The carbon pricing mechanism (the Mechanism) will have particular implications for the oil and gas industry, and in particular the export-orientated liquefied natural gas (LNG) industry. This paper focuses on the implications for oil and gas, including in particular:

  • The application of the Mechanism to the oil and gas industry.
  • The assistance available under the Mechanism.
  • The impact of the Mechanism on the LNG industry.
  • The general effect of the Mechanism on Australia's oil and gas industry.

How will the Mechanism apply to the oil and gas industry?

Who will it apply to?

The Mechanism is structured to only apply directly to the largest emitters of greenhouse gases, although others will be affected through indirect means. Facilities that directly emit greenhouse gas emissions of at least 25,000 tonnes of CO2-e per year will be covered. The assessment is made by reference to emissions by a 'facility' and not by an individual corporate entity, although the Mechanism will then identify a liable entity in respect of a covered facility (see below).

All scope 1 (direct) emissions, together with legacy waste emissions, will count towards this 25,000 tonne threshold, other than scope 1 emissions from fuels or other sources that are excluded from the emissions from some synthetic greenhouse gases as these will be subject to a separate mechanism using existing levies under the Ozone Protection and synthetic Greenhouse Gas Management for the purposes of the Mechanism. Scope 2 emissions are the release of greenhouse gases emitted from energy that is consumed at a facility but which is generated elsewhere. Scope 2 emissions for a facility will already be captured under the Mechanism as scope 1 emissions at the relevant generating facility.

According to the Government's figures, only around 500 businesses will be required to pay for their carbon emissions. A significant proportion of these operate in the oil and gas industry.

How will the Mechanism apply?

In the oil and gas industry, there are three main applications:

  • Direct application to large emitters: Any significant oil and gas facility is likely to pass within the direct operation of the Mechanism. For example, BP reports that its refinery at Kwinana emits between 600,000 to 800,000 tonnes of CO2-e per year1. The amount of emissions that an LNG production facility will emit depends on variables such as the size of the facility, the specification of the feed gas, the degree of flaring, venting and fugitive emissions, and the carbon efficiency of the refrigerant system used. However, in order for an LNG project to be commercial, it will invariably be of a magnitude which will cause it to emit more than the 25,000 tonnes threshold, and will typically emit in excess of a million CO2-e per year. For example, in the Environmental Impact Statement for the GLNG project, scope 1 emissions for the 3 million tonne per annum (mtpa) liquefaction facility (excluding emissions from upstream operations) are estimated to be 1,162,722 C)2-e per year, and for a 10mtpa facility the scope 1 emissions approach 3.5 million tonnes per year.2
  • Application of complementary measures: The oil and gas industry will also be affected by the amendments to the taxation position in relation to transportation fuels. The development and operation of petroleum projects, especially LNG projects, requires significant use of transportation and other non-transport consumption of fuels. This fuel consumption will fall outside of the direct permit obligations. However, a carbon price will effectively be imposed on business use of liquid fuels by reducing the business fuel tax credits from their current levels. Similarly for aviation fuels which do not currently attract a fuel tax credit, the fuel excise for domestic aviation will be increased. The cost of other inputs may also rise due to the Mechanism.
  • Application to retail gas: In addition to major emitters of carbon, suppliers of natural gas to domestic customers will also be directly liable in respect of emissions release from the use of the fuels by those customers. Where the customer is a large carbon emitter, then it is possible to transfer responsibility for emissions derived from the use of that gas to the customer where the customer quotes an obligation transfer number (OTN). For smaller companies, this is not possible and the retailer retains responsibility. Where natural gas is not supplied by a retailer, the relevant emissions will count towards the liability of covered facilities. Where the gas is not used at a facility covered by the Mechanism, the owner of the gas will be the liable entity. The OTN for large customers will be a voluntary mechanism, except that as a transitional arrangement a retailer must accept an OTN where
    1. gas is supplied under a contract entered into before the Royal Assent to the legislation, and
    2. the gas is to be used as a feedstock or where more than 25,000 tonnes of CO2-e per year are attributable to gas supplied under the contract.

Oil and gas facilities whose relevant emissions reach the 25,000 tonnes threshold and so will be covered by the Mechanism will need to report their emissions, in a manner similar to existing obligations under the National Energy and Greenhouse Reporting Act 2007 (Cth) (NGER Act) (please refer to our briefing on the NGER Act). Subject to any assistance afforded under the Mechanism, the liable entity or entities for those facilities will then need to buy and surrender to the Government on e carbon permit for every tonne of carbon pollution produced.

A description of the post 1 July 2012 market for, and pricing of, carbon permits is outlined in our overview of the Mechanism published on 10 July 2011.

