Good morning, everyone, and thank you for joining us for Santos' 2020 Half Year Results. With me today is our Chief Financial Officer, Anthony Neilson. Santos has delivered a solid set of financial results set against the challenging backdrop of significantly lower oil prices and, of course, the COVID-19 pandemic. Today's results are a testament to the hard work of all of our people to keep focused on safe and efficient operations during this pandemic. They also demonstrate the strength of our disciplined cash-generative operating model. The model allowed us to maintain activities key to sustaining strong operational performance across all of our core assets. Before we start, I draw your attention to the usual disclaimer on Slide 2. Let me start with some opening remarks about our performance before handing over to Anthony to discuss the financial results in more detail. After Anthony's presentation, I'll take you through our operations and growth opportunities before opening the call to questions. Moving to Slide 3. Our clear and consistent strategy, combined with our disciplined low-cost operating model underpin our investment proposition. The operating model is built to see Santos through the challenging times we're experiencing today and position us to leverage our growth opportunities when business conditions improve. The first half highlights are shown on the slide. And we particularly call out our low-cost diversified portfolio that delivered record production and strong free cash flow. We're expecting even higher production in the second half. This strong operating performance, combined with cost-outs and efficiencies, means we are now targeting a 2020 free cash flow breakeven oil price of less than $25 per barrel. I would remind you that this is less than half the level Santos required to breakeven in 2016 when we started our turnaround journey. We continued to progress our major growth projects while maintaining capital discipline and flexibility and commitment timing. We remain focused on driving shareholder value by operating and developing low cost, long life assets, utilizing existing infrastructure and delivering strong free cash flows through the oil price cycle. Slide 4 summarizes the financial results for the first half. Good operational and cost performance delivered $431 million of free cash flow and underlying profit of $212 million, despite a 34% decrease in realized oil price. The reporting result includes the previously announced impairments following revisions to our short- and long-term oil price assumptions. The Board has declared an interim dividend of USD 0.021 per share, fully franked. The dividend is consistent with our sustainable dividend policy, which targets a range of 10% to 30% payout of free cash flow. Given we are still dealing with COVID and the lower oil price environment, the Board determined it was prudent on this occasion to set the interim dividend at the lower end of the target payout range. The Board will review the payout again when it considers the final dividend in February. Moving to Slide 5. Our journey to become Australia's safest operator continues. Our core value at Santos is our Always Safe value. This means that every single day, every person who works at Santos is focused on safety and going home in the same condition that they come to work. Despite COVID, it is pleasing to see a continuing strong and improving trend in our safety metrics. Our LTIFR performance has improved again, continuing a trend of reducing injury frequency since 2017 despite higher activity levels and changes to operations due to COVID. Our injury severity, as measured by the number of injuries graded moderate harm or greater, has also declined over the past 4 years, as shown by the gray bars on the chart. We are very focused on ensuring the lessons from these type of events are learned across the organization and that we continue to drive these moderate harm incidences lower year-on-year. We're also focused on process safety, which is a key metric for us across the organization. I am pleased that our focus on disciplined integrity management and process safety management processes is delivering improved performance. There's still more to go, but we're pleased with the progress we are making across all of our safety-related metrics, and I would like to take this opportunity to thank everyone across all of our field-based operations for their focus during this very challenging period. Moving to Slide 6 and sustainability. For over 65 years, Santos has been safely and sustainably exploring and developing natural gas resources in partnership with local communities and landowners. Natural gas today remains a crucial part of the energy mix effort to solve the twin challenges of reducing carbon emissions while meeting the growing demand for secure and reliable energy. Santos is committed to a lower carbon future. In 2018, we were one of the first companies in our industry to state an aspiration to achieve net 0 emissions by 2050. We have set medium-term targets that align to our aspiration, and we are on track to achieve them. You can monitor our progress in our climate change reports. We have commenced a review of industry association climate positions, and we'll publish our findings. We also plan to release a new medium-term emissions reduction target at our Investor Day in December. Our midstream infrastructure and low-carbon energy division is focused on developing new energy solutions, including the decarbonization of natural gas production at source through CCS and the potential production of 0 emissions hydrogen from the Cooper Basin. I will talk more about these exciting opportunities later in the presentation. We are also committed to transparent reporting and disclosure through our suite of ESG reports, which you can access on our website. This also now includes our first Modern Slavery Report released in June, 12 months ahead of the required reporting date. On Slide 7, the COVID pandemic continues to challenge all of us. Everyone across our assets and offices has had to work in new ways over the past 6 months, while remaining always safe and maintaining business continuity. Through the hard work and discipline of everyone at Santos, we've remained COVID-free across the company. We will continue to strive to maintain that so that we can keep our people safe and well. This is at the forefront of everything that we do. We will continue to capture learnings from our experience that will be embedded in our company going forward. These include less travel, more virtual meetings and temperature and health screening across all of our operations and offices. Moving to Slide 8. You've heard me say before that we are running this business as a balanced portfolio that generates sustainable free cash flow through the oil price cycle. What we mean by balanced is in terms of our asset mix, it's a balance between onshore and offshore, between natural gas and liquids, conventional and unconventional and, of course, a balance between oil and CPI-linked fixed-price contracts. The Quadrant acquisition increased our weighting to CPI-linked pricing. As you can see in the pie chart, this was about 43% of our production volumes in the first half and gives us a strong natural hedge in times of volatile oil prices This underpinning cash flow, combined with our prudent oil hedging program, are important as we consider our growth plans. First half free cash flow was $431 million. This was achieved at roughly the same average oil price as the first half of 2016 when the business was free cash flow negative. As I said previously, we are now targeting a 2020 free cash flow breakeven oil price of less than $25 per barrel. And importantly, every $10 increment in oil price above our free cash flow breakeven increases annual free cash flow by between $325 million and $375 million before the impacts of hedging. In summary, it was a strong first half for Santos despite the challenging external environment. The business is running well. We're effectively managing the pandemic and keeping our people safe. And our operating model sets us up to sustain our production and grow when business conditions permit. I'll now hand over to Anthony to provide a detailed review of our financial results.

