9.3.1 Changing market dynamics
9.3.2 Developing more efficient gas markets
9.3.3 Responding to transitional pressures
Australia’s gas markets will continue to grow and evolve with the emergence of new resource developments and greater demand.
Australian gas markets are based primarily on confidential bilateral contracts, and while that is unlikely to change in the near future, the gas industry and consumers are moving towards a more dynamic operating environment in the way they use and trade in gas. It is critical that government policy provides the right policy structure to support growth and facilitate changing market dynamics.
It is the government’s strong view that these issues should be approached in the context of the overarching objective of ensuring adequate supplies of gas to Australian markets and that these markets should operate in the long-term interest of consumers.
This section examines the challenges and priorities associated with:
- changing market dynamics in the eastern and western gas markets
- the development of more efficient gas markets
- responses to transitional market pressures.
9.3.1 Changing market dynamics
Important changes are underway in the dynamics of Australia’s gas markets, driven by increased demand competition, the development of new but higher-cost gas reserves, and changing patterns in domestic use, including a growing interaction between gas and electricity markets. Because of the emerging connection between the domestic and international gas markets, changes in the LNG markets, particularly in the Asia–Pacific region, could also affect the development of our domestic markets in the longer term.
These changes are already affecting terms, prices and market structure in the eastern and western gas markets (discussed in detail below), and further transitional pressures are likely to emerge over the short to medium term as markets adjust.
Each of Australia’s gas markets is different from the others in its resource base, its current and future production, its demand profile and the maturity of its infrastructure. While headline trends may appear similar, each market should be assessed separately. Experiences in the western market cannot simply be translated to the eastern market (or vice versa) without considering their underlying differences. As market circumstances continue to evolve, it is also unrealistic to expect past price and trading dynamics in each market to apply automatically in the future.
Western market
Change has been underway in the western market since 2006–07, when domestic gas demand began to exceed North West Shelf long-term take-or-pay contracts and prices began to rise, reflecting the cost of new supply. Prices in new contracts have been reported to range from $5.55/GJ to $9.25/GJ (WA Government 2011).
Australia’s western gas resources are diverse and generally have high development costs. New offshore gas fields are in deeper waters and require higher volumes and export sales to support up-front development capital and to cover higher project risks. Where the resources are within economically feasible distances to domestic supply infrastructure, there are opportunities to monetise gas at an early stage and provide important cash flow. Stand-alone LNG production from smaller fields is generally not viable unless they can form part of a larger LNG project, but development for domestic supply can be commercially attractive where prices support production costs.
This has meant that domestic supply has been and remains heavily dependent on LNG projects. The scale of LNG developments has also meant that new supply has generally been available only in comparatively large increments, which has sometimes challenged new entrants and those contracting smaller domestic volumes.
This is now changing. The domestic market is diversifying as higher prices stimulate new domestic supply. Onshore exploration for tight and shale gas has also increased; for example, activity is underway in the Perth and Canning basins (WA Government 2012). However, while prices are likely to stabilise, it is unrealistic to expect a return to historical levels for the reasons outlined above.
Recent analysis suggests that projected supply capacity is capable of meeting likely demand to at least 2030, although there may be periods of short-term tightness (EnergyQuest 2011, WA Government 2011). While the progressive roll-off of existing North West Shelf supply contracts over this decade creates some future domestic supply risk, there is no reason to believe that the owners will not maintain a substantial market presence, given their existing commercial investments in domestic processing capacity. Further market response from other suppliers is also likely if supply or price begins to tighten and market flexibility and price incentives are maintained.
The Australian Government believes that future development of the Western Australian gas market will benefit from increased competition between different sources of supply. To increase competition, the government notes the importance of building customer numbers, increasing the liquidity of the market, improving transparency and mechanisms for trading gas, particularly on short-term arrangements, and adding alternative injection points and storage facilities. It notes in particular that the current joint marketing arrangements for the north-west shelf would be unnecessary with further development of the market.
