Chairman Rod Sims outlines key findings from the ACCC's recent east coast gas inquiry covering the changing market, gas supply and pipeline regulation. Mr Sims also discusses the potential for gas from the Northern Territory to supply the east coast market.
Check against delivery
It is a pleasure to be in Darwin. As most of you know, on 13 April 2016 the Australian Competition and Consumer Commission (ACCC) provided its Final Report to relevant Commonwealth Ministers after a year-long inquiry into the state of competition in the east coast gas market.
The ACCC’s inquiry was held under Part VIIA of the Competition and Consumer Act (2010) (CCA) and used compulsory information gathering powers to gather information and hold hearings to assess the level of competition. The ACCC conducted in excess of 30 private hearings and considered over 73,000 individual documents.
Based on this raft of information, we found that eastern Australia’s gas market has been upended by a triple whammy that has important ramifications for all Australians. We made a number of important recommendations on gas supply, information availability and the test for pipeline regulation.
In August, the COAG Energy Council agreed to a significant package of east coast gas reforms implementing the recommendations made by the ACCC and the AEMC. The focus of these reforms is on:
- encouraging more gas supply and more gas suppliers, taking account of each jurisdiction's circumstances
- better information for trading in the market
- creation of trading hubs in the North and South
- improved access to transport infrastructure
- better pricing information.
Today, I will outline the key findings from the ACCC’s inquiry that fed into this reform package, including those that may have some bearing for the Northern Territory.
Changing landscape for the gas market
The triple whammy experienced by the gas market in eastern Australia is driven by a combination of local and international factors with significant implications for commercial and industrial (C&I) gas users:
- First, the introduction of LNG has changed gas flows and domestic prices.
- Second, oil prices have fallen faster and further than some thought possible.
- Third, regulatory uncertainty and exploration moratoria are significantly limiting the potential for new gas supply.
The LNG ramp up is continuing with the last of the six LNG trains expected to come online by the end of this year. The simultaneous commissioning of these trains has caused significant disruption to the market and the demand-supply balance, with some LNG proponents having to supplement self-supply by contracting gas that would otherwise have been supplied into the domestic market.
In this environment, C&I gas users have had a particularly difficult time. As everyone knows, the ACCC’s East Coast Gas Inquiry arose out of a desire by the Government to understand the truth behind conflicting statements from producers and consumers over gas availability.
C&I users now find themselves in a new paradigm where there are very few suppliers offering gas and often on strict “take it or leave it” terms. Domestic gas prices have risen sharply above the historic average of $3-$4/GJ.
There is also continued uncertainty as to how much third party gas the LNG projects will require and how much will be available to the domestic market.
Ordinarily, higher gas prices would provide producers an incentive to increase investment in exploration and development activities. However, the east coast gas market is now in a ‘clash of cycles’, with historically high domestic gas prices coinciding with falling international oil prices.
When the three LNG projects made their final investment decisions from October 2010 to January 2012, the oil price averaged around US$108 per barrel. It fell as low as about US$30 per barrel in early 2016 and has now recovered to around US$50 per barrel.
While the speed of the fall in oil price came as a shock for many in the industry, it is much closer to the 45 year inflation-adjusted price for oil of around US$55 per barrel than the US$100 per barrel that many industry pundits believed would be the new normal floor price for oil back in 2011-12.
Unfortunately for gas users (and producers), the lower oil prices have resulted in significant write downs by some producers and prompted a large number to wind back their expenditure on exploration and development.
Negative sentiment in financial institutions about the sector has also led to a curtailment of financing to producers and explorers in the east coast. The reduced expenditure on exploration and development activities is contributing to the uncertainty about future gas supply.
Further complicating the picture for new entrants and existing producers is the spectre of regulatory uncertainty and state and territory-based moratoria which are making new exploration increasingly risky or stopping development entirely.
Moratoria and other regulatory restrictions in New South Wales, Victoria and Tasmania are preventing or impeding onshore gas exploration and development in those states, at a time when the level and diversity of supply are critical in the east coast.
In this environment, the impact of the changed market conditions on C&I users has been particularly acute. The effects on these users vary depending on the alternatives available to them, the extent of their trade exposure and their use of gas for feedstock or energy or both. For some gas intensive industries, gas can account for 15 per cent or 40 per cent of input costs, while for chemical producers it can account for 80 per cent of costs.
