Australian Domestic Gas Outlook Conference 2023
Sydney, Wednesday 22 March 2023
Good afternoon, it’s great to have the opportunity to discuss the significant issues currently confronting domestic gas markets.
Let me begin by acknowledging the Gadigal people of the Eora Nation, the traditional custodians of the land we are meeting on today and the Wurundjeri, the Bunurong and the Gunaikurnai, the traditional custodians of the land between Melbourne, the Mornington Peninsula and Gippsland where ExxonMobil operates the Gippsland Basin and Kipper Unit Joint Ventures. I pay my respects to Elders past, present, and emerging and extend that respect to Aboriginal and Torres Strait Islander people present among us today.
At this conference in 2021, I spoke about how investment in new gas supply and infrastructure would be required to ensure Australians on the east coast can continue to access reliable and competitively priced gas.
And in 2022 I spoke about the critical role natural gas plays in Australia’s economy, supporting an orderly energy transition and at the same time heating our homes and keeping the lights on.
Today both themes remain relevant, because the rate at which new gas supply is brought into production will increasingly determine the outcomes consumers experience.
The focus of this year’s conference has, unsurprisingly, been the unprecedented market intervention announced and legislated within a single week in December.
But instead of repeating the things that have already been said, I want to discuss something equally important for energy security on Australia’s east coast, ExxonMobil’s recent investments in domestic gas supply, and the next stage of life for the Gippsland Basin Joint Venture.
ExxonMobil has operated in Australia since 1895, and our reputation for reliably supplying energy to our customers is a valuable corporate asset. It’s who we are, and it’s what we do.
For over 50 years, Australians on the east coast have relied on gas from the Gippsland Basin Joint Venture, with every molecule of ExxonMobil’s equity gas being supplied to the domestic market.
It’s because ExxonMobil and our joint venture partners have invested $7 billion over the past 15 years to develop new domestic gas projects that the Gippsland Basin Joint Venture remains today the largest supplier of gas to the east coast domestic market, and in particular the South-East Australian gas market of New South Wales, Victoria, South Australia, and Tasmania.
The investments we made both before, and during the pandemic are supplying Australians on the east coast with the gas they need now.
We stepped up in 2022 to fill the gap left by coal generator outages, coal supply disruptions and lower than expected renewable generation. Last year the Gippsland Basin Joint Venture increased gas production by 11% over the year before, which meant Longford produced more gas in 2022 than in any year since 2017.
That is an extraordinary achievement. It was possible because we invested through the cycle in a stable investment climate and because we have great people who come to work for ExxonMobil to make sure Australians on the east coast can access the gas, they need every day.
In 2021 and 2022, I shared a chart like this one, and I am showing it again, updated with our most recent assumptions, because the key messages continue to be relevant.
From the profile on the left, you will notice the Gippsland Basin supplied more than 70% of Southeast Australia’s domestic gas demand in 2022. New investments are an important part of how we maintain supply to the market, and it’s easy to underestimate what it takes to do this. These are large, complicated projects which require long-term planning and a stable investment climate. For example, West Barracoutta, which started production in 2021, is and will remain the largest east coast domestic gas project to come online this decade.
And in the first quarter of 2022, we announced full funding of the Kipper Compression Project, which is shown in blue. As you can see on the upper right side of the chart, both West Barracouta and the Kipper Compression Project will each supply more gas to the domestic market this decade than Narrabri and Beetaloo combined.
But investing in new gas is only the first part. Ensuring continuous and reliable production is a 24 hour a day, 365 days a year commitment requiring over $1 billion of operating expenditure each year.
Because more than half the production anticipated from the Gippsland Basin in 2027 is not online today, execution of existing projects and investment in new projects are both key elements of the east coast supply outlook. The undeveloped resource shown on this chart includes well defined, currently unsanctioned investments that can produce more gas this decade than either the Narrabri or Beetaloo.
