Response to the Eastern Australian Domestic Gas Market Study

Transcription

1 Response to the Eastern Australian Domestic Gas Market Study February 2014

2 Contents Introduction Gas Market Reform Agenda Promote gas supply competition Improve commercial and regulatory environment for infrastructure Market data and transparency Role for non-market intervention Governance and implementation issues Other issues Recommendation on standard terms and conditions for secondary capacity trading Role of trading markets and contractual arrangements in the Eastern Australian Gas Market Access to upstream facilities

3 Introduction The Australian Pipeline Industry Association (APIA) welcomes the opportunity to comment on the questions posed by the Department of Industry in the Eastern Australian Domestic Gas Market Study (the Study). APIA, as the peak body representing Australia s gas transmission industry, has views on many of the issues raised in the Study. APIA s members build, own and operate the gas transmission infrastructure connecting the disparate gas supply basins and demand centres of Eastern Australia, offering a wide range of services to gas producers, retailers and users. Since 2000, APIA s members have invested in and built over $2.2 billion 1 of infrastructure providing 4000km of coverage across 10 major new gas transmission pipelines in eastern and northern Australia 2. These pipelines have been built to meet the demand of Eastern Australia s gas markets. There has been a similar amount of investment in expansions of existing pipelines over that time. It is this investment that has led to the evolution of a pipeline network across eastern Australia s gas markets, promoting basin on basin competition and underpinning the emergence of trading hubs in the demand centres of Eastern Australia. It is this network that will facilitate the next evolution in trading and increased flexibility across these markets. The revenue of this infrastructure is derived entirely from providing services to gas market participants and the interests of the gas transmission industry are best met when the needs of gas market participants are met. Importantly, this investment has occurred across a mix of regulated and unregulated assets and has been facilitated through bilateral negotiation and contracts, as envisaged under the regime established in the National Gas Law. It should be noted that the revenue generated by the gas transmission industry is the lowest contributor to the final cost of gas supply to consumers. The AER 3 has estimated that transmission charges contribute from 2% to 7% to delivered retail gas prices across Australia. This suggests that reforms focussed on the gas transmission sector are unlikely to deliver significant outcomes to gas markets. Eastern Australian domestic gas markets are undergoing once-in-a-lifetime structural change. The development of an LNG export industry in Queensland is driving a surge in production activity and will increase gas demand fourfold. The Study provides an excellent overview of the environment and challenges facing Eastern Australian gas markets currently and identifies a range of policy options for consideration in a future gas market reform agenda to minimise the risks presented to the market during this period of transition. 1 This investment does not include infrastructure built for LNG projects or expansion of existing pipelines. 2 AER State of the Energy Market 2013 p AER State of the Energy Market 2009 p

4 A key theme across the policy options identified is the need for improvement of the market s characteristics of transparency, liquidity and flexibility. APIA endorses this theme and supports appropriate measures to enhance these characteristics in the market. This theme has also been a major influence in recent gas market reforms, including the National Gas Bulletin Board; the Short Term Trading Market hubs in Adelaide, Brisbane and Sydney; and the gas supply hub at Wallumbilla. In APIA s view, the past and current contemplation of the improvement of these critical market characteristics has not sufficiently recognised the role that the size and breadth of the market plays in fostering an environment for them to develop. A gas market that has more producers; more supply basins; more connections between supply and demand; more users; and, most importantly, more gas usage, will be deeper, be more liquid and drive more transparency. There will be more transactions for market participants to observe; more parties to transact with; more marginal gas to transact under shorter-term arrangements; and more demand for services that promote transparency. APIA acknowledges that this issue is in part raised by the Study in its contemplation of competition issues, however there is not an explicit goal to increase the size and breadth of Australia s gas markets. There are no options presented in the Study to increase or support gas demand. To increase gas supply and encourage new entrants there needs to be confidence there is a strong and growing demand for gas. The future reform agenda should consciously consider the balance between reform that encourages liquidity and transparency and reform that encourages growth. An agenda that encourages both at appropriate levels is likely to achieve the greatest outcomes for gas markets. There are a number of key themes and points raised in the APIA s response to the Study questions that APIA would like to highlight: 3 The greatest issues facing market participants are related to gas supply. The immediate focus of reform should be on improving transparency and competition in gas supply, with the aim of accelerating the development of Australia s gas reserves. Rather than rule particular non-market interventions out, the Government should identify circumstances under which they could address market failures. This would involve identifying trigger points for market failure and contemplating appropriate scenarios. Industry-led initiatives to develop new services aimed at improving transparency, liquidity and flexibility should be supported and preferred as a matter of principle. Services that are developed and provided under commercial frameworks are likely to be more efficient, better tailored to market needs and allocate costs more appropriately than services developed under regulatory frameworks. The Australian Energy Market Commission has not participated in gas market development at the level set out in the Australian Energy Market Agreement. Conversely, the Australian Energy Market Operator has played a much larger role. The appropriateness of this should be considered during a review of existing governance arrangements.

5 The Gas Capacity Trading Decision RIS sets out a number of transparency reforms and development of market capability in the downstream sector which are not represented in the Study. The short-term priority for downstream reform should be the effective implementation of these reforms and the industry-led development of an operational capacity transfer service. It is important to consider reform beyond refinements to regulatory and administrative regimes. Innovative policy options should be included in the discussion, they are likely to lead to more substantial outcomes than improvements to existing regimes. Rather than rule particular non-market interventions out, the Government should identify circumstances under which they could address market failures. This would involve identifying trigger points for market failure and contemplating appropriate scenarios. After responding to the Study s questions there are three issues not specifically covered by the questions that APIA raises at the end of this submission. The recommendations arising from APIA s response are: The key priority for the forward Eastern Gas Market reform agenda must be increasing gas supply (Recommendation 1, Q1). o The Eastern Gas Market reform agenda should recognise that developing the breadth and size of gas markets will foster the characteristics of transparency, liquidity and flexibility. Reform that specifically targets growth in the number of participants and gas demand should be prioritised (Recommendation 2, Q1). o A detailed review of gas market competition, focussing on competition issues relevant to gas supply, should form a key part of the Prime Minister s Competition Review (Recommendation 3, Q2). o Improved information on gas supply should be given a high priority in the forward reform agenda (Recommendation 11, Q17). o The access regime for upstream facilities should be considered when developing the forward reform agenda (Recommendation 6, Q9). o Strengthened obligations on title holders to develop known resources has high potential to deliver increased gas supply and should be considered a priority area for reform (Recommendation 7, Q10). The existing commercial environment for gas transmission pipelines has delivered timely and efficient investment that has developed an interconnected grid across Eastern Australia. Focus should be on ensuring the investment environment continues to deliver the infrastructure required to support supply and demand (Recommendation 8, Q12). o There is little benefit in further development of trading hubs prior to a review of the STTMs. Attention must be paid to assessing existing, documented issues (Recommendation 4, Q6). 4

6 o Market reviews should be conducted by independent entities (Recommendation 5, Q6). o Perceived benefits of reform in the market frameworks for gas transmission should be clearly articulated and assessed before allocating resources to a review (Recommendation 9, Q14). o Consideration should be given to the role and scope of the AEMC, with particular reference to the market development role set out for in the AEMA (Recommendation 14, Q25). The industry-led operational capacity trading initiative and the reforms outlined in the Gas Capacity Trading Decision RIS should be implemented and allowed to take effect before contemplating further initiatives in capacity trading (Recommendation 10, Q16). o The benefits of industry-led initiatives should be recognised and priority given to such approaches where they can deliver new services to market in a timely fashion (Recommendation 12, Q23). The Government should carefully consider the non-market intervention options available to it, consider the merits of each for specific circumstances and identify when it would be appropriate to contemplate the implementation of each option (Recommendation 13, Q24). 5

7 1. Gas Market Reform Agenda Q1. What should the key objectives and priorities be for the eastern gas market reform agenda in the short, medium and long term? At the outset it is important to acknowledge the size of Australia s domestic gas market and consider its position in relation to Australia s international competitiveness and the gas export opportunity. Past domestic gas market reform agendas, typically aimed at improving transparency and liquidity, do not seem to have given sufficient weight to the fact these characteristics naturally evolve and increase as markets grow. A gas market that has more producers and users, more supply basins, more connections between supply and demand and, most importantly, more gas usage, will readily evolve and develop mechanisms that provide information and facilitate trade between parties. The reform agenda to date appears to have assumed that developing mechanisms to increase transparency and liquidity will be sufficient or will, of itself, enable significant growth in the market. A future reform agenda should actively consider the balance between reform that encourages liquidity and transparency and reform that encourages growth. An agenda that encourages both at appropriate levels is likely to achieve the best outcomes for gas markets. APIA has identified several key characteristics that will be inherent an effective, efficient future Australian gas market and should guide future market reform. The economic, environmental and emissions advantages of natural gas are well understood and used to Australia s advantage. The fostering of new and increased gas supply is recognised as the highest priority to promote the principles of transparency, liquidity and flexibility. This should be achieved by efficient regulation, innovative policy (both set out in APIA s Gas Supply for Australia) and better reserve management. An important area for policy development should be the timely development of gas reserves, with stronger criteria for the renewal of retention leases and the implementation of effective sunset clauses on undeveloped reserves. It will recognise the value to market participants of contractual relationships. The contract carriage market framework for the gas transmission sector will be applied consistently across the nation, providing security of tenure and certainty to gas producers and users over market carriage. Flexibility in contract carriage markets will be supported by effective trading markets. Market information will be readily available to assist parties in reaching efficient bilateral arrangements. It facilitates further, industry-led market development. Industry-led initiatives will typically be more timely and inclusive than centralised market development. Importantly, they will focus on the needs of the market, as market participants will be explicit in defining the services they are will to pay for. 6

8 Market development initiatives will recognise and respond to the specific supply and demand parameters in each market. It is a fundamental characteristic of Australian gas markets that they are fragmented into distinct supply and demand hubs. This fact must be recognised to guide effective evolution. Where consistent approaches are possible they should be encouraged. Similarly, where there is a need for bespoke solutions, these should be accepted and developed where needed. It has consistent levels of transparency, liquidity and flexibility across the supply chain. Much of the market development activity of the last decade has focused on downstream markets and infrastructure. Timely development of gas reserves is vital to an effective and growing gas market and initiatives that improve information about future supply must be encouraged. It has co-ordinated energy policy and is one that recognises the impact of the RET and other sector specific policies on other sectors. To ensure the most effective outcomes it is necessary to have a level playing field for all forms of energy. The fostering of new and increased gas supply is recognised as the highest priority to promote the principles of transparency, liquidity and flexibility. This should be achieved by improved regulation, innovative policy (both set out in APIA s Gas Supply for Australia) and better reserve management. An important area for policy development should be the timely development of gas reserves, with stronger criteria for the renewal of retention leases and the implementation of effective sunset clauses on undeveloped reserves. In APIA s view, the key priority for the gas market reform agenda is increasing gas supply and demand. A market that is shrinking is unlikely to be more transparent, more liquid or more flexible. In the short-term the key objective and priority should be ensuring adequate gas availability for domestic and export markets. In the medium-term the key objective and priority should be to encourage sufficient gas supply to apply downward pressure on domestic wholesale gas prices and grow domestic usage. In the long-term the key objective and priority should be to grow the market to sufficient size that it will naturally develop timely and efficient mechanisms to further advance its characteristics of transparency, liquidity and flexibility. It is likely that an increased reform focus on gas supply competition, including access to upstream facilities, and market data and transparency will be the most productive work in achieving these (short, medium and long-term) priorities. To a lesser extent, improving the commercial and regulatory environment for infrastructure will be beneficial. Given the latest reforms in access regulation for energy network infrastructure and SCER s already announced decision to develop and implement mechanisms to enhance gas transmission capacity trading (which will be best leveraged by the industry-led facilitated trading service), it is appropriate to place a lower priority on future 7

9 short- and medium-term reforms in this area and allow recently implemented and flagged reforms to work. RECOMMENDATION 1: The key priority for the forward Eastern Gas Market reform agenda must be increasing gas supply. RECOMMMENDATION 2: The Eastern Gas Market reform agenda should recognise that developing the breadth and size of gas markets will foster the characteristics of transparency, liquidity and flexibility. Conversely, a market that is shrinking in size is unlikely to create an environment that promotes these characteristics.reform that specifically targets growth in the number of participants and gas demand should be prioritised. Q2. Specifically, is there merit in commissioning a review of gas market competition? If so, what are the key elements to consider for the terms of reference and review mechanism? Yes, there is merit in commission a review of gas market completion. Given the PM announced a broad review of competition policy on 4 December, on par with the Hilmer Review, it is appropriate that a detailed review of gas market competition is undertaken as part of the wider process. For any such review of competition, it is vital to consult widely and, most importantly, reflect that consultation in the terms of reference. In the introduction to this submission, APIA has noted its view that the Study has not given due weight to the two key aspects impacting many stakeholders. It is clear the competition concerns currently in the market relate to third party access to upstream infrastructure, as noted in the Study, and joint marketing of wholesale gas, as noted in the Reith Report. An additional area is the potential conflict between a producer s strategic development of gas reserves and the timely delivery of gas to markets. These elements of competition should be the focus of review, should a review be required. Competition of downstream gas markets is well regulated under the National Gas Law and no specific concerns have been raised publicly about the downstream gas market competition. As pointed out earlier, there is much progress in this area; most recently with industry-led development for capacity trading. RECOMMENDATION 3: A detailed review of gas market competition, focussing on competition issues relevant to gas supply, should form a key part of the Prime Minister s Competition Review. 8

10 Q.3 What are the appropriate principles to underpin that reform (or views on draft principles in 7.4.3)? APIA considers that future gas market reform should promote the principles of transparency, liquidity and flexibility. In promoting these principles, it is important that any market reform or development initiatives carefully consider the costs and benefits of new proposals and do not force unnecessary or overly costly measures on to the market. Further, increased transparency, liquidity and flexibility in Australia s gas markets can be driven by an increase in their size and breadth which will have substantial benefits as noted above. It is critical that the primary purpose of future reform is to foster growth in Australia s gas supply and gas demand. The draft principles outlined in are broadly appropriate. With greater emphasis placed on the role of the market and industry-led initiatives over regulatory processes and some acknowledgement that a growing gas market will drive its own improvements, the draft principles are sufficient. APIA is concerned about one particular aspect of the draft principles. The first draft principle, relating to the purpose of reform states: The purpose of gas market reform is to promote efficient gas markets in the long term interests of consumers in accordance with the National Gas Objective (which covers residential, commercial and industrial users, including making LNG). Neither the NGL nor the NGR provide a definition of consumer, which itself has proved of interest during some reform processes. As APIA notes below, the NGO was drafted in a period where gas was contemplated being imported from Papua New Guinea, not exported from multiple facilities in Queensland. However, the term is used, depending on the context, interchangeably with user or small user and is clearly intended to refer to end users of natural gas. Makers of LNG are, effectively, not gas consumers as originally envisaged in the National Gas Objective (NGO). They are vertically integrated gas exploring, producing, processing, transporting, LNG producing and exporting entities. It is therefore not clear that including LNG production in the concept of consumer under the NGO is intended or appropriate. Q.4 What implementation models do you advocate for progressing reforms? There is a role for government and industry in progressing reform. New services arising from reform initiatives should be delivered by those best placed to do so. Industry-led initiatives will typically be more timely and inclusive than centralised market development. Importantly, they will focus on the needs of the market, as market participants will define the services they require. The current evolution of transmission capacity trading serves as an excellent example where, partially in response to Government analysis, industry has developed a low-cost solution that can be rolled out 9

11 on a case-by-case basis. Ultimately, if this solution is widely adopted by customers across most pipelines, a centralised service that anonymously matches bid and offers across multiple pipelines could be developed in the future. It is likely efficient evolution of such a system would include several interim steps during its development. The STTMs have been implemented through a regulatory model and there is a strong case to make that this has caused a number of fundamental flaws limiting their utility. The STTMs impose virtual hubs over physical assets and, effectively, ignore any physical constraints. This has created problematic issues in each hub that are yet to be resolved. These are covered in more detail in APIA s response to Question 6. Further, the cost of the STTMs is smeared across all gas users at the STTM hubs, whether they use the services or not. In 2013 AEMO s cost recovery fees increased by 11% (CPI in the same period rose 2.7%) to over 7c/GJ for all gas withdrawn from the hubs (i.e. all gas used in Adelaide, Brisbane and Sydney). This adds 1 to 2% to the daily price of delivered gas in each of these markets and is not insignificant to gas users. As a matter of equity, for those users simply seeking to match flat industrial loads, charges should only be imposed on balanced volumes. Q.5 What should the key performance indicators of a well-functioning eastern gas market be? A well-functioning eastern gas market should: be growing in size; have an increasing number of participants; presenting low levels of risk to participants; respond flexibly and transparently to change; have minimal costs of operation that allocate costs of services to those participants that use a service with a net cost-benefit; and have minimal regulatory intervention. Q.6 What priority should be placed on reviewing trading markets? The trading markets have been a primary of focus of gas market reform since There should be a high priority on reviewing these markets before considering further reforms, particularly further trading market development. However, it is somewhat premature to contemplate a short-term review of trading markets when the Wallumbilla Supply Hub is due to commence in March In terms of the Short Term Trading Markets (STTM), which have been operational in Adelaide and Sydney since September 2010, there are a number of areas that should be reviewed, primarily the cost of the markets and the effectiveness of these markets. 10

