5    Net Benefits

The purpose of this section is to provide an indication of the likely impacts arising from implementation of the options outlined in Section 4. It does this by analysing the costs and benefits of each option, and comparing the net benefit against the status quo.

5.1                         Impact analysis: status quo

Overview

If the status quo is maintained, then the Government will have no recourse to influence LNG exporter behaviour.

If this is the case, then there is nothing to suggest that the gas supply situation will improve for domestic and commercial gas consumers, particularly on the east coast. Despite the Government's announcement to introduce export controls, some companies have signalled their intent to increase LNG exports. Recent domestic short-term prices have risen above LNG netbacks (measured against spot prices) in Queensland, New South Wales, Victoria and South Australia. Further, there have been reports of industrial gas consumers receiving short, medium and long-term contract offers at higher than netback prices[7]. This indicates that the domestic market lacks confidence that there will be a sufficient gas supply in the future.

The supply shortfall identified by AEMO in the 2017 GSOO also has potential implications for system security within the National Electricity Market (NEM). Gas Powered Generation (GPG) is required in the NEM to provide operational flexibility by increasing and decreasing generation relatively quickly to meet changing demand when wind and solar generation is unavailable. The risk of short-term interruptions of electricity demand will increase when there is not enough GPG available to increase generation fast enough to meet demand.

If there is a gas supply shortfall, then there is a risk that large consumers such as manufacturers will be forced to reduce or cease production due to supply uncertainty. If the market perceives that there will be a shortfall, this could also have the effect of inflating future gas supply contract price offers. In both cases there are significant flow on effects to manufacturers, consumers and employees.

Costs

By its nature, maintaining the status quo would not result in any additional regulatory costs for the gas industry or Government. Nor would it change the current market situation where long-term take or pay export contracts, and the economics of LNG facilities are resulting in gas being exported at prices lower than those being offered to the domestic market. However, it means that domestic gas consumers would continue to bear the risk of insufficient gas to supply both domestic and export demand. These consumers include households, and gas-dependent businesses that employ thousands of Australians.

This could result in the untenable situation where domestic gas consumers have less reliable supply, and are paying more than their overseas counterparts that source their gas from Australia. In 2014, BIS Shrapnel estimated that a shortfall would cost the east coast manufacturing sector a minimum of $14 billion[8]. 

Benefits

Maintaining the status quo would provide greater certainty to the LNG export industry and other gas market participants. However, most gas market participants understand the need for the Government's concern about security of supply.

Net benefit

The cost of doing nothing outweighs the benefits. It is unacceptable to take no action.

5.2                         Impact analysis: industry led agreement to guarantee adequate supply

Overview

The Government would seek an agreement from exporters and other producers to guarantee an adequate gas supply to the domestic market. This was the objective of the meetings between the Government and industry in March and April 2017. Throughout the industry meetings, the Government made it clear that its preference was for industry to respond of its own volition, and improve supply and price outcomes without the need for Government intervention.

This approach was effective in getting gas producers and pipeline operators to guarantee that they would supply enough gas to the NEM in times of peak demand (e.g. in heatwaves)[9]^,[10]. However, east coast gas producers were unable to make a broader guarantee that the domestic gas market - not just the NEM - would be supplied with sufficient gas. As the Government continued its consultations (detailed in Section 6), industry did not provide evidence to suggest that such an agreement could be reached. Additionally, it is unclear how this option could be enforced to an extent that the domestic gas market had confidence that supply was assured.

Costs

This option would likely have no additional regulatory costs for LNG exporters. 

Once the agreement was developed, this option is likely to have ongoing business costs, depending on the terms of the agreement. As the agreement would be co-designed and enforced by industry, any additional costs would be taken voluntarily, and would form part of the exporters' social licence to operate; i.e. the costs would be an industry-accepted "cost of doing business".

A major drawback of this option is that the Government would not be in a position to intervene if exporters did not provide the domestic market with enough gas. By the time a shortfall was apparent, the negative effects would already be passed on to domestic gas consumers in the form of lower reliability and higher prices. In other words, the risk of an export-driven supply shortfall (and the associated flow-on effects) would still be borne by domestic gas consumers. This presents significant risks of industrial demand destruction.

Further, it is unlikely that LNG exporters would agree to guarantee a quantity of gas to the domestic market that is deemed sufficient by consumers and the Government. Such agreements may also take a long time to be reached. As discussed in Section 3, the Government has previously met with gas exporters and producers on the east coast, and given them the opportunity to improve supply and price outcomes of their own volition. Despite making progress, not all of the east coast LNG exporters satisfactorily outlined their plans to contribute a sufficient supply of gas to the domestic market. While the costs are unlikely to reach the levels of the status quo option, it is likely that this option would result in some users exiting the market, resulting in a loss of jobs and economic output.

Benefits

A commitment from exporters to provide the domestic market with an adequate supply of gas might decrease the likelihood, and perceived likelihood of a shortfall. If this happened, then this would ease supply and price pressures. However, unless the agreement outlined substantial consequences for failing to adequately supply the domestic market, these positive effects are unlikely to eventuate and are potentially small in magnitude.

Net benefit

If this option fails, or is perceived to be likely to fail, then it is likely to lead to reduced economic activity in Australian gas-reliant industries. Additionally, the likelihood of realising any benefit is small. The net benefit of this option is uncertain and potentially negligible. 

5.3                         Impact analysis: gas reservation

Overview

A gas reservation policy would require exporters to make a quota of gas available to the domestic market. Although a reservation policy would provide extra security to the domestic market, it would also present a number of difficulties.

Firstly, it would be difficult to target this option only at exporters, in order to meet the policy objective of preventing an export-driven shortfall. This is because it is hard to identify the point along the value chain at which the percentage should be applied, for example:

*         If the percentage is applied to the gas that an LNG exporter produces from its own fields, then it dis-incentivises the development of new gas, and encourages exporters to purchase from third parties. This would contradict the Government's intent to encourage a productive, socially responsible LNG industry.

*         If the percentage is applied to the third party producers from which an LNG exporter purchases gas, then it pushes the cost of mitigating an export-driven shortfall onto producers that aren't involved in exports, without having any impact on exporters.

*         If the percentage is applied to an LNG exporter after it purchases gas from a third party, then, using the 15 per cent example, an exporter could just purchase 115 per cent of the gas it wanted, and sell the remainder to the domestic market. This would do nothing to ease supply pressures for domestic gas consumers.

Secondly, if a blanket reservation policy was effectively targeted at exporters, it would spread the cost of preventing a shortfall across projects that did not contribute to it. This would shift accountability away from exporters that have had a negative impact on the domestic market onto exporters whose operations may have resulted in a net benefit to the domestic market.

Similarly, if the percentage was applied based on the quantity of LNG that an exporter ships overseas, or the exporter's nameplate capacity, then it would not discriminate between an exporter that produced all of its feed-gas itself, and an exporter that sourced all (or part) of its gas from third parties. This would not incentivise exporters to produce additional gas.

Thirdly, a reservation policy would increase the real cost to LNG projects in circumstances where the domestic market was already well supplied. This would reduce the potential profitability of LNG exports. However, the flip side of this is that when LNG projects are exporting large quantities of LNG, the domestic market would be supplied with a large quantity of gas. This extra supply could help drive down domestic prices.

