth areas, and within critical industry clusters. A forthcoming amendment to the State Environmental Planning Policy known as the Mining SEPP will finalise the implementation process.
In December 2012, South Australia released its Roadmap for Unconventional Gas Projects in South Australia, promoting a cautious optimism in the opportunities for tight and shale gas development.
In WA and Queensland, the Government is currently regulating unconventional exploration activities in accordance with its current legislation for oil and gas, ensuring high standards are enforced.
Standing Council on Energy and Resources Framework
On 31 May 2013, the Council of Australian Governments’ Standing Council on Energy and Resources endorsed a ‘National Harmonised Regulatory Framework for Natural Gas from Coal Seams’ (Framework). The non-legally binding Framework provides overarching best-practice guidance to Australian regulators in implementing coal seam gas (CSG) regulatory regimes across each Australian jurisdiction.
The Framework acknowledges that CSG is, and will continue to be, an important component of eastern Australia’s domestic gas supply and provides guidance in developing the regulatory tools required to ensure that this development is managed sustainably.
The Framework focuses on four key areas of operations which cover the lifecycle of CSG development:
- well integrity
- water management and monitoring
- hydraulic fracturing, and
- chemical use.
A list of ‘leading practices’ is identified in the Framework to mitigate the potential impacts associated with the development of CSG and build a robust national regulatory regime for the industry.
Each jurisdiction will report back to the Standing Council on Energy and Resources on its progress in implementing the Framework and on areas where State or Territory legislation remains inconsistent with it. The Framework is intended to be updated on a continuing basis in order to maintain currency with leading practice across Australia.
3. LNG Development Cost Pressure
In the past year, up to $150 billion dollars of Australian energy and mining projects have been shelved due to various economic factors including the high Australian dollar, rising labour costs and increased regulation. The economic viability of Australian gas projects is also being scrutinised in light of development of the US gas export market and new gas projects in East Africa.
Recent developments at the Gladstone LNG precinct as well as statements from major producers such as Santos and Shell indicate that, in addressing these concerns, cooperative arrangements are becoming increasingly front of mind for LNG producers. This is significant, as without a focus on new models of capital discipline and cost control, proponents may miss out on selling in to a predicted 160 million tonne annual global shortfall in LNG supply.
A McKinsey & Company report released in May of this year claims that, in addition to input from Government, critical cooperation is needed from project owners and the LNG industry to address cost increases and inefficiencies. Similar statements have been made by Santos CEO, David Knox, and vice president, Rod Duke, who have each called for a concerted and collaborative approach to improving efficiency and reducing costs.
Signs of greater collaboration and cooperation within the LNG industry are beginning to emerge such as between the three Curtis Island LNG facility operators who are currently negotiating bilateral gas swap agreements to improve overall facility efficiency and reduce export and production down-time, and some facility sharing. We expect this trend to accelerate over the next year as part of the industry wide trend to reduce costs through efficient plant operations.
4. Shale Gas
Following on from a steady deal flow in 2011-2012 and successful exploration and appraisal programs over the last twelve months, recent activity in the Cooper and Canning Basins has highlighted ongoing commercial interest in the development of Australian shale gas resources. Estimates indicate that Australia may have in excess of 1000 tcf of shale gas reserves.1
Cooper Basin, South Australia
In October 2012, Santos announced that it had commenced commercial natural gas production at a stabilised rate of 2.7 mmscf/d from its Moomba-191 shale well. Junior explorer Drillsearch (in joint venture with QGC (BG)) is due to commence a drilling campaign in the Cooper Basin targeting shale resources in late 2013.
In May 2013, Chevron entered into a farmin agreement with Beach Energy to acquire a 60% interest in PEL 218 and 36% interest in ATP 855. This two stage farmin involves an initial outlay by Chevron of $201 million followed by a further $125 million in stage 2.
The Cooper Basin and neighbouring areas appear to be the most commercially viable region for shale gas development in Australia, given ready access to infrastructure including the extensive pipeline and compression network supplying gas to SA, NSW, Qld and Victoria. Gas produced from the Cooper Basin has been earmarked as a potential source of gas for the various LNG projects in Queensland’s Gladstone region. Currently the market predicts significant increases in domestic gas prices, thereby improving the commercial viability of new projects.
Canning Basin, Western Australia
The Canning Basin is made up of several sub-basins and is estimated to hold about 229 tcf of unconventional gas resources.2 Like the Cooper basin, it has been the subject of interest from major independent oil companies.
In February 2013, PetroChina entered into a farmin agreement with ConocoPhillips to acquire a 29% interest in the Goldwyer Shale project. ConocoPhillips acquired a 75% interest in this project in July 2011 in exchange for $113.5 million of working commitments. Goldwyer Shale is stated to contain 229 tcf of recoverable gas.
In November 2012, the WA government entered a 25 year natural gas agreement with Buru Energy and Mitsubishi Corporation over their unconventional gas exploration program in the Basin. Work programs will be able to be optimised by the flexibility given by the State Agreement to credit gas appraisal work on adjacent Permits against ongoing statutory work commitments.
Unlike the Cooper Basin, given the Canning Basin’s distance from markets and the absence of any pipeline network, its low population density and limited road network, development will require significant discoveries to be identified to underpin the necessary infrastructure. During 2013-2014 the results of several significant work programs will become known and better forecasts of when and whether this Basin can deliver marketable quantities of gas can be made.
5. Developments in the Timor Sea
On 23 April 2013, Timor Leste commenced arbitration proceedings against Australia under the Timor Sea Treaty, in respect of the Treaty on Certain Maritime Arrangements in the Timor Sea (CMATS). Timor Leste alleges that CMATS is invalid because Australia engaged in espionage during negotiations in Dili in 2006. Australia has denied the allegations.
Under the arbitral rules, Timor Leste and Australia each appoint one arbitrator, with a third then appointed by agreement of the two nominees. The tribunal is required to rule on the matter within 6 months of first convening. As both countries have nominated their respective tribunal members it is possible that a binding tribunal decision could be made within 8 months, although jurisdictional and other legal issues could significantly extend this timeframe.
It is not yet completely clear why Timor Leste has opted to arbitrate rather than terminate CMATS, an option which it has had since February 2013. Timor Leste’s Resources Minister, Alfredo Pires, has suggested that the move to arbitrate is motivated by the desire to secure the long term certainty of the region. Although CMATS predominantly deals with the development of the Greater Sunrise project and associated tax sharing arrangements, it also amended the Timor Sea Treaty (which regulates operations in the Joint Petroleum Development Area (JPDA)) to make the two treaties coterminous. Termination of CMATS could therefore have significant consequences for the JPDA.
Commentators have suggested that Timor Leste is instead motivated by plans to re-negotiate CMATS (to force the Greater Sunrise gas processing plant to be built onshore in Timor Leste) or to undo the existing Greater Sunrise tax sharing arrangements, which would continue to bind Timor Leste following termination of CMATS.
Despite the environment of tenure uncertainty that has existed since February of this year, activity continues in the JPDA. In April 2013, Eni and INPEX entered into a new Production Sharing Contract (PSC) with the ANP, the administration authority for the JPDA. The area subject of this new PSC is adjacent to the producing Kitan field (also operated by Eni) and includes the drilling of 4 exploration wells.