Thank you, Kevin. Hello to everyone. Given the backdrop of the COVID pandemic and significantly lower oil prices, Santos has delivered a solid half year result. Free cash flow was strong and lower costs are being realized from the initiatives that we announced in March to reduce costs. Our continued efforts to embed safe, low cost, efficient operations across our assets, combined with strong production, mean we are well positioned to meet whatever challenges are thrown at us by the external environment. Moving to Slide 10. The 3 key financial priorities for the business remain focused on driving shareholder value. These priorities are: remaining focused on generating strong free cash flow; ensuring the balance sheet and liquidity is strong; and maintaining optionality on commitment timing for our major growth projects. As Kevin previously stated, we achieved strong free cash flow of $431 million despite significantly lower oil prices, and we're now targeting a 2020 free cash flow breakeven oil price of less than $25 per barrel, including the impact of hedging. The balance sheet is strong with liquidity of over $3 billion, comprising $1.3 billion in cash and $1.9 billion in committed undrawn debt facilities. We operate all of our major growth projects, except for PNG, and this means we have the flexibility and optionality on the commitment timing. We are well positioned to leverage these growth opportunities when business conditions improve. Slide 11 shows a solid set of results for the first half. Despite a 34% decrease in the average realized oil price, sales revenue decreased 16% to $1.7 billion, driven mainly by lower liquids prices, partially offset by higher volumes. Revenues for the first half were shielded by Santos' diversified portfolio, including the fixed price domestic gas contracts, which comprised 43% of first half production volumes. Also included are a high proportion of LNG volumes delivered under long-term contracts. We achieved strong realized LNG prices of $8.57 per million British thermal units for the period. Higher sales volumes, a record of 46.9 million barrels of oil equivalent, were due to higher equity interest in Bayu-Undan and Darwin LNG and the commencement of a major new domestic gas contract in Western Australia. These higher volumes, combined with cost savings and efficiencies but offset by lower average commodity prices, led to an EBITDAX of approximately $1 billion. Underlying net profit after tax of $212 million was 48% less than last year. And our free cash flow was down 32% to $431 million. The reported net loss of $289 million includes the previously announced impairments of $526 million after-tax due to revised oil price assumptions. The impairment charge is noncash and is excluded from our underlying profit. Slide 12 outlines the strong free cash flow generation from the business. To put this in perspective, the average realized oil price for Santos' portfolio has been included on the chart on the right-hand side of the page. You can see there the similar average oil price in 2016. Our operating and free cash flow are $0.5 billion stronger than they were 4 years ago. This reflects the resilience inherent in our strategy and our low-cost operating model, which are built to see us through the oil price cycle. Operating cash flow decreased 24% to just under $800 million, driven by these lower oil prices. We've also maintained our disciplined approach to capital management. And in March, announced reduced CapEx whilst maintaining safety, integrity and production activity programs. Discretionary CapEx programs were deferred. Slide 13 shows the trend in the earnings metrics and is a similar story to cash flow from the previous page. The business is now much more resilient and robust than it was 4 years ago. Again, our fixed price domestic gas contracts and our strong LNG contracts shielded first half revenues from the impacts of the significantly lower oil prices. I also note that sales revenue does not include proceeds from our oil hedging program, which yielded $39 million in the first half. Underlying profit was $212 million, a solid performance given these economic conditions. Slide 14 shows the half year production and sales volumes. Both were records and higher than the prior corresponding period due to the increased equity in Bayu-Undan production, from completion of the Conoco acquisition in late May and higher domestic gas production in Western Australia. Western Australia also saw commencement of the Alcoa contract in mid-June, which is a 12-year contract for an initial supply of 120 terajoules a day. We expect even stronger production and sales volumes in the second half of 2020 as the full benefit of the Conoco acquisition is realized. 2020 production guidance is maintained at 83 million to 88 million barrels and our sales volume guidance is also maintained at 101 to 107 million barrels. Slide 15 shows that despite the challenges from COVID-19 and the lower oil price, we've maintained our focus on safe, low-cost and efficient operations. Cost reductions are occurring across our operated assets, and this is reflected in the group unit upstream production cost for the base business, which was 6% lower compared to full year 2019. This includes one-off impacts of COVID-19 on our costs in the first half. When we add the Conoco assets, which we include in these results from the completion date of 28th of May, the unit production cost for the first half are $7.36 a barrel. This is high because we now include 68.4% of Bayu-Undan, which is a higher cost late life asset around $20 per barrel of oil equivalent. This is compared to the lower cost assets in the balance of our portfolio, which has a unit cost production of $6.81 per barrel. On a full year basis, 2020 upstream production cost guidance for the Santos base business, excluding Conoco, is unchanged at $6.70 to $7.10 a barrel. 2020 guidance, including Conoco, is also unchanged at $8.50 to $8.90 per barrel. This cost includes all shutdown, PNG earthquake recovery costs and all COVID impacts. Slide 16 shows the diversified nature of our portfolio, outlining strength across our 5 core assets and the balanced nature of their contributions to EBITDAX and our margins. Western Australia and PNG remain our 2 highest margin assets with strong stable cash flows, low costs and margins in excess of 70%. We continue to see underlying cost reductions across all of our assets, which is seen by the 6% reduction in the group production cost from 2019. However, we did see some impacts of COVID which has had some one-off increases to our production costs in the first half as we put measures in place to ensure safe and sustainable operations. Overall, our group EBITDAX margin was 58%, in line with the 2019 full year result. This is a strong performance in the lower oil price environment and again highlights the definitive nature of our portfolio. All our core asset segments have margins of greater than 40% and all are free cash flow positive at an oil price of less than $35 a barrel. And at the portfolio level, we are now targeting a free cash flow breakeven price of less than $25 a barrel in 2020. Slide 17 provides the CapEx breakdown by the 5 core assets for the first half of 2020. Total CapEx was just over $370 million, comprising $330 million in sustaining CapEx and $42 million in major growth CapEx, mainly for Barossa. As I mentioned earlier, we announced cost reduction measures in March, and our approach was to maintain sustained CapEx activities related to safety, integrity and production. Major growth project CapEx was curtailed with the deferment of the final investment decision on the Barossa project until macroeconomic conditions improve. In the meantime, our engineering team remains focused on progressing value improvement work to optimize project costs. We have full optionality and flexibility on the timing of our major growth projects. The chart on the right-hand side of the page shows the number of onshore wells drilled across the Cooper Basin and GLNG acreage in the first half of 2020. The lower cost and drilling activity is due to the commencement of the new phase of pilot horizontal drilling in the Cooper Basin to unlock additional reserves and resources. 2020 CapEx guidance is maintained at approximately $750 million in sustaining CapEx for the base business and approximately $150 million for major growth CapEx. Slide 18 shows at 30 June 2020, net debt was $3.7 billion, including a $399 million lease liability under AASB 16 and a new $750 million debt facility for the ConocoPhillips acquisition. Since the end of 2019, excluding the acquisition of Conoco, the underlying business still reduced net debt by approximately $330 million despite significantly lower oil prices. The chart shows that our net debt is actually less than 2018 when excluding AASB 16 leases impact, yet we are significantly larger business after the Conoco acquisition. Including the Conoco acquisition, AASB 16 and the impact of impairment, gearing was 34%. There is ample liquidity in place, comprising $1.3 billion in cash and $1.8 billion in committed undrawn debt. Our debt covenants have adequate headroom at current oil prices for a number of years. Oil hedging is providing protection to the downside. There are still 9.7 million barrels of oil equivalent hedged for the remainder of 2020 at a weighted average floor price of $38 per barrel and an average ceiling price of $49 per barrel. In addition, 5.4 million barrels of oil are hedged for 2021 with a floor price of $40 per barrel and a ceiling price of approximately $51.50 per barrel. This hedging, combined with our fixed price CPI gas contracts, means that approximately 60% of our production volumes have downside protection to lower oil prices. The balance sheet remains strong. There is optionality in our timing of growth projects, and we have potential proceeds coming in from the Barossa and Darwin LNG sell-downs, which are contingent on the Barossa FID. We also have flexibility to optimize the broader Santos asset portfolio through strategically aligned farm-outs and disposals. Slide 19 shows our debt maturity profile at 30 June. Our total drawn debt is $4.7 billion, including the PNG project finance debt, which is nonrecourse with the repayments coming from the cash flows of that project. Once the PNG project debt is removed, as shown on the right-hand side, our senior unsecured drawn debt falls to $3.4 billion. The $750 million Conoco acquisition debt due in 2022 is expected to be refinanced with 5-year or greater debt within the next 6 to 12 months. The debt bucket remains strong with ample liquidity and support. Moving to Slide 20. On the 28th of May, we welcomed the ConocoPhillips' Western and Northern Australian teams into Santos. We are leveraging the in-house expertise to successfully deliver the integration of Quadrant Energy in 2019. This team will ensure the transition is efficient. We're expecting to deliver the upper end of the $50 million to $75 million per annum synergy guidance range through removing corporate overheads, which included 42 Conoco expats and removing duplication. We are also investigating operational improvement opportunities across our combined offshore and onshore businesses. I'd like to finish by emphasizing the company's strong financial performance despite the significantly lower oil price in the first half of 2020. Our continued focus on safe, low cost-efficient operations and the integration of ConocoPhillips Western Australia into the business will provide a strong platform to deliver our growth opportunities once macro conditions improve. Thank you, and I'll now hand back to Kevin.