12 By way of example, as detailed below, the STTM withdrawal charges will exceed 7c/GJ in 2013/14 and will grow by 12% to over 8c/GJ in 2014/15. This is a significant cost to market participants and must be weighed against the benefits delivered. With regard to the effectiveness of the markets, regardless of the volumes being traded through them, there are fundamental flaws which have been acknowledged but unsatisfactorily dealt with since market implementation. The main flaws arise from the imposition of a virtual hub over physical gas networks and the failure to adequately accommodate physical constraints. These flaws manifest differently in each hub. In Adelaide, the operating pressure of the Adelaide distribution network imposes constraints on the deliverability of gas out of the Moomba to Adelaide Pipeline and the SEA Gas Pipeline. This causes virtual swings and deviations in the market operator stack (MOS) that accrue charges that must be paid yet do not reflect the intention or reality of market participant behaviour. This issue has been labelled counter-acting MOS and has been discussed since at least early As the AER states in its weekly gas report for the week January : At the Adelaide hub MOS services payments of around $ accrued during the week, most ($ ) occurring between Monday and Thursday. These large payments, the largest of which was $ on Tuesday 14 January, were due to counteracting MOS. In Brisbane, the virtual hub does not accurately represent the physical delivery points which are spread over a 30km distance. As a result, increased capacity to the centre of Brisbane made available by changes in gas movements within the hub cannot be represented in the STTM and artificial constraints are imposed on the highly utilised Roma to Brisbane pipeline. In days of high demand, this places an unnecessary pressure on the daily price of gas in the Brisbane STTM and limits the amount of gas that can actually be delivered to participants compared to the situation prior to the implementation of the hub. In Sydney, the differing pressures of the Wollongong and Sydney gas distribution networks affect the Eastern Gas Pipeline s ability to deliver gas into Sydney. This can create a counter-acting MOS occurrence, similar to but not as severe as that which occurs in Adelaide. Each of these issues imposes real costs, in addition to the STTM withdrawal charges, that must be borne by market participants. Market reviews of this type must be undertaken by parties that are independent from the design and operation of the market. Without this independence, it would be difficult for a review body to gain an objective view of the strengths and weaknesses of each market, and to deliver a

13 disinterested analysis of issues, which may extend to matters of market design and exercise of discretion by the market operator. RECOMMENDATION 4: There is little benefit in further development of trading hubs prior to a review of the STTMs. Attention must be paid to assessing existing, documented issues. RECOMMENDATION 5: Market reviews should be conducted by independent entities. 2. Promote gas supply competition Q.7 What are the key barriers or impediments to bringing on gas reserves? An issue of increasing concern for gas supply is the political response to community opposition to gas development. This has materialised primarily in NSW and Victoria. In NSW the Government has announced a two-kilometre exclusion zone around residential zones and further exclusion zones around viticulture and equine industry clusters to prevent new coal seam gas exploration, assessment and production activities. In Victoria there is a moratorium on all unconventional gas development. This type of response does not recognise the urgent need for increased gas supplies, and poses a risk to gas supply activities. Governments must work rationally and sensibly to ensure all land uses are made available. At the same time, the industry must work to develop and maintain the social licence necessary to conduct gas development activity, and work with government to provide appropriate information to affected landholders. Q.8 How would you prioritise government action for removing unnecessary impediments or facilitating specific projects? Equal priority must be given to action that facilitates new supply and to action that increases the information available to the market on supply activity, assisting market participants to mitigation the risks posed by gas supply. The latter is particularly important in the short-term, as any actions to facilitate supply are unlikely to deliver immediate improvements. In terms of facilitating and encouraging supply, actions that provide foster supply more broadly are preferable to those that facilitate specific projects. Q.9 Beyond facilitating and encouraging supply, are there other actions needed by governments to promote competition in supply? 12

14 It is clear many stakeholders consider access to upstream infrastructure to be a priority issue. APIA has raised concerns below with the Study s conclusions on the coverage potential of upstream processing facilities under the National Access Regime and there are other matters that are worthy of consideration, such as access to upstream gathering networks and trunk lines. The Government should at least conduct a review of access to upstream infrastructure and consider the benefits of greater access to these facilities compared to any co-ordination costs that may arise. RECOMMENDATION 6: The access regime for upstream facilities should be considered when developing the forward reform agenda. Q.10 Are there specific actions in title administration and management, or pre-competitive geoscience information, which should be given priority? What are the roles for industry and governments in those actions? There are grounds for further consideration of strengthened obligations on title holders to develop known resources in a timely fashion with the potential for title to be lost if this does not occur. Such provisions are typically known as use it or lose it. The Study itself notes on p97 that: However, there may be times where a title holder s strategic interest limits the development and supply of gas. APIA believes this observation is correct and consideration must be given to a mechanism to limit the opportunity for a title holder s strategic interest to take precedence over the requirements of the broader gas market, particularly the timely provision of gas supply. RECOMMENDATION 7: Strengthened obligations on title holders to develop known resources has high potential to deliver increased gas supply and should be considered a priority area for reform. Q.11 How could regulatory frameworks be improved to avoid unnecessary delays in gas supply development? APIA s 2013 policy document, Gas Supply for Australia (ATTACHMENT A), covers this issue in some detail. A summary of options identified by APIA is provided below. Reducing red and green tape 13

15 A key improvement often cited is the need to reduce red tape and green tape. Much of the regulatory regime overseeing gas supply is duplicated across federal and state levels and this decreases efficiency. The exploration and production industry is impacted by these inefficiencies. These inefficiencies extend to the pipeline sector. Pipelines provide important access to markets for producers and shippers. Pipeline developments and expansions (such as looping) can be hampered by overlapping and complex approval processes that can span multiple state jurisdictions, and also involve the Federal Government. The requirements of various road and rail authorities are also significant. These processes can add months for approvals before actual construction work can commence. Improving exploration information deficiencies Gas exploration is a high-risk activity, with significant capital investment required to locate and prove reserves. If successful, the rewards are sufficient to justify the investment and risk. Early availability of information can help increase investment and ensure it is directed to the most prospective regions. Through Government geoscience organisations, a range of information is available. Geoscience organisations both fund the gathering of new data and receive data from current explorers, the latter usually being subject to confidentially arrangements to give early movers appropriate financial security. Government can improve information arrangements by increasing funding and release of its own data and reducing the timeframes for release of privately captured data. This would increase the efficiency of exploration by: Better allocation of scarce exploration resources through government provision of increased early-stage data on prospective regions; and Improved competition by increasing the release of privately captured data into the public domain. More information on exploration information deficiencies is available in Appendix C of ACIL Allen s report. Changes to management of tenements Exploration The majority of Australian gas exploration tenements are offered on the basis of work bidding, with the proponent offering to do the most exploration in an area being awarded the tenement. This system has been put in place on the assumption that early and more exploration work is desirable. However, tenement allocation systems designed to increase the pace of exploration can lead to a misallocation of exploration resources, with proponents committing to more than necessary exploration work to secure a tenement. This misallocation leads to other areas not receiving enough exploration resources, diminishing the size of Australia s total gas reserves, gas supply and tax revenue. 14

16 A thorough reform of exploration tenement regimes is necessary in order to avoid misallocation and resource rent dissipation. More information on management of exploration tenements is available in Appendix E of ACIL Allen s report. Development clauses Given the potential for conflict between the strategic considerations of a tenement holders commercial interests and the need to ensure timely provision of gas supply, it is appropriate to consider developing clauses for petroleum tenements that ensure development milestones and timeframes are met. Royalty and taxation reform There are multiple forms of taxation that apply to the gas supply industry. At the Federal level, the company tax and petroleum resource rent tax regimes apply. At the State level, multiple royalty tax regimes are in place. These tax regimes distort incentives to explore, invest and extract. For example, different royalty rates in different states may direct investment toward one state over another, all other matters being equal. 3. Improve commercial and regulatory environment for infrastructure Q.12 Do you consider that the current gas supply infrastructure is adequate to support new upstream gas supply and effective competition? This question ignores the investment reality for gas infrastructure, it is built to meet existing requirements. A better question to ask is: Is the investment environment adequate to deliver the infrastructure required to support new upstream gas supply and effective competition? Whilst there are always improvements that can be made, the evidence of infrastructure development in Queensland to support the LNG developments suggest that, overall, the investment environment is adequate. Further, there is no evidence that any market is not being adequately serviced by transmission infrastructure. In respect to pipelines, gas transmission infrastructure is capable of meeting current and foreseeable gas demand in eastern Australia. When considering investment in this infrastructure is important to note that the prevailing model, that of contract carriage enables: Certainty for pipeline investors to reduce the risk of asset stranding and attract finance on very competitive terms. These lower financing costs in turn deliver lower cost transportation to shippers. Certainty of supply for shippers, enabling them to justify large expenditure in gas plant and equipment. 15

17 Unlike upstream facilities that have access to world prices for commodities, gas transmission companies generate their revenue by selling access to infrastructure bound within a domestic framework of regulation and demand centres. It is in the gas transmission industry s interest to encourage new upstream supply and additional users of its infrastructure. Additionally, the National Gas Law provides an effective access regime that market participants can access for all transmission pipelines, including those currently uncovered. This contrasts with upstream facilities, particularly processing facilities. The owner of an upstream facility has potential reasons to limit access to its facility: To prevent or increase the cost of a competitor from entering a gas supply market. To prevent or increase the cost of a competitor from developing gas reserves that the facility owner wishes to acquire. RECOMMENDATION 8: The existing commercial environment for gas transmission pipelines has delivered timely and efficient investment that has developed an interconnected grid across Eastern Australia. Focus should be on ensuring the investment environment continues to deliver the infrastructure required to support supply and demand. Q.13 What type of information, if any, would help improve price discovery and utilisation of infrastructure? There are a number of information reforms proposed under the Gas Capacity Trading Decision RIS and APIA supports, subject to confirmation of final detail, these reforms. APIA notes that in reality, lack of information is unlikely to be limiting infrastructure utilisation in any meaningful way. Better utilisation of infrastructure, particularly gas transmission infrastructure, will occur with increased gas usage. In APIA s view the policy focus should be on: Encouraging investment in counter-cyclical demand. An example may be the development of peaking gas power generation, typically in use on hot summer days, on a pipeline that experiences large winter demand. Encouraging the development of increased baseload gas power generation and new large industrial demand. The development of new, large, relatively flat loads will not reduce peaks but will decrease the differential between peak and non-peak usage, leading to relatively less unused capacity in non-peak times and increasing the efficiency of infrastructure. In short and as noted above, APIA considers the best way to improve all aspects of Australia s gas markets is to focus on measures that will increase the size of these markets. Q.14 Do you support exploring the merits of contract vs market carriage options? If so, how would you recommend pursuing this work? 16

18 APIA questions the merits of comparing contract and market carriage arrangements, particularly the perceived value that can be had from initiating a major change from existing arrangements. As noted above, gas transmission costs are a minor component of the delivered gas price. In APIA s view, the investment in gas transmission pipelines delivered under the contract carriage model speaks for itself. Since 2000, the contract carriage model has delivered over $2.2 billion in timely investment providing 4000km of major new gas transmission pipelines in eastern and northern Australia 5. A similar magnitude of investment has occurred in expanding the capacity of existing pipelines during this time. It is this investment that has led to the evolution of a pipeline network across eastern Australia s gas markets and it is this network that will facilitate the next evolution in trading and increased flexibility across these markets. In Western Australia, the contract carriage model has supported investment in expanding the State s two major pipelines in excess of $2 billion in the last ten years. Before contemplating such a review, it is important to understand the scope of any benefits that are perceived to arise from a change to the existing market frameworks for gas transmission. Given the low costs of gas transmission and the absence of any evidence, or claim, of market failure in the market for transmission capacity, it is not apparent that are substantial gains or improvements to be made by reform in this area. This contrasts with the potential benefits from reform that will facilitate and encourage gas supply, which have much greater potential to deliver real improvements to the market environment. APIA questions why the Study identifies this review, with major potential implications for the commercial framework of the gas transmission market, as a clear option for the future reform agenda but does not pose similarly big questions for other market sectors. Before proceeding on this review, such questions deserve further consideration. If a broad review is to be undertaken APIA considers the Australian Energy Market Commission to be best placed to conduct this review. RECOMMENDATION 9: Perceived benefits of reform in the market frameworks for gas transmission should be clearly articulated and assessed before allocating resources to a review. Q.15 Is there a role for government in supporting feasibility studies on potential infrastructure projects? If so, what would be some of the key infrastructure proposals that should be assessed? 5 AER State of the Energy Market 2013 p This investment does not include expansions of existing pipelines or pipelines built as part of the LNG projects in Queensland. 17

19 Yes there is such a role for Government. However, Government should be cautious to anticipate specific projects ahead of the market. If a project proponent considers such support would be beneficial to a project then Government should be ready to help. Q.16 What do you see as the merits or otherwise of enhancing pipeline capacity trading? What are the main issues to consider when developing a roadmap for this reform, including implementing recent SCER commitments? The gas capacity trading reforms formed a major piece of SCER s 2013 gas market reform agenda and it has led to a number of commitments that will have an impact on the environment for capacity trading. Implementation of the recent SCER commitments should be a priority and further action prior to implementation would be premature. The commitments will increase information and capacity trading opportunities substantially and will operate alongside industry-led initiatives currently under development. There should be an appropriate period of time, 3 to 5 years, before considering further reform. This will enable observation of the outcomes of such reform. The market will develop new methods and commercial arrangements to utilise the proposed new market information and capability and these will take time to take effect. As noted above, gas transmission companies working with customers to develop a consistent framework for the provision of operational capacity transfers. Operational capacity transfers are superior to bare capacity transfers for a number of reasons. They: are an incentive to offer capacity, as it reduces the administrative burden for shippers; provide a more appropriate allocation of risk as the obligations of the seller are transferred to buyer; increase operational efficiency as it preserves the relationship between pipeline operator and shippers, both new and existing; allow a buyer of traded capacity to easily aggregate capacity from multiple sellers; improve transparency through publication of bids and offers, information on trades, available and contracted capacity; and support new entrants as it allows new shippers to access short-term capacity. Engagement with market participants has shown a clear preference for operational transfers and it is expected that this service will be utilised where there is a market need. The Study does not recognise that this initiative, initially advocated by APA Group, has been endorsed by the gas transmission industry and can be readily applied to any pipeline in response to market need. Operational capacity transfers will be available on Wallumbilla hub pipelines operated by APA Group and Jemena at the commencement of that market. Both companies, and other pipeline service providers, are investigating its utility in other markets and on other pipelines. 18

20 Gas transmission capacity trading was, along with the development of the Wallumbilla hub, the main focus of SCER s gas market reform agenda in Changes are underway. Given the commitments made and to be implemented, a continued regulatory reform focus on this issue in the short-term is unlikely to yield improved outcomes. There are a number of areas of concern for gas market participants, several raised directly by senior energy industry stakeholders at December SCER meeting s Stakeholder Forum and none of them are related to capacity trading. RECOMMENDATION 10: The industry-led operational capacity trading initiative and the reforms outlined in the Gas Capacity Trading Decision RIS should be implemented and allowed to take effect before contemplating further initiatives in capacity trading. 4. Market data and transparency Q.17 To what extent do you consider that improved market information on CSG delivery is important to assist market participants in managing risk? To the extent that this is considered a significant issue, what specific information is most important and why? Improved market information on CSG delivery is vital to assist market participants in managing risk. Such information is necessary to form a view on supply availability, the key issue for most market participants as evidenced through the SCER Stakeholder Forum, media reports and public submissions. CSG deliverability is not the only supply information of interest. Increasingly, the LNG facilities are exerting influence over the entire gas market, with large volumes of gas supply flagged from the Cooper Basin and many parties actively exploring other opportunities to supply gas into Queensland. Initiatives in this area should not focus exclusively on CSG. The size of the CSG export demand in Queensland means that any shortfall in CSG delivery has implications for the entire eastern market, with LNG producers well placed to swap gas, provide preferential treatment to each other and to readily subsume all available gas supplies. The shortand long-term risks presented to eastern gas markets from problems with CSG delivery cannot be overstated. In the short-term, any temporary deliverability issues have an immediate impact, with an LNG exporter likely to have a temporary demand for as much gas as the market can supply. This will have price impacts at trading hubs and short-term arrangements. In the medium and long-term, the predicted production schedule of CSG fields supplying LNG facilities and the performance in meeting it will influence the total available gas supply. If production forecasts and well drilling programs are matching well with LNG ramp rates, the market can be confident supply will be adequate. If they are not meeting expectations, further supply tightness can be anticipated. 19