Assistance provided under the Mechanism

Assistance available to all qualifying industries

The Mechanism includes a temporary assistance package for certain industries that will be heavily affected, based on an assessment of emissions intensity and trade exposure (EITE). The duration of this assistance is discussed below. The approach is consistent with the process, criteria and requirements currently used for Partial Exemption Certificate assistance under the Renewable Energy Target program.

Two tiers of initial rates of assistance have been established by reference to emissions intensity:

  • For activities which have an emissions intensity of at least 2,000t CO2-e/$m revenue, or at least 6,000t CO2-e/$m value added, companies will receive a free allocation of permits equivalent to 94.5 per cent of the industry average baseline.
  • For activities with an emissions intensity between 1,000t CO2-e/$m and 1,999t CO2-e/$m revenue or between 3,000t v and 5,999t CO2-e/$m value added, companies will receive a free allocation of permits equivalent to 66 per cent of the industry average baseline.

The industry average baseline for emissions intensity will be calculated using average industry emissions during the two financial years 2006-2007 and 2007-2008, divided by the industry average revenue or value added data taken from the financial year 2004-2005 through to the first half of 2008-2009.

Through the application of a 'carbon productivity contribution', these initial r4ates of assistance will reduce at a rate of 1.3 per cent per year. This structure should encourage better carbon efficiency, by financially incentivising assisted facilities to ensure their covered emissions do not exceed 94.5 per cent or 66 per cent (as applicable) of the industry baseline average, and to reduce emissions on an ongoing basis by no less than 1.3 per cent per year.

Before qualifying for the EITE assistance however, in addition to the emissions intensity criteria, the relevant 'activity' must also satisfy the trade exposure assessment. Trade exposure looks at all entities conducting the relevant activity during the reference years of 2004-2005, 2005-2006, 2006-2007 and 2007-2008, and requires that in any one of those years, the value of the international trade for that activity was at least 10 per cent of the value of the domestic production for that activity. There must also be a demonstrable inability to pass through the additional Mechanism costs due to the potential for international competition.

For LNG projects specifically

The Plan states that LNG facilities will receive a Supplementary allocation' of permits to ensure an Effective assistance' rate of 50 per cent in relation to their LNG production each year. However the Plan does not provide any detail on how this assistance will operate in practice, or interact with EITE rates of assistance described above.

It is also unclear from the Plan whether this 'effective assistance' rate of 50 per cent will be eroded by 1.3 per cent per year through the application of the carbon productivity contribution. The language of the Plan is consistent with the carbon productivity contribution only applying to the two tiers of 'initial rates of assistance' for EITE outlined above, however the placement of the paragraphs could be read to suggest that the carbon productivity contribution will also apply to erode the LNG supplementary allocation.

Some guidance might be taken from the earlier proposed Carbon Pollution Reduction Scheme (CPRS), which adopted language consistent with the language used in the Plan. In November 2009, the Australian Government amended its proposed CPRS to include an 'additional supplementary allocation' of permits under the EITE assistance for LNG projects. The supplementary allocation was intended to ensure all LNG projects received an 'effective assistance' of at least 50 per cent in the LNG projects were eligible for that assistance, and would have been an ongoing measure and not a fixed-term transitional assistance program. The supplementary assistance to LNG under the CPRS did not appear to be subject to an ongoing erosion Mechanism such as the carbon productivity contribution.

Relying on the CPRS design features to interpret the Plan and add 'flesh' to the Mechanism should be done cautiously. The CPRS went through a number of changes during legislative action before lapsing in September 2010. While the Mechanism incorporates a lot of the features of the CPRS, there are notable significant deviations, and the current Government is not bound in any way by the details of the previously proposed scheme.

The final language of the implementing legislation will therefore be important. In particular, the definition of 'LNG project' and the specific 'activity' that will attract the supplementary assistance, will determine how far upstream the supplementary allocation of permits will stretch. If the definition refers to only to the liquefaction processing facilities, then the upstream exploration, development and production operations will effectively operate under a different carbon pricing scheme compared to the liquefaction activities. The legislation should take into account that some LNG projects will also be producing gas for domestic use and LPG, and the definition of the activity will need to cater for this in an equitable manner. This may impact how developers wish to structure their holdings.

Whatever assistance is ultimately provided to existing LNG producers will also be provided to new LNG projects. This equitable treatment is designed to ensure the Mechanism does not operate to discourage expansion of the industry. A the same time, allocations to existing LNG projects will not be affected or adjusted by reason of allocations to new LNG projects.

