ACCC initiatives addressing the Australian domestic gas market

Ms Nicole Ross, Gas Inquiry Unit
6th Annual Australian Domestic Gas Outlook Conference
28 February 2018

Nicole Ross, General Manager ACCC Gas Inquiry Unit, delivered the speech on the ACCC Chairman's behalf due to an unavoidable scheduling conflict. The speech outlines what the ACCC is doing to help bring about a more competitive east coast gas market.


Check against delivery

It’s a pleasure to be here today at the annual Australian Domestic Gas Outlook, representing ACCC Chairman Rod Sims.

Mr Sims sends his apologies.

Unfortunately, as he would have told you could he have been here, there is still plenty to talk about in relation to the east coast gas market and lots more work that needs to be done.

Last year, Mr Sims used the word ‘crisis’ to describe the state of the east coast gas market and he did not use that word lightly. He spoke, in particular, of the effect on some industrial gas users, with the very real prospect of plant closures and job losses arising from the state of the gas market.

What has changed in a year?

The ACCC has spoken to a range of commercial and industrial (C&I) users in the last few months, who together make up more than a third of total industrial consumption.

Gas is a significant cost for these companies, and can account for around 10 to 40 per cent of input costs for some gas intensive industries and 50 to 70 per cent for chemical producers.

The current market conditions are having significant impacts on C&I users, who historically were paying prices for gas in the range of $3-4 a gigajoule (GJ).

The ACCC reported in our December Gas Inquiry report that large industrial users operating in the east coast were receiving offers for commodity gas in the range of $8 to $12/GJ in the second half of last year for supply this year.

While this represented a reduction in the offers that we were seeing earlier in 2017, of up to around $16, these prices are still higher than we would expect to see in a well-functioning and competitive market.

Mid last year, most C&I users the ACCC spoke to had only one supplier willing to supply.

By the latter half of the year, large C&I users reported more engagement from suppliers, generally having 2-3 competing suppliers making offers to them and two users had offers from six different suppliers.

Smaller industrial users have been facing higher prices than larger users, typically not being large enough to enter into negotiations directly with producers and having to rely on retailers for gas supply.

In some cases, these users were still only receiving offers from one or two retailers, with some users reporting that retailers were still claiming to have no gas available.

Across the east coast, wholesale gas prices remain generally higher than the Asian LNG spot netback prices and in the southern states in particular they are potentially $2-4/GJ higher than would be likely to prevail if there was sufficient supply and diversity of suppliers in the south.

Australian businesses competing in global markets face high costs for a range of inputs, and prices for gas that are higher than appropriate benchmarks are a threat to Australian industry’s competitiveness.

The big jump in wholesale gas prices also has a significant impact on small businesses and households, and the impact can be very stark for low income households relying on gas to heat their homes.

Today I will cover three topics:

  1. The current state of the gas market in the east coast of Australia
  2. What a well-functioning market looks like (and what a well-functioning gas market would look like)
  3. What the ACCC is doing to help bring about a more competitive market.

1. The current state of the gas market in the east coast of Australia

As the ACCC has pointed out in the first two interim reports of our current gas inquiry, released in September and December last year, there remain major problems with the workings of the gas market in the east coast.

The market is currently incredibly tight, although the announcement from Arrow Energy in December that it has entered into a 27-year gas supply agreement with the QGC project is a significant positive development.

Arrow Energy is set to develop over 6,000 PJ of its gas reserves in the Surat Basin, with first production anticipated in 2020.

However, market forces are not operating as they should for the benefit of the customer; the industrial user, the household, and the generators of electricity.

The simultaneous commissioning of the three LNG projects in Queensland has caused a significant disruption to the east coast gas supply/demand balance, with massive LNG exports; more than double the volume of domestic demand.

While in aggregate across the three projects, they are expected to contribute more gas to the domestic market than they expect to take out through third party purchases of gas for 2018 and 2019, they have disrupted gas flows and competitive dynamics in the east coast.

The situation is most stark in the case of the southern states and territories of South Australia, New South Wales, the ACT, Victoria and Tasmania.