But the significance of these investments is not limited to the quantity of gas supplied over the decade. Equally important is the daily capacity they add to the South-East Australian market in the second half of this decade. In the lower right of this chart, you can see by 2027, recently executed projects, projects currently in execution and currently unsanctioned projects all exceed by a wide margin the incremental capacity of the gas that could be delivered to the South-East Australia gas market from announced South West Queensland Pipeline and Moomba to Sydney Pipeline expansions. With the most material contribution to daily capacity in 2027 currently remaining unsanctioned.
So, while the recent, current, and possible future investments in domestic gas supply by ExxonMobil and our joint venture partners have been and will remain critically important to the market, it is also the case that the broader supply side response has been below expectation.
In this respect the ACCC is right to highlight the long list of reasons that are either preventing or delaying gas development. To focus on just one; in the United States it takes one month or less to apply for and receive an onshore drilling permit, and less than 2 months to apply for and receive an offshore drilling permit. In Australia it takes 24 months for both, and it continues to head in the wrong direction.
We support a careful and diligent approach to regulation however this unnecessary erosion of our national competitive advantage has implications beyond just gas markets and will make the energy transition more difficult and more expensive than it needs to be. Just last week the Australian Energy Market Operator confirmed again the key role for gas enabling the growth of weather-dependent renewable electricity generation.
At last year’s conference, I discussed the unplanned coal plant outages at Callide and Yallourn in the second quarter of 2021, and how the additional production from Longford to fill the gap in May and June 2021 was only possible because the ExxonMobil operated West Barracouta field had been commissioned in the month before.
Immediately following last year’s conference, we experienced unprecedented coal plant outages in autumn and winter and sourcing the gas required for gas fired power generation at short notice was a critical driver of gas spot market prices in 2022. Effective policy needs to recognize spot market prices through the winter of 2022 were largely a response to events here in Australia.
The slow progress developing new gas supply and infrastructure over the past few years reduces capacity to respond to similar events in the future and maintain the reliability, resilience, and stability of the grid.
Although the Gippsland Basin Joint Venture remains the largest supplier of gas to the east coast domestic market, as offshore capacity continues to decline, the production system will and must operate differently. This means its role in the system and market will change. Today I will highlight why it’s important to understand these changes.
Gas production from the Gippsland Basin Joint Venture has historically either been onshore facility constrained or market demand constrained. In other words, the productive capacity of the offshore fields was greater than the volume of gas that could be processed through Longford, and during summer the volume of gas that could be processed through Longford was greater than market demand.
If we went back to 2010, we would see the Gippsland Basin Joint Venture producing from 122 wells to 8 gas platforms supplying 3 onshore gas plants. What that meant was if an offshore platform was for some reason unavailable, another offshore platform could step into its place, production from Longford would remain unaffected and customers would continue to receive the gas they expected.
In 2022 the Snapper field played an important role offsetting reduced production from other fields three times. For example, in November last year, a platform went offline for unexpected repairs. That platform was returned to production over the course of 33 hours and during this time, Snapper production was increased to cover the gap, ensuring no curtailment of supply to Longford and ultimately consumers.
Today we have 68 wells producing to 6 gas platforms supplying 3 onshore gas plants. We can still vary the offshore field mix to meet demand, and this has meant Longford has not had a day without production since 2017. But achieving this requires careful field management, and once Snapper is depleted, likely within the next 12 – 24 months, it will no longer be able to perform that vital role.
As more legacy fields cease production in the future, we will need to continue to match onshore capacity with reduced offshore capacity, both to continue to produce gas at a competitive cost but also to maintain system process stability.
By next winter we expect to have 36 wells producing to 6 gas platforms supplying 2 onshore gas plants, a 70% reduction in the number of producing wells since 2010.
In the past, offshore capacity was provided by strong water drive fields. With the continued decline of water drive reservoirs such as Snapper and Barracouta the production system will also become more reliant on offshore compression.
