Australia Consumer and Competition chairman Rod Sims delivered the following address on Australia’s energy market today to 5th Annual Australian Domestic Gas Outlook 2017, one year after the ACCC’s inquiry into the east coast gas market.
It has been almost a year since the ACCC delivered its report on the east coast gas market to the Government.
We held more than 30 private hearings and considered over 73,000 individual documents, largely obtained using our information gathering powers.
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 regulation of pipelines.
At last year’s conference, a year ago, I warned of… “an urgent need for both new and importantly more diverse sources of gas supply into the domestic market.” The outlook for gas supply is now even worse than it was a year ago; indeed, our worst fears are being realised.
The word “crisis” can be much overused. Some see it of grave concern that much less gas is now going to gas-fired electricity generation; at the margin, this will see more coal-fired generation than otherwise.
This trend was clear a year ago, and even clearer now. By one estimate (Energy Quest) gas-fired generation in the NEM has fallen 37% from Q4 2015 to Q4 2016.
No one should be surprised.
We also observed a year ago that wholesale gas prices make up 15-30% of total residential gas bills and that household bills would increase by 5% in NSW and 11% in Victoria if wholesale gas prices increase by $2 / GJ.
We now know that wholesale gas prices have or will increase by many times $2/GJ.
To me, however, the real crisis is facing some industrial gas users, and this point is insufficiently recognised.
The effects of the gas price shock will vary depending on whether they have alternatives to gas and the extent of their trade exposure. Many industrial users have no real alternative to gas, and gas can often be 5% and for some, 15-40% of input costs.
The gas spot price recently has been above $10/GJ, some 150% higher than past prices, and some companies are apparently being offered gas at $20/GJ, if they receive supply offers at all.
At best, how can these companies invest and plan with such high and uncertain gas prices and with considerable supply uncertainty. At worst, plants will close and jobs will be lost purely as a result of the current gas crisis.
Australia often makes it hard to be involved in manufacturing. We are now making it extremely difficult if not impossible for some.
I will cover three topics:
1. Reflections on the triple whammy that has upended Australia’s gas market
The triple whammy experienced by the gas market in eastern Australia was 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 changed gas flows and domestic prices.
Second, oil prices fell faster and further than some thought possible, curtailing investment in gas exploration and development.
Third, regulatory uncertainty and exploration moratoria have significantly limited or delayed the potential for new gas supply.
The simultaneous commissioning of the six LNG trains in Queensland 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.
C&I users found themselves in a new situation where there were very few suppliers offering gas, and often on strict “take it or leave it” terms. Domestic gas prices increased sharply above the historic average of $3-$4/GJ.
Ordinarily, higher gas prices would provide producers an incentive to increase investment in exploration and development activities. However, the east coast gas market was caught 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. It has recently recovered to around US$50 per barrel, which is close to the 45 year inflation-adjusted average price for oil of around US$55 per barrel.
Unfortunately for gas users, and producers, the lower oil prices resulted in significant write downs by some producers and prompted a large number to wind back their expenditure on exploration and development.
Further complicating the picture was the spectre of regulatory uncertainty and state and territory-based moratoria, which delayed or stopped development entirely.
Moratoria and other regulatory restrictions in New South Wales, Victoria and Tasmania were preventing or impeding onshore gas exploration and development in those states, at a time when the level and diversity of supply were critical in the east coast.
In this environment, the impact of the changed market conditions on C&I users was particularly acute.
AEMO’s GSOO last week noted that an increase of $2/GJ in wholesale prices for industrial customers using gas could lead to a reduction in consumption by 20 PJ/a (around 8.6%) as operations close due to price shock.
The concerns of C&I users about rising energy prices affecting their viability has escalated since the ACCC conducted its Inquiry in 2015. Over the past few days we have seen businesses like Coogee Chemicals discuss how they have already stopped production. Others talk about how they will have to close based on current energy prices.
Arising out of this triple whammy we now have a strange debate about the three Queensland LNG projects.
As our Inquiry pointed out, Australia has enormous gas resources; gas availability is clearly not the issue. The Inquiry also pointed out that Australia has and will benefit enormously from the three large LNG projects in Queensland. These three projects also saw significant gas resources developed that otherwise would not have been.
If there is a criticism of the three LNG gas developers it is that they fell into the usual commodity project trap of assuming then high $100 plus oil prices would continue, when long run average oil prices of around $55 would have been a better planning assumption.
The three LNG producers, however, could not have foreseen that after their investment decisions were made east coast onshore gas exploration and development would be largely prevented. I doubt anyone in the industry expected Victoria to ban all onshore gas exploration and production, which has stopped even conventional gas projects; nor could they have foreseen the delays and uncertainty over projects in NSW and the NT.
It is, of course, up to Governments to make such decisions. Having made them, however, it is difficult to see how people can then criticise the commercial contracts that were freely entered into by the LNG producers at a time when the likely supply outlook was very different.