Thank you, Anthony. Now let's take a look at our asset portfolio, starting on Slide 22. As I said earlier, Santos is a portfolio play. We have 5 core assets each generating free cash through the oil price cycle. The base business provides steady production for the next 5 or 6 years before the impact of any major growth projects. One of the things that I believe sets Santos apart is that we have growth opportunities across all of our assets. Our growth is not beholden to 1 project, 1 product market or 1 region. Our strategy is also a brownfield upstream growth strategy, leveraging existing infrastructure positions to deliver superior shareholder returns. We now operate 4 of our 5 core assets. This provides significant flexibility and importantly, control our growth spend timing, which gives us optionality to take FIDs when market conditions are supportive. Let's start with the offshore business on Slide 23. Our offshore business comprises our Western Australian and Northern Australia core assets. The acquisition of Quadrant in 2018 transformed the scale of our offshore WA business. With the commencement in June of the 12-year fixed price U.S. dollar-denominated contract with Alcoa for 120 terajoules a day, Santos now supplies around half of WA's domestic gas requirements. It's a low-cost, strongly cash-generative business with an EBITDAX margin of 72%, underpinned by fixed price domestic gas contracts. Production costs have fallen by 36% over the past 3 years to $6.55 per BOE. And in Northern Australia, the ConocoPhillips acquisition brings operatorship and control of long life natural gas assets and strategic LNG infrastructure at Darwin. We have a high-quality portfolio of operating production assets, short-cycle tieback opportunities and, of course, major growth with Barossa and Dorado. I'll talk about some of these opportunities over the next few slides. On Slide 24, we have a portfolio of short-cycle infill and tieback opportunities in the offshore business. Following the successful Phase 1 infill project at Van Gogh, we have taken FID on Phase 2. This will involve 3 dual lateral wells targeting undrained parts of the field, with first production expected on schedule in late 2021. The Ningaloo Vision FPSO is currently in dry dock in Singapore for planned maintenance. Due to COVID restrictions in the shipyard, the FPSO is now expected back on-station in the first quarter of 2021 when production will recommence from the existing wells. Pleasingly, we have made up for the production deferral this year from the shipyard delay with stronger production from our other WA offshore assets. We are also assessing further infill drilling at Pyrenees. The West Australia crudes from Van Gogh and Pyrenees earned strong premiums in the market to date in Brent as they require very little or no refining to meet IMO Marine Fuel Standards to reduce emissions. Consequently, this makes our infill project high return, short-cycle projects as they are relatively straightforward tiebacks to existing infrastructure. At Bayu-Undan, the successful Phase 2 infill drilling campaign increased liquids production and improved well deliverability. With our joint venture partners and the Timor-Leste government, we are now evaluating a further phase of infill drilling to optimize field recovery and extend field life at Darwin LNG production. The planned program includes 3 new wells, 2 drilled from the platform and 1 subsea well. We are targeting FID by the end of this year, subject to joint venture and regulator approval. Our goal is to optimize the period between Bayu-Undan and production ending and Barossa starting up. Moving to Slide 25 and the Barossa project. What I really like about Barossa is that it's a low-risk, mainly upstream Brent through project with liquids and it's positioned at the right end of the supply cost curve. It's a relatively straightforward offshore scope tied into an existing pipeline and LNG plant. Since assuming operatorship with the completion of the Conoco acquisition, we have commenced value improvement work targeted at reducing project costs. This work is progressing well, and I am confident of an even more robust project. We are targeting to be FID ready by the end of this year. However, FID will be subject to business conditions. We have signed an LOI to sell down 12.5% interest in Barossa to JERA, an existing Darwin LNG partner. We are also in advanced discussions with other parties to sell a further 10% equity as we target a Santos interest in Barossa of around 40%. And although I am bound by confidentiality conditions, I can inform you that the Barossa and Darwin LNG partners have made good progress on finalizing the processing agreement and toll for Barossa gas to support an FID decision. On the marketing front, we continue to have positive discussions with multiple LNG buyers on offtake agreements. However, COVID has impacted on the timing of these agreements as a result of schedule uncertainty and our ability to have face-to-face discussions with the various parties. On LNG prices, I believe they will improve even if this takes a wee while to play out. The cost of supply will ultimately determine the longer-term floor. And right now, spot prices are significantly below the actual cost of supply. These lower prices will drive increased demand. And given the advantage of natural gas over coal from an emissions perspective, I expect to see continued coal-to-gas switching for power gen over the near term, which will soak up supply. I also expect that the effects of some greenfield LNG project being deferred and maybe some never being sanctioned will further strengthen LNG prices over the next few years. And while we are on LNG markets, I remind you that more than 90% of our current LNG volumes are sold on mid- and long-term contracts with strong slopes to oil. This means we have minimal exposure to the LNG spot market. Moving to Slide 26 and Dorado. Work on the project is progressing well, and we are targeting a FEED entry decision in the second half and FID next year, subject to business conditions. The project is underpinned by a high-quality liquids resource of over 150 million barrels of 2C. The shallow water depth and compact reservoir footprint allows for a relatively straightforward wellhead platform and FPSO development. The preferred development concept is an initial FEED of oil and condensate development followed by a future phase of gas export following further basin appraisal. The initial phase is expected to need only 8 to 10 wells and allow for an initial oil production rate of between 75,000 and 100,000 barrels per day. We are investigating both bond and lease options for the FPSO. CapEx estimates will be refined during FEED, depending in part on the FPSO option that is chosen. Moving to Slide 27 and our onshore business. We have an integrated business across 3 states and northern territory, serving both domestic and export markets. I am proud of the fact we are Australia's lowest cost onshore operator with growth self-funded within the disciplined operating model. The Cooper Basin is performing