Eastern market
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 baseload capacity may not be needed until later this decade (or beyond) if overall demand remains subdued (AEMO 2012a). The combined impact that these factors will have on final demand for gas is not yet clear, although overall growth is expected.
The cost base of the market is also increasing because new production is from higher-cost resources (BREE 2012i). 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 (DEEDI 2012:vi). Acil Tasman has projected regional gas prices rising to $11 and above by 2030 (BREE 2012i:61).
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 (AEMO 2012c, RET, GA & BREE 2012, DEEDI 2012), and there is good potential to identify further commercially viable CSG and new shale and tight gas resources.
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 (DEEDI 2012). 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 (DEEDI 2012). Meeting project development 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 2020 (BREE 2012i, DEEDI 2012). 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 (BREE 2012i).
It is clear that the market has yet to establish a new trading dynamic, particularly around contracting terms and prices. Given the factors discussed above, this is likely to take some time to emerge. While long-term bilateral contract arrangements are likely to continue to dominate in the future, market participants are increasingly likely to look for more sophisticated and flexible ways to manage supply and price risks, perhaps through greater use of short-term and multiparty trading than in the past. This can be supported through further market development.
The following two sections examine the need for further development of our gas markets and, in that context, the government’s approach to managing transitional pressures in the markets.
9.3.2 Developing more efficient gas markets
Australian gas markets have evolved considerably in the past 20 years, developing deeper competition and wider trading possibilities. However, as emerging pressures are showing, there is a need (and capacity) for further market development to promote more informed and balanced long-term decision-making and to improve trading flexibility. It is important that market design and regulation facilitate efficient market evolution in the face of changing circumstances.
Setting market reform in a long-term context
The next steps in the reform process should be considered in the context of the longer-term direction of gas markets and, in particular, the characteristics that mature gas markets should display. Those characteristics could include:
- mature and well-functioning physical and financial markets with upstream and downstream trading platforms to promote flexible trading and transfers of gas
- this could include a greater reliance on harmonised spot markets supported by robust secondary markets for managing risk and promoting market transparency
- arrangements could also provide for competitive access to unused pipeline capacity and easier title transfers
- highly flexible and connected networks, including interactions between electricity and gas
- mature sets of commercially public market information that supports efficient trading, including information on prices, volumes and infrastructure capacity.
Options for achieving these goals will rightly be the subject of ongoing discussion between governments and market participants. The Australian Government welcomes open debate about the longer-term direction of the market.
The government considers that current market development priorities should include a greater ability to go to market for price, easier transfers of title, competitive access to unused pipeline capacity, better rewards for efficient pipeline investment, and confidence in the ability to access gas from the market.
Australia can draw lessons from a number of overseas gas market models, such as the Henry Hub market in the United States. Australian gas markets may be some way away from the physical maturity that would support such models and, given our unique market characteristics, might not develop to that level of sophistication. However, incremental reforms can be made now to provide the appropriate policy and regulatory framework for their efficient operation and evolution. These reforms should take market development down a path consistent with our long-term objectives.
Improving market information
Because of the significant developments in the gas industry, including the growing role of gas in the National Electricity Market, it is critical that sound and timely market information is publicly available. It is arguable that this is not currently the case.
While there is much gas market information in industry reports such as the AEMO’s Gas statement of opportunities and the Australian Energy Regulator’s State of the market reports, gaps remain in areas such as the forecast domestic supply of gas, the forecast adequacy of supply, current and forward prices and market liquidity. This information asymmetry can lead to suboptimal decisions by participants, policymakers and regulators. The lack of public information is partly due to its commercial sensitivity, but the Australian Government believes that information provision can be improved for the benefit of all participants while balancing legitimate commercial concerns and the cost of provision.
A range of options could be considered to achieve this, including incremental improvement to existing mechanisms such as the Gas Statement of Opportunities to provide a more detailed market outlook, the establishment of a market-driven mechanism to report price expectations (such as a gas price index), and mandated reporting of price and contract terms. These options may not be mutually exclusive.