Duration of the assistance

It is important to note that the assistance is not permanently enshrined. The Productivity Commission will review the impact of the Mechanism on the competitiveness of EITE industries in 2014-2015, and from then on at regular intervals consistent with the timing of general scheme reviews. A review may be conducted earlier at the request of the Government. Following such a review the Productivity Commission may suggest changes to the rate of assistance received by, or the carbon productivity contribution applied to, a particular activity. Companies may also request a review of their sector under guidelines that are yet to be formulated.

The Productivity Commission is specifically tasked with considering whether the LNG supplementary allocation policy remains appropriate.

Any changes in assistance "that will have a negative effect on business" will not occur before the sixth year of the Mechanism, with three years' notice to be provided of modifications of EITE allocations that will have a negative effect on business. For potential new LNG projects, the value of this assistance may need to be discounted when making a final investment decision to proceed, as it is theoretically possible that the EITE assistance and supplemental permit assistance could be reduced or removed altogether even before commercial operations at the LNG project have commenced or ramped-up to full production.

Possible Impact on LNG projects

The North West Shelf and Darwin LNG projects have been fully operational for many years. Several other projects have taken their final investment decision and are in varying stages of development, including the Pluto, Gorgon, GLNG, Queensland Curtis and Prelude LNG projects. It may be that these projects will all fall within the application of the Mechanism, notwithstanding their investment decisions were made in advance of the Mechanism being contemplated, formulated or legislated.

The additional Mechanism costs will also need to be factored in to the economic modelling and decision-making process by sponsors of new LN G projects, before they commit to development costs. Projects under consideration include the Arrow, Australia Pacific, Bonaparte, Browse, Cash Maple, Ichthys, Sunrise and Wheatsone LNG projects. It is yet to be seen whether the Mechanism will have any real impact on the appetite for future investment in these and other new LNG projects.

On one hand, the uncertainty surrounding the carbon rice beyond the Fixed Price period – even while the price collar is applied in the early years of the flexible Price period – combined with the additional uncertainty around the Productivity Commission review and adjustment process, may be cause for concern, for both LNG project developers and their financiers. However, the Mechanism does provide a method for achieving some certainty in carbon pricing, by effectively providing two forward costs curves for the price of carbon:

  • On 1 July 2015 the Mechanism will move from the fixed carbon price period into the flexible cap and trade emissions trading scheme. The 2014 budget will identify the pollution caps for the first five years of the scheme, with implementing regulations to be tabled by 31 May 2014. Regulations will be introduced on an annual basis to extend the caps by one further year, which will ensure a constant five year price horizon which can be used to draw a short-term cost curve for the carbon price.
  • The legislation will also provide for a default pollution cap in the event that Parliament rejects the proposed caps in any of the regulations. In respect of the 2014 regulations, the default position will be a cap that will ensure a five per cent reduction in emissions below 2000 levels by 2020, and thereafter a reduction consistent with the annual reduction in emissions implied by the five per cent emissions reduction target.

The default position cost curve will be the marginal abatement cost of reducing emissions to five per cent below 2000 levels by 2020, and projected in a linear fashion beyond 2020. This provides a legislated bottom line for the setting of caps, providing business and industry with a yardstick by which to assume the levels of scarcity of carbon permits in supply, allowing them to extrapolate a carbon price beyond 2020 and in line with the time-scales of investment in major infrastructure. In practice, however, regulations passed by Parliament may move the actual permit scarcity away from this legislated default position.

Given the high up front capital costs of developing LNG projects, and the long payback periods, the five year price horizon on carbon might not provide as much certainty as potential investors want or need. This is particularly the case if there is scope for the reduction in caps to be accelerated (and therefore the carbon price increased due to scarcity) ahead of the legislated default position.

Overall, the Mechanism should operate to encourage LNG producers to reduce their emissions and thereby reduce their compliance costs. Some high emitting activities however are largely outside of their control. This includes the gas compression/refrigeration process – which is probably the highest emitting aspect of an LNG project – where there are only a small number of suppliers and the processes are heavily patented and licensed.

What this means for you

The Mechanism has the potential to significantly affect the LNG and oil industries over the coming years. Although only 500 businesses are expected to be directly liable under the scheme, the imposition of a carbon price may significantly increase the costs of energy intensive industries such as the LNG and oil industry. In order to mitigate the impact of the Mechanism, businesses operating in these industries have a range of options available to them.

Liable entities

Under the Mechanism, the liable entity for direct emissions is generally the person exercising control over operations of the emitting facility. Where the facility is operated by an unincorporated joint venture, then all of the venture parties will be liable entities in proportion to their respective interests in the facility.