well. Our well production is up and our operated midstream infrastructure is processing the highest gas and oil volumes in years. GLNG upstream is also performing well with record production levels driven by ongoing strong well performance at Brova and now our newest area, Arcadia. In our second quarter report, we guided to GLNG LNG sales of 5.9 million to 6.1 million tonnes for this year as customers exercise contractual flexibility on cargoes due to lower demand. On Slide 28, the turnaround of the Cooper continues as we position the asset as a high-value swing producer, supplying both domestic and export markets. Our focus on low cost-efficient drilling, combined with our renewed focus on the rocks, is delivering improved reserve replacement as well as higher production. By developing reserves in the Cooper Basin with a much more disciplined field development plan approach, we are targeting a 3-year rolling average reserves replacement of around 100% level over the next few years. As you can see in the chart, we also expect to grow production this year to around 17 million BOEs, 5 years ahead of our 2025 target. Our operating model sees us allocate capital to the Cooper such that the asset is free cash flow positive at less than $35. This currently represents sustaining CapEx of around $300 million per annum and drives the number of wells we drill. As more horizontal wells enter the program, we could drill less wells to deliver the same production and reserves outcome. The actual well count each year may also vary depending on participation by our joint venture partner. On Slide 29, we continue to seek opportunities to improve capital efficiency and optimize the value of our midstream infrastructure. As we spoke about at the last Investor Day, we are including horizontal wells in the program to drive down unit development costs. Initial results have been promising. The first well, Durham Downs North 8, drilled 1,500 meter horizontal section and came online at over 10 million scfs per day. And this rate was constrained by our gathering system. Unconstrained, the well could have produced at significantly higher rates. The production rate is 5x the previous vertical well in the field and is expected to recover 5x the reserves. The potential for 2 further horizontals in the field is currently being assessed. Utilization of our Cooper Basin midstream infrastructure continues to increase, including record liquids throughput at Port Bonython and the highest Moomba gas throughput in 10 years. This performance is supported by our own strong upstream production and volumes from third parties. We continue to focus on unlocking value and increasing returns for our midstream infrastructure assets across the company. This work is undertaken in our midstream infrastructure and low-carbon operations division, now led by Brett Woods, and we look forward to providing an update at our next Investor Day in December. Brett and the team are also leading the Moomba carbon capture project, which I will talk about on the next slide. CCS is a critical technology to achieving the world's climate goals. The Cooper Basin is uniquely placed for CCS and has the potential to store up to 20 million tonnes of CO2 per year. The first phase, 1.7 million tonne per annum project, is progressing rapidly through FEED, and we expect to commence an injection trial in the fourth quarter. We are targeting to be FID ready on the project by the end of this year. We have also signed a Letter of Intent with BP, which would see BP invest in Moomba CCS, subject to project FID. Moomba CCS is a low cost -- is low-cost at less than AUD 30 per tonne full life cycle cost. Once in operation, the cash cost is forecast at $6 to $8 per tonne. CapEx is estimated in the range of $125 million to $155 million gross. Moomba CCS not only has the potential to significantly reduce our emissions, but would also provide a new revenue stream for Santos, and we are working with the government departments to qualify CCS projects for the creation of Australian carbon credits. We believe strongly that CCS is an essential part of the solution. And with the right incentives, I believe we will see significant investment in projects around the world in the coming years, particularly as you consider some of the forecast carbon prices announced recently by some energy companies. We think CCS is an exciting opportunity for Santos now and into the future. Moving to Queensland upstream on Slide 31. We see a similar upstream capital-efficient story to the Cooper. This efficiency focus, combined with better-than-expected reservoir performance, has delivered record upstream GLNG production. This performance has been underpinned by ongoing ramp-up at Roma and strong initial production at Arcadia, as you can see in the chart. Again, all of this activity is within the capital constraints of a disciplined operating model. GLNG upstream is a flexible asset as our customers exercised contractual DQT in the first half due to COVID, we haven't had to turn our fields down. Rather, we have managed jobs -- we managed upstream production through a combination of injection into Roma storage and exercising flexibility on our third-party gas supplies. This gas has been available when we need it. It is this disciplined approach to operations and development that we hope to be able to bring to Narrabri, which I will touch on in the next slide. At New South Wales, the assessment of the Narrabri gas project is on continuing via independent planning commission. We expect a determination of the project next month. Santos has relied on the best science to inform the EIS for Narrabri. Following the public hearing process and submissions to the IPC, we remain confident that the project, if approved, will deliver more affordable, secure, cleaner energy for New South Wales customers. It will bring more investment, jobs and regional development for New South Wales communities. And will be developed safely and sustainably without harm to water resources or the environment. Should the project be approved, we will then move into a 12 to 18-month phase of appraisal. Subject to FID, the project will then be developed in phases such that we can appropriately phase the spend within our disciplined operating model. We have already committed 100% of Narrabri gas for the domestic market. Gas customers are keen for Narrabri gas to come into the market, and we have announced a number of heads of agreements for gas offtake, subject of course to project sanction. In summary, on Slide 33, our clear and consistent strategy to focus on long-life assets that generate sustainable free cash flows through the oil price cycle is delivering consistent and clear results. Today is another solid set of financial results, set against a challenging backdrop of significantly lower oil prices and the COVID pandemic. Today's results also demonstrate the strength of our diverse balanced portfolio and a disciplined cash-generative operating model. On that note, I'm going to wrap up now. So thank you for joining us today. I'll now open the call to questions.