Gas production from the traditional sources of supply in these states is in decline and the bulk of production from the Cooper Basin in South Australia has been committed to the Queensland LNG projects.

If we exclude the Cooper Basin, there is not enough production forecast in the southern states to meet southern demand in 2018 and this is currently expected to continue in the medium term.

How has this southern shortfall come about?

As with most things to do with gas, there are a number of reasons.

Traditionally, gas users in the southern states relied on local production from the Cooper Basin and offshore Victoria.

However, production from these sources is not enough to meet current domestic demand in the southern states even if Cooper Basin gas was directed south. And there is little prospect of this changing anytime soon.

The biggest offshore producer in south east Australia, the Gippsland Basin Joint Venture, is forecasting a significant decline in production in 2018 compared with record production levels in 2016 and 2017.

The Gippsland Basin Joint Venture legacy fields are reaching the end of their life after over 45 years of operation.

This decline is not being offset by new onshore development, with moratoria and other regulatory restrictions in New South Wales, Victoria and Tasmania preventing or impeding onshore gas exploration and development in these states.

The ACCC will not weigh into the debate about the environmental issues surrounding these restrictions, but a blanket ban which captures all potential projects, including conventional reserves, has consequences in the form of significantly higher gas costs for consumers and industrial users of gas in these states.

It also acts as a brake on exploration and precludes industry even confirming gas reserves that on a robust cost benefit analysis would improve consumer outcomes.

This southern shortfall means that gas produced in Queensland will need to be sent to the southern states to meet the needs of gas users in those states, adding costs of transport and weakening southern buyers’ bargaining power to secure gas.

This has a significant effect. It could add at least $2/GJ and possibly up to $4/GJ to the prices paid by gas consumers in the southern states.

A natural consequence of the LNG export projects is that the east coast is now exposed to global markets, with the costs and benefits that that brings with it.

Our analysis of benchmark prices shows that recently agreed 2018 prices are generally above the prices that would be likely in a well-functioning and competitive market.

The market is just not operating as it should.

Estimated 2018 benchmark prices in Queensland range from $5.87 to $7.85/GJ and for the southern states, this is $6.55 to $9.93/GJ, with the upper limit relevant to Victoria and the lower limit relevant to South Australia.

Contract prices agreed over the last two years are higher for supply from Queensland producers; averaging $8.45/GJ.

And prices in the southern states are significantly higher than appropriate benchmark prices.

In these circumstances, the major players in this market would do well to consider the effect on the domestic market of their actions. Two particular instances come to mind.

The first is AGL’s self-described ‘regrettable’ sale to GLNG; gas it had acquired from QGC.

But rather than being able to make offers to domestic customers coming off contracts last year, it was sending this gas off to export via GLNG.

Another instance that the ACCC drew attention to in our September report was significant volumes of LNG forecast to be exported and sold on the international LNG spot markets in 2018 at a time of significant expected domestic shortfall and consequently high domestic demand and prices.

Domestic users are not well served by these sort of actions.


Turning to another issue, the change in the pattern of flows of gas necessary to deal with the changes in the supply/demand balance mentioned earlier make it imperative for an optimal network of transportation pipelines that are priced efficiently and allocated to the highest value use.

While reforms are on their way, at the moment, we are well short of this ideal.

Most of the key pipelines needed to deliver gas from Queensland to the southern states were close to fully contracted in December for 2018, with a significant proportion of the firm capacity rights on these key pipelines held by the two largest retailers.

Other parties in the market have told us this creates a problem in seeking to move gas from Queensland to the high demand centres in the south.

They can seek to negotiate with an existing capacity holder for secondary capacity or acquire as-available or interruptible services from pipeline operators, or avoid the need for transportation services by entering into gas swap arrangements.

However, none of these options are easy.

On key pipelines, while we have not seen evidence of hoarding of capacity, we have not seen much secondary capacity trading, despite the existence of spare capacity throughout the year.

As-available or interruptible rights are lower in priority than firm rights; however, on the key north to south pipelines, the price for these services is set at relatively high rates.

Moreover, pricing in general for transportation services has remained high. There have been some instances of a change in pricing, such as the two dollar ‘special’ APA has recently offered for carrying gas to Sydney or Melbourne under certain conditions. Overall, though, there has been little change from the monopoly pricing identified in our 2015 inquiry report.