Fourthly, it would be challenging to develop a comprehensive gas reservation framework that could be agreed by the Australian and all State and Territory Governments in Australia within a reasonable timeframe to address near term market concerns. It is likely that such framework would only be prospective rather than retrospective which would mean that it would only begin to incrementally influence market supply as new gas supply projects were developed rather than having an immediate or near term impact.

Costs

There are negligible regulatory costs associated with LNG exporters complying with gas reservation policies.

There is, however, potential for substantial business costs. As an example, consider the three east coast LNG exporters operating out of Gladstone, who have a combined nameplate capacity of 25.3 million tonnes per annum (Mtpa). Five per cent (a third of WA's 15 per cent reservation policy) of this is nearly 1.3 Mt, which is equivalent to 70 PJ, or just over a tenth of east coast domestic demand. At the March 2017 export unit value for Australian LNG ($8.30/GJ[11]), this volume would be worth over $580 million[12]. Depending on the price of gas domestically, compared with internationally, this could have significant impacts on LNG exporters' profitability, particularly if the domestic market was already adequately supplied. This is evident in Western Australia, where domestic spot prices are well below LNG spot prices[13]. Lower domestic prices could also discourage exploration and development aimed at supplying the domestic market.

The retrospective application of a gas reservation policy would introduce the risk of LNG exporters not being able fulfil contractual volumes with buyers, if gas field production could not be ramped up to meet the additional supply required under the reservation requirements. Undelivered LNG cargoes would incur penalties, however the terms of LNG sales-purchase contracts are confidential, and it is therefore not possible to quantify the cost on exporters or if force majeure clauses would apply. 

Applying a blanket gas reservation policy would also carry a high level of sovereign risk. LNG projects require billions of dollars in upfront exploration and infrastructure investment. Australian and overseas investors make their investment decisions with the knowledge that Australia has a historically stable regulatory environment. Applying a reservation policy retrospectively would reduce the profitability of all LNG projects by changing the rules under which investors made their final investment decisions. It might also impact the ability of exporters to meet their contracts[14], given their economically viable levels of production, and would inflexibly change the parameters under which the exporters can do business.

If the reservation policy was applied at all times (see Section 4.3), then it is possible that the domestic market would become oversupplied, and prices would become artificially low. This would have the effect of shifting a cost from domestic gas consumers, to producers. Several studies have argued that this results in an overall loss to the economy, because resources could be allocated more efficiently[15]^,[16]. It should be noted that the Deloitte report that argues this point compares the effects of a reservation policy, to an environment that is entirely market driven. This is not currently the case in Australia, because some state and territory government policies restrict the exploration and development of onshore gas. An alternative view is that the lower gas prices would benefit the economy in the long run, due to reduced cost for industrial gas users like manufacturers[17]^{, [18]}.

There are also potential long term costs for consumers. The ACCC's 2016 Inquiry into the east coast gas market investigated the benefits of a gas reservation policy. After considering evidence from the former Bureau of Resources and Energy Economics, and the Western Australian Economic Regulatory Authority, the ACCC recommended against reservation policies "given their likely detrimental effect on already uncertain supply". This is because, in the long run, a reservation policy has the potential to reduce export profitability, resulting in reduced levels of exploration and development, and increased pressure on supply.

Finally, under the Constitution, any regulation from the Australian Government must not discriminate based on geographical location. Therefore, a blanket reservation policy would impact exporters operating out of all Australian states and territories. Given that it is not currently physically, or economically viable to transport gas between the west and east coasts, a reservation policy would potentially impose a cost on exporters that are not in a position to increase supply to consumers experiencing a shortfall on the other side of the country.

Benefits

The benefits of a gas reservation policy centre on the guarantee of a dedicated long term supply of gas for domestic gas consumers. Internationally, several countries have gas reservation policies, including Israel, Indonesia and Egypt that reserve between 30 and 60 per cent of gas production for domestic users. Providing a long term dedicated supply, particularly for industrial gas users such as manufacturers, is important as it provides certainty on the cost and availability of a critical business input.

In the basic chemical manufacturing industry, for example, gas accounts for about 25 per cent of intermediate input costs. In other heavy manufacturing industries like glass and glass product manufacturing, ceramic product manufacturing and polymer product manufacturing, gas accounts for at least 10 per cent of the input costs. Therefore increasing gas prices could have a significant impact on the profitability of these industries. These industries are also significant employers. The polymer product manufacturing industry, for example, employs over 31 000 people throughout NSW, Victoria, Queensland and South Australia.

Western Australia is the only Australian state with a broadly applied gas reservation policy. The policy, introduced prospectively rather than retrospectively, reserves 15 per cent of gas from each LNG export project for the domestic market, with allowances for negotiations between the state and LNG companies to occur on a case-by-case basis. It should be noted that the east and west coast markets have different characteristics (e.g. infrastructure constraints, demand profiles), and it is difficult to separate the impact of a reservation policy from these factors.

However, the western domestic gas market has significantly lower gas prices compared to the east coast. As outlined in Figure 1, east coast spot prices have increased as LNG production has ramped up in Gladstone[19]. This increase is significant, with gas in April 2017 valued at roughly $9/GJ, which is about triple the price in September 2010. In Western Australia, domestic spot prices are currently below 2009 levels, at $4-5/GJ (see Figure 2) despite LNG export volumes nearly doubling. Domestic spot prices on the east coast have also been significantly more volatile than on the west coast.

These trends indicate that Western Australia's domestic market has a secure supply, regardless of how much LNG is exported. It is probable that this security is achieved through Western Australia's reservation policy, as evidenced in short-term trading market (STTM) pricing. It should be noted that Western Australia's gas is primarily sourced from offshore conventional resources.

Figure 1: East coast short term gas - daily prices (monthly average)[20]

 

Figure 2: Western Australian short term gas - daily prices (monthly average)[21]

 

According to BIS Shrapnel, Western Australia's reservation policy has been able to supply stable, secure and affordable energy to users, and enabled development of Western Australia's mining, minerals processing, power generation and manufacturing industries. Gas reservation has also provided price competition to other alternative energy sources, such as coal, ensuring more competitive energy pricing overall[22]. The Western Australian Government also considers the availability of low cost gas to have been a major driver of the State's strong economic growth over the two decades to 2006[23].

Net benefit

In comparison to the status quo, a permanent gas reservation policy would have a substantial short to medium term net benefit for domestic gas consumers, but come at a high cost to all LNG exporters, and potentially Australia's reputation as a low-risk destination for international investment. In the long run, the impact of restrictions on LNG projects is likely to result in a reduction in exploration and development of new fields, because production in Australia has historically been the direct result of LNG projects. This could diminish or negate any long term benefit to consumers.

5.4                         Impact analysis: export controls

Overview

Export controls would work by limiting the quantity of LNG that gas exporters are licensed to ship overseas. This would increase the amount of gas available to domestic gas consumers, by incentivising exporters to redirect their production to the domestic market. There are a number of ways to implement export controls, which are discussed in Section 8. This section focuses on the costs and benefits of implementing the ADGSM, which is outlined in Section 4.4. Importantly, the ADGSM would only result in export controls if the domestic market was not adequately supplied.