[Operator Instructions] Your first question comes from James Redfern from Bank of America.

Just a couple of questions. First one is just in relation to a very slight delay with FEED entry for Dorado. It was previously the September quarter, it's now second half of the year. I'm just wondering what the reason for that is? And the second one is just in relation to gearing. And then gearing 34%, medium-term target is 25% to 30%. Just wondering when you see line of sight to get back to that medium-term target gearing range?

All right. Thanks, James. Let me tackle the first one first. Really, it's just been with the impacts of COVID and our ability to get the engineering work done. And in addition to that, James, we initiated an FPSO design competition, which knocked back the FEED process -- the entry to FEED, if you like, by a couple of months. That should gain us time further on because we've now got a short list of 3 FPSO contractors who have done that initial work as part of that pre-FEED phase of the project. On gearing, why don't I hand that one to you, Anthony?

Yes. Thanks, James. Look, yes, as I said in the talking notes, we've got flexibility around the timing of our major growth projects. So that allows us -- that flexibility depending on macro conditions on the de-gearing. Also, the sell-downs for Barossa are conditional on the FID. So when the sell-down money comes in aligned with an FID that also helps to add to the de-gearing. And then the last thing that we've got, as I said, is there's always options for us as well to look at strategic farm downs and alignments across our portfolio as well. So all of those things will unfold sort of over the next 6 to 12 months, subject to macroeconomic conditions.

And what I would add to that, James, is we saw the last time from this portfolio how much cash it generates and the quiet way it generates cash as oil prices increase. And we made the point in the notes earlier on that for every $10, the oil price goes above our free cash flow breakeven, that we should be generating between USD 325 million and USD 375 million and free cash flow on a go-forward basis. And so we saw that last time during 2017, '18, how critically we're able to de-gear. And I should also mention, of course, we've announced some sell-downs in Barossa and Darwin LNG.

Your next question comes from Mark Wiseman from Macquarie.

Just a question on the second half production increase versus the first half. I just wondered if you could clarify, to what extent is the increase in WA DOM gas production driving that increase? And also, could you just provide a bit more color on what drives the 5 million barrel range? Which assets or sort of scenarios would put you to the bottom or top end of that guidance for the second half?

So thanks, Mark. It's Anthony. Yes, look, in terms of second half production, it's driven by 2 things. It's driven by Bayu-Undan, obviously having a much higher percentage going from 11% up to 68.4%. So that's one of the main contributors. And you're right, the second impact is we'll have a stronger second half in WA gas, driven by 2 things: one, the very good Alcoa contracts, which is 120 TJs a day for the whole of the second half because we didn't have that much in the first half, it was literally only a few weeks in the first half; and also, we had added a major customer in WA for the first 6 weeks, beginning of the year. And that's obviously not going to -- hopefully, not going to occur again in the second half. So those 2 factors are the main contributor to the jump in production. Your second question was production cost, was it not?

No, no. The second question I wanted to ask was around the Barossa FID. Could you just confirm that at the time that you take FID and you do the sell-down to JERA as well as the sell-down to the other party that you're negotiating 10% with, would you receive those proceeds from SK at the same time towards the end of this year? And you also have to pay to Conoco the contingent payment. Will that all be aligned at the same point in time? And could you just comment with the sell-downs on Barossa, are they likely to be all cash upfront? Or would it be sort of a contingent sort of structure as well?

No, Mark, the sell-downs are all executed or completed on FID. So basically, when we take FID of the project that would be the final condition precedent that would then complete those deals. And so the payments would all be on Conoco completion. And that would include SK and any Barossa selldowns.

Okay. Great. And just a final...

Just to be clear, just to be clear, what I said this morning was we aim to be FID ready by the end of the year. We didn't say we take FID at the end of the year. And that will be subject to, obviously, macro conditions.

Okay. And just a final question just on the dividend. Clearly, that's surprising the market today that you've opted to the bottom end of the payout ratio guidance. I mean, we've seen other companies here in Australia and in the region sort of cushioning the impact of low profits by opting towards the upper end of their payout range. I just wondered what the discussion was in the Board room there. And also what your consideration is around activating the DRP in the future?

Well, for me, if you want to get detail on the discussion in the Board room, you have to join the Board. But look, in terms of the decision, as we said in the speech earlier, that the Board considered it prudent at this point in time as we're dealing with second waves and still coming through COVID to move to the bottom end of the range, but retain the flexibility, obviously, a full year dividend to reassess that. And we'll do that at that time.

Your next question comes from Adam Martin from Morgan Stanley.

Just Dorado obviously looks like a pretty defensive oil opportunity versus some other projects out there. But obviously, oil is now clearly still pretty uncertain environment. Just wondering how you're thinking about the 80% commitment there? Does it make more sense to try and farm down pre-FID? And so the second part there is, if oil is still at $45 a barrel next year, is that enough to move forward on that project?

Well, look, there's a couple of different parts to that question, Adam. Let me just start by saying that Dorado is an exceptional project. And there's a lot of interest to get equity in that project, as you would imagine. The time to do that will be at FID. We don't have to do it today. We don't have to rush that. We don't have to sell at the bottom of the market. And if we do decide to do that, that's an option we have. As long as -- along with a lot of other options, as Anthony said earlier, including infrastructure and/or equity and different assets. So we will consider all of those things if and when appropriate. And we would obviously -- if we're going to execute anything like that, we would do it at a time that we feel would maximize the value of that particular transaction. In terms of the robustness of the economics. I'm not going to say when we would take FID. We aim to be FID ready next year on this project. What I can tell you is this project would work at current oil prices. It's a very, very robust project. But that's not to say we would take FID at that point in time. It will depend on the market conditions, as we said earlier.

Okay. Okay. And just on -- you've talked about value engineering for Barossa. Can you just provide a bit more detail there? What particular areas of the project do you -- are you trying to reduce costs? Understand brownfield should be more competitive to some other greenfields, but clearly, the LNG market is still very tough. So just what particular areas there are you looking to try and reduce costs, please?

Well, look, at the end of the day, the one way to absolutely guarantee to deliver value in a project is to take the cost of it down. And so the guys are very focused on any opportunity across the project whilst we're resetting, if you like, for an FID decision in the future. And the areas we're looking at, obviously, we've got options around the FPSO, whether we want to go lease rather than buy. We've got drilling. Drilling costs are quite considerable. And so we've identified some good opportunities there, some of the subsea scope. And just generally going through every part of the project and looking to see if there's opportunities to reset some cost reductions, et cetera. And we're pretty optimistic we'll be ready to improve the cost profile of that project.

Your next question comes from Mark Samter from MST.

Just a couple of questions, if I can. First one, just on the Bayu-Undan in field possibilities. I think I'm not wrong in saying that maybe at least 1 of the JV partners has spoken about the opportunity to extend it maybe up to 2024, 2025. Is there any latest thinking on how long? And does that give you a bit more of a buffer with the Barossa FID decision as well?