21 These risks will be amongst the largest influences on gas supply and price for the eastern gas market in the years ahead. Increased transparency on these matters is necessary. The Study identifies limited options to compel the release of such data in the short run and this should be seen as an indication that more focus should be put on this important issue. RECOMMENDATION 11: Improved information on gas supply should be given a high priority in the forward reform agenda. Q.18 To what extent do you consider such data could be delivered via voluntary reporting? What commercial sensitivities would need to be addressed? What mechanisms should be used to collect the data and who should be responsible for data collection? What would be the likely compliance costs? Q.19 Is there merit in the government considering pursuing mandatory reporting of such data? Voluntary reporting of information can work, but only in circumstances where its provision is in the interest of the provider or at least neutral. In the case of the information proposed, this is unlikely to be the case. Mandatory processes are likely to be more effective in delivering the proposed information, information which has great implications for market and supply risk and is of high consequence to the market. APIA notes that a range of mandatory data is contemplated in the Capacity Trading Decision RIS to improve the environment for capacity trading. In each instance, the best outcomes will be achieved when government and market participants work closely to best determine the information that will be of most utility. Q.20 Are there priority areas for improvement to the National Gas Market Bulletin Board, Short Term Trading Market and GSOO? A range of improvements have been proposed for the National Gas Market Bulletin Board in SCER s Gas Capacity Trading Decision RIS and these should be implemented. The STTMs must be improved to address the failings arising from the imposition of virtual hubs over physical networks as detailed above. Q.21 Are there any other key information gaps that, if filled, would enhance the operation of the market? What would be likely sources of significant costs and benefits of addressing these gaps? It is necessary that all transparency reforms have detailed, comprehensive cost benefit analyses accompanying them. It is easy to assume transparency initiatives deliver major benefits to the market and to consider such initiatives are sufficient to drive change and reform. 20

22 Q.22 What do you see as the role of forward markets for improving wholesale market efficiency? Do you see there is a need to improve on current markets and what would you propose as the mechanism for progressing any reforms? Q.23 What do you see as the role of industry-led approaches in the Study, like price indices? Are there any other industry-led initiatives or tools that could assist stakeholders and what should be the role of government in facilitating such work? The role of industry-led approaches is a very important one. Industry-led approaches are the most likely to lead to the timely provision of new services that are tailored to the specific needs of market participants. It is APIA s view that this fact is often over looked when government initiates, develops and implements gas market reforms. There are several segments of gas market whose business model is predicated on the delivery of services to the market. The gas transmission industry is one such segment. It is in the interest of these service providers to develop new services, be flexible in the delivery of service and provide as many services as possible. There is a threat that government initiatives will erode value associated with offering those services and stifle innovation in developing new services. One factor that could be limiting the development of new services is the number of market participants to offer such services to. The relatively small number of market participants in eastern Australia is demonstrated in the number of registered STTM participants above. APIA considers a focus on increasing the number of market participants will improve information and market efficiency. RECOMMENDATION 12: The benefits of industry-led initiatives should be recognised and priority given to such approaches where they can deliver new services to market in a timely fashion. 5. Role for non-market intervention Q.24 Should non-market interventions like reservation policy or export controls be ruled out? The future gas market reform agenda is of great importance to Australia s economy, with its influence extending both to essential domestic energy supply and export issues. The composition of questions that will shape the agenda are of high consequence. With regard to possible non-market interventions, APIA does not consider it appropriate to rule out individual policy mechanisms. The Government should carefully consider the options available to it, consider the merits of each for specific circumstances and identify when it would be appropriate to contemplate the implementation of each option. By way of example, gas reservation in Eastern Australia has been the subject of extensive discussion in recent years and advocates for and against have allocated significant resources to making their case. APIA supports SCER s current position on gas reservation as outlined in the Study and does not 21

23 believe it presents a viable option to improve long-term gas supply and should not be applied to retrospectively to existing projects. However, there may be circumstances under which a gas reservation policy becomes appropriate. Consider the potential responses to a gas supply emergency: in a case where a failure in the gas supply chain (such as the 1998 Longford incident) reduces the capacity to deliver gas to domestic and export markets, the Government is likely to have to direct the allocation of gas by gas producers in the short-term in some way. Such an approach can be labelled a form of gas reservation. If the Government rules out such a policy under any circumstance, it may limit options available to it in times of crisis. With regard to export controls, including the national interest test, there is a stronger case for such mechanisms to be explored in the short-term. As recently as 2010 it was assumed there would be a flood of ramp-up gas from the LNG projects, driving down gas prices and increasing gas usage. The opposite has eventuated. It is appropriate that some consideration is given to impacts on domestic markets before further LNG projects, whether expansions or new, proceed. It is apparent that a typical LNG project has roughly equivalent gas demand as the entire eastern domestic gas market. It is reasonable to question the impact any further facilities will have on a major energy source for Eastern Australia. RECOMMENDATION 13: The Government should carefully consider the non-market intervention options available to it, consider the merits of each for specific circumstances and identify when it would be appropriate to contemplate the implementation of each option. Q.25 What circumstance(s) would support a potential role for non-market interventions in the eastern gas market? What would be the objective/s of such an intervention? What mechanism/s would you advocate, including views on managing trade-offs or any negative consequences? As detailed in APIA s 2013 document, Gas Supply for Australia, APIA believes it necessary for Government to ask these questions and fully consider responses. This will provide gas market participants with some assurance that worse case gas supply scenarios have been considered and planned for. As such, APIA welcomes this question in the Study and considers there to be a significant value to allocating resources to exploring triggers and responses. APIA considers a circumstance where domestic gas users are asked to pay gas prices above the LNG netback price should be a trigger for intervention. In such a case there is clearly insufficient supply to cover both export and domestic demand domestic demand is likely to be lower priority for LNG exporters. Such a supply tightness has broader implications for energy security and creates real potential for permanent demand destruction. 22

24 In the very short-term, it may be that the only efficient option available to address the high prices created by a market failure in gas supply is some form of temporary, targeted demand-side compensation package. This would ensure the, presumably temporary, high prices do not cause long-term or permanent damage to gas price sensitive sectors of the Australia economy. The permanent loss of long-term viable industries due to short-term pressures is a sub-optimal outcome for the Australian economy. Greater consideration of this question, including exploration of failures in Australia s gas markets, is made in APIA s 2013 position paper, Gas Supply for Australia, which has been provided to Government and is attached at Attachment A for completeness. 6. Governance and implementation issues Q.26 Are there mechanisms for improving the gas market governance framework, including the role and responsibilities of SCER and institutions? APIA considers the role the AEMC plays in gas market development can be strengthened and improved. The gas market governance framework, outlining the responsibilities of SCER, the AEMC, AEMO and the AER was developed and finalised in the mid-2000s, in a gas market environment that is very different from that of today. That environment did not include an east coast LNG export industry with demand three times that of eastern Australian domestic markets. It is clear there is major structural change underway catalysed by the development of this LNG export industry and it is appropriate to consider certain aspects existing institutional frameworks. From APIA s perspective, the AEMC s ability to conduct energy market reviews and provide advice to SCER is limited by the disconnect between the scope of its function and the new market environment. One way it has already impacted is in the AEMC s inability to fully consider upstream gas market issues and provide advice to SCER on these matters, as the AEMC commented in its information note on its 2013 Gas Market Scoping Study 6 : The Commission recognises that a study of this nature will not address the upstream physical supplyside issues currently affecting the eastern gas market. This is because questions around the physical supply of gas relate to areas outside of the AEMC s functions. In addition, APIA believes it is appropriate to consider the AEMC s and AEMO S role in gas market development. Section 5.1 of the Australian Energy Market Agreement (AEMA) is clear:

25 The Parties agree that the Australian energy market institutions will comprise: (a) The AEMC, responsible for rule-making and energy market development at a national level, including in respect of the National Electricity Rules, the National Gas Rules and the National Energy Retail Rules. (b) The AER, responsible for regulation and compliance at a national level, including in respect of the Australian Energy Market Legislation. (c) AEMO, responsible for the day-to-day operation and administration of both the power system and electricity wholesale spot market in the NEM, the retail electricity markets, the retail and wholesale gas markets and other support activities. 7 Even so, in practice, the AEMC has played very little role in gas market development, with the primary development responsibility of the STTMs and the Wallumbilla hub falling to AEMO. The division of responsibilities outlined in the AEMA was intentional, to ensure that the institutions with administrative and compliance obligations did not have excessive influence over the markets to be administered and regulated. This separation is essential to ensuring that markets, their administration and regulation are efficient and deliver net benefits. SCER s ongoing practice of tasking AEMO with gas market development responsibilities should be reconsidered in light of the stated responsibilities, and intentions behind these, in the AEMA. RECOMMENDATION 14: Consideration should be given to the role and scope of the AEMC, with particular reference to the market development role set out for in the AEMA. Q.27 What would be useful processes to facilitate stakeholder engagement and improve accountabilities? One process to increase accountability of the governance institutions is to conduct an independent review into the scope of their responsibilities and the timeliness and outcomes of each institution in meeting its responsibilities. There is also scope to improve accountability by mandating timeframes for some NGR processes that do not currently have them. Two that occur to APIA are: The AEMC must follow defined timeframes in making a decision once it publishes a rule change proposal. There is no equivalent timeframe set out in the NGR to direct the AEMC to publish (or decline to publish) a rule change proposal once it has been received. There are a number of reviews of various initiatives required under the NGR, which typically require AEMO to conduct the review and publish results by a specific date. There is then no corresponding time to implement recommendations of the review. Whilst APIA considers 7 Section 5.1 of the AEMA, 9 December

26 25 the mandating of reviews to be unnecessary, if reviews are to be mandated under the NGR a timeframe for implementing recommendations should also be mandated.

27 Other issues Recommendation on standard terms and conditions for secondary capacity trading In reference to the Gas Capacity Trading Decision RIS, the Study states on page 102 that one of the recommendations is: developing standardised contractual terms and conditions applying to pipeline transport This is also stated in the executive summary of the Decision RIS. This statement is inaccurate. The Decision RIS on page 60 actually recommends to: Develop standard contractual terms and conditions for secondary capacity trade. This is an important distinction and it is important the actual recommendation is reflected accurately in future publications. Role of trading markets and contractual arrangements in the Eastern Australian Gas Market The Study does not sufficiently acknowledge recent gas market reforms such as the Bulletin Board and the three Short Term Trading Markets (STTMs). The STTMs have been designed specifically as balancing mechanisms to support the bilateral contract market. The Study acknowledges low volumes of gas traded through the STTMs but does not make any conclusions about this. they currently trade insignificant gas volumes. (p64) The Australian Energy Market Commission s recently completed Gas Market Scoping Study sets out 8, in APIA s view, that STTM usage is significant in the context on the STTMs primary purpose, that of a balancing market: In terms of the overall size of the STTMs, when measured on the basis of scheduled ex-ante quantities, Sydney is the largest, followed in declining order by Brisbane and Adelaide. In terms of traded volumes, estimates developed by Deloitte indicate the following: 12% of the gas supplied to Adelaide over the period 1 July June 2012 was traded in the STTM and around 7% was traded between different parties; 8% the gas supplied to Sydney over the same period was traded through the STTM with around 4% traded between different parties; and 5% of the gas supplies in Brisbane over the period 1 December June 2012 was traded through the STTM with around 3% traded between different parties. 8 AEMC Gas Market Scoping Study 2013, p62 26

28 Given the Study has stated this proportion of total flow to be insignificant, it would be useful if the future gas market development activity sets and articulates clear goals for outcomes, such as volumes traded in the STTM. APIA considers a more significant issue is the small number of registered participants. As the AEMC states 9 : At present there are: nine shippers and seven users (six retailers and one large end-user) in the Adelaide STTM. All of the registered users in this STTM also have a corresponding shipper status; eight shippers and eight users (four retailers, three large end-users and one generator) in the Brisbane STTM. Of the eight registered users, all but one has a corresponding shipper status; and 12 shippers and ten users (five retailers, four large end-users and one generator) in the Sydney STTM. Of the ten registered users, all but one has a corresponding shipper status. The number of participants reflects the small size of eastern domestic gas markets. As stated, APIA considers a key priority of further reform should be the expansion, in size and participation, of Australia s domestic gas markets. This is most likely to lead to the development of significant and useful trading markets and increasing short-term market transactions that aide liquidity. In reality, in the Australian market, bilateral contracts underpin investment in gas production, transportation infrastructure and the facilities that create gas demand. Gas producers, particularly smaller producers, require contracts to justify the development of resources and building of upstream infrastructure. Gas transporters require contracts to mitigate the risk of stranded assets and access low-cost finance (which reduces the cost of transportation for all). Gas users require contracts to underpin investment in plant and equipment that use gas. LNG exporters require contracts to underpin the tens of billions of dollars of investment required to develop LNG export capability. There is a role for mechanisms that enable and facilitate shorter-term transactions. The importance and relevance of these mechanisms will increase as there is more gas available to be transacted. The supply and demand of gas transacted under short-term arrangements will be developed through investments underpinned by contracts. Policy reform seek to increase the amount of gas available to the market, not shift existing supply arrangements to shorter-term transactions. To cannibalise gas available under contract to increase gas available for short-term transactions would, ultimately, reduce investment in gas plant and gas infrastructure, reduce demand for gas and reduce the relevance of trading markets. 9 AEMC Gas Market Scoping Study 2013, p59 27

29 Access to upstream facilities Of critical importance is the fact that the Study has misinterpreted the Productivity Commission s (PC) view on the exclusion of processing facilities in the CCA 2010 and the actual likelihood of access requests to processing facilities under the CCA The Study states: While the Productivity Commission did not consider the National Gas Law, the two regimes are similar and the Commission concluded that processing facilities should not be included as facilities covered in the National Access Regime. (p54) The PC did not make this conclusion and in this matter APIA notes the following. Firstly, the PC makes no direct mention of processing facilities in its draft report, as implied in the Study s statement of the PC s conclusion. Secondly, the exclusion for coverage under the CCA 2010 does not apply specifically to processing facilities; it applies to production processes. As the PC notes on page 149 of its draft report: BHP Billiton appealed this decision to the High Court (BHP Billiton Iron Ore Pty Ltd v National Competition Council [2008] HCA 45), which found that the rail lines are an integral part of the rail line operator s production process for a marketable commodity (accepting the definition used in the Hamersley case). However, the Court also found that use of the rail lines (part of the production process) by an access seeker did not constitute a use of that production process. The High Court s decision means that use of part of a production process does not constitute use of the production process itself and is covered by the National Access Regime. The definition of production in the CCA 2010 is: "production" includes manufacture, processing, treatment, assembly, disassembly, renovation, restoration, growing, raising, mining, extraction, harvesting, fishing, capturing and gathering. In the case of the upstream gas industry, the production process itself would comprise the extraction infrastructure (wells and well head), treatment infrastructure, transport infrastructure (gathering networks and trunklines) and processing infrastructure (the processing facility). As the processing facility is part, not the total, of the production process it should be eligible for coverage. Importantly, the PC does not dispute or criticise the decision of the High Court nor suggest the National Access Regime needs to be altered to alleviate the effects of the High Court s decision. Rather, the PC states, also on p149: In this context, the Commission considers that the production process exception provides a useful initial filter for the obvious cases where coordination costs will exceed any competition benefits. 28

30 Subsequently in the draft report the PC suggests improvements to the consideration of coordination costs. APIA believes the correct interpretation of the PC s considerations of the production process exemption to the CCA 2010 is that access to part of production process is covered under the CCA 2010 where the competition benefits exceed the coordination costs for that part. As gas processing facilities in Australia do process third party gas, it is likely the coordination costs are not prohibitively high. APIA believes the Study s representation of the PC draft report is incorrect and the interpretation of the CCA 2010 is not entirely correct. This is a key matter to be addressed and it is APIA s strong view that the future gas market reform agenda needs to consider questions of access and competition in upstream gas markets. 29

31 Securing Australia s Gas Future Lower emissions Higher efficiency July 2013 Australia has abundant supplies of natural gas and it is an essential part of Australia s energy mix, with tremendous benefits: Low emission energy Security of energy supply Economic efficiency Natural gas in Australia provides heat and power, efficiently and cleanly. Natural gas is a major export earner for Australia. It is time to ensure that the best policies are in place so that Australia can make the most efficient and effective use of natural gas for the national economy and the nation s people.