The consequence of these changes is the Gippsland Basin Joint Venture’s ability to step in and supply the market in the way it has in the past will be reduced, for example during the Callide and Yallourn outages in the second quarter of 2021 or the 11% increase in production during 2022.
So, what can be done? At this conference in 2014, ExxonMobil called for additional investment in storage. Seasonal demand swings in southeastern Australia have mostly been met by varying production at Longford, running the gas plants at high rates in the winter months and at significantly lower rates when demand is low in summer. In this way the east coast of Australia is unique compared to markets like the United States, Canada, and Europe and this results in significant underutilization of installed production capacity.
Similarly increased pipeline interconnection between Queensland and the southern states to allow more gas to flow from where 90% of east coast gas reserves are located to where three quarters of Australia’s domestic gas demand is located would make a significant difference.
It has been encouraging to see some governments and regulators acknowledge that it is not possible to send more Queensland gas to the southern states at the time it is needed most. Peak southern state winter demand exceeds 2,000 TJ/day and the pipeline infrastructure which connects Queensland to the southern states already largely operates at full capacity moving gas south during winter.
Today we have a 3-lane highway that can move gas from Queensland to the southern states and committed upgrades mean that by winter next year it will be a 4 lane highway. But just keeping up with the forecast decline in southern state production requires adding another lane every year for the next decade. That is not economic, nor is it even possible, and so because pipelines from Queensland at full capacity can supply less than 20% of peak southern state demand it is clear investing in new sources of gas supply to the southern states is the only sustainable way to both ensure reliable supply and apply downward pressure on price.
The Gippsland Basin Joint Venture will no longer have the capacity to step in as it has in the past to provide whole of market solutions when planned or unplanned maintenance events occur, or when additional gas is required to support the electricity market. However, for ExxonMobil’s gas customers, we will continue to be a significant and reliable supplier of gas.
In anticipation of upcoming changes, we have been progressively making changes to the way we sell gas, to ensure we continue to provide our firm contract customers with the products they expect as we move to this next stage of operations.
As we stepped up to keep the lights on, we have also reduced our own emissions. Since 2018 ExxonMobil has reduced flaring by 45% and the use of gas as fuel by 29% across our Victorian operations. The gas we’re now saving at Longford is enough to supply gas to almost 100,000 households every year.
Along with other changes to the way we operate these steps have allowed us to reduce the greenhouse gas intensity of our gas production by 18% since 2018.
We are also commercializing beneficial uses for our emissions, helping to further reduce the carbon intensity of Gippsland gas. We have signed two long-term carbon dioxide supply agreements with Air Liquide and BOC to capture and reuse carbon dioxide from the Longford Gas Conditioning Plant in two new facilities to be constructed adjacent to the Longford Gas Plant. The carbon dioxide will be processed and used in food and beverage products, in addition to water treatment, desalination, manufacturing and medical industries. This is a great example of industry working together to create new regional construction and manufacturing jobs, creating value added products and delivering improved environmental outcomes.
The next significant step to reduce the greenhouse gas intensity of gas production will be the Southeast Australia Carbon Capture and Storage Project in the Gippsland Basin announced last year. To realize the full potential of this infrastructure we are also in discussions with operators in hard to abate sectors such as manufacturing, heavy industry, and energy to build on the foundation project to decarbonize other parts of the economy.
ExxonMobil and our joint venture partners have invested in domestic gas supply through the cycle to provide the gas Australians on the east coast need now.
Next year the way the Gippsland Basin Joint Venture operates will change, this is a necessary consequence of natural field decline.
And next year will also be a decade since ExxonMobil outlined the steps required to ensure reliable and competitively priced gas supply in the southern states.
Additional investment in domestic gas supply is required to provide the gas Australian households and businesses need and to support the energy transition.
I want to thank the conference organizers for again inviting ExxonMobil to share our perspective on the domestic gas market and I am of course very happy to answer any questions.