Costs

The regulatory costs to industry associated with this option are largely administrative. Costs have been estimated based on the labour required to comply with each step of the process. This RIS estimates the total regulatory cost to the gas industry to be approximately $180,000 per annum. A full breakdown of this estimate, including assumptions and caveats is detailed in Appendix B. This figure is relatively insignificant in an industry where the yearly revenue for an export project is measured in billions. A regulatory offset has not been identified. However, DIIS is seeking to pursue net reductions in compliance costs and will work with affected stakeholders and across Government to identify regulatory burden reductions where appropriate.

It is also worth noting that the annual regulatory burden is likely to be lower than estimated in most years, because the Resources Minister's determination point (see Appendix B) of the export controls process would only be instigated in the event that a domestic shortfall was likely.

The multi-step process also means that export controls would not be applied all the time. Therefore, the cost for businesses to redirect gas into the domestic market would not be permanent, as would be the case for a permanently applied gas reservation policy[24]. Additionally, exporters would only be impacted to the extent that they were contributing to a shortfall. Both of these design features lower impact on industry, in comparison to a gas reservation policy. However, there would still be an additional cost in comparison to the status quo.

Like the reservation option, there are other potential negative impacts from the prospective application of export restrictions. This includes the risk of LNG exporters not being able fulfil contractual volumes with buyers if gas field production could not be ramped up to meet the additional supply required to meet Export Permission conditions. Undelivered LNG cargoes would likely incur penalties, however the terms of LNG sales-purchase contracts are confidential, and it is therefore not possible to quantify the cost on exporters. 

Applying export controls also carry a high level of sovereign risk. LNG projects require billions of dollars in upfront exploration and infrastructure investment. Australian and overseas investors make their investment decisions with the knowledge that Australia has a historically stable regulatory environment.  As with a reservation policy, it is likely that Australia's attractiveness as a destination for investment in gas resources and infrastructure would be affected. At this point it is difficult to determine the extent of the damage to Australia's reputation as an investment destination in the gas sector and this will likely depend on the frequency and depth at which export controls are applied and the nature of LNG contracts.

The best assessment is that the cost to industry would be less than the equivalent cost under reservation, because the total amount of gas redirected would be linked to exporters in a shortfall market rather than a sector wide and permanent regulatory requirement. The number of LNG exporters captured by export controls would also be lower than under a reservation policy. This is not to say the cost of redirecting gas from export to the domestic market is not potentially significant but in the current market circumstance where domestic wholesale prices are at or above export parity, it could even be possible for the exporter to arbitrage across both markets through a combination of domestic diversion and LNG swaps to minimise losses or even gain value.

Although there may be a small degree of regulatory burden for gas producers, exporters and large consumers to generate production and consumption forecasts, this is not directly a result of this policy option; it is a requirement of other Government initiatives, including market reform work led by the ACCC, and improved forecasting by organisations like AEMO. Therefore, this RIS does not include generating this information as an additional business cost. The process of collating the information and supplying it to the Government is captured in the regulatory burden costing in Appendix B.

Despite these impacts, the ADGSM is still a reasonable option for two reasons. Firstly, the ADGSM would have a substantial net benefit on security in domestic supply and consequently lower prices for domestic consumers. Secondly, the alternative to targeted export controls, which would still address the policy problem adequately, is a broader policy like gas reservation. As discussed in Section 5.2, a blanket policy would result in higher costs (and therefore a lower net benefit), thereby making it less desirable.

If enacted, the ADGSM would prevent LNG exporters from selling a certain volume of gas to the export market and increase the availability of supply to the domestic market. As spot prices in export markets are currently below international contract prices, it is anticipated that exporters would make up the shortfall in the spot market.

Failure to ensure an adequate supply of gas would have significant negative effects on industrial gas users, the gas power generation sector and residential gas consumers.

Benefits

Export controls that are linked to projected shortfalls, would ensure that the domestic market is supplied with an adequate quantity of gas. This would help to combat market uncertainty, which may, in turn, reduce pressure on prices.

Gas reliant industries (detailed in Appendix A) are the other main beneficiary from export controls. These industries employ more than 65 000 Australians and their dependence on gas makes them sensitive to any price fluctuations.

Other direct beneficiaries would include the 50 per cent of Australian households who have mains gas. For these households, the increased availability of reasonably priced gas would have a direct reduction in cost of living expenses. Energy bills make up a significant part of monthly household expenditure. For example, in Victoria, energy services (which include both gas and electricity) are estimated to cost approximately $550 per month for an average house and $355 per month for an average apartment[25]. Reductions in gas prices, therefore, will result in a meaningful difference to Australian households, especially as reductions in gas prices are likely to cause price competition in energy sources and place downward pressure on energy prices more broadly.

Net benefit

Compared to all other options, including the status quo, the export controls outlined in the ADGSM have the strongest likelihood of securing an adequate supply of gas for domestic users, with the least market distortions. In times when the market was sufficiently supplied, the ADGSM would not be triggered.

Non-regulatory costs would only be imposed in the event that a domestic shortfall was likely. Additionally, the mechanism would only impose business costs on exporters that were in net deficit (i.e. contributed to the shortage). This means that the overall cost would be proportionate to the exporters' role in contributing a shortfall, while the benefit to consumers would be substantial and widespread. As a result, the net benefit of this proposal is greater than the net benefit of all other options, including the status quo.

6    Consultations

Between March 2017 and May 2017, the Government had steady engagement with industry in order to deliver Australian households and businesses with an adequate supply of gas at reasonable prices.  The Government will continue to collaborate with industry, as it refines the ADGSM to better safeguard Australia's domestic gas supply. This section summarises the consultation process.

It should be noted that the consultations focussed on the ADGSM. However, the industry provided feedback on additional policy options, including some additional options for implementing export controls, which are discussed in Section 8. Some additional options were considered unfeasible, and/or did not solve the policy problem. These options were not included in this RIS.

6.1            Past consultations

Initial 'round table' consultations

Before considering intervention in the gas market, the Prime Minister hosted meetings with east coast gas producers and exporters on 15 March 2017 and 19 April 2017. At those meetings, the Government sought commitments:

*         from gas producers to make more gas available to the domestic market as soon as possible

*         from LNG exporters to have a net contribution gas to the domestic market, rather than 'drawing down' on domestic supply.

In addition to meeting with gas producers and exporters, on 29 March 2017, the Government met with gas pipeline operators, and relevant peak bodies.

Throughout the industry meetings, the Government made it clear that its preference was for industry to respond of its own volition, and improve supply and price outcomes. However, the Prime Minister also made it clear that the Government would intervene if gas producers did not meet commitments to address the current tightness in the domestic market. Despite making progress, not all of the east coast LNG exporters satisfactorily outlined their plans to contribute enough gas to the domestic market to offset the impact of their operations.

Consultation on the ADGSM

Following the unsatisfactory outcome of the Government's initial industry meetings, Senator the Hon Matthew Canavan, Minister for Resources and Northern Australia, wrote to industry and government stakeholders in late April 2017 to inform them of the proposed ADGSM. His letter included a discussion paper, which outlined the ADGSM's initial design. Minister Canavan requested feedback on the ADGSM, and asked for participation as the Government continued to develop the mechanism. Minister Canavan initially requested written submissions by 11 May 2017, but this deadline was later extended in order to allow for more comprehensive consultations.