That said, if I was providing private advice to the LNG producers I would say, they would be well advised to support the domestic market as much as they can at this critical time.
2. Some comments on the gas supply outlook
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 was whether there would be sufficient supply over time to meet it.
The gas production forecasts at the time of the our inquiry indicated that sufficient gas was expected to be produced to meet domestic demand and existing LNG export commitments until at least 2025.
However, whether this outcome would materialise was contingent on two critical factors.
First, on the supply side, the production forecasts indicated that from about the start of this year, meeting the expected demand would require development of new reserves. These reserves had been identified by gas producers but still required extensive investment.
Second, the equation changes on the demand side if the LNG projects seek to sell gas on international LNG spot markets on top of meeting their existing contractual commitments. In these circumstances, even more new gas reserves would be required to meet this additional demand.
A large portion of future production in the market was expected to come from unconventional CSG fields in Queensland, which are primarily being developed by the LNG projects. The need for continual reinvestment in CSG infrastructure creates commercial and technical uncertainty over the exact timing and volume of future gas from these reserves.
Adding to this uncertainty was the lack of clear information about the likely timing and size of the Arrow project development, which still holds the most significant uncommitted gas reserves on the east coast.
Traditional sources of supply, such as Gippsland, Otway and Cooper basins faced increasing costs and challenging decisions about potential new field expansions in the prevailing economic conditions. In the absence of timely additional investment, there would likely be a significant reduction in supply from these traditional sources in the southern states.
We were optimistic then that the decision by the Northern Territory government to construct the Northern Gas Pipeline to connect the Northern Territory with the east coast gas market would potentially bring new gas supply into the east coast. This is now uncertain.
Today, C&I customers increasingly complain that the lack of genuine gas offers is on par, if not worse, than it was over the 2012-14 period that we discussed extensively in our report. As I have said, some C&I customers are finding that most gas suppliers are not able to offer any gas at all.
The gas supply outlook is now even more uncertain than 12 months ago. In Queensland, all six LNG trains are now up and running with increasing volumes of gas being exported overseas.
Importantly, most LNG producers are selling gas on the LNG spot markets in addition to meeting their contractual commitments and these volumes are expected to increase going forward.
The comment that I made at the end of the last section of my speech seems relevant here.
It is unclear to what extent this additional gas has been supported by additional gas development, as the well drilling rates for at least some projects has been affected by capital constraints. GLNG continues to supplement self-supply by contracting substantial volumes of gas from reserves that previously served the domestic market. A significant portion of this gas has come from the Cooper Basin and some of it is coming all the way from Victoria.
We understand that some of the LNG producers have diverted gas into the domestic market at times of domestic market tightness over the past 12 months, but the extent to which this has happened is unclear. It also remains to be seen what kind of volumes are likely to be sold by LNG producers to domestic users under longer term contracts, particularly as their legacy domestic contracts expire. These longer term contracts are critical for C&I customers as many of them cannot just rely on the ad hoc purchases of gas on the spot market.
The timing of development of the Arrow reserves is still unknown, with the only news being the write-down of the Arrow reserves in the Surat Basin.
As I mentioned earlier, we now know that gas won’t be coming from mainland Victoria. Last year, the Victorian Government 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 conventional onshore gas until 2020.
Undoubtedly, there are important environmental and social considerations underpinning this policy decision. The ban comes, however, 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.
While we do not purport to weigh in on the debate surrounding the environmental issues, we feel that policy makers need to consider the cost or benefits of projects on a case by case basis.
It is easy to accept that some projects will fail on environmental grounds; it is, however, difficult to accept that they all do.
In NSW, while there have been some recent announcements by Santos and APA potentially indicating that steps are being taken to progress the Narrabri project, it still remains unclear when and, in fact, whether this project will commence production.
As I already said, the gas supply outlook is very bad news for C&I gas users. As we feared, without new gas supply from a range of basins and producers, there are significant implications for gas prices and gas availability, particularly in the southern states. Gas users in the south are being forced to bargain with the Gippsland Basin Joint Venture in a market where their only alternative may be to source gas from Queensland, and pay the considerable transport costs on top of the netback price.
And again to repeat, we understand recent price offers have gone up again and are in the vicinity of $11-12/GJ. Shortly before the Australian Industry Group published Energy Shock: No Gas, No Power, No Future? in February 2017, it had begun to receive reports that Victorian manufacturers were being offered one- and two-year contracts at wholesale gas prices of $20 or more.
It seems to me that we take too little account of our manufacturing industries in our energy debate. Many large gas users are going to find it extremely difficult to sustain their business.
As others have suggested, more incentives may be needed to assist with the social licenses required for the production of gas to enable more gas supply. What lies below the ground is owned by the States under legislation, but perhaps further incentives could be provided to land holders to help them feel compensated or comfortable with the incursion on their land which gas development necessarily involves.
3. Some brief comments on our other recommendations and the progress with them
The Gas Market Reform Group’s (GMRG) work on pipeline transportation reforms is under way with changes to the pipeline regulatory framework to address the market power issues our Inquiry identified. This is important work with, for example, the potential for it to assist with the unlocking of Northern Territory gas.