Well, look, I mean, I think the 2 are running in parallel, Mark. So they do impact each other. Because, as you would imagine, if we are going to extend the life, we've got to make sure that we understand when first gas from Barossa can be delivered because whether that's in tolling agreements, LNG offtake agreements or whatever, that's a very important date. So we've got to be able to maintain integrity around that date. So extending the field life, if it went too far, could have an impact on that. Our current view is it's probably 6 months up to a year of extension at this point of view because the production will come in as we're still producing from the current wells. But there are varying views. When you look at the type curve for these wells, you go from a P50 to a P90 profile. It could be significantly longer and that's, of course, theoretically, it could be shorter as well as the uncertainty we have in this business. On a P50 basis, so we would expect an extension of somewhere between 6 and 12 months.

And then just a question [indiscernible] to ask on the WA gas market announcement this week because to me, personally, it's not sure the government know particularly what they're saying about loan industry consultation on how to understand it. But can you give us just a bit of a concept of the contracted profile for the WA gas business? And I guess, we can't tell you, you think this could have impact on longer-term gas prices, if it's not the use case policy, it probably sends prices higher rather than lower. But just to feel around how your WA gas book is looking and it goes to?

Yes. Yes. Look, I mean, we're going to reserve our business on the WA government's announcement this week until we fully absorb it and get opportunity to talk to them about what the longer-term views on market development and policy are. However, what I would see is a significant volume of our reserves today are contracted and with strong contracts with stable cash flows out as far as 2032. I think I understand the genesis of your question is really around the weightier gas coming into the market. And all I've really read is that they've got the ability to -- for a temporary period or short period to put that through the LNG facilities. And if they strike a deal and they're able to do that, my gut tells me that turning that around, it might be a longer period. And -- but the bottom line is, in the interim, it still doesn't oversupply the domestic gas market. The domestic gas market is still strong. I'm very bullish on our position in that market. As I said earlier, we provide around 50% of the gas in WA today. We have a very low-cost of supply producer in West Australia. We think that's a very significant competitive advantage against any of our competitors in WA, and we intend to maintain that advantage going forward.

Your next question comes from James Byrne from Citi.

I have a couple of questions on the Cooper Basin. Anthony, first one for you, just around this intention to unlock the latent value you see in the infrastructure position in the Cooper Basin. I guess it makes sense to unlock that capital upfront if you had, say, a large franking balance that you wanted to distribute. Why would selling equity in your infrastructure, not just be financial engineering, why does that unlock value? Because I think that the market will typically look through this type of financial engineering exercise and perhaps not give you the benefit that you might be looking for. Why do you think that assessment is wrong?

Yes. Thanks, James. Look, from a midstream and low-carbon business review, strategic review, as we said, we're still continuing to do it this year, and we'll definitely put some more information out at the end of the year when we move to our strategy day. So it'll give a much better flavor of what that business looks like. It's not just Cooper that we're looking at from how to unlock value. So it's the whole infrastructure business, which includes now Darwin WA, GLNG, Cooper. So all of our operated assets across Australia. But more importantly, with Cooper, we haven't made a decision on what we want to do. And as Kevin said, there's some significant value upside in Cooper with the CCS projects moving forward and then potential hydrogen and other views to go forward in the future. So we have not made a call on that, but we see significant upside value in Cooper. So it's not just about financial engineering, but there is significant value unlock potentially as we move forward with that midstream area, and we're still finishing that strategic review.

Yes. If I could just add to that, James. Let me just add to that. What -- we're not looking to do financial engineering. That is exactly what we don't want to be doing. And there's no need for us to do that. Our competitive advantage today is coming from driving down our low cost of production, our operating costs. Unlocking and high OpEx would be counter to that. And so when we say that there's many facets to how we're looking at unlocking value from our infrastructure, there's many ways to do that. But what I can say is it's not simply a case of trying to do financial engineering and driving our OpEx up.

I look forward to hearing more about it. So that's actually a good segue to the CCS project. So you've stated that your long run marginal costs in the high 20s, the recent ACCU auctions, let's just work on the assumption that you can sequester carbon and earn the ACCUs. I mean the recent auction prices are in the mid-teens. So can you help us understand the magnitude of the costs that you're going to incur there sort of on a per annum basis real? And then how do you then think about turning what is effectively going to be a cost to sequester carbon into an opportunity? Because I note that if you're able to actually earn, say, European carbon price, I mean, that's pricing at AUD 50 a tonne at the moment. So is there a way to actually turn that cost into revenue stream?

So James, look, I mean, you've touched on a lot of good points there. This is a project that really excites us, and it's one that's gone from a few years ago being considered as a cost we maybe have to incur to one that we see now as a real upside opportunity that can deliver significant revenue streams in the future. I think the first thing to get your head around is the volume we're talking about. On a world basis, a world CCS project basis, this is a very significant project, 1.7 million tonnes of CO2 per annum that will be reinjected into Cooper reservoirs. What we've said, the life cycle cost based on a period of time would, say, 20 years, I think it's based over 20 years, and the CapEx upfront cost and the OpEx, all adding them, we can deliver for less than AUD 30 per tonne, right, life of the mine. And the CapEx aspect of that is between $225 million and $255 million -- sorry, $125 million to $155 million, sorry, gross, right? So that's the total upfront CapEx expectation to deliver this project. From an OpEx point of view, and this is important, because I think you were indicating -- I maybe misheard you, but I think you were suggesting $28 running cost?

Yes.

The cash cost of production or operations because normally production for this project would be between $6 and $8 per tonne per annum. So you can see it's not that significant at all. It's actually one of the lowest cost CCS projects globally when we benchmark them. And the point you make about access to foreign credits is spot on. The King Report has recommended that CCS qualify for carbon credits. Here in Australia we're working with the government to do that. But we're also working at various levels to get access to foreign investment and carbon -- and credit markets through bilateral arrangements, which are permitted under Article 6 of the Paris agreement.

Okay. That's really helpful. But nonetheless, like, if you weren't able to access foreign credits, then the reality is that the ACCUs are below the long run marginal cost. So it would still be NPV negative. But I guess the reality is that you have to sequester carbon if Barossa is coming online. Is that correct?

Well, look, it helps with that. But you're also assuming the cost won't go up. And there are other commercial models we're evaluating. So we have many other operators, other companies who are talking to us about ways of investing in this type of project. And there's not a lot I can really say on that other than we're evaluating all of those options for revenue streams.

Understood. Third and final one for me, very quick. We saw white CICAD agreements nonbinding money to your Northwest Shelf. Just wanted an update on where you're at on your own negotiations for getting the behind pipe, gas you've got in WA into Northwest Shelf as well? Appreciate that, that's in federal waters, so it's not subject to WA premium?