Many users have few or no alternatives of gas available to them. Some are deciding to defer investments or reduce their gas usage, while others are considering whether they need to shut down some manufacturing plants entirely.
How can we address the issues on the east coast?
- We need more gas supply from a range of basins and producers.
- We need to improve the overall market operation and make better information available to industry participants.
- We need to address the problems associated with pipeline availability and pricing. In particular, it is important that the regulation of gas transmission pipelines, or the threat of regulation, is effective, which is not the case now.
In all this the Northern Territory has an opportunity to play a significant role. There are potentially very large gas resources in the Northern Territory and there is now going to be a pipeline built to connect them to the east coast gas market.
However, for this potential to be realised it is imperative that we have some further onshore gas development.
As the demand for gas in the east coast tripled virtually overnight with the simultaneous construction of the six LNG trains, the critical question for the gas industry is whether there will be sufficient supply over time to meet it.
While some of the LNG projects are producing most of the gas they need for export themselves, GLNG is relying on purchasing substantial volumes of gas from the domestic market to supplement its own production. A significant portion of this gas has come from the Cooper Basin and some of it is coming all the way from Victoria.
The East Coast Gas Inquiry found that this has severely disrupted the competitive dynamics in the southern states.
The Cooper Basin and basins offshore Victoria have historically supplied the southern states, in direct competition with one another.
With most Cooper Basin production now being directed toward the LNG facilities in Queensland, offshore Victoria has become the primary source of supply for the southern markets.
As the Otway and Bass Basin reserves decline during the next decade, gas from the Gippsland Basin, and the Gippsland Basin Joint Venture in particular, will be increasingly important in meeting southern market demand.
Without new gas supply from a range of basins and producers there will be significant implications for gas prices and gas availability in the southern states.
Gas users in the south will be forced to bargain with the Gippsland Basin Joint Venture in a market where their only alternative may be to source gas from Queensland. In this scenario, the Gippsland Basin Joint Venture will want to price up to the delivered price of this alternative. This will amount to the LNG netback price at Wallumbilla plus the cost of transport to ship it south.
Many C&I users are going to find it extremely difficult to sustain their business at such gas prices. The level of desperation in the industry is rising sharply. Some C&I users are contracting for gas that is not yet commercially proven, while others are talking about importing gas to a southern port via a floating storage and regasification unit.
There is little prospect of a significant increase in supply from the existing production basins in the southern states. Development of replacement reserves is currently lagging and may not be available soon enough.
Traditional sources of supply, such as Gippsland, Otway and Cooper basins face increasing costs and challenging decisions about potential new field expansions in the current economic conditions. In the absence of timely additional investment, there is potential for a significant reduction in supply from traditional sources in the southern states.
We now know that this gas won’t be coming from mainland Victoria. The Victorian Government recently announced a decision to place a permanent ban on the exploration and development of all onshore unconventional gas in Victoria and extend the current moratorium on exploration and development of even conventional onshore gas until 2020.
Undoubtedly, there are important environmental and social considerations underpinning this policy decision. However, it comes at a time when there is a critical need for more gas supply in the east coast, particularly in the south. Without this supply it is clear that gas prices must increase, which will damage C&I users and increase household energy bills. It is also important to note that we understand there are projects in Victoria potentially not reliant on fracking, like Lakes Oil, that are caught up in this ban on conventional gas.
As we look over the horizon, it is difficult at this stage to envisage where new gas supply will come from in the short to medium term to alleviate the high prices looming for gas users in the south.
There are Arrow reserves in Queensland, but there is still no clear information about the likely timing and size of this development and the bulk of it is probably destined for export.
It seems to me that the Northern Territory could play a significant role. As we know there is some gas in the NT not requiring fracking.
You will all be aware of a recent media release by Central Petroleum where the following statement was made:
"At the Mereenie JV (50% Central/50% Santos) alone Central operates 59 wells drilled and capable of production (none of which require additional fracking going forward). Of these wells, only 7 are required to meet the present gas contracts…we presently have 175 PJs of uncontracted gas available for sale into the east coast via the NGP. With appropriate pricing signals at the fields, an additional 125 PJs of gas could be made available from the Stairway formation in time for the scheduled commissioning of the NGP in 2018."