Some improvement

While the current state of the gas market on the east coast remains a grim one, there have been some short-term improvements in market conditions in recent months.

We saw significant quantities of gas diverted from planned exports to the domestic market following the Heads of Agreement between the LNG operators and the Australian Government.

The LNG operators reduced their planned exports for 2018 and made sales largely to aggregators and retailers.

Industrial customers started receiving more offers from a range of suppliers and at lower prices.

While we reported in September that many industrial customers were holding off signing contracts given the high price of offers, by December, with lower prices, most of those customers had secured supply for 2018.

The outlook for the supply/demand balance for 2018 improved in December, from a substantial expected shortfall expected in September, to a more balanced position.

However, things are still incredibly tight and the fundamental problems remain.

2. What a well-functioning market looks like (and what a well-functioning gas market would look like)

We all know what a well-functioning market looks like.

As a customer, you would have multiple suppliers to choose from who actively compete for my business. You would face low costs to determine whether you are being offered a good deal and have confidence that the price you are paying is an efficient one which doesn’t reflect market power or other inefficiencies.

Translated to the east coast gas market, as an industrial user in a southern state, you would be able to receive competing offers from three or more suppliers and prices which made sense considering appropriate benchmarks.

For the suppliers competing to win your business, the retailers and aggregators would also have choices of where to source their gas from and would be able to access reasonably priced transportation capacity.

The east coast gas market is now exposed to international prices through the LNG export projects.

International LNG spot prices can be very volatile and at any point in time reflect seasonal factors or short-term supply and demand shocks.

This can be readily seen in the recent increases in the Asian LNG spot prices.

These appear to be due to a range of factors, including a marked increase in Chinese demand in line with the Chinese government’s policy of switching from coal to gas for heating, and a number of supply disruptions.

While short-term volatility in overseas prices might be alarming for some domestic gas buyers, we must bear in mind that some (and I emphasise it is some) fluctuation in domestic contract prices is not surprising in an export exposed commodity like gas now is.

In a well-functioning export-exposed market, we would expect domestic contract prices to bear a relationship to reasonable benchmarks based on the expectations of future prices over the period of the contract in question.

The ACCC’s work in publishing estimated LNG netback prices is designed to bring some increased transparency to this relationship.

The LNG spot netback price published in the ACCC’s September and December reports was based on an expected average of Asian LNG spot prices over the course of 2018.

As at September 2017 this was US$6 per million British thermal units (MMBtu), as at December 2017 it increased to US$7.50 per MMBtu and as at February 2018 it is about US$8.60 per MMBtu.

It is uncertain where price expectations will move over the medium term, with some talk of a global LNG glut pushing prices down, but also reports of an increased demand in countries such as China and India.

The ACCC considers that Australian gas users should not be paying more for gas than is indicated by reasonable benchmark prices.

However, this might not fully occur for a number of reasons.

Bottlenecks in transportation, limitations in storage capacity and, importantly, a lack of competition, particularly in the south, are important factors.

Another potential factor is that we are not currently importing LNG into Australia, although it is being looked at.

The east coast gas market is at a crossroad and we must make a choice now of which path to take in order to try to arrive at the best outcome for the east coast gas market across the supply chain.

The ACCC sees three possible paths.

The first one is to return to the situation we were in when Mr Sims last addressed this audience – a year after the ACCC had delivered its report on the east coast gas market to the Government.

Mr Sims described the state of the market at that time as one in crisis.

This is an easy choice; don’t choose that road!

Australia has moved on a bit since then.

The second path is to stay on the road we are on now.

A road where the Government is stepping in to bring about more sensible responses to the domestic situation from the LNG exporters and where the ACCC is acting to address issues of market power and lack of transparency in the market.

This is better than the first path, but not good enough; prices are still too high and fundamental problems remain.

The only real palatable choice, along with continuing with our work, is to address the fundamental supply problem, particularly in the south. Increased gas supply on the east coast would better serve domestic gas users, especially when global prices are high.