DIIS conducted three meetings (4 May 2017, 11 May 2017 and 26 May 2017) with each of the joint venture partners involved in each of the east coast LNG projects. These meetings aimed to provide clarity about the policy intent of the ADGSM and its proposed operation. The meetings provided the exporters with the opportunity to critique the mechanism and offer improvements and alternative suggestions. At the meetings, DIIS encouraged out of session communication to help the mechanism to achieve its policy objectives, while minimising the burden on the LNG export industry.

On 15 May 2017, DIIS held a similar meeting for interested parties at the 2017 APPEA Oil & Gas Conference and Exhibition. This invitation was extended to all joint venture partners in LNG projects that operate out of the Northern Territory and Western Australia.

DIIS also had a number of meetings with individual companies when requested.

On 5 June 2017, exposure drafts of the regulations, guidelines and explanatory material for the ADGSM were released for consultation until 12 June 2017. Stakeholders including LNG projects, major gas users, peak body and consumer interest groups, and State and Territory governments, were invited to make submissions.

34 submissions were received from LNG projects, LNG producers, large gas consumers, businesses, State and Territory governments, other affected stakeholders, and members of the public. Feedback from the submissions was considered and informed the further development of the ADGSM.

DIIS also consulted with the Australian Government Department of Prime Minister and Cabinet, Department of Immigration and Border Protection, Department of Foreign Affairs and Trade, Department of the Treasury, and Department of the Environment and Energy.

During the week beginning 19 June 2017, DIIS conducted international consultations with major trading partners including Japan, South Korea, Malaysia and China.

In addition to the formal meetings, Minister Canavan has engaged directly with industry leaders in person, and by correspondence.

6.2            Planned consultations

The Government will continue to encourage industry to engage with DIIS, as it works towards finalising the mechanism.

Implementation of the ADGSM will build in further opportunities for consultations with industry in relation to the possibility of industry-led solutions which would preclude the need for export controls.

7    Recommendation

7.1        Recommendation and justification

This RIS considered four options to increase the security of Australia's domestic supply by influencing LNG exporters.

The first option was for the Government to maintain the status quo, and leave the LNG export market unregulated. This option is untenable, because it leaves Australian gas consumers in a position of shouldering all of the risk of an export driven shortfall.

The second option was for LNG exporters to voluntarily agree to guarantee an adequate supply of gas to the domestic market. The net benefit of this option is negligible, because the likelihood of an enforceable commitment effectively preventing a shortfall, or perceived shortfall is low. As in the first option, the risk of an export-driven supply shortfall (and the associated flow-on effects) would still be fully borne by domestic gas consumers.

The third option was a blanket gas reservation policy. Compared with the first two options, this option is substantially more likely to meet the policy objective of securing an adequate supply of gas for domestic gas consumers. However, less restrictive options were available. If the reservation policy was permanent, it could also have negative effects on long term supply, because it dis-incentivises exploration and development. This would counter the positive short to medium term benefit to domestic gas consumers. The only viable non-permanent reservation method is equivalent to implementing export controls (see Sections 4.3 and 8.2 for further discussion).

The fourth option was for the Government to employ export controls. Compared to the status quo, the export controls outlined in the ADGSM have a strong likelihood of securing an adequate supply of gas for the domestic market. Compared with a blanket reservation policy, the ADGSM is likely to redirect less gas into the domestic market, so the short term benefit to consumers is less. However, the ADGSM is likely to impose a substantially smaller cost on LNG exporters, which would be in proportion to their contribution to a domestic shortfall. Although the regulatory burden is higher for export controls in comparison to the other options, the cost is negligible in comparison to other business costs incurred by the LNG export industry.

After considering all four options, this RIS recommends export controls as the most appropriate method to solve the policy problem. The preferred method of implementation is through the proposed ADGSM, as it would meet the policy objective more effectively than other export control designs (see Section 8). 

However, the Government does not believe that export controls is the only solution to all of the issues with Australia's domestic gas markets. Export controls, and the implementation of the ADGSM, would complement other government, including CoAG Energy Council actions, which are designed to improve the efficiency, competitiveness and transparency of gas markets and increase the development of Australia's gas resources. 

7.2        Stakeholder feedback

The stakeholder consultations described in Section 6 were centred on export controls, and the ADGSM. Although gas exporters understood the Government's rationale, they challenged the need for intervention. DIIS heard a number of arguments to this effect, including:

*         The overarching cause of supply pressures is due to restrictive state and territory government policies.

*         Exporters should not be held accountable for supply pressures if there are other market forces (e.g. declining field production) that are also placing pressure on supply.

*         Wholesalers are having a larger impact on domestic prices than exporters.

The Government has taken this feedback into account and is undertaking separate actions to address non-exporter related issues with Australia's gas markets. However, none of these points justified Australian consumers bearing the risk and cost of export-driven shortfalls.

After voicing their opinions on the need for any regulation in the first place, industry stakeholders constructively provided feedback on how export controls would best work in practice, and the design of the ADGSM. DIIS heard a number of exporters' concerns, including the following.

*         It is important for the mechanism to be temporary, because increasing supply is the preferred long term solution.

*         The shipping schedules of many LNG exporters are finalised in the prior calendar year, following a period of contractual negotiations between LNG exporters and consumers. These schedules are difficult to change for logistical and contractual reasons.

*         The complex commercial structures of different LNG exporters require the ADGSM to have robust definitions around the respective points of net-deficit assessment and licensing (see Section 4.4).

*         There should be careful thought given to the definitions and methodology used to determine whether an exporter is in net deficit to the domestic market.

*         There may be an incentive for different LNG exporters to 'game' the mechanism by engaging in anti-competitive behaviour.

*         There needs to be provisions to ensure that accurate data (from both producers and consumers) are available and forecasting follows best practice.

*         Cargo swaps are not an option for all exporters for contractual reasons.

The Government is continuing to refine the ADGSM, in consultation with industry stakeholders, to take into account the above points.

7.3        Caveats and qualifications

Industry consultations regarding alternative policy options to the ADGSM, did not yield effective or acceptable solutions to ensure reliable and affordable gas supply for Australian consumers[26]. Further detail on these alternative models is available in Section 8.2. In the absence of suitable alternatives, the ADGSM has been recommended as the best option for the Government to improve supply security for domestic gas consumers whilst also balancing exporters' interests. 

The ADGSM is a temporary and targeted measure that will only be implemented upon formal certification, from the Minister for Resources, that there are reasonable grounds for doing so. Such a certification is subject to the Government receiving advice from the ACCC and market bodies such as AEMO, before determining the volume of gas required.

The implementation of the ADGSM will, as much as possible, accommodate for LNG exporters to honour their ongoing contracts, recognising that they may be subject to logistical constraints such as, for example, shipping schedules. Definitions and methodology used to determine whether an exporter is in net deficit to the domestic market will be made to obtain accurate data from both producers and consumers.

The ADGSM is expected to commence on 1 July 2017. However, there will be ongoing consultations with industry to find a suitable compromise that minimises the burden for both the Government and gas exporters, whilst achieving the policy objective of securing domestic gas supply. Further industry consultation may change how the ADGSM is implemented and how it may affect upstream production and joint ventures.

Risk mitigation and other implementation details are discussed in greater detail in Section 8.