When the Northern Territory government announced in November of last year that it had selected Jemena to construct a pipeline to connect the Northern Territory with the east coast gas market, this represented a potential opportunity for that gas to be commercially developed.
This gas from the Northern Territory could serve as a source of supply for the east coast gas market. The potential job creation and investment in the NT would go hand in hand with the preservation of jobs and investment which might otherwise be threatened for C&l users in the south.
While we do not purport to weigh in on the debate surrounding the environmental issues, we consider that policy makers need to consider the cost or benefits of projects on a case by case basis. This is particularly pertinent to the Northern Territory, given the prospective gas projects are likely to be spread across the vast landscape and potentially represent different levels of risk.
If new sources of gas supply emerge with more gas suppliers, this will address the supply uncertainty for downstream gas users and put downward pressure on prices in the market for C&I and residential users.
Market operation and information availability
The East Coast Gas Inquiry found that changes to the gas markets have reduced the traditional options available to users to manage their gas requirements and more flexible short-term trading options and risk management tools are required.
The East Coast Gas Inquiry also found that the gas market is opaque and inflexible. Lack of transparency and information about the level of reserves, and commodity and transport prices, are hindering efficient market responses to the changing conditions and are not signaling expected supply problems effectively.
In August, the COAG Energy Council committed to measures to ensure the reporting of consistent reserve and resource information across the east coast gas market by all explorers and producers.
They also endorsed a range of other transparency measures proposed by the AEMC, including the development of a gas commodity price index and greater reporting by LNG proponents and the demand side of the market.
The COAG Energy Council also endorsed a number of ACCC and AEMC reform measures related to transmission pipelines. I turn now to the problems that the ACCC identified, which affect both the price and availability of transportation services on major transmission pipelines.
While gas supply is crucial for the market, an efficient gas market also requires an efficient transportation sector with competitive prices.
The East Coast Gas Inquiry found that most transmission pipeline operators have responded in a dynamic way to the changes currently underway in the market. In the main, pipeline operators have undertaken necessary investments in a timely manner and offered more flexible services to meet the changing needs of some users and producers.
As a result of this investment, there are now a number of pipelines that are operating on a bi‑directional basis, including the Moomba to Sydney Pipeline (MSP) and Moomba to Adelaide Pipeline System (MAPS), which are allowing gas to physically flow from Victoria to Queensland and vice versa.
While the market has benefited from this dynamic response, the Inquiry found that many transmission pipelines on the east coast face limited constraints when negotiating with shippers and are using their market power to engage in pricing, sometimes well above competitive levels, which is not surprising.
Let’s focus on the effect this type of behaviour could have on the supply of gas from the Northern Territory into the east coast market.
First, let me quote again from a Central Petroleum media release.
"Managing Director, Richard Cottee, said Central Petroleum has significant supplies of gas already available to help address the looming gas shortage in five states peaking from 2018-19. But, he said, the lack of economic regulation for existing and mature pipelines has distorted market pricing signals needed to bring new gas supplies to market, unnecessarily elevating delivered gas prices for customers and constricting the critical investment in new gas supplies which is needed to address supply shortages which are already starting to emerge."
In an email to the ACCC, Central Petroleum stated that the “critical barrier to us selling (gas) into the east coast domestic market is the pricing for utilising existing pipelines.”
Let me explain.
If gas is to be transported from the NT to the east coast market then it will have to be transported via the Amadeus to Darwin Pipeline (ADP), the soon to be developed Northern Gas Pipeline (NGP), the Carpentaria Gas Pipeline (CGP) and then either:
- the South West Queensland Pipeline (SWQP) for onward supply into Queensland and the LNG facilities; or
- the SWQP, Moomba to Sydney Pipeline (MSP) and/or Moomba to Adelaide Pipeline System (MAPS) for supply into NSW, South Australia and Victoria.
In the case of the NGP, which was subject to a competitive bidding process, the pipeline operator’s market power can be expected to be constrained for the duration of the foundation contracts. Indeed, the ACCC’s Inquiry found that the rate of return for the pipeline adopted in the winning NGP bid suggested a good level of competition between bidders. Potential users of the NGP moreover have told the ACCC that they have no problem with the resultant prices to transport gas to Mt Isa.