However, this is not a choice for the ACCC; this is a choice for governments!

3. What the ACCC is doing to help bring about a more competitive market

The ACCC’s current inquiry runs for three years, concluding at the end of April 2020.

This inquiry gives the ACCC powers to compulsorily obtain information from parties across the supply chain.

In this market, characterised by its opacity, the ACCC’s work and subsequent reports help to shine a light on the market.

In the first two reports released last year, the ACCC published gas prices and price offers, the supply-demand outlook and user experiences and information on transportation and storage and LNG markets.

We presented benchmark prices in the form of LNG netback prices and we are currently consulting on the creation and regular publication of an LNG netback price series.

This is something the ACCC recommended in our east coast gas inquiry report in 2015 and something gas users have been asking us for.

Its publication could increase transparency in the market and provide information to assist gas buyers in their negotiations with gas suppliers.

The ACCC, of course, is also the enforcer of our competition law, and we will continue to investigate potential breaches of the law that we become aware of in our monitoring role.

The ACCC announced in December that BHP and Esso had given court enforceable undertakings to end their joint marketing of Gippsland Basin gas from next year.

The ACCC investigated the effect of the joint marketing arrangements after concerns arose about those arrangements during our 2015 inquiry.

The GBJV is the largest producer of gas for the southern states and ensuring separate marketing of that gas by the JV partners will increase competition, which is much needed.

The ACCC expects, and will be watching, that gas buyers will receive improved prices and contract terms for supply.

The ACCC also investigated the conduct of some retailers, whose unwillingness to trade secondary pipeline capacity on some pipelines was alleged to be restricting competition for the supply of gas to users.

We have now seen that those retailers are now making spare capacity available on those pipelines for use by other market participants.

These users now have a greater choice for sourcing gas supply.

There remains a lot more for the ACCC to do.

We will continue, in regular reports, to publish gas prices and offers to industrial users, the expected supply/demand outlook, transportation prices, and the experience of users and will monitor and report on the LNG exporters’ commitments under the Heads of Agreement with government.

And we will publish the results of more focussed work in a number of areas of interest, including an LNG netback price series; as well as the use of pipelines and storage, and retail pricing.

An example of the work we will be doing to improve transparency is in the area of reserves and resources reporting. There is currently no clear, consistent and accurate reporting of reserves and resources, so gas users lack a clear insight into actual reserve positions when negotiating for new supply contracts.

We will be working to take forward the recommendation that we made in our 2015 inquiry that all explorers and producers, including non-ASX listed companies, should report consistent reserve and resource information across the east coast gas market.

We will continue to advocate and recommend changes to laws where we think they are needed to improve the workings of the gas market.

The Vertigan reforms contained in Part 23 of the National Gas Rules are beginning to take effect. These transparency and arbitration measures are very much welcomed by us!

The AEMC has just yesterday released its draft recommendations into the review of pipeline regulation and we will be making a submission to this process. At this stage, it seems to me that the current array of regulatory regimes applying to pipelines is unnecessarily complex as it has developed over time.

We currently have light regulation, Part 23 and full regulation.

The Part 23 reforms have just recently come in and are the result of a careful examination by the GMRG.

The information provisions under that regime are perhaps more useful to users than what is covered under light regulation and we are pleased that we agree with the AEMC on this.

With the introduction of Part 23 though, there is a real question about whether the need for light regulation has fallen away. We will provide our thinking on this in a public submission.


We are at a critical point for government policy making in addressing the issues faced in the east coast gas market.

To go backward to where we were a year ago is unthinkable.

But to continue on the path we are on, while a much better position, is simply not good enough.

The fundamental problem of a lack of both sufficient and divergent sources of supply, particularly in the south, needs to be addressed. And this needs to happen soon, given the lags in bringing supply to market.

Frankly, it was needed several years ago.

This is an issue that governments can act on rather than the ACCC.

The ACCC will continue to play our very important role.

It is our mandate to shine a light, bring more transparency to the market and investigate anti-competitive behaviour in gas and any other markets in Australia.

But, without addressing the supply problem, we will not be able to get to the competitive market that should be available for domestic users of gas.

Thank you for your time today.