Well, well, James, we've never announced that we're in negotiations with the Northwest Shelf or any other parties in Western Australia. We do have -- that gas has been very valuable this year. But we've been able to make up for the departure of the Ningaloo Vision by being able to bring that gas on and demonstrate we can bring it on very quickly at a very low cost. We will continue to look at all opportunities to maximize the value of our reserves in Western Australia. That will include export and domestic gas opportunities. There's not really a lot I can say on that at this point in time.

Your next question comes from Saul Kavonic from Crédit Suisse.

I'm just going to come back to WA. To be clear though, the WA gas policy that's just come out this week, are you able to clarify whether your gas field by the Quadrant acquisition, whether that applies to them or not?

No. Saul, we can't clarify. At this point in time, we've got no detail. So we just have to -- I mean that would be retrospective if they did. But we just got to work to find that out over time when we engage with the West Australian government.

So my follow-on question to that is I mean I know this policy has come as a surprise to many, and it seems Santos as well. But you've had other companies, Woodside, Beach, Mitsui where there's clearly -- doesn't appear to be a surprise, and they've had discussions with the government on this. Given how important WA government policy is to WA gas cycle and how big Santos' footprint is there, should we be concerned that this has come essentially as a surprise for Santos? And you haven't had the same level of relationships with the government there that it appears some of your peers did have?

No, I don't think so. I mean, we've been in discussions with the WA government for a long time. I mean, we don't know the details behind some of the aspects of this release, and we're in discussions with the WA government right now to ascertain what exactly that means over the longer term. But as a producer of 50% of the domestic gas market in Western Australia, we have lots of interaction with the government. We recognize the importance of our assets -- our current assets to that market. And we maintain a good positive relationship with the WA Government. I don't have any concerns on that front whatsoever, Saul. And as I said earlier, I'm still very bullish on that market, our position in that market and our ability to maintain a very significant market share for a long time to come. Indeed, today, as I said earlier, we've got a lot of our gas contracted with stable cash flows out to 2032. And our uncontracted volumes, we're actually in advanced discussions today with a few suppliers. Our ability to supply a low-cost of supply and very importantly, reliably supply and deliver sets us apart from most of our competitors in Western Australia today.

Great. Also on the Bayu-Undan abandonment, I see you've submitted to NOPSEMA the decommissioning plan this week, where it seems to say you'll begin decommissioning between 2021 and 2023. Are you able to give us any update on timing and the amount of CapEx we can expect for Bayu-Undan over the next 3 years?

We'll give guidance when appropriate. The timing of that submission is not a firm proposal. It's basically being ready to get the plans approved to go by that time. And the timing would be subject to many other approval processes, design processes, best availability, the usual project planning time processes that we have to go through. So I wouldn't read anything into that particular document's timing by which we need to have the plan approved. That really is just tied to having the plan approved by an expected end of field life milestone.

Great. And just one final question. It's coming back to Barossa. I think you've clearly indicated that you're seeing progress is going well in the tolling agreement, but it's an element of discussion that keeps coming up in the market. Can you just provide more color for us that -- should -- is there any reason for markets to have concern that any 1 of that joint venture in Barossa might be having cold feet about taking FID in the wake of COVID? Or are all indications still very positive towards an FID in the next 12 months, again, depending on the market conditions?

So by any one of the partners, you mean those of SK? Or are you referring to the Darwin side?

Both sides.

Well, on the Darwin side, there is no alternative projects. So they're all pretty aligned, they're pretty keen for Barossa to come in because it's -- decommissioning is the alternative project. And on the Barossa side, SK are still very positive. We're working with them. They're working hard to drive things forward for FID and very supportive partner.

Your next question comes from Gordon Ramsay from RBC Capital Markets.

Kevin, just on the Dorado project. Is it a black and white decision for the FPSO lease per zone? Or will you consider lease with option to buy back in the future?

Look, that's a good question, Gord. Look, there'll be a number of options in there, Gordon. So you've got a kind of black and white lease versus buy, the conventional lease versus buy. Then there are a range of other options on the lease side, where you can buy up to 5 years, 7 years, 10 years or whatever. Or alternatively, you can have -- well, not just alternatively, but in addition, a step down lease arrangements where the lease rate changes over time based on the decline curve of the assets. So we're looking at a range of options on Dorado. It's too soon to kind of give any indication on which we'd be leaning.

Okay. And in terms of exploration, is there any kind of an update on the timing of when that might resume in the area?

Look, if I can, I'm going to defer giving you a sort of a detailed update on that until Investor Day later this year. But what I can see over the course of the next sort of 4, 5-year horizon, we've identified 2 or 3 really exciting moving prospects in that basin that we do want to evaluate to build on the success we've had at Dorado. And the seismic work we've been doing, the subsurface work we've been doing, has really, I guess, made us more excited about those prospects. Some very exciting sizable prospects that we want to test at some stage over the next few years.

Okay. And just lastly, just coming back to Barossa. I just want to understand the terminology here. What does FID-ready mean as opposed to an FID target date? And is it simply the statement that you've made subject to business conditions? Or are there other issues at stake?

No, really, it's only business condition. So FID ready, for us, means that other joint venture partners are all technically satisfied, all the key contracts are in place, our boards have basically said, good to go and we're just really waiting for the market conditions to be suitable, so we press the button.

Your next question comes from Daniel Butcher from CLSA.

First question just on Cooper Basin JV. I think that you've said the other day, fully off the few wells for this year. I'm just wondering what sort of level of well drilling do you think you need beyond FY '21 to get to 17 or even 19 million barrels and maintain it there.

Well, Dan, look, we've given some guidance there in terms of sort of run rate. We're talking about the sort of 90 wells expectation for this year. And that's not a bad proxy to use going forward. And that's if our joint venture partners are participating in the wells. Of course, if they don't participate, we have a concept where we can actually so risk some of those wells. And then we get all the reserve dollar production from those wells. So it doesn't mean that we're drilling 90 wells in that case. It would be a lower number of wells and we still want to match that within our disciplined operating model framework. In other words, we want the CapEx to be much sustained overall. But it really depends on what the participation level ends up being with our partners. And we won't know that until we do those -- go through those budget processes over the course of the next few months. But my suspicion would be given that announcement, that it's going to be less than 90, and we all have higher equity in some of those wells.

We could hold -- we can hold 17 million barrels because of that higher equity in the wells.

Okay. Second one, just I noticed you sort of didn't want to answer the question about Dorado, what oil price you need to see. But I'm wondering whether you can maybe have another go. With Barossa, what sort of market conditions would you like to see to be able to go FID early in 2021?