32 Report released July 2013 The Australian Pipeline Industry Association L1, 7 National Cct Barton ACT 2600 PO Box 5416 Kingston ACT 2604 (02) apia@apia.asn.au Page 2 Securing Australia s Gas Future

33 Executive summary Australia s gas markets are in the midst of their largest structural change since the privatisation of gas infrastructure assets in the 1990s. This latest structural change is driven by the expansion of liquefied natural gas (LNG) export facilities in Australia s west and north and by the development of LNG export facilities in the east for the first time. Australia is currently the world s third-largest LNG exporter and is on track to be the largest exporter by Australia is now a major participant in the international gas market. The benefits of increased LNG exports will be felt by Australians in the form of increased Government revenues from taxes and royalties. Australia s relatively (on a global scale) small local gas markets are dwarfed in comparison to the demand created by these export facilities, which require massive investments and enable the shipping of LNG to energy hungry global markets, particularly those of Asia. The demand for gas from the existing and new LNG facilities will be almost triple that of the entire domestic market. This means that the fortunes of the domestic market are now inextricably linked to the ability of gas producers to meet the demand of their export facilities. The rapid expansion of coal seam gas development and related infrastructure has increased demand for resources which has challenged the capacity of the Australian gas industry and resulted in rapid escalation of costs. Severe weather events in Queensland have pushed back production schedules. While the outcome remains unclear, the expectations of stakeholders in the domestic gas market are that the presumed readily available ramp-up gas from the LNG projects might be difficult to achieve. Already, in the current market, domestic gas users are facing prices for longterm supplies of gas that are double that of the long-term average. These issues may be resolved relatively simply or could continue for some time. With the surge in demand continuing for the next few years, increasingly difficult, and expensive, reserves of natural gas will need to be accessed in order to meet the demand. However the supply-demand balance is achieved, it is apparent that the structural change will have short- and long-term consequences. Development of Australia s natural gas resources is a positive for the industry and the economy; however, policy makers must develop an informed view about the costs and benefits associated with the export of natural gas and the use of natural gas in the economy. The direct impact on Government revenue from exports is clear and positive. The indirect impacts of high gas prices on Australia s domestic industries are not clear. The Federal Government s Energy White Paper sets out the challenges for Australian gas markets and notes they are currently experiencing a transition period. It states that there is no evidence of market failure to justify government intervention and that the Government will monitor markets closely to ensure the timely and adequate supply of gas to meet domestic needs. The Energy White Paper does not identify Page 3 Securing Australia s Gas Future

34 what market conditions would provide evidence of a market failure and what the Government would do if it occurs. If a market failure does occur in gas supply, the Government will need to act swiftly and decisively to minimise its impact. A market failure of supply would be characterised by unsustainably high prices in domestic markets with a potential for permanent demand destruction. This has direct and indirect implications for Australia s manufacturing, agricultural and construction sectors. There are very few options to address a failure of gas supply in the short term. Each would involve market intervention. In the long-term, it is apparent that the impacts of the structural change currently under way can be minimised by Government encouraging gas supply, putting in place regulatory systems, administration and policies that will improve the efficiency of the regulatory environment and accelerating the development of Australia s extensive gas reserves. It is clear there is sufficient gas in Australia to meet the needs of domestic and export markets; it is incumbent on Government to ensure the appropriate conditions are in place to facilitate the necessary investment. In addition to creating a positive environment for gas investment, it is also vital that the Government provide the necessary signals to investors that natural gas has a long-term role in Australia s energy mix. The low emissions intensity of electricity generated from natural gas, the highly efficient heating capacity of natural gas in direct applications, the economic and environmental efficiency of the transmission pipelines that carry natural gas can all contribute to rapidly reduce Australia greenhouse gas emissions at very low cost if the appropriate policy environment exists. Planning for electricity investments that will supply electricity post 2020, must begin soon, given the lead times (at least three years) required for long lived infrastructure. In the absence of useful signals from Government, industry could make short-term, less efficient decisions. The Government should commence development of an emissions intensity based electricity sector scheme to ensure appropriate energy investment in 2020 and beyond. Such a scheme would be technology neutral, supporting all technologies that reduce the average emissions intensity of electricity generation. Australia is fortunate to have large reserves of natural gas, a stable regulatory environment, efficient infrastructure and well-developed downstream gas markets; it is important to establish an environment that maximises the nation s ability to exploit this energy source for economic and environmental benefits. APIA is of the view that, in addition to structural changes in Australia s gas markets, policy failure is exacerbating future challenges. In light of this, government should consider the policy intent of recent regulatory interventions and the policy establishing market frameworks. To date, policy makers have been tempted to focus on what appears to be simple solutions making the domestic market work better, drawing comparisons with the US market. However, this assumes the domestic market requires improvement, and there is no evidence of this. Both in a practical sense and economic sense, such a small (compared to the US), illiquid market must have the security of long-term contracts in order to underwrite or provide the finance for infrastructure, thus Page 4 Securing Australia s Gas Future

35 facilitating expansions as required. The gas transportation system works: suppliers and users reach an agreement and the infrastructure will be expanded or constructed to meet requirements usually well before the completion of the facilities that require the gas. Pipelines are built to meet peak capacity and are usually fully utilised during peak periods. However, there is available capacity for shippers to move gas during nonpeak periods, and this interruptible capacity is readily available either from the pipeline owner or the gas user which has purchased capacity to meet peak requirements but will not use that capacity during non-peak periods. To address the short term transitional issues in Australia s gas markets, APIA recommends: The Federal Government work with gas stakeholders to establish and implement effective monitoring of gas markets, with clearly identified triggers (such as price) for potential market failure; As a matter of urgency, the Standing Council on Energy and Resources identify the policy mechanisms it would use to respond to a short-term gas supply shortfall if the monitoring provided evidence of this. To address the long-term issues created by the structural changes in Australia s gas markets, APIA recommends the Federal Government should prepare policy to increase the efficiency of gas supply and consider policy that will accelerate the development of Australia s gas reserves. Such policy should include: A supply-side policy the Government should establish technology neutral energy investment policy that allows renewables, clean coal, low-emission gas and other clean technologies to compete for funding on the basis of emissions reduction and energy supply. A demand-side policy a technology neutral emissions intensity electricity sector scheme should be established to provide appropriate signals to investors. In the case of gas, it would provide all investors, including explorers, with the signal that low-emission gas technology has an important role to play in the electricity sector. Improvements to regulatory and administration regimes, including tenement management, taxation, land access and information. Page 5 Securing Australia s Gas Future

36 Table of Contents 1. Natural gas is an essential fuel for the Australian economy 7 2. The current situation 8 3. The importance of unlocking gas supply Lower gas prices Lower greenhouse gas emissions Improved energy security Increasing gas supply Accelerating innovative investment Other measures to encourage supply development Delivering efficient power generation investment Mitigating the effects of potential transitional pressures The case for Government intervention in markets Analysis of the short-term situation Easing short-term transitional pressures The policy settings for Australia s gas markets Recommendations 26 APPENDIX A: Overview of natural gas in Australia 28 APPENDIX B: Analysis of the GGAS Scheme 34 APPENDIX C: Discussion of market failure in the east Australian gas market 36 ATTACHMENT 1: Australia s Natural Gas Supply: an assessment of current policy issues and options ACIL Allen Consulting Page 6 Securing Australia s Gas Future

37 1. Natural gas is an essential fuel for the Australian economy Natural gas is an essential part of Australia s energy mix. In 2010/11, 1515 petajoules (PJ) of natural gas was consumed in Australia, comprising 24.8% of our primary energy needs 1. Appendix A contains further background information and details of gas in Australia. In Australia, there are three distinct geographical areas that can be considered separate markets. These are the eastern market, the western market and the northern market, displayed on the map below. Figure 1: Australia s Gas Markets Source: RET, GA & BREE (2012). The eastern gas market, the focus of this document, is the largest and most mature market. There are multiple demand centres and source basins spanning the states of Queensland, New South Wales, the Australian Capital Territory, Victoria, South Australia and Tasmania. A number of major transmission pipelines connect sources and demand centres between these states. The development of CSG reserves and LNG export facilities is a major activity underway in this market. 1 Energy in Australia 2013 Page 7 Securing Australia s Gas Future

38 2. The current situation The current circumstances of gas markets in Australia, particularly east coast markets, have been discussed at great length. The development of an LNG export industry will see east coast natural gas demand increase from around 700PJ/annum to almost 2,500PJ/annum in less than 5 years. The work required by the production industry to meet this new demand is extensive, and can be impacted by environmental and water controls, extreme weather events, disproved forecasting and community and political reaction to the expanding CSG industry. This challenging demand growth occurs at a time when the long-term gas supply contracts of many existing Australian gas users are due to expire. Gas users are faced with new risks in regard to terms and price; the only certainty being that existing arrangements will not continue. The Australian Government s Energy White Paper (Nov 2012) summarises the issue as follows: Australia s eastern gas market has entered a period of extended transition as new CSG reserves and LNG developments reshape market dynamics and structure. LNG supply requirements are sharpening competition for gas and will remain the main driver of market expansion for the next decade or longer. Many domestic large-user contracts expire from 2014 onwards, and new supply contracts have yet to be negotiated. The impacts of carbon pricing and lower than previously expected electricity demand on the prospects for gas-fired power generation are also unclear. While there may be a need for additional peaking plant, new gas-fired base-load capacity may not be needed until later this decade (or beyond) if overall demand remains subdued. The combined impact that these factors will have on final demand for gas is not yet clear, although overall growth is expected. The Energy White Paper states that the structural changes in the market are likely to have long term effects on gas prices: The cost base of the market is also increasing because new production is from higher-cost resources. However, demand competition from LNG expansion is also expected to become a more significant driver of prices, which are widely forecast to increase towards LNG netback levels by the second half of the decade. The 2012 Queensland gas market review modelled domestic gas prices ranging from $6.50/GJ to $10/GJ by 2015, depending on the LNG development outlook. ACIL Tasman has projected regional gas prices rising to $11 and above by While developing CSG remains challenging, there is projected to be enough gas to meet all expected demand well beyond 2035 if known reserves can be brought on, and there is good potential to identify further commercially viable CSG and new shale and tight gas resources. The Energy White Paper also identified the potential for a gas price spike in the short term: Nonetheless, pressures are emerging in the market. Recent floods in Queensland slowed CSG production, and some LNG producers have begun to supplement contracted reserves in the ramp-up period from conventional supplies in the Cooper Basin. The 2012 Queensland gas market review has pointed to suggestions that some LNG producers may also be building contracted gas positions to preserve options for further LNG train development. Meeting project development Page 8 Securing Australia s Gas Future

39 schedules is resource intensive and remains a principal focus of business development for these producers. These factors suggest conservative supply positioning. Recent market assessments suggest that this could result in transitional supply tightness from 2015, potentially until However, given current uncertainties about future demand and the timing of new supply, including the extent of additional LNG expansions and CSG flows, it is not yet clear how material that risk may be. In these circumstances, large industrial gas users without existing upstream positions are particularly exposed to rising prices and may face ongoing difficulties in securing long-term contracts at prices they deem to be acceptable. Residential customers will also face rising gas prices over the decade. Increases in residential prices are likely to be proportionally less than rises for industrial customers because fuel costs are only around 30% of the delivered gas price. 2 These issues have been addressed extensively by many gas industry stakeholders and do not need to be covered in further detail here. The ACIL Allen report, accompanying this document at Attachment 1, also provides information. Since the Energy White Paper was written, it has become apparent that the risk of transitional supply tightness from 2015 is becoming more likely. Regardless of how much gas will be available in the long term for domestic applications, high gas prices resulting from supply tightness could, even if temporary, pose issues for large gas users and, possibly, the wider Australian economy. The final resolution of gas supply and its impact on price is unknown, it is generally accepted that future prices will be higher than those previously experienced. ACIL Allen has developed illustrative scenarios that demonstrate the broad relationship between supply and price and the potential trajectory of a short-term gas price spike. Figure 2: Schematic of potential intensity and duration of gas price spike 2 Australian Government, Energy White Paper, p Page 9 Securing Australia s Gas Future

40 The occurrence of a price spike is not certain. The severity and timing of any price spike are uncertain and will be influenced by a number of factors including: the extent of the supply/demand mismatch; the speed with which new gas production can be brought to market (which in turn involves both technical and commercial issues around the proving up and development of new gas reserves, whether conventional or unconventional); and future oil and international LNG prices. As ACIL Allen notes 3 : The transient gas price spikes illustrated in Figure 5 (Reference to figure in Attachment 1) reflect complex interactions of commercial, technical and intertemporal factors that are likely to determine how the gas supply/demand balance in eastern Australia plays out in practice over the next five to ten years. The price profiles shown in this diagram are illustrative only and are not based on detailed modelling. However they represent, in our view, a plausible range within which local gas prices could move, rising sharply before easing to a lower long-run equilibrium level as new supply (stimulated by high price) comes into the market. The Base Supply case illustrates what might be expected under reasonable assumptions about the supply/demand balance through the period of LNG rampup. Prices rise in anticipation of LNG plant commissioning, but do not reach levels higher than estimated long-run (capital inclusive) LNG netback prices of around $9.50/GJ. After LNG start-up, full CSG supply to meet plant requirements is established quickly and incremental supply becomes available to meet domestic demand, with competition between alternative sources pushing prices below full long-run LNG netback. The high and low supply scenarios are then guided by the likely impacts of supply exceeding or failing to meet expectations respectively. Figure 3 in Section 3 of this report shows the potential trajectory of gas prices in high and low supply scenarios in the absence of a gas price spike. Full detail of ACIL Allen s scenarios is included in Attachment 1, Section 2.1. In this environment, it is appropriate for government to revisit existing policy and regulation affecting gas supply, assess whether it is sufficient and consider the introduction of new, innovative policy to address both the long-term issues posed by the structural changes in the gas market, and the short term transitional issues. 3 Attachment 1, p15 Page 10 Securing Australia s Gas Future

41 3. The importance of unlocking gas supply The east Australian gas market is facing short term transitional pressures and these may need to be addressed. More importantly, actions need to be taken to increase the development of gas supply in the long term. The Australian economy benefits from producing more gas rather than less gas. In the long term, an increase in gas supply will be vital to ensuring that the demands of both exporters and domestic users can be met. Given there is a constraint on how much gas can be exported as LNG, increased gas supply should lead to decreased gas prices for domestic gas users, which most stakeholders contend is desirable. It is important to emphasise that there is a permanent structural change underway in Australian gas markets. LNG exports from the east coast are expected to lead to higher gas prices in eastern markets in the long term, as they have in Australia s west coast market. However, a smaller increase in gas prices is better than a larger increase for Australian gas markets, users and the broader economy. Understanding how increased gas supply can benefit the Australian economy will help to assess the importance and priority of addressing supply issues. There is a range of benefits of increased gas supply in the long term, including: Lower gas prices; Lower greenhouse gas emissions; and Improved energy security. 3.1 Lower gas prices Actions taken today to increase future gas supply should result in a long-run average price that is lower than these estimates, reducing the direct and indirect costs to the Australian economy. ACIL Allen has performed some modelling on the accelerated development of Australia s gas reserves and found that the impact on price is beneficial. ACIL Allen has modelled three gas supply scenarios: A base case scenario, comprising latest gas powered generation forecasts, supply/cost assumptions, commercial pricing behaviour by LNG proponents and other variables. In this scenario shale gas production from the Cooper Basin is limited to 50PJ/annum with a median production cost of $7/GJ. It is increasingly likely that the base case scenario represents a best case scenario that is no longer achievable, with current gas prices suggesting there are constraints on CSG supply leading to higher prices. Page 11 Securing Australia s Gas Future

42 A CSG squeeze scenario, comprising a 20% reduction in Qld and NSW CSG production capacity and reserves on the base case. This is likely to be more representative of current gas supply circumstances. A Shale Rush scenario. Building on the CSG squeeze scenario, the Shale Rush scenario includes Cooper Basin gas expanding to 450PJ/annum within 15 years and at 20% lower production cost. All other things being equal, modelling these scenarios shows that the Shale Rush scenario has around $1.80/GJ lower gas prices than the scenario without accelerated shale gas production. Figure 3: Potential prices arising from CSG Squeeze and Shale Rush Scenarios Base case scenario unlikely to represent actual market circumstances Further detail is in Attachment 1, Section It is clear that measures to increase gas supply should exert downward pressure on gas prices. The ACIL Allen modelling indicates that accelerated development of shale gas alone would lead to increased production and lower costs of production (largely brought about by economies of scale and increased capabilities) that can lower Australia s long-term gas prices by more than 20%. It would appear that there is an overall positive benefit to the Australian economy from having a lower gas price rather than a higher gas price, and therefore any measure to increase supply should be explored. 3.2 Lower greenhouse gas emissions The increased availability and therefore use of natural gas could deliver substantial environmental benefits. In particular, the increased utilisation of gas for electricity generation could significantly reduce the emissions intensity of Australia s electricity sector. Electricity generation Combined-cycle gas turbines (CCGT) are a mature technology that can utilise Australia s substantial gas reserves to produce electricity at one-third the emissions Page 12 Securing Australia s Gas Future