The ACCC Gas Inquiry found the East Coast gas market had benefited from dynamic responses by pipelines such as through increased investment in pipeline interconnections and bi-directionality. However, it also found that many transmission pipelines on the east coast face limited constraints when negotiating with shippers and were using their market power to engage in pricing sometimes well above competitive levels, which is not surprising.
Market participants raised concerns during the Inquiry about the ability of pipeline operators to exercise market power when negotiating the price of transportation services.
The Inquiry found there was substance to these claims. A large number of pipeline operator’s internal documents showed relatively high returns on assets and incremental investments. Analysis subsequently carried out by Credit Suisse provided further support for this finding.
To try and counter the market power held by pipeline operators, the Inquiry recommended greater disclosure of financial information across all open access pipelines and a change to the test for pipeline coverage to a market power based test.
As you all know, Dr Michael Vertigan, at the request of the COAG Energy Council (Energy Council), conducted his own review on potential changes to the regulatory framework that applies to gas pipelines. His report, which was delivered to the Energy Council in December, indicates that he heard similar concerns from a range of shippers about information asymmetries, imbalances in bargaining power and the exercise of market power by some pipeline operators. Independent analysis carried out by JP Morgan for Dr Vertigan also revealed that excessive pipeline returns were being generated.
Rather than changing the test for regulation, Dr Vertigan recommended that greater emphasis be placed on addressing the imbalance in bargaining power faced by shippers by requiring greater transparency and information disclosure from pipelines and providing shippers with access to binding commercial arbitration if negotiations fail.
Dr Vertigan’s recommendations, cleverly in my view, address the consequences of the market power issues that the Inquiry found. In contrast to the ACCC’s recommendations, which would have required an assessment of market power before a pipeline could become subject to regulation, Dr Vertigan’s proposal in effect extends the information disclosure and negotiate-arbitrate framework to all pipelines and therefore provides shippers with more protection than they would have had under our proposal.
I understand that Dr Vertigan has commenced work on the design of this new regime. It will be critical that the information pipeline operators are required to disclose extends to cost information so that shippers can assess whether prices are cost reflective and readily identify any attempted exercise of market power.
This is the standard model in a number of overseas jurisdictions: cost information is reported annually in Canada, New Zealand, the United Kingdom and the United States.
As Dr Vertigan noted in his report, the efficiency of pipeline prices is critical to ensure the efficient movement of gas around the system and with this in mind I would like to add to some comments I made last September in Darwin on the great potential for Northern Territory gas to assist Southern users.
AEMO’s GSOO released last week identifies Northern Territory gas, available via the in development Northern Gas Pipeline (NGP) as a potential source of new supply. And one which could alleviate almost entirely AEMO’s forecast supply shortfall conditions from summer 2018/19 based on reserves available from the Mereenie basin.
Central Petroleum has previously confirmed it has significant resources available to meet 2018-19 peak demand, which do not require fracking. Interest in the Northern Territory seems to be hotting up, with Origin recently indicating it has very significant prospective resources in the Beetaloo basin. However, during the Inquiry, 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 under development 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 contrast to the NGP, the other pipelines required to transport the gas have been in existence for some time and in most cases the foundation contracts have expired. These pipelines are not subject to the same constraints as the NGP when setting prices or the terms and conditions of access.
To put this in perspective the ACCC found that if tariffs on some of the major routes were, say, 50% 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 Northern Territory, which requires 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.
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 and downstream industrial users, and the prices paid for products and services produced by gas.
Monopoly pricing can also prevent gas from flowing to where it is valued most highly.
Having made those important points, I would like to make another very important point, and one there would be almost universal agreement on. Pipeline reform is meaningless if there is no gas to supply.
When the Northern Territory government announced in November 2015 that it had selected Jemena to construct the NGP, the Northern Territory appeared set to have an opportunity to play a significant role in the east coast gas market.
This development has been put on hold due to a moratorium on fracking instituted by the Northern Territory government last September, pending resolution of the inquiry into the social, economic, cultural and environmental impacts of the shale gas extraction method.
My comments earlier on the need for a case by case assessment basis for moratoria are 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.
Finally, perhaps the most consistently made comment to the ACCC Gas Inquiry was that the market was opaque. The scope, quality and consistency of gas industry information has been discussed for a number of years and our recommendations in these areas need to be progressed urgently.
Having reviewed vast amounts of information through the Gas Inquiry, otherwise typically not available, it is clear to me that what is presently publicly available is insufficient for policy makers, let alone C&I users who are trying to make investment decisions.
Our energy markets as a whole could be said to be in crisis, both electricity and gas. As policy makers grapple with the issues we need to keep a close eye on the impact on all energy users, large and small.
In particular, once some industrial gas users close they will not likely reopen. Australia in general, and many of our geographic regions in particular, will be the worse for this.
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