8    Implementation

All aspects of the implementation process included in this section have been informed by consultation (see Section 6) and are subject to further development. DIIS is actively engaging with industry stakeholders to minimise implementation risks, and maximise the net benefit to Australia.

8.1        Steps to implementing the ADGSM

The Government has committed to introduce export control regulations by 1 July 2017. The export controls would be implemented by amending the Customs (Prohibited Exports) Regulations 1958.  The Department of Immigration and Border Protection (DIBP) is the agency responsible for this legislation. However, as with export controls for uranium and diamonds, DIIS will have primary responsibility for policy and administration, but work closely with DIBP on these matters.

The following remaining steps required to implement the ADGSM are:

*         further consultation with industry (both gas producers and consumers) on the design of the mechanism[27]

*         industry consultation on the exposure draft and guidelines in early June 2017

*         consultation in early June 2017 with Australia's LNG trading partners

*         tabling of the regulation in Parliament, and the subsequent disallowance period of 15 sitting  days.

After the regulation is made by the Governor General, and tabled in Parliament and is not subject to disallowance, the ADGSM could be activated by the Minister for Resources. The Australian Government currently does not prohibit the export of LNG; however they are required to report their exports by way of Export Declarations. The LNG industry would therefore transition from reporting at time of export (Export Declaration) to requiring to obtain a permit prior to time of export while continuing to report export details as required of a prohibited export, when the Resources Minister determines there to be a shortfall in the LNG domestic market. To assist the industry with the transition, guidelines outlining the steps, responsibilities and timeframes involved will be developed. Each decision point would be appropriately timed to ensure companies, market bodies and the ACCC had sufficient time to consider and respond to requests. Through the Minister for Resources, DIIS would be responsible for all aspects of the administrative process required to implement the ADGSM (see Section 4.4 for a flowchart describing the process). Responsibility for each step is articulated in the guidelines.  

Minister's Declaration

The Resources Minister would make a public declaration of his/her intent to make a determination of whether export controls would be implemented in the forthcoming year. The determination would occur no sooner than 30 days after the declaration. After making the declaration, the Resources Minister would write to:

*         relevant market bodies and agencies (e.g. AEMO, ACCC) requesting advice on the potential for a domestic gas shortfall, and associated analysis

*         LNG project managers, requesting information such as gas production figures or planned export volumes, for example.

*         relevant Australian Government Ministers, for consultation and to notify them of his/her declaration.

*         any other stakeholders that the Resources Minister considers appropriate.

Assessment and decision

After receiving submissions, the Resources Minister would consider all relevant and available information. The Resources Minister would then make a determination as to whether export controls would apply in the following year.

If no shortfall exists, the process would end. If the Resources Minister determined that export controls should be implemented in the forthcoming year, then the Resources Minister would determine exporter obligations and permitted export volumes as outlined in Section 4.4 . The method for determining obligations will be detailed in the guidelines.

Minister's Determination

The Resources Minister would issue a public decision with a statement of reasons. The Resources Minister would also write to LNG exporters advising them of any provisional Export Permission decision (if triggered) and reasons for the decision. Where practical, exporters would have 30 days to consider and respond to their provisional Export Permission determination and any conditions attached to it.

The Resources Minister would then assess any relevant additional information before finalising Export Permissions. The granting of an Export Permission would be conditional on gas supply and production throughout the permission period matching information supplied to the Government as part of the process.

An Export Permission period would apply from 1 January to 31 December of the following year.

Export Permissions would be based on a quantity of gas (linked to its energy content), rather than the number of cargoes. DIIS would be responsible for monitoring compliance of the export volumes for LNG companies subject to Export Permissions. DIBP's role would be to provide export information to DIIS for verification against permissions, and prevent any cargoes classified as a prohibited export departing Australia (e.g. if an exporter was breaching its Export Permission).

Implementation risks

The Prime Minister has requested export controls be implemented by 1 July 2017 to respond to the risks to the economy resulting from a potential shortfall of supply to the domestic market. 

Consultation on the framework with impacted LNG exporters, market bodies and the ACCC has occurred within a short timeframe as it is a priority to minimise any unintended consequences. Consultation with industry on the design of the mechanism occurred on the following dates: 4 May, 11 May, 15 May and 26 May 2017. In addition to this, ad hoc consultations will serve to address further issues.

Reviewing the mechanism

The ADGSM is intended to be a temporary intervention in the market. It is intended to only operate for five years (to 1 January 2023) and will be subject to a review after two full years of operation.

The review will evaluate the efficacy of the mechanism by analysing if export controls have made a material impact on reducing supply shortages to the domestic market. This will include reviewing the behaviour of exporters, to determine if restrictions (or threat of restrictions) on export volumes have improved domestic gas availability over time.

The review will also consider whether gas users have had improved access to gas and whether demand destruction had occurred due to industry closures. Administrative aspects of the mechanism would also be reviewed to determine if steps and timeframes for information gathering from market bodies and exporters restricted the Resources Minister's ability to make informed decisions.      

Analysis of the performance of the policy against its objectives will take place throughout the operation of the ADGSM.

8.2        Alternatives to the ADGSM for implementing export controls

The impact analysis in Section 5 uses the proposed ADGSM design to estimate the regulatory costs, because it was deemed to be the most feasible and beneficial implementation method. This section outlines several alternative methods to implement export controls, including anonymous suggestions from industry stakeholders.

Gas-sourcing model

Under this model, LNG exports would be permitted where the exporter can demonstrate that feedstock gas was wholly (or partially with a specified minimum amount) derived from designated 'export-compatible fields'. While this model may be preferable to exporters as it offers them more flexibility if 'export compatible fields' can be unambiguously identified, it could potentially involve a high level of regulatory burden to ensure that exported gas is derived from said 'export-compatible fields.' Moreover, this model may not actually increase the volume of gas available to the domestic market. Therefore, this model compares unfavourably to the ADGSM, which only requires action in the incidence of a shortage of supply to the domestic market and results in targeted, temporary changes to exports.

Equally distributed restrictions, or restrictions linked to gas volumes

Under this method of implementation, export restrictions would either be applied equally between LNG projects (i.e. all exporters get their exports restricted by a fixed percentage of the shortfall), or linked to the scale of operations (e.g. via nameplate capacity, or realised export volumes). These models are similar to a reservation policy in that they would impose an additional cost on exporters, regardless of whether their operations provided the domestic market with more gas. This would also disadvantage exporters that responsibly developed their own gas supplies, which contradicts the Government's support of a productive, socially responsible LNG industry and would reduce the incentive for exporters to develop new fields. Compared to the targeted nature of the ADGSM, this model poses a higher level of intervention in exports without achieving a higher level of security for the domestic market.

Future contracts model

This model would not impact on gas sold as part of existing long term export contracts; as licensing would apply only to spot cargoes and future long term contracts. Export restrictions based on this model would have relatively certain impacts on exporters, however this method will not solve the problem of a potential domestic gas shortage in the short to mid-term. Relative to the ADGSM, it would reduce incentives for exporters to develop new sources of gas.

9    Appendices

9.1        Appendix A: Gas use statistics

Manufacturing industries most exposed to energy price shocks. 