43 intensity of brown coal and one-half that of black coal. CCGT will have a long-term role in Australia s energy future. Figure 4: Average emissions intensity of electricity generation Australia, 2010 Fuel Emissions intensity (t CO 2 /MWh) Brown coal 1.20 Oil 0.97 Black coal 0.92 Gas 0.54 Renewables 0.00 Australian coal average 1.00 Australian fossil fuel average 0.92 Sources: ABARES (2011); Frontier Economics (unpublished data); Productivity Commission estimates. In terms of emissions intensity, gas sits between coal and renewables. However, it should be noted that as the majority of electricity produced from gas generators is currently sourced from less-efficient open-cycle gas turbines (OCGT), the average emissions intensity of electricity sourced from CCGT is even lower. The 2012 Australian Energy Technology Assessment places CCGT emission intensity at t CO 2 /MWh, a 70% reduction on existing brown coal and a 61% reduction on existing black coal emission intensity. If effective carbon emissions reduction measures were in place and if gas was in plentiful supply, demand for gas-fired electricity should increase. This is not currently the case. The gas supply issues currently being experienced, combined with uncertainties in regard to energy and carbon reduction policy and declining demand forecasts, have led to a halt in the progress of all base-load gas fired electricity projects. It is unlikely that these issues will be resolved until at least the end of the decade, leaving base-load low emission power generation investors in a state of flux. Measures to increase gas supply will address some, but not all, of these uncertainties. In addition to the direct environmental benefits of gas as a clean-burning fuel, there are also environmental benefits due to the higher transmission efficiency of using CCGT generation. Gas transmission losses are around 1%, whereas electricity transmission losses are typically above 5%. When CCGT power stations are placed close to geographic demand areas, overall energy transmission losses are lower, further improving economic and environmental efficiency. Direct applications The emissions intensity of natural gas used in direct applications is around half that of electricity generated by natural gas and well under four times lower than the average emissions intensity of Australia s electricity. This is because direct applications of natural gas are not affected by conversion losses. If natural gas is not available, or priced so high that alternatives such as diesel fuel or electricity (largely sourced from coal) become competitive for direct applications, there will be an unnecessary increase in Australia s emissions. Page 13 Securing Australia s Gas Future

44 3.3 Improved energy security A diverse mix of energy sources improves Australia s energy security. The higher the availability of gas supply, the more of a role gas can play in Australia s energy mix. It is in Australia s interest to maximise the choice of energy sources and to minimise the cost of these options. An increased gas supply enhances the role gas can play in securing Australia s energy future. As highlighted in the Energy White Paper, Australia s energy security can be improved by: continuing supply and demand-side market reforms to maximise investment and improve the flexibility and resilience of energy markets; encouraging diversity of supply and infrastructure reliability for supply chain resilience; attracting the necessary capital investment and skilled labour to meet future energy demand. 4 The recommendations set out by APIA in this paper are aimed directly at achieving these outcomes. 4 Energy White Paper, p48 Page 14 Securing Australia s Gas Future

45 4. Recommendations for a response to structural change There is a range of policy options available to improve gas supply and minimise the impacts of the long-term structural change driven by increased exports from Australia s gas markets. Below are some of the more fundamental options. 4.1 Accelerating innovative investment It is accepted that high gas prices will lead to increased exploration and development activity, which in time can be expected to apply downward pressure on prices. However, any supply response will take some years, as gas production projects have long lead times, and the overall downward impact on gas prices is likely to be delayed and mitigated by structural changes. The situation experienced in the US gas market can serve as an example of what may occur in Australia. A combination of factors caused US energy prices to rise rapidly in 2004/05, including a high level of global energy demand driven by China, severe, long winters and diminishing traditional US domestic fields. A sustained abnormally high price period for gas persisted from early 2005 through to 2009, relieved only by the development and rapid deployment of technology that unlocked the potential of shale gas. This is the anticipated supply response that would be desirable in the east Australian market. There are several factors that may impede such a response in Australia. US demand remained relatively stable during this time, there was no new domestic demand driving prices higher. The development of an LNG export industry in Australia is creating new demand, tripling east coast demand over a period of three or four years. This means the supply response must be relatively stronger and more rapid to achieve effective impacts on domestic gas prices in Australia. Further compounding the issue, the Australian gas industry is much smaller and the infrastructure necessary to facilitate development of remote reserves is not as developed as in the US. Therefore, the Australian gas industry has lower capacity to adjust to change than does the US gas industry, in large part due to the market characteristics raised in Appendix A. There is clear evidence that potential future gas supply pressures are influencing the price of gas available to the domestic market. Some of this evidence is discussed in section 5.2. What has not been identified by Government or stakeholders are genuine solutions to accelerate the development of gas reserves and ensure the provision of timely and adequate domestic gas supply. Accelerated development of gas reserves would increase gas supplies in the longterm, therefore minimising any increases to long-run average gas prices. Higher gas prices do have winners gas suppliers enjoy increased revenue and governments receive increased royalties, resource tax payments and company tax payments. ACIL Allen 5 estimates the NPV of all Government taxes paid by a 6-train 5 ACIL Tasman (2012b), Economic Significance of Coal Seam Gas in Queensland, report to Page 15 Securing Australia s Gas Future

46 LNG industry in Queensland to 2035 will be $66 billion. But there are ways that the windfall Government revenues from high gas prices can be invested by Government to increase gas supply and enhance the availability of gas to the domestic market, ensuring the balance between export and domestic requirements is more easily achievable. It is clear that there are substantial external benefits available to the gas industry and the broader Australian economy from the discovery of new opportunities and capabilities from innovative activities such as shale gas development in central Australia. Policy which accelerates the development of Australia s remote and unconventional gas reserves will help ensure a timely and affordable supply of gas, creating lasting economic and environmental benefits for the Australian economy. Bringing forward gas supply will be an efficient and effective measure to mitigate higher gas prices in the long term. The environmental benefits of gas as an energy source are outlined in section 3.2. For the environmental benefits of gas as an energy source to be maximised, both upstream and downstream investors must face a higher degree of certainty about future prices than currently exists. The development of gas supply will need to be brought forward in order to mitigate pricing concerns. The Government should establish consistent policy across its energy funding programs, such as a single fund to enable the accelerated development of desirable energy projects. Current programs are not technology neutral, being largely directed towards renewable and clean coal technologies. However, all technologies that reduce Australia s emissions from the energy sector should be encouraged. APIA believes that there should be the opportunity for such programs to be used to fund increased gas development. This would benefit the wider economy by alleviating long term pricing pressures, which would, in turn, encourage the use of gas as a cleaner, economical energy source. Access to the fund would be on the basis of competitive bidding with Government selecting the projects based on return on investment, emissions reduction and other criteria. APIA believes gas would be a competitive low-emission energy source under such a policy. While this policy would obviously not be limited to gas projects, this paper focuses on the benefits relating to gas projects. APIA s proposal would achieve the stated purpose of accelerating development of gas reserves by: Reducing the risk of new gas investment. Government co-investments, requiring lower returns than those required by private investors, would effectively reduce project costs and therefore the risk faced by private investors, making such investments more attractive to the private sector. This would stimulate supply, bringing otherwise marginal gas basins on line earlier. Improving the efficiency of investment. Government investment or underwriting of projects would enable them to take advantage of economies of scale, a particularly large potential benefit to gas pipeline projects. For a slightly higher Page 16 Securing Australia s Gas Future

47 initial cost, substantially more capacity can be built, lowering the transportation costs of all gas in a region. Increased supply from unconventional gas reserves would increase competition in the domestic gas market, reducing price pressures earlier, and enabling the increased use of gas as a clean, reliable and economical energy source. Similar principles apply to other forms of energy. There are numerous Government energy funding programs, largely focused on picking winners, that could be improved by allowing all technologies capable of achieving the programs intent (usually emissions reduction) to compete on an equal basis. This proposal can be structured to have a positive impact on Government finances. As gas prices increase, Governments receive windfall revenues. These revenues can be used to establish a fund that focuses on accelerating the development of remote energy reserves. It is not proposed that the fund be used to provide grants to projects. It is proposed that the Government co-invest in projects that have national importance on a competitive bidding basis. If Government sets its required return at a slightly higher level than the government bond rate it achieves a better return on investment than it would otherwise receive, and industry effectively has a lower cost of debt. As shown by ACIL Allen in Figure 3 (Section 3) the accelerated development of shale gas should deliver genuine downward pressure on gas prices. 4.2 Other measures to encourage supply development Optimising land access An issue of increasing concern for gas supply is the political response to community opposition to gas development. This has materialised primarily in NSW, where the Government announced a two-kilometre exclusion zone around residential zones and further exclusion zones around viticulture and equine industry clusters to prevent new coal seam gas exploration, assessment and production activities. This type of response does not reflect the industry s safe processes and its strict regulations. It does not recognise the urgent need for increased gas supplies, and poses a risk to gas supply activities. Governments must work rationally and sensibly to ensure all land uses are made available. At the same time, the industry must work to develop and maintain the social licence necessary to conduct gas development activity, and work with government to provide appropriate information to affected landholders Reducing red and green tape A key improvement often cited is the need to reduce red tape and green tape. Much of the regulatory regime overseeing gas supply is duplicated across federal and state levels and this decreases efficiency. The exploration and production industry is impacted by these inefficiencies. As APIA s membership is not always a direct participant in gas production, APIA does not have detailed analysis of which areas require most improvement. The Australian Petroleum Production and Exploration Page 17 Securing Australia s Gas Future

48 Association s (APPEA s) 2012 State of the Industry document contains a comprehensive treatment of this issue in Section Some specific areas for improvement include the duplication of approvals, particularly environmental, processes between state and federal governments and the timeliness of approvals Improving exploration information deficiencies Gas exploration is a high-risk activity, with significant capital investment required to locate and prove reserves. If successful, the rewards are sufficient to justify the investment and risk. Early availability of information can help increase investment and ensure it is directed to the most prospective regions. Through Government geoscience organisations, a range of information is available. Geoscience organisations both fund the gathering of new data and receive data from current explorers, the latter usually being subject to confidentially arrangements to give early movers appropriate financial security. Government can improve information arrangements by increasing funding and release of its own data and reducing the timeframes for release of privately captured data. This would increase the efficiency of exploration by: Better allocation of scarce exploration resources through government provision of increased early-stage data on prospective regions; Improved competition by increasing the release of privately captured data into the public domain. More information on exploration information deficiencies is available in Attachment 1, Appendix C Changes to management of exploration tenements The majority of Australian gas exploration tenements are offered on the basis of work bidding, with the proponent offering to do the most exploration in an area being awarded the tenement. This system has been put in place on the assumption that early and more exploration work is desirable. However, tenement allocation systems designed to increase the pace of exploration can lead to a misallocation of exploration resources, with proponents committing to more than necessary exploration work to secure a tenement. This misallocation leads to other areas not receiving enough exploration resources, diminishing the size of Australia s total gas reserves, gas supply and tax revenue. A thorough reform of exploration tenement regimes is necessary in order to avoid misallocation and resource rent dissipation. More information on management of exploration tenements is available in Attachment 1, Appendix E Royalty and taxation reform There are multiple forms of taxation that apply to the gas supply industry. At the Federal level, the company tax and petroleum resource rent tax regimes apply. At the State level, multiple royalty tax regimes are in place. These tax regimes distort incentives to explore, invest and extract. For example, different royalty rates in different states may direct investment toward one state over another, all other matters being equal _web.pdf Page 18 Securing Australia s Gas Future

49 As an additional consideration, different tax regimes apply to different resources, despite the fact the resources may be in competition. Relevant examples are the tax regimes that apply to gas and coal extraction. Gas and coal compete as fuels for electricity generation but the tax regimes for extraction are very different and impact the relative competiveness of the commodities. Comprehensive reform of royalty, PRRT and company tax regimes, along with resolution of federal-state issues, is essential to maximise efficiency of gas supply. The Henry Tax Review provided a reasonable model 7. An alternative is to base taxation models on economic profits rather than resource production. More information on tax regime reform is available in Attachment 1, Appendix D. 4.3 Delivering efficient power generation investment In light of the investment co-ordination issues commonly experienced in the resources sector, where project development and market demand are codependent, a policy which strengthens domestic demand for gas should encourage the increased development of supplies in the long term. This will provide investors in new gas projects with confidence that there will be strong, long-term demand for gas in Australia, which is easier to supply than the demand of overseas LNG buyers. The investment co-ordination issue is discussed by ACIL Allen in Attachment 1, Appendix C. It is apparent that the size of future gas demand will have an influence on activity to increase gas supply. In particular, there are uncertainties around the role gas will have in Australia s electricity supply. Clear signals from the Government that gas has a strong role to play in Australia s electricity mix will provide shale and other conventional and unconventional gas project proponents with confidence that there will be a market for the development of their discoveries. Such signals are currently absent in relation to gas fired generation, due to several factors. The Australian Energy Market Operator s 2012 Electricity Statement of Opportunities substantially downgraded forward estimates of electricity demand. As the levels of electricity generation mandated under the Federal Government s Renewable Energy Target (RET) were based on estimates in the early 2000s, the Australian generation sector is now faced with the unforeseen situation where the RET is effectively requiring that all new generation to 2020 be from renewable sources. This is neither the original intention of the RET nor an efficient economic outcome for the Australian generation sector, as it does not encourage other cleaner and economically competitive generation sources, such as gas. Additionally, input prices and electricity prices are not acting as earlier forecasts anticipated. Gas prices are rising, coal prices are falling. Wholesale electricity prices are flat. The carbon price will not be as high as originally planned and there is a high likelihood it will be abandoned. Uncertainty in international carbon policy has resulted in the EU scheme carbon price being forecast to remain at around 6 to 8 until Australia will be able to source 50% of its liability from the EU market but will require material domestic abatement activities for the remaining 50% to meet significant emission targets. 7 Henry Tax Review, Chapter 6, May 2010 Page 19 Securing Australia s Gas Future

50 It is therefore timely to revisit the intentions and assumptions of earlier policy decisions in order to assess the influence of complimentary policies, reflect the current outlook and enable Australia s generation sector to transition to lower emission intensity technologies as efficiently as possible. APIA believes the Government should commence development of policy to lower the long-term emissions intensity of the electricity sector. Given there is little new demand to be met prior to 2020, the focus of this policy should be on influencing electricity generation beyond There are currently no signals to the investment market as to what electricity projects should be planned once the RET has achieved its goals in Current demand forecasts (which can change) indicate new baseload investment will be required in Government policy has an increasingly large influence on investments in the electricity sector and clear advance signals need to be provided to the market in order to guide investment in 2020 and beyond. A single, technology neutral, electricity sector emissions intensity based carbon reduction scheme should be prepared for deployment in Such a scheme would influence the costs and output of existing and future generators and provide the market with clear signals that investment in low emissions electricity will be encouraged. Such a signal would also give shale and other gas project proponents sufficient confidence in the long-term viability of gas-fired power generation and assure them of a growing domestic demand to justify investment in gas supply. This would help to address the issue of co-ordination. Increased investment in unconventional gas is needed today, in order to influence gas supply in future years. That investment cannot occur unless there is confidence in future demand. Such a policy would reduce uncertainty in the market, leading to more efficient investment outcomes. AGL has identified in 2010 that greater certainty would lead to more economically efficient generation investment in the National Electricity Market 8. This policy would also ensure delivery of the environmental benefits of gas as a clean energy source, addressing the need to reduce emissions across the electricity sector and in the economy in general. It is acknowledged that any policy aimed at reducing emission intensity in the electricity sector will exert upward pressure on electricity prices. This is already occurring through programs such as the RET. It is also clear that a policy that allows the market to choose the methods to achieve emissions reduction in the electricity sector will encourage pursuit of the lowest cost options. A policy which is technology neutral should have a lesser impact on electricity prices than policies which do not let the market decide on technology investments. APIA believes that a scheme that functions in a similar way to the NSW and ACTbased Greenhouse Gas Reduction Scheme (GGAS), applying to electricity generators, should be implemented. Such a scheme would serve to encourage the increased use of gas fired generation if it is efficient, in contrast to the unintended effect of the 8 AGL s Paul Simshauser, Capital adequacy, ETS and investment uncertainty in the Australian power market, 2010 Page 20 Securing Australia s Gas Future

