Overcoming gas affordability issues

Speakers: 
Mr Rod Sims, Chair
Conference: 
Australian Domestic Gas Outlook conference 2021
24 March 2021

ACCC Chair Rod Sims addresses the Australian Domestic Gas Outlook (ADGO) 2021 conference on topics related to the recent ACCC gas inquiry, recent disruptive impacts on the market and what more needs to be done to encourage a functioning competitive market for businesses and households.

Transcript: 

Check against delivery.

Introduction

It is a pleasure to again be here at the annual Australian Domestic Gas Outlook conference.

My appearance, of course, is a mixed blessing.

The reason for the ACCC’s continued involvement in the east coast gas market, and for your kind invitation for me to be at this conference, is because gas users have found it incredibly tough for many years.

There was some good news over the past year. Gas prices fell significantly, driven in part by record low oil and LNG spot prices exacerbated by the COVID-19 pandemic. While wholesale commodity gas prices that commercial and industrial users pay have reduced, our January 2021 report found that prices were still higher than export parity.

Lower gas prices will not persist indefinitely, however, and the risk of a supply shortfall remains.

Our inquiry continues to find that the gas market is still not a functional, competitive market. At the ACCC, we can see no end to the increasingly complex and difficult environment we are in, unless we all work together.

There are three topics I will cover today:

  • How did we get here?
  • The impact this has had on the market, and
  • What more needs to be done?

1. How did we get here?

In a market as complex as gas it is useful to remember how we got where we are today.

In late 2010, the development and construction of three liquefied natural gas projects in Queensland triggered unprecedented changes in the east coast gas market.

It is obvious that there was not enough gas for three LNG projects. As a consequence, a number of market disruptions occurred.

First, at the time gas companies assured governments that prices would not go up; this turned out not to be the case, by a very wide margin.

Second, LNG projects supplemented supply from their own coal seam gas reserves by contracting gas from reserves which served the domestic market, notably from the Cooper Basin but also from the Gippsland Basin.

Third, offers of supply to users dropped. From around 2012 there were sometimes no offers of supply. Or, where industrial users received offers, they were often at drastically higher prices and on strict ‘take it or leave it’ terms.

At the same time, suppliers and their peak bodies were telling the public that the gas market was functioning well and that plenty of supply agreements were being executed with domestic users.

These conflicting claims about the availability and competitiveness of offers to supply gas were the genesis of the ACCC’s first gas inquiry in 2015. This initial inquiry revealed that the concerns of users were well founded; not so the comments of the suppliers.

Sadly many of these market conditions have persisted, leading the ACCC to its second gas inquiry.

2. Impact on the market

The impact on the gas market has been profound.

A major cause of the east coast gas market problems relates to a lack of supply relative to demand.

The long term supply outlook shows us that there is a risk of a shortfall for southern states as early as 2024, and the east coast market as a whole in 2026 and beyond. We reported on this risk in our January 2020 interim report. We now find ourselves one year closer to a potential shortfall and it is concerning that essentially no progress has been made to ensure this shortfall does not eventuate.

Adding to this problem is the very limited degree of competition at the producer and retailer level, which results in higher prices and a reduction in competitive outcomes for commercial and industrial users.

On a positive note, our January interim report observed that competition between suppliers and their selling practices have improved in some areas. Some users reported that more suppliers are making more offers for supply in 2021 than in previous years. Some also noted that suppliers are more willing to actually engage with them about their needs.

While this news is encouraging, these improvements may be more as a result of a perceived threat of government intervention. Our January 2021 interim report examined suppliers pricing strategies for the first time. This examination revealed that competition has had limited influence on pricing decisions. We found very limited references by suppliers to the pricing behaviour of competitors.

We would expect to see such references in a well-functioning market. This is why we welcome more recent signs of competition in the east coast market with a degree of caution. We fear a return to the conditions that we observed earlier in the inquiry where users were generally unable to obtain offers from more than one gas supplier and any offers received were at very high prices and on less flexible terms.

This leads me to the high cost of gas.

When the current ACCC gas inquiry commenced in April 2017, many domestic gas buyers in the east coast were receiving offers for gas supply at prices that were well in excess of LNG netback prices. The highest priced offers were made by retailers, peaking as high as $22/GJ in March 2017.

This was a clear sign that the east coast gas market was dysfunctional.

In October 2017, once the ACCC highlighted this, the Australian Government reached a Heads of Agreement with the LNG producers. Under the terms of this agreement, the LNG producers committed to offer sufficient gas on competitive terms to the domestic market.