In March 2012, the AEMO concluded that there is potential value in amending the Gas Bulletin Board to include a medium-term outlook. This would help market participants plan for scheduled outages or changes in available capacity that affect transmission pipelines and gas storage and processing facilities. The AEMO has also proposed extending capacity outlook information from three to seven days to provide longer lead times for operational decisions.
The Australian Government supports the proposed provision of short- and medium-term outlook information as a necessary foundation for a more efficient and evolved market, and notes that the AEMO’s recommendations are currently being considered by the Australian Energy Market Commission through the rule change process.
Improving price transparency and trading opportunities
There is a need for more flexible and transparent upstream transactions between parties, beyond the current market frameworks, to enable market participants to manage gas portfolios and contract obligations efficiently, especially in the face of variable supply and demand.
Upstream trading opportunities could be expanded through the establishment of a supply hub trading market that would allow gas and capacity to be traded separately. The objective of a gas supply hub is to enhance transparency and reliability of supply by creating a voluntary market that offers a low-cost, flexible method to transfer title of gas from one party to another.
A national supply hub trading market model would be further upstream than the current demand hub model, and could therefore increase overall participation in gas markets by attracting large users, such as LNG plants and gas-fired generators. This has the potential to provide a mechanism to balance gas supplies at least cost.
Through the SCER, the Australian Government and other jurisdictions have agreed to the development of a national gas supply hub trading model, and have tasked the AEMO to prepare a report, in close consultation with industry participants, on the detailed design of a gas supply -brokerage hub- trading market at Wallumbilla, Queensland. Ministers will consider this issue further in December 2012.
Improving infrastructure efficiency
Gas transmission and distribution developments need to be efficient and timely to ensure access to the market. This is fundamental to the further development of an efficient gas market and end-use industries, such as electricity generation and manufacturing.
To date, investment in Australia’s gas transmission and distribution networks has been mainly demand driven. As a result, new pipeline investments have historically been underpinned by long-term pre-investment contracts with large foundation customers. While this appears to have delivered on-time investment, there is a risk of poorly timed investment if market signals are dampened by a lack of price transparency and forward price discovery.
A related issue is the efficiency of current infrastructure and access to pipeline capacity. Although most pipeline capacity is fully contracted, there is often considerable unused capacity on any given day. The underutilised capacity could be used by participants to ship gas, increasing network flexibility and trading opportunities. The current owner of that capacity would need to be fully compensated for its 'sale'.
Access to pipeline capacity affects the ability of shippers to participate in a supply hub trading market: haulage rights on what are currently fully contracted pipelines into Wallumbilla are needed for market participants to ship gas to and from the hub.
Understanding potential linkages between gas and other energy markets
Over the long term, carbon pricing is expected to increase domestic demand for gas-fired electricity generation, including for distributed or co-generation, peaking and baseload capacity. With appropriate storage facilities, energy businesses may be able to develop well-balanced coal, gas and renewable energy portfolios that provide for more flexible generation management based on relative cost and availability. Such developments would improve Australia’s energy security and, if managed efficiently, reduce overall costs.
It will be important that these investments, including locational decisions, are efficient. However, there is some potential for distortion through mismatched locational incentives in gas and electricity transmission and distribution incentive structures. This may occur where electricity infrastructure and connection costs that meet certain tests are able to be spread across a broader customer base, while pipeline and other gas infrastructure costs must be directly recouped from users.
These issues are not currently well understood, so further analysis of the potential interactions and their drivers is needed to underpin a considered policy and operational response (if one is required).
9.3.3 Responding to transitional pressures
Emerging pressures in our gas markets must be addressed smoothly, efficiently and in ways that are consistent with the principle of market-based development. Well-functioning markets with access to timely and adequate supply remain the most effective mechanism for providing energy security.