In contrast to the NGP, the other pipelines that the gas would need to traverse have been in existence for some time and in most cases the foundation contracts have expired. These pipelines are not subject therefore to the same constraints as the NGP when setting prices or the terms and conditions of access.
While it is often claimed that the ability and incentive of these pipelines to exercise market power will be constrained by other factors, such as competition from other pipelines or alternative energy sources, the countervailing power of shippers and/or the threat of regulation, the Inquiry found that the majority of existing transmission pipelines on the east coast have market power and face limited constraints when negotiating with shippers.
It is not surprising therefore that the Inquiry found that a large number of pipelines in the east coast were pricing at well above competitive levels.
For pipelines that might deliver NT gas to east coast demand centres, the Inquiry found a number of examples of such pricing. Three pipeline examples involving different asset owners were:
- One was earning 70 per cent more in revenue than the pipeline operator estimated it would be earning if it was regulated.
- One was earning over 20 per cent per annum based on a return on its historic written down asset value.
- Another had generated an internal rate of return of 19 per cent on a recent investment that had been fully underwritten by a shipper.
To put this into perspective, the ACCC report found that if tariffs on some of the major routes in the east coast were, say, 50 per cent lower, then it could result in a $1/GJ reduction in the delivered price of gas in the southern states; for example, the transportation charges on the South West Queensland Pipeline/ QSN (west) and Moomba to Sydney Pipeline (Moomba to Wilton).
For gas transported from the NT, which has to traverse far more pipelines, the effect would be much more significant. While some may question the assumption that tariffs would halve, it is consistent with internal documents provided by some pipeline operators and the ACCC’s own analysis, which showed that the prices on some pipelines are 50-80 per cent higher than what they would be if they were regulated.
The argument is sometimes made that regulation to address monopolistic pricing is unnecessary, because monopolistic pricing is the simple transfer of economic rents between parties in a supply chain.
However, excessive pipeline charges can have a significant impact on investment in new gas supply, as shown in the above quotes from Central Petroleum, and downstream industrial users, and the prices paid for products and services produced by gas. Critically, the Inquiry found that in the emerging east coast gas market, gas may often have to travel across multiple pipelines to reach end users. Monopoly pricing can prevent gas from flowing to where it is valued most highly.
The Inquiry, therefore, proposed changing the test for regulation (the coverage criteria) in the National Gas Law to provide a more effective test of whether regulation is required.
Under this new test, a gas pipeline would be covered where the pipeline in question has substantial market power, if that market power will continue to exist in the medium term, and if coverage is likely to contribute to achieving the National Gas Objective.
We recognise that, in the medium term, new gas pipelines might be built to provide alternative options for gas producers and gas users. This might place a constraint on the behaviour of existing pipelines. The proposed coverage criteria would take this potential constraint into account.
Our proposed changes to the coverage criteria also recognise that pipeline coverage needs to be aligned with the broader objective of the National Gas Law, which is to promote the efficient development and supply of gas services for the long term interests of gas consumers. This is intended to involve a qualitative assessment of efficiency benefits, as is done in other Australian regulatory contexts.
For proposed new pipelines, offering a 15 year no-coverage exemption under the National Gas Law would continue to provide up-front certainty for new pipeline investors.
As it stands today, less than 20 per cent of pipelines in the east coast are subject to any form of economic regulation. This is in stark contrast to other comparable international jurisdictions such as the US, New Zealand and the EU, where the vast majority of transmission pipelines are subject to economic regulation.
Notably, in overseas jurisdictions, the decision to regulate focuses on the market power of the pipeline.
Noting the above, the ACCC welcomes the COAG Energy Council’s current consultation on what needs to be done with the coverage criteria under the National Gas Law to address the ACCC findings. We also welcome the COAG Energy Council consulting further on enhanced pipeline financial information reporting by pipelines so that users, including potential users in the NT, can negotiate more effectively with pipeline operators.
The eastern Australian gas market faces large problems.
The largest problem is a lack of gas, and a lack of diversity of gas suppliers. Having a more appropriate test for whether pipelines should be regulated will also improve our gas market.
Thank you for your time this morning.
 The Inquiry only focused on transmission pipelines not distribution pipelines. References to pipeline operators should be interpreted as references to the operators of transmission pipelines.