By the year’s end, gas commodity prices in domestic offers reduced substantially and stabilised around the $8-11/GJ range. Since then prices have fluctuated between $6 and around $14.

Over 2020 we saw LNG prices drop internationally; partly due to COVID and lower demand. We also saw this play out in the domestic market with prices dropping from $8-$10/GJ to $6-$8/GJ.

While dropping prices are welcome, commercial and industrial gas users remain concerned about prices over the medium and longer term.

Many Australian manufacturers continue to be under extreme pressure to remain internationally competitive. The high cost of gas is making it extremely hard for these businesses and poses an imminent threat. We have already seen examples of businesses going into administration. Once large manufacturers relocate or shut down their plants, they are unlikely to come back.

3. What more needs to be done?

Our objective, surely a reasonable one, is that businesses and households should pay no more for gas than would be expected in a well-functioning competitive market.

From this perspective, it is clear that much more needs to be done.

More supply

First, as we have outlined in our recent interim reports, new sources of supply and related infrastructure will be required to avoid a potential shortfall in supply from 2P reserves in the east coast from 2026, and from as early as 2024 in the southern states.

In the south, there are a number of new domestic supply projects that could be brought online by 2024, but some of these are quite speculative in nature. We run the risk that some projects will not come online in time, if at all, and those that do come online will not be sufficient to avoid the projected shortfall.

There are also a number of new domestic sources of supply in the south and the north that have not yet been sanctioned that could potentially be brought online. This includes a number of projects that are not yet connected to the east coast market, such as Narrabri, and from the northern Bowen Basin and the Galilee Basin.

The development of these new domestic supply projects will, however, need to overcome a range of geological, commercial, financial and regulatory barriers. There is no easy path.

The long-term supply outlook is becoming critically dependent on the timely development of new projects. We are running out of time.

Governments need to continue to actively monitor producers’ compliance with their permits and be prepared to take action for non-compliance where appropriate, with measures that:

  • encourage producers to bring gas to market in a timely manner
  • discourage larger producers from ‘warehousing’ gas, and
  • continue to encourage greater diversity of suppliers (for example, by granting new tenements to junior producers and explorers).

We welcome the steps taken by various governments over the last year to try and facilitate the development of new sources of supply. The Commonwealth Government, for example, announced its intention on 15 September 2020 to implement the 'Gas-fired recovery plan' consisting of a number of measures including:

  • setting new gas supply targets with the states and territories and enforcing potential 'use-it or lose-it' requirements on gas licenses
  • providing funding for five basin development plans, which will initially focus on the Beetaloo sub-basin, Galilee and north Bowen basins
  • providing funding for a National Gas Infrastructure Plan, to identify priority pipelines and infrastructure and to highlight where government may need to step in if private sector investment is not forthcoming, and
  • exploring options for a prospective gas reservation scheme.

The Commonwealth Government has also recently announced funding of up to $50 million to fast track exploration in the Beetaloo sub-basin.

These are all positive steps but if they don’t work in time to avoid a shortfall then Australia could find itself forced to use imported gas.

Import terminals

There are currently five, potentially six, proposals to develop LNG import terminals, all of which are located in the southern states.

Recent announcements suggest that the proposed LNG import terminal in Port Kembla will proceed. Major construction of the terminal is expected to commence next month and be completed within 18 months, with supply to commence by the end of 2022. If the terminal is built by then, it should provide sufficient supply to avoid the projected shortfall in both the southern states (in 2024) and the broader east coast market (from 2026) until 2028.

While this is welcome, prices will necessarily be at import parity, and in many (if not most) circumstances higher than export parity price levels.

Of the remaining four projects, three are in the FEED stage and if a decision is made to proceed, supply could commence as early as September 2022 from one of the terminals.

LNG netback pricing review

Second, in terms of pricing, we started publishing the LNG netback price series in 2018 to add much needed transparency to the market and to provide information on the prices that LNG producers could expect to receive for LNG that could otherwise be provided to the domestic market. The review of our LNG netback series was another element announced as part of the government’s ‘Gas fired recovery plan’.

Global LNG markets have changed since the ACCC developed the current approach. Given the time that has passed, a change in factors that could influence pricing strategies and varying industry views about the most appropriate international price marker, now is a good time to review the netback price series.

It is vital that we get this right. We intend to consult widely with gas users and suppliers, and invite interested parties to provide a submission in response to the issues paper we published last week.

We want all sides to engage publicly, including with each other, in an analytical and fact-based way.

Following our consideration of submissions, we will publish a draft position paper. This draft position paper is expected to be released in June. We will finalise the review by the end of September, as requested by government.