Analysis of the Australian Bureau of Statistics (ABS) Australian System of National Accounts Input-Output tables indicate that the six manufacturing industry groups with the most significant exposure (share of total intermediate inputs) to gas price fluctuations are as summarised in Table 1, with Basic Chemical Manufacturing being the most exposed. Note, these data are on a national basis and does not disaggregate to the level of specific regions susceptible to a domestic gas shortfall, such as the east coast gas market.

Table 1 Australian Industries most exposed to gas and energy price shocks, including through direct inputs with high energy shares (2013-14)

Manufacturing and Other Product Group	Gas Share of Intermediate Inputs	Value Share of Intermediate Inputs Exposed to Energy* Price Shocks	Value Share of Total Production Costs Exposed to Energy* Price Shocks	Average Employment - Year Ending March Quarter 2017
Basic Chemical Manufacturing	25%	27%	18%	5,275
Glass & Glass Product Manufacturing	13%	22%	11%	5,700
Ceramic Product Manufacturing	11%	18%	10%	5,175
Polymer Product Manufacturing	10%	18%	9%	31,675
Petroleum & Coal Product Manufacturing	10%	17%	10%	5,650
Plaster & Concrete Product Manufacturing	9%	14%	9%	12,425
Subtotal				65,900
Electricity Generation	8%	39%	22%	N/A

* Energy = Gas + Electricity; Departmental calculations.

Source: ABS (2016) 5209.0.55.001 Australian National Accounts: Input-Output Tables - 2013-14, Table 5; ABS (2016) 5215.0.55.001 Australian National Accounts: Input-Output Tables (Product Details), 2013-14; ABS (2017) 6291.0.55.003 - Labour Force, Australia, Detailed, Quarterly, Feb 2017.

9.2   Appendix B: Cost analysis of the ADGSM

This section follows the chronological process of the ADGSM to identify the regulatory burden on industry. It then outlines key assumptions that were included in the costing model. A regulatory offset has not been identified. However, DIIS is seeking to pursue net reductions in compliance costs and will work with affected stakeholders and across Government to identify regulatory burden reductions where appropriate.

Cost summary

Table 2, Table 3, and Table 4 detail the regulatory costs of the ADGSM for a single LNG project. The estimates in each table are inclusive of the activities of all joint venture partners involved in the project. Estimates of hours taken for industry to complete regulatory tasks are based on the administrative effort required.

Table 2 breaks down the regulatory cost to a business when the Minister for Resources makes a declaration of intent to make a determination under the ADGSM.

Table 2: Estimate of regulatory costs for one LNG project to respond to the Resources Minister's declaration

Activity	Worker type	Total hours	Labour rate ($/hr)	Cost ($)
Government writes to market bodies, ACCC, LNG exporters, and Ministers	No cost to industry
LNG project operator develops submission including views on market outlook, and information on forecast production and consumption	Project planner	22.5	131.92	2968.24
	Planning manager	1	211.07	211.07
LNG project operator circulates  submission to joint venture partners	Project planner	1	131.92	131.92
Joint venture partners assess the submission, and determine if changes are required.	Planning manager	12	211.07	2532.89
	Executive	4	452.57	1810.28
LNG project operator amends the application as per requests from individual joint venture partners	Project planner	7.5	131.92	989.41
	Planning manager	1	211.07	211.07
Joint venture partners reassess the submission	Planning manager	8	211.07	1688.60
	Executive	2	452.57	905.14
LNG project operator submits the application	Project planner	1	131.92	131.92
Total				$  11,580.55

 

Table 3 breaks down the regulatory cost to a business when the Minister makes an assessment about whether export controls will apply in the following year. 

Table 3: Estimate of regulatory costs for one LNG project when the Resources Minister makes an assessment

Activity	Worker type	Total hours	Labour rate ($/hr)	Cost ($)
Government analysis of data, and determination of shortfall	No cost to industry
Government calculation of  each exporter's net deficit
Government develops provisional permissions

 

 

Table 4 breaks down the regulatory cost to a business if the Resources Minister makes a determination to invoke export controls (described in the flowchart in Section 4.4).

Table 4: Estimate of regulatory costs for one LNG project when export controls are invoked

Activity	Worker type	Total hours	Labour rate ($/hr)	Cost ($)
Government announces its decision on whether export controls will be enforced, and writes to LNG exporters to issue permissions	No cost to industry
LNG operator circulates government feedback to joint venture members	Planning manager	1	211.07	211.075
Joint venture partners formulate an opinion about the government feedback and licensing.	Project planner	12	131.92	1583.059
	Planning manager	4	211.07	844.298
	Executive	4	452.57	1810.280
Joint venture partners provide feedback to the LNG project operator	Project planner	20	131.92	2638.432
The operator formulates a response to the Government, explaining how the project will meet its obligations to the domestic market	Project planner	37.5	131.92	4947.060
	Planning manager	4	211.07	844.298
The operator circulates submission to joint venture partners	Project planner	1	131.92	131.922
Joint venture partners assess the response, and determine if changes are required	Planning manager	12	211.07	2532.895
	Executive	4	452.57	1810.280
LNG project operator amends the response as per requests from individual joint venture partners	Project planner	7.5	131.92	989.412
	Planning manager	1	211.07	211.075
Joint venture partners reassess and approves the response	Planning manager	8	211.07	1688.596
	Executive	2	452.57	905.140
LNG project operator submits the response	Project planner	1	131.92	131.922
The Government assesses the response, and issues a final permission	No cost to industry
Total				$  21,279.74

 

Given the current state of the LNG export market in Australia, the model assumes that:

*         A Minister's declaration of intent to make a determination would affect 10 LNG export projects.[28]

*         The Resources Minister's determination to invoke export controls would affect at most three export projects (i.e. at most three projects would be in net deficit, and would be granted a provisional license for a quantity smaller than the exporter had planned on).

*         The ADGSM decision making and licensing process would occur, at most, once a year.

Taking these assumptions into account, Table 5 outlines the estimated total annual cost to industry.

Table 5: Total annual regulatory cost to industry[29]

ADGSM period	Number of impacted LNG projects	Cost per project	Total cost
Declaration	10	$             11,580.55	$  115,805.51
Assessment of shortfall	N/A - During this period, the only work is conducted by Government
Determination	3	$             21,279.74	$    63,839.23
Total			$  179,644.74

 

Additional assumptions and methodology

Overarching assumptions and caveats

*         The costing model incorporates conservative assumptions with the intent to avoid underestimating the ADGSM's regulatory cost to business.

*         The cost could be higher or lower depending on the number of internal review points (e.g. a joint venture partner querying the submission) in the Resources Minister's determination (see Table 2) and Minister's declaration (see Table 4) points of the ADGSM.

*         The model assumes that all LNG projects would treat the ADGSM in a similar way. This allows the model to calculate the cost for each project, and then multiply it by the number of projects in order to reach a total cost.

Wage rates

Wages in the gas and LNG industries are higher than Australia's average wage rates. Therefore, this RIS does not use the average wage rates listed by the Office of Best Practice and Regulation (OBPR) in their Guidance Note[30]. Instead, it uses the job descriptions and wages in the 2016 Hays Salary Guide[31] for the "Oil and Gas" industry. OBPR standard wage rate assumptions are obtained from ABS data, however these ABS sources are not sufficiently detailed for the purpose of this analysis.