While current pressures may remain for some time, both the eastern and western markets have the production capacity to respond to tightening conditions. In the eastern market this can occur through a range of options, including adjusting production schedules, increasing production from existing fields, such as Gippsland, bringing forward incremental capacity from new CSG reserves, or any combination of those options. In this context, there is a critical window of opportunity to develop the Gunnedah CSG basin in New South Wales, although with a four- to five-year development timeline the contribution that may make to market supply in this period is fast narrowing.
However, the key to stimulating effective and timely market response is to maintain open trading arrangements that do not constrict the proven ability of the market to deliver. This must allow price to play its role as a balancing incentive that can drive the development of additional supply. It is also critical that current impediments to the safe and sustainable development of new gas resources are addressed as a matter of priority.
For this reason, the Australian Government does not support calls for a national gas reservation policy or other forms of subsidy to effectively maintain separation between domestic and international gas markets or to quarantine gas for domestic supply.
While the immediate focus of industry and governments should be on ensuring adequate supply, it is critical that this is not focused solely on addressing shorter-term transition issues, but is consistent with the broader future needs and direction of Australia’s gas markets. This should recognise how the changing dynamics will affect the medium- to long-term operation of the market and provide a supporting framework for smooth adaptation to them. This will help to ensure that gas market policy is effective in the long term, to the benefit of both industry and consumers.
The policy objective should be to provide the most efficient framework for the market to flexibly manage emerging pressures while monitoring market outcomes closely to ensure that the market is responding as necessary. The provision of better information on production, supply, demand and prices will also work to increase market confidence and give industry greater certainty in its decision-making.
In this context, a national reservation policy would add to, rather than reduce, long-term market risk by eroding development and supply incentives. It would be likely to impede the development of efficient gas markets and reduce returns to the economy from the development of our natural gas resources. Furthermore, the government notes that as a policy instrument for ensuring affordable supply, gas reservation does not in itself promote market or price separation or ensure timely supply in response to changing market conditions beyond that which would be incentivised through free-forming market incentives.
The prima facie evidence from the application of reservation policy in Western Australia supports this view. There is no compelling evidence that it has constrained domestic prices, and domestic supply obligations placed on the North West Shelf project have been exceeded well ahead of schedule, driven by commercial incentives rather than mandated production requirements.
Beyond concerns about its impact on market efficiency, a national reservation policy would also be damaging to the nation’s investment reputation, and would be at odds with our longstanding national commitment to open and fair trade.
Claims that intervening to provide cheap domestic gas would support the large-scale development of new industries must be also tested against the investment outcomes that occurred when gas was available at such prices over the past two decades. The best value-add outcome for Australia will be achieved by allowing resources to flow to their highest valued uses.
Comparisons of higher Australian gas prices with the low prices in the United States to justify intervention are also misplaced. The US gas market has been transformed by the development of shale gas reserves that are high in valuable liquid content (oil and condensate) with easy access to interconnected gas pipelines, resulting in extremely low-price gas. In contrast, Australian CSG has no liquid content and our prospective shale and tight gas resources are likely to be lower in liquids than those in the United States (due to differing geology) and, with the exception of the Cooper Basin, will require costly new infrastructure to develop.
The government does not accept the proposition that export developments are compromising Australia’s gas security. Transitional pressures notwithstanding, LNG exports provide a critical platform for the expansion of our domestic markets and gas supply infrastructure. LNG projects are expected to produce $30 billion in export earnings by 2016–17 (BREE 2012g). These projects provide enormous returns to the Australian economy that would not be possible from domestic development alone.
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.
As discussed in Chapter 5: Energy resources, when assessing retention leases or considering grants of production licences, the Australian Government pays close attention to the potential for offshore LNG projects to supply the domestic gas market. Further responses, if any, would be developed through the SCER and be consistent with market development objectives.
The government will continue to engage with the gas industry and relevant jurisdictions to identify opportunities to promote market liquidity, while recognising that it is not the role of government to interfere in commercial negotiating processes.