51 RET, and by doing so would also encourage the increased development of gas supplies, including the associated economic benefits. Analysis of the existing GGAS scheme is contained in Appendix B. The benefits of an emissions intensity scheme for the electricity sector post-2020 are three-fold: Environmental benefits. In the current climate it is difficult to determine a $ value for this benefit, but it is known that emissions reduction will remain an international issue. Policies and actions to reduce emissions and increase investment in emissions reduction practices today are useful and will increase in utility. Investment efficiency benefits. Provides signals to the electricity sector in regard to the direction of future investment. Increased gas supply development. Provides certainty to the gas supply sector that domestic markets for gas will continue to grow as long as CCGT remains competitive economically and on an emissions intensity basis. This would provide the basis for investment in gas projects today that might not begin supplying gas for several years. Increased gas supply development will help to mitigate the effects of the structural shift in the east Australian market, reducing long term pricing pressures. Additionally, gas-fired generation has two further unique benefits. CCGT turbines are able to respond rapidly to changes in electricity demand while coal boilers can take days to be ramped up or down, CCGT turbines take only hours. Also, gas transmission is generally more economical to build than electricity transmission and, importantly, the investment frameworks for each mean that the costs of gas transmission are better attributed to the parties that create the need for the infrastructure. These efficiencies are explored in detail in Chapter 8 of the Australian Energy Market Operator s 2011 National Transmission Network Development Plan National-Transmission-Network-Development-Plan/Report-Chapters Page 21 Securing Australia s Gas Future

52 5. Mitigating the effects of potential transitional pressures 5.1 The case for Government intervention in markets The policy refinements and proposals suggested in the above two sections are not forms of market intervention and would not have an immediate impact on gas markets, as it would take time for their effects to impact gas supply. They would, however, create favourable conditions to improve the efficiency of new supply and, if successful, accelerate the timing of new supply. There have been numerous calls for market intervention in response to recent anticipated short term transitional issues in the east Australian gas market. Market intervention is an option of last resort and should not be entered into lightly. Interventionist measures should only be undertaken if demonstrated market or policy failures have occurred. Clearly, evidence of such market or policy failures must first be identified. According to the Energy White Paper: Market interventions should always be a matter of last resort and undertaken only where there is clear evidence of market failure. In the government s view, those conditions do not currently exist in Australia s gas markets. However, the government does not dismiss the potential risks associated with emerging pressures, particularly the ongoing lack of liquidity in the long-term contract market on the east coast and the impact that might have on existing large users. Therefore, it will work as a matter of priority with the relevant jurisdictions and gas market bodies to further develop gas market arrangements as described above and to closely monitor market conditions to ensure that markets are delivering against stated objectives, particularly the provision of timely and adequate domestic supply. 10 This raises four questions: 1. What constitutes clear evidence of market or policy failure in Australia s gas markets? 2. How will the Government closely monitor market conditions to ensure that markets are delivering against stated objectives, particularly the provision of timely and adequate domestic supply? 3. If monitoring produces evidence of market or policy failure, what action will be taken by Government to address this? 4. What are the policy objectives of Australia s gas markets and do they need to be re-examined? 10 Australian Government, Energy White Paper, p Page 22 Securing Australia s Gas Future

53 Detailed discussion of these questions is contained in Appendix C, and a brief summary of APIA s views are shown below. Based on the National Gas Objective and Energy White Paper, two of the key purposes of Australian gas markets are to: ensure the provision of timely and adequate supply; and maximise efficiency in natural gas services, including supply. If gas markets are not achieving these purposes, it is likely there is a market or policy failure. APIA therefore believes that inadequate gas supply, reflected by substantially increased prices, can be used to identify market or policy failure in Australia s gas markets, as this would be a result of the market failing to ensure the provision of timely and adequate domestic supply 11. Logically, a long-term domestic gas price above the LNG netback price (the price of gas paid by overseas LNG buyers, less the costs associated with converting and transporting the LNG) would constitute evidence of a market or policy failure. This would be indicative of Australian gas supplies failing to meet demand from LNG producers. 5.2 Analysis of the short-term situation In the case where there is clear evidence of market or policy failure, and in order to avoid potential damage caused by short-term price transitional pressures, a shortterm policy intervention has been proposed. Clearly, in the long term, there would be a supply response to high prices and the market would be seen to respond. However, in the short term, a dramatic price hike could lead to demand destruction in some domestic industries that would be expected to survive in the longer term, but not through a short-term major price increase. LNG netback is believed to be around $9/GJ, and market reports place domestic customers currently entering long-term purchase contracts at prices up to $9/GJ. If it is taken that prices above LNG netback indicate a failure of the market or policy to ensure adequate and timely supply of domestic gas, then there is a risk that market failure will occur in the next few years, leading to a period of natural gas prices above LNG netback. The market itself will, in time, respond to the high prices caused by a failure in gas supply by increasing exploration and production efforts to capitalise on the high prices. This should invoke a classic supply response, leading to an oversupply and reducing price pressure. However, such a response will not be timely. Given the timeframes associated with gas projects, it can take many years. In the meantime, demand destruction may occur in the Australian economy. Increasing the provision of gas supply is a medium- to long-term endeavour. There are very few efficient short-term responses that can increase gas supply. A market failure of gas supply requires two responses, one with an immediate response to address the price effects and one with a longer-term response to promote increased supply. Both responses are necessary to limit the detrimental effects of limited 11 Australian Government, Energy White Paper, p145 Page 23 Securing Australia s Gas Future

54 supply. In Section 4, medium- and long-term measures to improve gas supply arrangements have been addressed. 5.3 Easing short-term transitional pressures APIA believes that the Government should work with stakeholders to implement effective price and contract monitoring to fully assess the supply-demand balance in Australia s gas markets. Government should also seek to define trigger points and therefore identify evidence of market failures which justify market intervention. APIA suggests domestic gas prices above LNG netback would constitute such a sign, though it is likely there are other trigger points that may be considered. In the very short-term, it may be that the only efficient option available to address the high prices created by a market failure in gas supply is some form of temporary, targeted demand side compensation package. This would ensure the, presumably temporary, high prices do not cause long-term or permanent damage to gas price sensitive sectors of the Australia economy. The permanent loss of long-term viable industries due to short-term pressures is a sub-optimal outcome for the Australian economy. The basis for, and further details of, such an intervention are set out in Section 3.7 of the ACIL Allen report at Attachment The policy settings for Australia s gas markets An effective, efficient market is one that responds to supply tightness with higher prices. The supply is allocated to the users that value it most. The higher price is also an incentive to increase supply, and eventually as supply begins to exceed demand reducing prices. Markets are designed within a policy framework. When there is perceived unfairness or failure within a market, often when there is a shortage of supply and prices rise, the point is usually made that allowing the market to work will eventually see the higher prices generate increased supply, so that prices then fall. However, a focus on the actual policy framework for a market is often overlooked because this is a more difficult and substantive challenge. Australia s east coast gas market is a case in point. The National Gas Objective is to: promote efficient investment in, and efficient operation and use of, natural gas services for the long-term interests of consumers of natural gas with respect to price, quality, safety, reliability and security of supply of natural gas. Open, competitive markets will be able to ensure that the highest price for a commodity is achieved, but may be unable to give consideration to broader issues that may form part of a market s purpose or objectives. Government policy, such as the intent embodied in the National Gas Objective, defines the purpose of a market and sets the boundaries in which competition should occur. The gas market policy settings for Eastern Australia have been developed in an environment where producers were focussed on the domestic market and supply to large gas users. The market environment has changed to one where the largest producers are focussed on export markets far bigger than the domestic market. The Page 24 Securing Australia s Gas Future

55 policy settings framing the markets have not changed and thus require reconsideration. The policy framework for the Eastern Australian gas market was developed without consideration of gas exports. In fact, it was assumed that gas would be imported from Papua New Guinea or from Western Australia. This was prior to the development of coal seam gas in Queensland, which has supplied the domestic Queensland market for many years. The early development of coal seam gas to supply the Eastern Australian market was not a challenge to the policy framework it merely factored out imports from PNG or WA to address demand issues. For good reason that policy framework, with no changes, allows producers to sell gas to the users that value it most highly. That is an appropriate market outcome when producers themselves do not have a major interest in downstream demand. With the establishment of an LNG export industry in Eastern Australia, major producers are now the primary suppliers and the source of the largest gas demand. This challenges the existing policy framework. It is set out in the Energy White Paper that a primary purpose of the gas market is to ensure timely and adequate domestic supply. If producers have larger incentives, both price-driven and contractual, to pursue export markets it is possible that due consideration will not be given to providing timely and adequate domestic supply. If there is a shortage of gas, producers have a choice between the export and domestic markets. There is nothing in the policy framework for the Eastern Australian market that ensures Australian gas users (consumers/manufacturers/generators) will have access to that gas even if they are prepared to pay the LNG netback price. Efficiency and flexibility adjustments in the domestic gas market do not address the fundamental question of the choices made by producers regarding allocation of this (artificially) scarce resource. While adjustments are being made to the domestic gas market, the gas being supplied to that market is diminishing and the adjustments provide no solutions to the actual amount of gas being supplied. It is appropriate to revisit the policy framework governing wholesale gas markets to ensure the appropriate incentives are in place to enable the timely and adequate provision of domestic supply. Page 25 Securing Australia s Gas Future

56 6. Recommendations The transitional period being experienced in Australian gas markets is creating new uncertainties around long-term gas prices, gas availability and the future demand for gas. There are a number of actions that can be taken by Government to address these uncertainties and in doing so provide confidence to investors in gas production and use, that the Government values the timely and adequate long-term supply of gas to the Australian economy. APIA is of the view that, in addition to structural changes in Australia s gas markets, policy failure is exacerbating future challenges. In light of this, government should consider the policy intent of recent regulatory interventions and the policy establishing market frameworks. To address the short term transitional issues in Australia s gas markets, APIA recommends: The Federal Government work with gas stakeholders to establish and implement effective monitoring of gas markets, with clearly identified triggers (such as price) for potential market failure; As a matter of urgency, the Standing Council on Energy and Resources identify the policy mechanisms it would use to respond to a short-term gas supply shortfall if the monitoring provided evidence of this. To address the long-term issues created by the structural changes in Australia s gas markets, APIA recommends the Federal Government should prepare policy to increase the efficiency of gas supply and consider policy that will accelerate the development of Australia s gas reserves. Such policy should include: A supply-side policy the Government should establish technology neutral energy investment policy that allows renewables, clean coal, low-emission gas and other clean technologies to compete for funding on the basis of emissions reduction and energy supply. A demand-side policy a technology neutral emissions intensity electricity sector scheme should be established to provide appropriate signals to investors. In the case of gas, it would provide all investors, including explorers, with the signal that low-emission gas technology has an important role to play in the electricity sector. Improvements to regulatory and administration regimes, including tenement management, taxation, land access and information. Page 26 Securing Australia s Gas Future

57 Appendix A Overview of natural gas in Australia Natural gas is an essential part of Australia s energy mix. In 2010/ petajoules (PJ) of natural gas was consumed in Australia, comprising 24.8% of our primary energy needs 12. Whilst primary energy consumption is the standard metric by which a fuel s contribution to the economy is judged, it does not tell the full story. According to the Australian Government s publication, Energy in Australia 2012, the usable energy provided directly to the economy by natural gas in 2009/10 was 740PJ. The usable energy provided by the electricity sector was 756PJ. Given that 15% of electricity is generated by natural gas, it is apparent that more usable energy is provided to the economy by natural gas than by the entire electricity sector. Importantly, the delivered price of gas for households is around one quarter of that for electricity on a $/GJ of energy basis. 13 Natural gas is transported from producing basins around the country to industrial demand centres and cities through 30,000km of high-pressure steel gas transmission pipelines. Only the very largest industrial gas users, manufacturers, minerals processing facilities and power stations connect directly to this infrastructure. In remote mining regions, natural gas transmission infrastructure often provides the only link to larger energy markets. More than 4,350,000 residential and small commercial and industrial customers and 2000 large industrial and commercial customers are supplied natural gas through Australia s 87,000km of gas reticulation networks, the distribution networks running through cities and towns providing access to gas 14. These gas users depend on natural gas for a large part of their heating needs. In households, cooking, space heating and hot water are the primary uses of natural gas. Commercial uses of natural gas include heating of buildings, cooking, large-scale laundry facilities and much more. Hospitals, with their large scale heating, cooking, hot water and laundry requirements are particularly dependent on natural gas to provide low cost energy. Industrial uses of natural gas include those where natural gas is used directly as feedstock to manufacture chemicals and other materials such as basic chemicals, fertilisers, explosives, paints, pharmaceuticals, soaps and detergents, cosmetics, rubber products and plastic products. Where direct application of heat is required in a manufacturing process, natural gas is the fuel of choice. Dependent manufacturers include the cement, brick, tiles, glass and plasterboard industries. In the mining and minerals sector, natural gas is used both for on-site energy (including electricity generation) and to fire smelters and ore processing facilities around the country. 12 Energy in Australia AER, State of the Energy Market Energy Supply Association of Australia, Electricity Gas Australia 2012 Page 27 Securing Australia s Gas Future

58 Last but not least, more than one third of natural gas demand is for use in electricity generation, providing low emission electricity that plays a vital role in responding rapidly to the short-term variations in electricity demand. In addition to peaking power, combined cycle gas turbines have the potential to transform the emissions intensity of Australia s electricity, by playing an increasing role in providing economic electricity at well under half the emissions intensity of Australia s dominant electricity source, coal. Gas Exports Gas is also exported from Australia in the form of Liquefied Natural Gas (LNG). Around 1085PJ/annum 15 of natural gas is exported as 24 million tonnes of LNG from export facilities in north-western Australia and Darwin. This capacity is expanding rapidly, with developments in existing locations and in Queensland forecast to increase Australia s export potential to over 50 million tonnes/annum by million tonnes of this new capacity is being built in Queensland alone. Australia s gas markets There are three distinct geographical areas that can be considered separate markets. These are the eastern market, the western market and the northern market, displayed on the map below. Source: RET, GA & BREE (2012). The eastern gas market is the largest and most mature market. There are multiple demand centres and source basins spanning the states of Queensland, New South Wales, Victoria, South Australia, Tasmania and the Australian Capital Territory. A number of major transmission pipelines bring a level of interconnectivity to these sources and demand centres. The development of coal seam gas (CSG) reserves and LNG export facilities is a major activity currently underway in this market. 15 Energy in Australia 2013 Page 28 Securing Australia s Gas Future

59 The western gas market is almost entirely served by gas from the north-west self, with two major pipelines bringing gas south to the demand centres of the south-west and central regions of Western Australia. With existing LNG export facilities, the western market is currently the largest producer and exporter of gas. The northern gas market is Australia s smallest gas market and is centred on the major demand centre around Darwin, with gas primarily being supplied by offshore fields. There are existing and planned LNG facilities. There are further distinctions between these markets. Each gas processing facility represents a market for supply, and if serviced by multiple pipelines may represent multiple markets. Each gas transmission pipeline services a specific demand centre at the end of the pipeline. Each LNG facility has an export market to service. There are managed markets: in Victoria there is the Declared Wholesale Market and in three capital cities there are Short Term Trading Markets. Currently under development is a Gas Supply Hub in Queensland. Each of these markets has its own attributes and issues. Collectively, they can be called Australia s gas markets, the means by which natural gas supply and demand are balanced. The term domestic market is also used for Australia s gas markets. This should not be confused with the residential market, which accounts for a small portion of total Australian gas demand. There are several key factors that shape Australia s gas markets: Remoteness of gas supply basins. The majority of Australia s main gasproducing basins are remote from population centres. They typically serve one or two demand centres through a very long and narrow diameter (by international comparisons) single pipeline to each centre. Concentration of population. The majority of Australia s population lives in coastal capital cities separated by long distances. This concentrates energy demand in regions around these cities. The distance of capital cities from the locations of gas supply means no single pipeline serves more than one major demand centre. (Nevertheless, it should be noted that the eastern centres are connected. The Adelaide, Sydney and the Victorian markets are serviced by more than one pipeline and Brisbane has access to gas from other centres through the linkage of the transmission pipeline system.) A relatively low gas demand, by international comparisons. Australia has a small population, a small manufacturing sector, an electricity sector primarily fuelled by coal, and a temperate climate. These factors contribute to a relatively low gas demand, meaning most demand centres can be easily served by a single larger pipeline or two smaller pipelines, noting that a large pipeline by Australian standards is half the diameter of a typical large pipeline in the US or Europe. To further clarify the size of Australia s gas market, it is useful to compare Australia s gas markets to those in the United States of America. Australia and the US have a similar geography and both have substantial reserves of natural gas. The US is home to the most sophisticated gas market in the world, the Henry Hub. The Henry Hub, located in Louisiana, is the deepest and most liquid gas market in the world, one of the few true spot markets for gas and often referenced by Australian policy makers Page 29 Securing Australia s Gas Future