The Hays Salary Guide provided a range of yearly wages for a given position and state. For example, a Maintenance Supervisor could annually expect to earn between $135,000 and $180,000 in Western Australia, whereas the equivalent worker in Queensland would earn between $130,000 and $190,000. There were several steps in the process to calculate the hourly wage rates used in Table 2 and Table 4.

First, the average yearly wage rates were calculated by taking the average of the maximum wage for the equivalent job in Queensland and Western Australia. Using the Maintenance Supervisor example above, the average yearly wage was calculated to be:

The average of Queensland and Western Australia was used because most LNG export projects operate from those states. The maximum was chosen in order not to underestimate the labour costs.

After the average was taken, it was scaled up by the standard assumption of 75 per cent to account for on-costs (e.g. superannuation, payroll tax) and overheads (e.g. electricity, equipment). Finally, the model assumed an average working week of 38 hours, and that the employee would work 48 weeks in a year. The hourly wage for the Maintenance supervisor example used was therefore calculated to be:

The model considered three types of employees. A 'project planner' covered the employees that would do most of the work, including data analysis, forecasting and communication. Project planners would report to 'planning managers', who would have an overview of the entire project's operations.

'Executives' covered senior members of the organisation and had the authority to sign off on the project's various responses to the Government. Executives might be CEOs, presidents, vice presidents or similar. The Hays Salary Guide did not include information on executives' salaries. To estimate the yearly salary of an executive in the gas industry, this RIS took the average value of the Executive Incentive Plan for Woodside executives that held their position for the entire 2015-16 financial year. To estimate the hourly wage, this RIS assumed that executives worked for 50 hours each week, for 48 weeks in a year. The model did not add an additional loading for on-costs for the executive wages, because their remuneration package was comprehensive. It should be noted that this is a rough approximation only, and detailed information on executive pay within an industry is difficult to source.

Table 6 summarises the hourly wages used in the costing model.

Table 6: Wage rates used to calculate the regulatory costs

Hays Salary Guide description			RIS description
Title	WA yearly wage ($'000s)	QLD yearly wage ($'000s)	Title	Labour rate ($/hr)
Planner	120-160	90-115	Project planner	131.92
Planning manager	170-220	170-220	Planning manager	211.07
Woodside average "executive incentive plan"	1086		Executive	452.57

 

Exclusions

The following costs were not included in the costing model

*         Set-up and record-keeping costs

The model assumes that exporters can prepare applications using existing data (e.g. production and export data, use of third party gas), and that these data would be readily available as part of regular business as usual. This is reasonable because exporters will need to provide the same sort of information to the ACCC, and market forecasters (e.g. AEMO) on a regular basis.

*         Ongoing reporting or compliance costs

This RIS does not envisage any ongoing reporting obligations on LNG exporters. Each LNG exporter is expected to provide rigorous submissions. The mechanism is not designed to have a continuous submissions process.

*         Costs of delay

The costing model assumes that enough time is built into the ADGSM process to avoid interfering with "business as usual" activities, like negotiating shipping schedules.

*         Costs to government

The costs of establishing a new licencing framework, and of the government's internal assessment of an export application are outside the scope of the Regulatory Burden Measurement Framework, and have not been quantified.

 

 

Details of the Customs (Prohibited Exports) Amendment (Liquefied Natural Gas) Regulations 2017

Section 1 - Name

This section specifies the name of the Regulations as the Customs (Prohibited Exports) Amendment (Liquefied Natural Gas) Regulations 2017.

Section 2 - Commencement

This section provides that the Amendment Regulations commence the day after they are registered on the Federal Register of Legislation.

Section 3 - Authority

This section sets out that the Amendment Regulations are made under the Customs Act 1901.

Section 4 - Schedules

This section is a machinery clause that enables the Schedule to amend the Regulations. The Amendment Regulations contain one schedule.

Schedule 1 - Amendments

Customs (Prohibited Exports) Regulations 1958

Item 1 - At the end of Part 3

This item inserts a new Division 6 into the Customs (Prohibited Exports) Regulations 1958. Division 6 creates a framework for the prohibition of exports of LNG in circumstances where the Resources Minister reasonably believes there will not be a sufficient supply of gas in the Australian domestic gas market, or a part of the Australian domestic market, unless exports of LNG are controlled. Division 6 includes the following provisions.

Regulation 13GB Definitions

This regulation sets out definitions of terms which are used in the new Division 6.

Regulation 13GC Export prohibited during domestic shortfall years

This regulation provides for: the prohibition of exportation of LNG in a domestic shortfall year without a permission; the ability for the Resources Minister or an authorised officer to grant permissions to export LNG; the ability for conditions to be imposed on a permission; and the imposition of obligations on the holder of a permission to comply with conditions imposed. This regulation contains the following subregulations.

Subregulation 13GC(1)

This subregulation sets out that the exportation of LNG is prohibited during a domestic shortfall year unless a permission in writing to export the LNG has been granted by the Resources Minister or an authorised officer, and the permission is produced to the Collector. The purpose of this subregulation is to apply export controls, and to require exporters of LNG to hold written permissions prior to exporting LNG, during a domestic shortfall year. The meaning of 'domestic shortfall year' is set out in subregulation 13GE(1), as discussed below. If the Resources Minister does not determine a year as a domestic shortfall year, exports of LNG will not be controlled in that year.

Where the Resources Minister determines a year as a domestic shortfall year, exports of LNG will be prohibited, and permissions required for exports, Australia wide. This is despite that only a part of the Australian domestic gas market may be in shortfall. This ensures exporters are treated equally regardless of their location within Australia.

The Resources Minister may grant permissions to LNG exporters to allow them to export LNG during a domestic shortfall year. The Resources Minister may also authorise an SES officer of the Resources Department to grant a permission in accordance with this subregulation. This is intended to provide flexibility for the Resources Minister in the administration of permissions for the export of LNG.

A permission may be granted for a period that is longer than a domestic shortfall year. It is intended that there should be flexibility to grant permissions which provide exporters of LNG with as much certainty as possible over their ability to export, and the volumes of gas they may export.

Subregulation 13GC(2)

This subregulation sets out that a permission may specify conditions to be complied with by the permission holder, and when the holder must comply with a condition. It is anticipated that, for exporters associated with LNG projects that are able to contribute gas to parts of the Australian domestic gas market that are experiencing a gas shortfall, the Resources Minister may impose limits to the volume of LNG allowed to be exported. The Resources Minister may also impose conditions to require exporters to provide regular reports about the volumes of LNG they export during the term of their permission, as well as any other conditions the Resources Minister considers appropriate.

Subregulation 13GC(3)

This subregulation sets out that the Resources Minister or an authorised officer may vary a condition of a permission with the consent of the permission holder, or accept the surrender of a permission, including in exchange for granting another permission. The purpose of this subregulation is to allow permissions to be varied, or (where a permission is surrendered) replaced, by the Resources Minister or an authorised officer with the consent of the permission holder. The Resources Minister or an authorised officer may not unilaterally vary a condition of a permission without the consent of the holder of the permission, unless the permission holder breaches a condition, as discussed below.