Look, I mean, I'm not going to try and answer that on this call, Dan. Good at [indiscernible] but bottom line is we'd like to know that -- we'd like to see the green shoots of recovery coming out of the pandemic. The sort of things that are important to me, it's not just about the resource price. Obviously, we'll take a view on that at the time. And we will be stress testing at the lower prices as per our operating model. In other words, first of all, it's going to be free cash flow positive below 35 at all types through the cycle. That's a rule we have for all of our assets. And then we have our various other planning IRR, NPV type metrics. And of course, in the case of Barossa, we have to have LNG contracts off-take agreements in place to support the FID. But what's really important to me, for example, would be the certainty around the fact that we can go in a shipyard and get it delivered and not be interrupted with lots of outbreaks of the virus shutting down shipyards. And so that schedule certainty will be very important to us as well. That's what we mean by macro conditions. It's not just resource prices, it's also the ability of the market to deliver, the service companies to deliver on their commitments.

Okay. That's helpful. Third question, maybe a final one. Just on the Conoco run rate synergies of 70 -- $50 million to $75 million, could you just maybe outline what the run rate was at June 30 or what the average was over the first half? And how fast towards that target you're currently running?

And so on track and it was above the minimum. There you go. The run rate was above the minimum. That will help you. But look, Anthony's given guidance that we're guiding towards the top end of that range. We're going to be pushing that hard just as we said for the Quadrant, which we ended up delivering above the top of the range of Quadrant. But yes, I mean, we've identified a number of opportunities that we've yet to lock in. We're very disciplined about letting the organization lock in synergy. It's got to be cemented and firmed. As Anthony said, we've got a good head start because it was something like 42 expats who were released and that expats are typically very expensive.

And Dan, you'll also get this year you'll obviously have costs such as redundancies, et cetera, that will offset one-off -- one-off costs that will offset some of that synergy. So you don't see the full synergy flowing through in year 1. But the run rate comes through in the following years.

Yes. Okay. Just curious, I mean, maybe follow-on to a previous question that sort of alluded to the fact you might be able to put gas volumes through Northwest Shelf. After this half period where you get the benefit of our coal, but some contents not rolling off and you're pretty much at capacity into next year, how much spare capacity do you have upstream at Varanus? Is it kind of in the order of 50 TJs to 100 TJs a day? Or is it kind of less than that?

Yes. We've always got swing capacity between our 3 assets in WA between Varanus Island, Devil's Creek and, of course, Macedon. And that gives us a lot of flexibility in how we operate our WA market, but we experience tech production levels to be relatively flat for the next few years, as we said earlier.

Your next question comes from Baden Moore from Goldman Sachs.

I appreciate you've answered a lot of questions this morning. I just had some follow-on on the CCS details you've given. Because that $30 a tonne looks very competitive versus global projects. And I was wondering, you mentioned a run rate there on consumption of CO2. Can you talk about what you think the project life duration would be at that sort of run rate? And then also whether you're factoring in other economics from other projects like enhanced oil recovery or anything to get that $30 a tonne?

Well, we're not -- just to start with that last point, we're not including economic benefits from any add-ons to this project. This is just a pure CCS project economic update we're giving you here today. We believe we can drive that cost down over time with scale as well. And that's an important consideration. Our initial 1.7 million tonnes per annum is because that's all the CO2 we can actually get our hands on. And so all the limitation we have is we don't have enough CO2, frankly, to get our hands on. And so the next phase, and the way to drive the cost down is through volume and scale. And that's what we'll be working on how we can get our hands on creating and capturing more CO2. In terms of the life span of the project, really, it can run as long as there's gas to get the CO2 from the Cooper Basin. We have enough capacity in the Cooper Basin to take 20 million tonnes of CO2 per annum for more than 50 years. So there's no shortage of capacity at the Cooper Basin. We've spent the last 50-odd years emptying it or at least emptying some of the reservoirs there and depleting them, and we are in the perfect storage environment.

Your next question is a follow-up from Mark Wiseman from Macquarie.

Just wanted to ask one quick follow-up question. Just on the spot LNG exposure. As you mentioned, you're more than 90% contracted. And I think for the half, you said 7% spot. How do this infill drilling at Bayu-Undan impact that? And what's your strategy for contracting that over the next few years? I appreciate it's a pretty quick payback project and only for a temporary period, but should we think about that increasing your spot exposure to something significantly higher than 7% for a period of time?

Yes. Look, that's right, Mark. You should think of that. It's a very small exposure, as you point out. But yes, it would increase our exposure to the spot market. But it's a very -- I should also add that it's a very low-cost of supply project.

Your next question comes from Scott Ashton from SHA Energy Consulting.

Kevin and Andrew, no, it's been a while, so I'll just make it really quick. Anthony, just a quick comment maybe on the impact of the new royalty regime in Queensland. And Kevin, the announcement yesterday on the Amadeus to Moomba pipeline. Could I just maybe get an idea of how you see that, obviously, that's an MOU molecule to arrive at Moomba. And obviously, there's a tolling charge there. But does that free up molecule on the eastern seaboard for you to put into GLNG? Could you just maybe give a comment on how you see that panning out over the next sort of 3 to 4 years?

Well, look, I mean, I think what I would say is I'm a believer as we build in more pipelines to connect up the grid here further on the East Coast and through the center of Australia. All pipelines should lead to Moomba, it doesn't matter whose pipeline, this should lead to Moomba. Moomba is connected to every state territory, and it makes a lot of sense to think of Moomba almost as the Henry Hub, a very small-scale of Henry Hub of [indiscernible], but the Henry Hub here on the East Coast of Australia. Another benefit for us -- and we are open for business with any pipeline operators or consortiums and they know that. They know that. And what I would add to all this, it's not just about gas coming through Moomba and offering further processing opportunities, third-party processing opportunities for Santos. It's also more gas that's got CO2 in it. So if I go back to the CCS project we're talking about earlier on, these are some of the ways that we see of increasing supply of CO2 to the Cooper Basin in the years ahead and helping not only ourselves reduce our emissions but obviously, being able to reduce emissions of other gas producers as well. And we'll have a lot more to say about that at our Investor Day later this year. But I just wanted to add that point to your question. And then, do you want to comment that, Anthony, on the royalty, Queensland royalty?

Yes. Thanks, Scott. So look, on the royalty, we're pretty -- we're fairly neutral with it compared to the old versus new. The process was run well through the Queensland government. We had a lot of -- as an industry, and both as Santos, we had a lot of the input into the design of it. So we're quite happy with the design. It's less complicated. Worked through a series of pricing bands that we've all had input into. And so overall, it's a lot less onerous in terms of the way it's calculated and the way it works. And overall, we're comfortable with it from a sort of neutrality perspective.

When does it actually kick in? This year or next year or now?

This year, 1st of July.

Thank you. There are no further questions at this time. I will now hand back to Mr. Gallagher for closing remarks.

Well, I'd just like to thank everybody for joining us today, and I look forward to catching up with many of you over VC or conference call over the next week or so. So thank you.