60 as the model gas market Australia should aim toward. Whilst this seems a reasonable goal, the factors listed above and the facts provided below suggest it may be inappropriate to compare Australian gas markets with others. Comparison of gas market characteristics: Australia, USA and Louisiana Australia USA (lower 48) Louisiana Area(sq km) 7,692,024 8,080, ,642 Population 23,022, ,675,006 4,533,372 Gas consumption (PJ) 1,515 27,450 1,576 Gas export (PJ) 1,086 1, (to other US states) Major pipelines Pipeline length (km) 28, ,000 78,500 Storage facilities Source 16 Louisiana is roughly half the size of Victoria, has a local gas demand exceeding Australia s, exports around 6 times as much gas as Australia; and has a pipeline network almost 3 times as long as Australia s. On its 30 major pipelines there are 75 regulated gas transportation entities 17. It is a deep and liquid market. The environment for Australia s gas markets to evolve or develop the sophisticated markets seen in the US simply does not exist. The following maps help illustrate the facts. 16 Australian gas statistics are from Energy in Australia 2013 and APIA s pipeline data, US and Louisiana gas statistics are sourced from the US Energy Information Administration. Population statistics : Australian Bureau of Statistics and US Census Bureau (2010 Census). Area statistics: United Nations Statistics Divisions and US Census Bureau (2000 Census) 17 Louisiana Department of Natural Resources Page 30 Securing Australia s Gas Future

61 Page 31 Securing Australia s Gas Future

62 Page 32 Securing Australia s Gas Future

63 Appendix B Analysis of the GGAS scheme The Greenhouse Gas Reduction Scheme (GGAS) commenced operation in NSW and the ACT on 1 January The intention of the GGAS scheme was to reduce the annual carbon dioxide emissions of the electricity sector in NSW to a benchmark of 7.27t CO 2 per person by It was implemented through a baseline and credit system, whereby electricity retailers and some other organisations are legally required to surrender offset certificates (NSW Greenhouse gas Abatement Certificates or NGACs) if the CO 2 emissions associated with the electricity they supply exceed their benchmark. The firm-level emissions benchmark is determined by market share. NGACs are intended to represent a one tonne reduction in CO 2 emissions and can be established based on the following rules: the generation rule the demand-side abatement rule the carbon sequestration rule the large user abatement rule (which allows large electricity customers to claim certificates for reducing on-site emissions from non electricity-related industrial processes at sites they own and control). It is important to note that the PC study focussed on electricity, so the implicit abatement subsidy for GGAS was determined only considering NGACs produced by the generation rule. In short, for the generation rule, average emissions intensity of electricity sourced from the electricity grid in NSW is determined, then all electricity produced at lower emissions intensity generates NGACs. In 2010 the average emission intensity was 0.97 tonnes CO 2 /MWh. Renewable energy in NSW would generate NGACs at a rate of 0.97 NGACs/MWh. A gas fired power generator, at the Australian average of 0.52 tonnes CO 2 /MWh, would produce 0.43 NGACs/MWh. The cleaner the energy, the more NGACs produced. The three additional rules allow an electricity firm to source emissions abatement from alternative sources if it is more economical to do so than through emissions reduction from generation source. The NGACs required to be submitted by a firm are determined by that firm s share of electricity generation. An open market to trade NGACs sets the price. In essence, the GGAS is an electricity sector emissions intensity based scheme. Such schemes are generally accepted as an efficient method of achieving reductions in greenhouse gas emissions. Its primary advantage is that it has a lower impact on Page 33 Securing Australia s Gas Future

64 electricity prices (economic efficiency) and its primary disadvantages are that it creates uncertain abatement (final abatement is dependent on electricity demand) and it only affects the electricity sector. Nevertheless, such a scheme should be pursued because: It is technology agnostic, rewarding the cleanest forms of energy and punishing the dirtiest; It is the most efficient way of reducing emissions in the electricity sector; The electricity sector comprises around 50% of Australia s emissions, so it would be effective; and It can be used to achieve the desired emissions intensity of the electricity sector by imposing gradually increasing costs of emissions. Page 34 Securing Australia s Gas Future

65 Appendix C Discussion of market failure in the east Australian gas market The objective of Australia s gas markets In order to determine whether there is a market or policy failure in Australia s gas markets, the purpose of the gas markets must first be defined. The Energy White Paper does not explicitly state the purpose of Australia s gas markets, but it does make some statements that can put this into context: Our gas markets have provided reliable and competitively priced gas 18 Security of supply to consumers is vital 19 ensure that markets are delivering against stated objectives, particularly the provision of timely and adequate domestic supply. 20 (There appears to be no specific statement that explicitly sets out the objectives of Australia s gas markets) The Energy White Paper identifies that policy success will produce: more competitive and efficient gas markets adequate supply to meet current and projected domestic and export needs. 21 an investment schedule in gas development, processing and transmission pipeline and distribution infrastructure that can meet projected demand in all three geographical markets. 22 If policy success will produce these results then it can be presumed they are fundamental purposes of Australia s gas markets. Further to this, Australia s formal gas trading markets, currently comprising the Declared Wholesale Gas Market in Victoria and the Short Term Trading Markets in Adelaide, Brisbane and Sydney (the gas supply hub in Wallumbilla is still under development) are all established and operated under the National Gas Law (NGL). Gas transport infrastructure is also regulated under the NGL. The NGL and National Gas Rules (NGR) are in place to ensure the National Gas Objective (NGO) is achieved. The NGO was established to: promote efficient investment in, and efficient operation and use of, natural gas services for the long term interests of consumers of natural gas with respect to price, quality, safety, reliability and security of supply of natural gas. Whilst the NGO only explicitly applies to markets governed by the NGL and NGR, it seems reasonable that, as a National Gas Objective, the principles it states are more 18 Australian Government, Energy White Paper, p Australian Government, Energy White Paper, p Australian Government, Energy White Paper, p Australian Government, Energy White Paper, p Australian Government, Energy White Paper, p145 Page 35 Securing Australia s Gas Future

66 widely applicable to the entirety of Australia s gas markets. A natural gas service is defined in the NGL to be: (a) a pipeline service; or (b) the supply of natural gas; or (c) a service ancillary to the service described in paragraph (b), In December 2012 the Standing Council of Energy and Resources (SCER) issued a Statement of Policy Intent in response to its Expert Panel s review of the Limited Merits Review Regime that affirmed: that, in interpreting the National Electricity Objective and the National Gas Objective, the long-term interests of consumers (with respect to price, quality, safety, reliability and security of supply) are paramount in the regulation of the energy industry. 23 Therefore, based on these statements from legislation and policy documents, it can be concluded that two of the key purposes of Australian gas markets are to: ensure the provision of timely and adequate supply; and maximise efficiency in natural gas services, including supply. While these are not the only purposes of Australia s gas markets, they: are likely to be agreed by all stakeholders; and are being affected by the current structural changes underway with the rapid development of the LNG export industry. What constitutes market or policy failure in the east Australian gas market? Evidence of market failure is difficult to define and identify. What is a failure in Australian gas markets and how do we know one has occurred? The following contributions should assist the debate. It is likely all stakeholders can agree that the provision of timely and adequate domestic supply is a fundamental purpose of Australia s gas markets. If the market cannot supply enough gas to meet demand then a market failure has occurred. This would be evidenced by very high prices, with price becoming a rationing mechanism by which a limited amount of gas is allocated to those who value it most highly. This means the gas price is a particularly important matter to consider when assessing a market failure of this nature. If a pure approach is taken, higher gas prices maximise economic benefit and are desirable. This is true if there are no constraints on gas supply. At some point, it can likely be agreed that the gas price is too high because gas supply cannot meet all demand. In such an event, the market has failed to ensure the provision of timely and adequate domestic supply 24. The question becomes, at what price can we determine that a market failure occurred? 23 SCER Statement of Policy Intent, December Australian Government, Energy White Paper, p145 Page 36 Securing Australia s Gas Future

67 The concept of LNG netback is familiar to the industry. It is the price of gas paid by LNG importers minus the specific costs associated with converting gas to LNG and transporting LNG. These specific costs are open to debate. Only LNG producers (and possible LNG importers) know the details, but in general they are believed to be around $7/GJ. Similarly, only the parties to an LNG supply contract know the exact price paid for LNG and each contract would have a unique price influenced by the particular terms of the supply arrangement. The price of Australian LNG exports to Asian markets is generally assumed to be around $16. This places the LNG netback price at around $9/GJ. This is essentially the price producers receive for gas that enters their LNG trains. It is appropriate for market observers to make their own assessment of LNG netback when considering it as a sign of market failure. Presumably, LNG producers are willing to sell gas that is surplus to their needs at this LNG net back price. As the amount of gas that can be exported as LNG is limited by the capacity of LNG trains, the greater the gas supply, the greater the competition to sell gas for purposes other than LNG, likely leading to Australian gas users paying a lower price than LNG netback. If gas supply cannot meet the capacity of the LNG trains, then LNG producers will have difficulty meeting the requirements of their LNG supply contracts. In such a circumstance, the priority will be ensuring the terms of the contract are met and there is the likelihood that LNG producers would be willing to pay above LNG netback prices in Australia s domestic markets for available gas in order to meet these contract obligations. Therefore, a gas price above LNG netback could be considered a market failure in Australian gas markets. It is noted that a key purpose of the gas market to balance supply and demand through price and that the appearance of high prices as a response to tight supply is a sign the market is working effectively. Indeed, this is a common point raised by market participants not concerned by high prices. If the only purpose of the gas market was to allocate supply to those that value it most highly this would be true. As the Energy White Paper points out, the provision of timely and adequate domestic supply is an objective of Australian gas markets. The clearest signal of the failure of the market or policy to achieve this objective is high domestic gas prices and prices above LNG netback are ones that can be deemed unacceptably high. Obtaining evidence of market or policy failure There are three pieces of evidence that could aid assessment of whether gas supply is failing to achieve its objective. Firstly, gas prices themselves could be observed. However, there is no easy way to publically observe contracted gas prices in Australia. Two options available are media reports and prices at gas hubs. Current media reports indicate domestic users are entering into gas supply contacts up to $9/GJ. A commonly cited transaction is the supply of gas by Origin Energy to MMG (2012). As a resource firm, MMG is relatively insensitive to gas prices, as long Page 37 Securing Australia s Gas Future

68 as the gas price is lower than the alternative (likely to be diesel fuel) it is willing to pay. The price of gas paid at gas hubs is not a reliable indicator of the ability of supply to meet demand. It should be noted that those spot markets for gas in Australia that do exist are unlike international, high volume markets. There is not a concentration of demand and competition of supply in any single region that would enable the development of a deep, liquid market. The STTM hubs are balancing markets, attempting to improve market efficiency by assisting gas users to account for marginal changes in day-ahead forecast gas requirements in a market arrangement. STTM prices do not, and are not designed to, reflect currently available long-term gas contract prices, and it is the latter price that will influence the gas market. Secondly, production forecasts may be analysed, though these may not be readily available. It relates to the ability of LNG producers to meet their contracts. These contracts were entered into on the back of production forecasts that LNG producers used to assess the amount of gas available. Information about how current production is tracking according to those forecasts would be very informative for the market. Gas producers must report actual well production to state Governments. It may be possible to use this data in association with other derived information to achieve a better understanding of LNG producers ability to meet production forecasts. This may not be necessary; the current prices being levied on large Australian gas users suggest that, in the absence of actual supply constraints, LNG producers are unsure about their ability to meet production forecasts. Thirdly, industry consultation could be utilised. A further option to help establish a view on current gas prices is to maintain a program of industry consultation with gas producers and large gas users. This would enable a market observer to access confidential information and receive direct feedback from market participants. Page 38 Securing Australia s Gas Future

69 ATTACHMENT 1: Australia s Natural Gas Supply: an assessment of current policy issues and options ACIL ALLEN CONSULTING Page 39 Securing Australia s Gas Future

70 REPORT TO AUSTRALIAN PIPELINE INDUSTRY ASSOCIATION JUNE 2013 GAS POLICY AUSTRALIA S NATURAL GAS SUPPLY: AN ASSESSMENT OF CURRENT POLICY ISSUES AND OPTIONS

71 ACIL ALLEN CONSULTING PTY LTD ABN LEVEL FIFTEEN 127 CREEK STREET BRISBANE QLD 4000 AUSTRALIA T F LEVEL TWO 33 AINSLIE PLACE CANBERRA ACT 2600 AUSTRALIA T F LEVEL NINE 60 COLLINS STREET MELBOURNE VIC 3000 AUSTRALIA T F LEVEL ONE 50 PITT STREET SYDNEY NSW 2000 AUSTRALIA T F SUITE C2 CENTA BUILDING 118 RAILWAY STREET WEST PERTH WA 6005 AUSTRALIA T F ACILALLEN.COM.AU RELIANCE AND DISCLAIMER THE PROFESSIONAL ANALYSIS AND ADVICE IN THIS REPORT HAS BEEN PREPARED BY ACIL ALLEN CONSULTING FOR THE EXCLUSIVE USE OF THE PARTY OR PARTIES TO WHOM IT IS ADDRESSED (THE ADDRESSEE) AND FOR THE PURPOSES SPECIFIED IN IT. THIS REPORT IS SUPPLIED IN GOOD FAITH AND REFLECTS THE KNOWLEDGE, EXPERTISE AND EXPERIENCE OF THE CONSULTANTS INVOLVED. THE REPORT MUST NOT BE PUBLISHED, QUOTED OR DISSEMINATED TO ANY OTHER PARTY WITHOUT ACIL ALLEN CONSULTING S PRIOR WRITTEN CONSENT. ACIL ALLEN CONSULTING ACCEPTS NO RESPONSIBILITY WHATSOEVER FOR ANY LOSS OCCASIONED BY ANY PERSON ACTING OR REFRAINING FROM ACTION AS A RESULT OF RELIANCE ON THE REPORT, OTHER THAN THE ADDRESSEE. IN CONDUCTING THE ANALYSIS IN THIS REPORT ACIL ALLEN CONSULTING HAS ENDEAVOURED TO USE WHAT IT CONSIDERS IS THE BEST INFORMATION AVAILABLE AT THE DATE OF PUBLICATION, INCLUDING INFORMATION SUPPLIED BY THE ADDRESSEE. UNLESS STATED OTHERWISE, ACIL ALLEN CONSULTING DOES NOT WARRANT THE ACCURACY OF ANY FORECAST OR PREDICTION IN THE REPORT. ALTHOUGH ACIL ALLEN CONSULTING EXERCISES REASONABLE CARE WHEN MAKING FORECASTS OR PREDICTIONS, FACTORS IN THE PROCESS, SUCH AS FUTURE MARKET BEHAVIOUR, ARE INHERENTLY UNCERTAIN AND CANNOT BE FORECAST OR PREDICTED RELIABLY. ACIL ALLEN CONSULTING SHALL NOT BE LIABLE IN RESPECT OF ANY CLAIM ARISING OUT OF THE FAILURE OF A CLIENT INVESTMENT TO PERFORM TO THE ADVANTAGE OF THE CLIENT OR TO THE ADVANTAGE OF THE CLIENT TO THE DEGREE SUGGESTED OR ASSUMED IN ANY ADVICE OR FORECAST GIVEN BY ACIL ALLEN CONSULTING.