Subregulation 13GC(4)

This subregulation sets out that if the permission holder does not comply with a condition of their permission, the Resources Minister may, by writing, revoke the permission or vary one or more conditions of the permission. 'Vary', in relation to conditions, is defined to include to omit or substitute conditions. The purpose of this subregulation is to allow the Resources Minister to revoke or vary a permission where the permission holder does not comply with a condition of a permission.

Where the Resources Minister revokes a permission, the Resources Minister may grant the permission holder a new permission. A replacement permission could include conditions that differ from the revoked permission in light of the condition breached (for example, a lower volume of gas allowed to be exported, or stricter information reporting requirements).

Regulation 13GD Assignment of permissions

This subregulation sets out that permissions may specify that they may be assigned to a third party, where the Resources Minister or an authorised person consents. If a permission is assigned, the Resources Minister or an authorised person may vary the conditions of the permission as appropriate. This subregulation also includes a requirement that the consent to assign, as well as any variations to conditions, must be endorsed on or annexed to the permission.

Regulation 13GE Determining a domestic shortfall year

This subregulation provides for the Resources Minister to determine a forthcoming calendar year as a domestic shortfall year. In a domestic shortfall year, exports of LNG are prohibited unless the exporter has received a written permission from the Resources Minister, and produced it to the Collector. The Resources Minister's determination of a domestic shortfall year is a notifiable instrument, which must be registered on the Federal Register of Legislation. The Resources Minister's determination of a forthcoming calendar year must be made on or before 1 November in the preceding year.

The Resources Minister may only determine a domestic shortfall year if the conditions in subregulation 13GE(2) are met.

Subregulation 13GE(2)

This subregulation sets out that the Resources Minister must not determine a domestic shortfall unless three conditions are met.

The first condition is that the Resources Minister must have reasonable grounds to believe that there will not be a sufficient supply of natural gas for Australian consumers during the year unless exports are controlled, and that exports of LNG would contribute to that lack of supply.

In relation to the first condition, it is intended that the Resources Minister will consider Australian consumers in each part of the Australian domestic gas market, including each of the major gas markets that together comprise the Australian domestic gas market (that is, the Western, Northern, and Eastern gas markets). For the purpose of making a determination under subregulation 13GE(1), it is intended that the Resources Minister may determine that Australian consumers in part of the Australian domestic gas market (for example, the Eastern gas market) will be affected by an insufficient supply of gas, notwithstanding that consumers in other parts of the Australian domestic gas market will not be affected by an insufficient supply.

The calculation involved in 13GE(2)(a) will require the Resources Minister to assess a forecast supply of natural gas against an assessment by the Resources Minister of the amount of gas Australian consumers need - in other words, an appropriate level of demand for gas for the market for the relevant calendar year. In considering this forecast supply of gas, it is intended that the Resources Minister may use price as an aspect in deriving the appropriate level of demand for gas. Estimates of the likelihood and extent of a potential shortfall would be developed using a reasonable price which reflects that Australian gas consumers (at a wholesale level) should, on average, pay no more for their gas than the value of that same gas if sold for export (for example, the applicable LNG netback price).

Exports of LNG would be considered to contribute to a lack of supply where one or more exporters of LNG are drawing down from the Australian domestic gas market in net terms.

The second condition is that, prior to making a determination, the Resources Minister must have consulted with the Prime Minister, the Energy Minister, the Industry Minister, and the Trade Minister.

The third condition is that, at least 30 days before the determination is made, the Resources Minister must have notified his or her intention to consider whether to determine the year as a domestic shortfall year. The Resources Minister's notification is a notifiable instrument, which must be registered on the Federal Register of Legislation. Practically, this requires the Resources Minister to provide at least 30 days' notice to the public before he or she makes a decision about whether or not to determine the forthcoming calendar year as a domestic shortfall year.

Because a determination made by the Resources Minister in accordance with s 13GE(1) must be made on or before 1 November in the year preceding the domestic shortfall year, this means the Resources Minister's notification under paragraph 13GE(2)(c) must be made on or before 1 October in the year preceding the domestic shortfall year.

Although the Resources Minister may commence this process at any time up until 1 October in the year preceding a calendar year, it is expected that the Resources Minister would ordinarily make a notification earlier in the year (for example, in July) in order to provide as much notice as possible to affected stakeholders, especially LNG exporters.  

Where the Resources Minister makes a notification in accordance with paragraph 13GE(2)(c), the Resources Minister will consult with stakeholders to seek information about the Australian domestic gas market. This will include consultation with relevant market bodies and agencies (for example, the Australian Energy Market Operator and the Australian Competition and Consumer Commission), all LNG projects, relevant Commonwealth ministers, as well as any other stakeholders with whom the Resources Minister wishes to consult.

The Resources Minister will then consider the submissions and make a final decision about whether the forthcoming calendar year should be determined as a domestic shortfall year.

The requirement to give the public at least 30 days' notice, and the opportunity for stakeholders to provide information to the Resources Minister, is intended to ensure the Resources Minister's assessment of the state of the Australian domestic gas market will be based on the best available information and advice. 

Subregulation 13GE(3)

This subregulation sets out that the Resources Minister may revoke a determination of a domestic shortfall year at any time. The purpose of this provision is to allow the Resources Minister to revoke a determination of a domestic shortfall year where circumstances have changed. For example, this could include where the Resources Minister considers a forecast gas shortfall has not eventuated.

Regulation 13GF Resources Minister may publish guidelines

This regulation sets out that the Resources Minister may publish guidelines by notifiable instrument which are relevant to the exercise of powers under Division 6. The guidelines are likely to set out relevant requirements, indicative timing, processes, and considerations associated with the operation of Division 6 and the Resources Minister's decisions therein. 

Regulation 13GG Review of Division

This regulation sets out that the Resources Minister must cause a review of the operation of Division 6 to be undertaken during 2020. It also sets out the matters which the review must address (as a minimum, noting the provisions do not limit the matters that may be addressed by the review). This regulation also provides that in conducting the review, the legitimate interests of all relevant stakeholders must be taken into account.

Regulation 13GH Repeal of Division

This regulation sets out that Division 6 of the Regulations will be repealed on 1 January 2023. This reflects that Division 6, and the ADGSM, are intended to be a short to medium term solution to the problem of gas shortfall in the Australian domestic gas market. The ADGSM will be reviewed prior to 2023 and consideration will be given to whether it should continue or be allowed to end, and whether any alternative solution is required.

Statement of Compatibility with Human Rights

Prepared in accordance with Part 3 of the Human Rights (Parliamentary Scrutiny) Act 2011

Customs (Prohibited Exports) Amendment (Liquefied Natural Gas) Regulations 2017

These Regulations are compatible with the human rights and freedoms recognised or declared in the international instruments listed in section 3 of the Human Rights (Parliamentary Scrutiny) Act 2011.

Overview of the Legislative Instrument

The Regulations amend the Customs Act 1901 (Prohibited Exports) Regulations 1958 to provide a framework for the Resources Minister to:

*         prohibit the export of liquefied natural gas (LNG) in periods where there is a reasonable prospect of a gas supply shortfall in the domestic market, and

*         grant permissions to LNG exporters to export LNG over such periods.

Human rights implications

The Regulations do not engage any of the applicable rights or freedoms.

Conclusion

The Regulations are compatible with human rights as they do not raise any human rights issues.

 

Hon Peter Dutton MP

Minister for Immigration and Border Protection