Entities that are directly liable under the Mechanism will need to develop policies and procedures setting out how they intend to manage that liability including determining:

  • which entity within the corporate group has operational control of the project or facility
  • whether it is entitled to and appropriate to transfer that liability. Currently, the Mechanism allows for the operator to apply for a liability transfer certificate to transfer liability to another member of its corporate group, a person outside of its corporate group that has financial control over the facility or in respect of an operator of an unincorporated joint venture, to the joint venture participants in proportion to their interest in the facility
  • how to manage and mitigate that liability (for example, through the purchase of carbon permits or domestic or international offsets in the most cost effective way including, after the Fixed Priced Period, by forward purchasing permits in order to provide price certainty, by accessing international carbon markets, and by trading permits)
  • whether the costs associated with that liability can be passed through under the various contractual arrangements entered into with third parties and
  • whether any of the financial assistance measures detailed by the Government are available.

The directors and officers of such companies should also ensure that the company has in place strategies to manage that liability including by investing in lower emission or renewable energy intensive technologies. One means of achieving this would be to establish a committee which is responsible for, amongst other things, developing a carbon strategy addressing the issues identified above.

Pass through of costs

Liable entities and entities that buy or sell energy intensive goods or services should review the 'change in law', 'change in tax', or other like clauses in their existing contracts to determine:

  • whether they are able to pass through the additional costs that are imposed through the Mechanism, and
  • whether they are ideally suited to pass through such costs.

This requires a careful consideration of the language used. In this context it is worth noting that the Mechanism is not strictly a tax, but rather an emissions trading scheme that, during the initial fixed price period, in practice operates in the manner of a tax. A generic contractual pass through of 'taxes' may not capture costs imposed under the Mechanism.

If existing contractual arrangements do not adequately provide for the pass through of such costs, counterparties should consider negotiating amendments to their existing contracts by inserting pass through clauses that address (amongst others) the issues raised above. Customers might not be willing to entertain such discussions, particularly where there is price uncertainty and therefore the exposure cannot be accurately ascertained, unless there are other benefits to be traded in return.

Australia has a relatively high unit cost for developing LNG projects compared to other host countries. Competitors targeting the same LNG markets that largely underpin the Australian projects include Brunei Darussalam, Indonesia, Malaysia, Oman, Papua New Guinea, Qatar and the Russian Federation. If those countries do not introduce an equivalent carbon pricing mechanism, Australian projects might only be able to pass through the additional Mechanism costs if their customers can identify other factors that justify paying a higher price for LNG from Australia, such as access to upstream interests and security of supply.

If costs are passed through, in new or revised contracts, customers may wish to ensure that the relevant clauses incentivise the supplier to minimise the costs to be passed through under the Mechanism (for example, by including provisions requiring the supplier to use all reasonable endeavours to minimise these costs in accordance with good industry practice). A customer will also wish to ensure that, where a supplier provides services to a number of other customers, the increased costs are allocated in an equitable manner.

On the other hand, suppliers will wish to ensure that the relevant clauses:

  • provide for the ongoing, periodic assessment and pass through of both direct and indirect costs (as distinct from traditional change in law clauses which reflect the assumption that the cost impact of the change in law can be estimated up front and then applied over the unit price of the relevant goods and services), and
  • capture costs that are imposed on, or assumed by, another entity within the supplier's group (such as the supplier's holding company).

For existing long term LNG sale and purchase agreements in particular, the parties should consider the price review and re-opener provisions. These are contractual provisions that entitle, or require, the parties to review and possibly amend the contractual pricing mechanism. Whether these provisions can be used by an LNG supplier to pass through additional Mechanism costs will depend entirely on the drafting of the relevant clause. These reviews may be structured to occur at a specific time or frequency, or on the occurrence of a trigger event which could be formulated as broadly as one party considers a substantial or material change in circumstances has occurred. Buyers and sellers of LNG may wish to review their contracts to determine whether the Mechanism may trigger such a price review.

Continuous disclosure under the ASX Listing Rules

Finally, listed entities should consider the extent to which, amongst other things, the Mechanism will affect its existing or planned operations, and whether that information should be disclosed to the market inn compliance with ASX listing Rule 3.1.

Related updates

Carbon pricing mechanism snap shot: key features, certainty and flexibility

A framework for pricing carbon in Australia

Carbon Farming Initiative legislation tabled

If you would like further information about the impact of the Government's clean Energy Future package on the power and renewable energy industries. Please contact a member of the energy team.

  1. BP Refinery Kwinana, Environmental Update, accessed on 15 July 2011
  2. GLNG Project – Environmental Impact Statement, Table 6.9.3 on page 6.9.10, accessed on 21 July 2011

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.