72 C O N T E N T S Key Points iv 1 Natural Gas in Australia: An Industry in Transition The Export Revolution Eastern Australian Gas Consumption Cost Pressures 6 2 The Gas Case Future Scenarios Economic scenarios Gas supply/demand scenarios Adjustment and Transitional Issues Should Governments Intervene in the Transition Process? Potential short-term price spikes: evidence of market or policy failure? Summing-Up the Challenge 20 3 A Package of Australian Policy Responses Recent Policy Initiatives Affecting the Gas Industry Australian Government Policy Initiatives Proposed Policy Initiatives for Gas Supply Maximise resource rent, capture a high proportion, and apply it astutely Manage Structural Adjustments Eschew Protectionist Policies Removing Market and Policy Failure Impediments to Gas Supply Addressing a short-term gas price spike 28 Australia s Natural Gas Supply: An assessment of current policy issues and options ii

73 Appendix A Natural Gas Terminology A-1 Appendix B Policy Design and Assessment Principles B-1 Appendix C Market and Policy Failures Affecting Gas Supply C-1 Appendix D Policy Failures Affecting Gas Supply D-1 Appendix E Policy Failures in Measures to Increase Supply E-1 Appendix F Management of Mineable Resources Boom and Bust F-1 Appendix G Bibliography G-1 List of boxes Box 1 Henry Tax Review on Charging for Mineable Resources B-5 Box 2 Box 3 Gaffney on Maximising and Capturing a High Proportion of Resource Rent B-9 Tinbergen on Interdependence of Instruments and Incompatibility of Targets B-11 Box 4 Stiglitz s Subsidy-Tax Scheme for Petroleum Exploration C-3 Box 5 Market Power Not an Issue in Domestic Gas Market C-6 Box 6 Adjustments or Disease F-1 Box 7 Economic Waste from Medium-Term Volatility of Commodity Prices F-3 Box 8 Limits of Monetary Policy as Mining Boom Unwinds F-5 List of figures Figure 1 Queensland CSG production history 3 Figure 2 Committed and proposed CSG LNG projects in Queensland 4 Figure 3 Eastern Australia gas consumption in 2012, by customer type 5 Figure 4 Modelled eastern Australia gas consumption forecasts 5 Figure 5 Schematic of different intensity/duration gas price spikes 16 Australia s Natural Gas Supply: An assessment of current policy issues and options iii

74 Key Points A C I L A L L E N C O N S U L T I N G Natural gas is a key component of Australia s energy mix, accounting for 23 per cent of primary energy consumption. It is a fuel and feedstock for a wide range of manufacturing, electricity generation, mining and mineral processing industries, and is relied on by millions of households and commercial entities. The Australian gas industry currently faces a period of unprecedented change as a result of the rapid expansion of LNG exports in both Western Australia and Queensland. By 2020, the amount of gas exported from Australia will be four times the amount consumed locally. The rapid expansion of LNG production will generate great economic benefits for Australia. It is also a structural shift that will permanently change Australia s gas markets and it poses significant risks for local gas users who face the prospect of substantially higher prices in the short- to medium-term future, as a result of constrained supply. These changes within the gas industry are occurring in the context of a more general boom in demand for and prices of mineable commodities. This extraordinarily long-lived boom, which emerged in 2003 and is only now showing signs of waning, has pushed up the exchange rate, boosted demand for non-tradeable goods and services and driven up input prices. It has seen resources bid away from other sectors of the economy into the mineable commodities and (to a lesser extent) non-tradeables sectors, and driven up input prices to all sectors. The impacts have been economy-wide, affecting not only gas consumers, but also all trade-exposed sectors including tourism, other tradeable services, and metal fabrication industries. Pro-cyclical government fiscal policy supported by higher government revenues has tended to exacerbate the cost pressures experienced by the gas industry and other trade-exposed sectors, particularly those not benefiting from booming commodity prices. In these circumstances there is a case for Government action to ensure suitable conditions are present for the timely and adequate supply of gas to the Australian economy. Gas-specific adjustment pressures apply to gas users rather than to the economy more generally. There is now a real risk that the emergence of the CSG LNG industry in Queensland will cause a transient gas price spike arising from a delay or shortfall in the ramp-up of gas production needed to supply the LNG plants. If production capacity is initially unable to keep pace with demand, gas prices could be pushed up to levels above long-run LNG netback prices before easing as supply catches up. The severity and timing of any such gas price spike effects are uncertain, but could persist for some years. The risk is that gas-consuming industry that would be economically viable in the long-term could be lost during this transitional period, resulting in avoidable, unnecessary economic waste. The emergence of a gas price spike would have potentially damaging effects on downstream gas users, particularly those for which gas costs comprise a large component of operating costs. Such users are likely to be particularly sensitive to gas prices if their products compete in export markets, or compete in domestic markets supplied with imported alternatives. The industries likely to be most vulnerable to high gas prices are feedstock industries such as fertiliser and basic chemical manufacture. Other gas intensive operations such as largescale mineral processing facilities are also relatively price-sensitive. Combined-cycle gas turbine (CCGT) electricity generating plant is sensitive to increasing gas prices, because higher fuel costs increase the short-run marginal cost of generation and reduce plant competitiveness relative to coal-fired plant (even after carbon prices). Australia s Natural Gas Supply: An assessment of current policy issues and options iv

75 Retail gas customers, including residential and commercial gas consumers and smaller industrial facilities are generally less sensitive to rises in the wholesale price of gas than large industrial and electricity generation customers. However, poorer households could be inequitably disadvantaged by higher gas and electricity prices during the gas price spike. The adverse impacts on Australian gas consumers of the anticipated rise in gas prices can be mitigated to the extent that: the height of any gas price spike is as low as possible and its length is as short as possible; and the long-term equilibrium gas price is lower rather than higher. Package of Australian Policy Responses A comprehensive package of policy responses would consider gas as one of many mineable resources, exploration for and exploitation of which have been influenced by prices that have been unusually high for an unusually long period of time. The policy responses can be grouped into three key areas: managing the resources boom facilitating new gas supply managing the risk of a gas price spike to avoid economic waste. Policy responses that fall into the area of managing the resources boom are more general, economy wide measures and are not the main focus of this paper. Nevertheless, any gas policy package should be developed and implemented in the context of a broader set of policy initiatives directed to managing the effects of the resources boom with regard to exchange rate, fiscal and monetary policy, tax policy and resource allocation. The Australian Government, in the Energy White Paper released on 8 November 2012, has acknowledged the risk that transitional pressures associated with LNG start-up will affect gas supply and price particularly in the eastern Australia market. The Energy White Paper identifies a number of measures designed to stimulate increased gas supply by improving information flows and enhancing trading opportunities. The challenge for Government will be to build on the Energy White Paper by: identifying effective monitoring techniques identifying trigger points that indicate the gas supply market has failed preparing appropriate responses in advance of these trigger points being reached, and building confidence by articulating these response options to gas market participants. Figure ES 1 identifies the gas-specific elements of the policy package. It does not detail the broader elements of a package of policy responses aimed at addressing departures from economic efficiency and equity principles. Australia s Natural Gas Supply: An assessment of current policy issues and options v

76 FIGURE ES 1 ELEMENTS OF THE GAS POLICY PACKAGE Facilitate New Gas Supply Maintain government funding of precompetitive exploration, data collection and early data release Provide targeted subsidies to pioneers, phasing out as external benefits diminish; cut loose losers quickly Reform royalty and tax systems Avoid Potential Economic Waste from Gas Price Spike Closely monitor gas price spike risk Provide temporary, variable, targeted assistance subsidy funded by royalty and tax revenue windfall from gas price spike ; adjust and remove when price spike passes Australia s Natural Gas Supply: An assessment of current policy issues and options vi

77 1 Natural Gas in Australia: An Industry in Transition The history of natural gas in Australia stretches back to 1900 with the discovery of gas in a water bore at Roma, in southern Queensland. However it was not until the late 1960s and early 1970s with the construction of pipelines connecting gas fields in the Surat Basin to Brisbane, the Cooper Basin to Adelaide and Sydney, the Gippsland Basin to Melbourne and the Perth Basin to Perth and Kwinana that natural gas became widely available in the major population centres throughout Australia. The subsequent construction and expansion of new and existing pipeline facilities and networks has seen the interconnection of the eastern states (including Tasmania) so that gas can now be traded throughout the east coast region. Western Australia and the Northern Territory remain separated from other markets. Natural gas is now an important component of Australia s energy mix, accounting for 23 per cent of primary energy consumption. Total consumption of natural gas in Australia currently stands at around 1,125 petajoules per year (PJ/a), comprising 730 PJ/a in Eastern Australia, 365 PJ/a in Western Australia and 30 PJ/a in the Northern Territory. Gas is a key input to the manufacturing, electricity generation, mining and mineral processing and residential sectors. Gas-fired generation provides around 15 per cent of the country s electricity, although the proportion varies widely from state to state with Western Australia and South Australia heavily reliant on gas-fired generation, while Victoria, New South Wales and to a lesser extent Queensland are more heavily reliant on coal. Liquefied natural gas (LNG) has also become a major export industry. In , Australia s LNG exports were around 20 million tonnes (Mt) and accounted for about 50 per cent of Australia s gas production. Exports of LNG have increased strongly in recent years by around 11 per cent a year over the past five years supported by expansions to the North West Shelf (NWS) project and the start-up of the Darwin LNG project. In 2010, around 70 per cent of Australia s LNG exports was sold to Japan. Australia s second largest market is China, which accounted for a further 20 per cent (Copeland, Grafton, Hitchins, Syed, 2012). 1.1 The Export Revolution After almost fifty years of steady growth and consolidation, the Australian natural gas industry now faces a period of unprecedented change as a result of the rapid expansion of LNG exports, including for the first time planned exports from large scale liquefaction facilities in eastern Australia. In 2010, Australia s LNG exports stood at about 20 Mt/a. By 2020, that figure will have more than quadrupled to over 85 Mt/a or 4,700 PJ/a four times the amount of gas currently consumed in the entire Australian domestic market. Around Australia, there are currently seven LNG projects under construction with a total design capacity of 61 Mt/a. Another project (Pluto, 4.3 Mt/a) is currently in the commissioning phase. The Browse LNG project is scheduled to be subject to a final investment decision during These projects, their estimated capital costs, and gas feed requirements are summarised in Table 1. Australia s Natural Gas Supply: An assessment of current policy issues and options 1

78 TABLE 1 AUSTRALIAN LNG DEVELOPMENT PROJECTS Project Proponents Capacity Mt/a DATA SOURCE: ACIL ALLEN COMPILATION FROM PUBLIC DOMAIN SOURCES. Estimated Cost US$ million Pluto Woodside , Gorgon Chevron, Shell, Mobil, Osaka Gas, Tokyo Gas, Chubu Electric 15 45, Wheatstone Chevron, Shell, Apache, KUFPEC, Kyushu Electric , Prelude FLNG Shell , Ichthys Inpex, Total , Browse Woodside, Shell, BP, BHPB, Mitsubishi, Mitsui 15 46, QCLNG BG Group, CNOOC, Tokyo Gas , GLNG Santos, Petronas, Total, KOGAS , APLNG ConocoPhillips, Origin, Sinopec 9 24, TOTAL ,200 4,554 Annual gas inputs This rapid expansion of LNG production capacity is coming about in response to rapidly rising demand for energy and in particular for clean burning natural gas in the developing eastern Asian economies. China in particular has been the primary source of demand growth, and notwithstanding some easing of the recent frenetic pace of Chinese economic growth, most analysts predict that China s appetite for LNG will continue to grow strongly. Japan, Korea and Malaysia have also helped to underwrite new LNG capacity in Australia with long term off-take agreements. The new LNG projects in Western Australia and the Northern Territory are for the most part based on very large, offshore conventional gas fields that were discovered years, even decades, ago. These resources have effectively lain dormant, awaiting the market opportunities provided by rapidly growing Asian demand and high oil and LNG prices. In eastern Australia, the story is somewhat different, although the confluence of Asian demand growth and high prices has again provided the impetus for development. The emergence of an LNG export industry in eastern Australia is a phenomenon that was not even contemplated ten years ago. Prevailing wisdom was that the conventional gas resources in eastern Australia were too small and too geographically scattered to support LNG exports. Indeed, with gas reserves in the Cooper and Surat Basins declining and deliverability falling, the 1990s saw a serious push to import gas into north-eastern Australia, not as LNG, but via a proposed pipeline from Papua New Guinea (PNG). The PNG pipeline project was finally abandoned in 2006, when a decision was made to direct the gas from the Kutubu and Hides fields into an LNG project at Port Moresby, rather than pipe it to Australia. The main reason that the PNG pipeline project had not gone ahead earlier was the emergence of coal seam gas (CSG) as a major new source of supply in Queensland. Since the late 1970s, CSG projects in Queensland had struggled to achieve commercial success. Even those projects that demonstrated the technical capacity to produce gas at commercial rates faced major obstacles gaining a toe-hold in the tightly held market. However, the patience of the CSG proponents was finally rewarded as producers in the Bowen Basin and later the Surat Basin secured a number of key contracts contracts that in a number of instances had been regarded as foundation loads for the PNG pipeline. The emergence of the Queensland CSG industry was further supported by a Queensland government policy that mandated the use of gas for electricity generation (the so-called 13 per cent gas scheme ). Once the Queensland CSG industry was up and running, it progressed at a spectacular rate. As shown in Figure 1, production of CSG in Queensland increased from negligible PJ/a Australia s Natural Gas Supply: An assessment of current policy issues and options 2

79 CSG Production (PJ) A C I L A L L E N C O N S U L T I N G levels in 2000 to around 225 PJ/a 30 per cent of the entire eastern Australian market by FIGURE 1 QUEENSLAND CSG PRODUCTION HISTORY CSG (Bowen Basin) CSG (Surat Basin) CSG (undifferentiated) DATA SOURCE: QUEENSLAND DEPARTMENT OF EMPLOYMENT, ECONOMIC DEVELOPMENT & INNOVATION, MINES & ENERGY DIVISION ; 2011 DATA FROM ENERGYQUEST QUOTED IN MINING WEEKLY ONLINE,19 MARCH Indeed, the rate of increase in CSG reserves posed something of a problem for the industry. By the end of 2009, announced proven and probable (2P) reserves of CSG in Queensland stood at around 23,000 PJ or more than 30 years reserves cover for the entire eastern Australian market. The reporting code which sets out the rules under which most petroleum exploration companies in Australia report reserves and resources (SPE/WPC/AAPG/SPEE Petroleum Resources Management System, p.6) states (emphasis added) that: To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability. There must be a reasonable expectation that all required internal and external approvals will be forthcoming, and there is evidence of firm intention to proceed with development within a reasonable time frame. Clearly, with the aggregate 2P Reserves announced by Queensland CSG companies sufficient to meet the entire Eastern Australian market for more than 30 years, the commerciality criterion requiring a firm intention to proceed with development within a reasonable time frame could not be met. A larger market was needed, both to support the claimed reserves levels and to provide resource owners with a clear path to monetisation. The realisation that Queensland CSG reserves were large enough to support LNG exports provided the market outlet needed. Initially, the proposals to use Queensland CSG resources to support world-scale LNG production were met with considerable scepticism because: CSG LNG had not been done anywhere else in the world concerns were raised over gas quality (lean methane with no higher hydrocarbons and hence low heating value) management of production ramp-up presented problems inability to turn down production to manage operational flexibility was seen as an issue water production and disposal had to be managed various other matters had to be resolved. Australia s Natural Gas Supply: An assessment of current policy issues and options 3

80 LNG Production Capacity (Mtpa) A C I L A L L E N C O N S U L T I N G However, technical and commercial solutions to each of these obstacles were identified. Now, three separate CSG LNG projects are under construction. FIGURE 2 COMMITTED AND PROPOSED CSG LNG PROJECTS IN QUEENSLAND Arrow T4 Arrow T3 APLNG T APLNG T3 GLNG T3 QCLNG T3 Arrow T2 Arrow T1 APLNG T2 APLNG T1 GLNG T2 GLNG T1 QCLNG T2 QCLNG T1 Committed SOURCE: ACIL ALLEN COMPILATION OF PUBLIC DOMAIN DATA. As shown in Figure 2, the three committed projects involve six LNG production trains with a total capacity of about 25 Mt/a. A fourth large scale project lead by Shell (Arrow LNG) is in the planning stage, and if all four large-scale projects were to proceed to full announced capacity, Queensland LNG production could reach almost 60 Mt/a. It is important to contrast the magnitude of these developments with the size of the existing domestic and the resources position, because doing so illustrates not only why the emergence of the CSG LNG industry represents a great economic opportunity for the state and the nation, but also a very significant threat to local gas-consuming industries. 1.2 Eastern Australian Gas Consumption Gas consumption in eastern Australia in 2012 is expected to total around 720 PJ/a. As shown in Figure 3, half of this consumption will be attributable to retail customers. Electricity generation and co-generation will account for about 32 per cent of consumption; large industrial and chemical manufacture about 10 per cent; and mining and mineral processing about 8 per cent. Australia s Natural Gas Supply: An assessment of current policy issues and options 4

81 PJ/a A C I L A L L E N C O N S U L T I N G FIGURE 3 EASTERN AUSTRALIA GAS CONSUMPTION IN 2012, BY CUSTOMER TYPE Co-generation, 26 Electricity, 198 Retail - comm/res, 184 Retail - industrial, 176 Mining & mineral processing, 58 Chemical manufacture, 42 Large industrial, 32 SOURCE: ACIL ALLEN GASMARK MODEL Note: Consumption in PJ/a. Figure 4 shows the results of modelling of the Eastern Australian gas market by ACIL Allen, under a scenario involving construction of eight LNG trains with aggregate nominal capacity of 32 Mt/a by While domestic consumption is forecast to grow slowly to around 850 PJ/a by 2030, gas inputs to LNG production for export are predicted to reach almost 2,000 PJ/a within the next decade. FIGURE MODELLED EASTERN AUSTRALIA GAS CONSUMPTION FORECASTS (8-train, 32 Mtpa LNG scenario) Commercial/Residential Small Industrial Large Industrial Power Generation - steam turbine Power Generation - OCGT Power Generation - CCGT Power Generation - cogeneration LNG SOURCE: ACIL ALLEN GASMARK MODELLING. A combination of factors now appears likely to limit domestic gas consumption in eastern Australia in the medium to long term. Australia s Natural Gas Supply: An assessment of current policy issues and options 5