Examination of pricing strategies and intention to better understand competition limitations

Understanding the complex gas market dynamics is no easy task. As such, we will continue examining suppliers’ pricing strategies and reporting on practices undertaken with a view to understanding the implications for competition. As I said earlier, our review of suppliers' pricing strategies material suggests competitive dynamics have only been a limited constraint on gas prices over the past few years.

We have also seen some indications more recently that producers and retailers in southern states are starting to factor in the higher LNG import pricing and supply dynamics into their strategies and assumptions.

In addition to finalising our examination of pricing strategies, we are also starting to look at upstream competition issues and whether there are features of the market that are limiting competition between gas producers, and between all gas suppliers.

When we conducted our first East Coast Gas Inquiry in 2015, we were concerned that the joint marketing arrangements between BHP and Esso for Gippsland Basin gas were likely to have resulted in a substantial lessening of competition in the market for the supply of gas to buyers in the southern states. We believed that competition in this market was negatively affected by the elimination of independent rivalry between BHP and Esso.

Following an investigation by the ACCC, in December 2017 BHP and Esso provided court enforceable undertakings to separately market their share of gas produced under the Gippsland Basin Joint Venture.

The commencement of separate marketing in 2019 has seen increased competition between the two parties, with the market operator observing:

  • an increase in the volumes of gas offered to the Victorian and Sydney short term spot markets by BHP and Esso, and
  • BHP and Esso offering gas to these markets at different prices, with prices coming down over time.

The fact Esso and BHP are now competing on price is a major win for competition.

New Heads of Agreement

Third, last year, in our July 2020 Interim Report, we recommended that the Australian government extend or enter into a new Heads of Agreement with the three east coast LNG producers to ensure they continue to offer uncontracted gas to the domestic market before offering it to international markets.

As well as extending the Heads of Agreement, we also recommended the focus broaden from supply to include stronger price commitments. That is, the government should consider referencing the LNG netback price expectations and the prices LNG exporters could expect to receive for uncontracted gas in overseas markets over the relevant supply period.

We were pleased to see the government act on this recommendation, entering into a new Heads of Agreement in late December 2020 covering the period 2021-2023.

Under this new agreement, individual prices offered to the domestic gas users must be internationally competitive and have regard to LNG prices of the same term. This is an important change from the previous agreement, which required offers to be made only on 'competitive terms'.

LNG producers are also required to report to the ACCC price expectations and assumptions for international spot and term markets over the relevant supply period. This is in addition to existing requirements to report to the ACCC on sales, offers to sell, bids declined and the terms and conditions in such transactions.

The ACCC will closely monitor compliance with these new commitments and has already issued notices to parties as part of this important role. The ACCC will not hesitate to report where producers fall short of their commitments.

Gas Code

Finally, as I’m sure this audience is aware, the voluntary Gas Code is intended to ‘better empower gas consumers’ by ‘level[ing] the negotiating playing field for gas producers and consumers’.

This Code presents industry with a valuable opportunity collectively to develop a voluntary code that addresses poor selling practices and facilitates competitive outcomes. The Government has made it very clear that it will consider a mandatory approach in the event a voluntary Code cannot be agreed by gas suppliers and users. A deadline was set by Government for a Code to have substantially progressed by February, with collective agreement from both sides of industry.

Amazingly, we are now at the end of March and users have yet to see a copy of the Code. This is an unacceptable outcome and, I would have thought, completely at odds with the Government’s expectation. A Code that has not even been circulated in draft form to users cannot be considered well developed.

For our part, it is fundamental that the Code provides clear and meaningful obligations on gas suppliers and offers clarity and certainty to users. Independent and detailed governance and dispute resolution arrangements are also key for the Code to be effective.

Conclusion

As I said earlier, responsibility for fixing the dysfunctional east coast gas market must be shared between LNG producers and other suppliers, pipeline operators and governments.

We will, of course, continue to also play a part by monitoring and reporting on the behaviour of all gas suppliers and pipeline operators over the remainder of our Inquiry. More specifically, we will:

  • carefully consider the difficult and complex issues around LNG netback calculations and the relationship the Australian market has with international markets
  • watch carefully the pricing behaviours of LNG producers to see that they are meeting their commitments to the Heads of Agreement
  • be available to advise industry and government as requested on how best to design the gas Code to ensure it delivers outcomes for gas users, the east coast gas market and the economy, and
  • continue to understand where competition limitations exist, through our examination of upstream competition issues.

Thank you for your time today.

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