Ladies and gentlemen, thank you for standing by, and welcome to the Santos Limited 2019 Full Year Results. [Operator Instructions]. At this time, I'd like to hand the conference over to Mr. Kevin Gallagher, Managing Director and CEO. Please go ahead, sir.

Thank you, and good morning, everyone. Thank you for joining us for the Santos 2019 Full Year Results Presentation. With me today is our Chief Financial Officer, Anthony Neilson. I'm pleased to announce that Santos has delivered another strong set of financial results. These results demonstrate the strength of our disciplined cash-generative operating model and the successful integration of the Quadrant acquisition into our business. We have also continued to drive unit cost down and deliver efficiency gains despite cost pressures seen across our industry. The year was also highlighted by our announcement in October of the acquisition of ConocoPhillips' business in Northern Australia and Timor Leste. The acquisition brings operating interest in long-life, low-cost natural gas assets and strategic LNG infrastructure. It is fully aligned with our growth strategy to build on existing positions around our core assets just as we did with Quadrant. I am pleased to say we're on track to complete the Conoco acquisition around the end of the first quarter. Before we start, I draw your attention to the usual disclaimer on Slide 2. Let me start by -- I'll start with some opening remarks about our performance before handing over to Anthony to discuss the financial results. 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 operating model, continues to deliver strong financial results for the company. The highlights are shown on the slide and includes strong growth in free cash flow, reported NPAT and sales revenue. Importantly, these results also demonstrate that the acquisition of Quadrant has delivered the promised it would and more, with synergy savings run rate now forecast at more than $60 million per year. The results highlights are we generated over $1.1 billion in free cash flow, up 13%. Sales revenue is up 10% to $4 billion; and reported NPAT, up 7% to $674 million after-tax. The Board has declared a final dividend of USD 0.05 per share, fully franked. This brings full year dividends to USD 0.11 per share, up 13%. The dividend is consistent with our sustainable dividend policy, which targets a range of 10% to 30% payout of free cash flow. Moving to Slide 4. Our journey to become Australia's safest operator continues. A 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 conditions that they come to work. Our LTIFR performance has improved back to both 2014 levels but with significantly higher activity levels as shown by the number of onshore wells drilled. Our injury severity, as measured by the number of injuries graded moderate harm or greater, has also declined over the past 3 years as shown by the gray bars on the chart. We are very focused on ensuring the lessons from these types of events are learned across the organization and that we continue to drive these moderate harm incidents lower year-on-year. We are 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. Still more to go, but we're pleased with the progress that we're making. Moving to Slide 5. We are very focused on free cash flow generation in this business. This is how we measure our performance and how -- and we are not going to let up on that. I'll remind everyone that back in 2016, our free cash flow breakeven was just shy of $30 a barrel. We had assets that were over $70 breakeven. Stepping forward to 2019, our free cash flow breakeven has reduced to $29 and even lower if we include the effect of oil price hedging. All of our assets are under $40. This is the Santos disciplined operating model in action. Free cash generation in 2019 was a record $1.1 billion. Over the past 4 years, we have generated USD 3 billion in free cash and finished 2019 with a free cash flow yield of around 10%. This free cash flow, combined with a strong balance sheet, underpin our brownfield growth strategy. Moving to Slide 6. The Santos disciplined operating model continues to drive lower cash unit production costs across our operated assets. You can see the results on the slide. Compared to 2 years ago, we have delivered reductions of 28% in Western Australia, 17% in the Cooper Basin and 5% in Queensland. I believe this is industry-leading performance which has been achieved despite cost pressures seen across our industry and our focus on growth over the last year or so. Now I'd like to talk about our growth on Slide 7. At our Investor Day in December, we increased our 2025 production target to 120 million barrels of oil equivalent. 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. Ours is also a brownfield upstream growth strategy, leveraging existing infrastructure to deliver superior shareholder returns. We have conventional offshore growth in Barossa and Dorado. We have onshore growth in the Cooper and Queensland. Narrabri is also moving forward and is being assessed by the New South Wales Department of Planning. Our reserve and resource position underpinning this growth is shown in the pie charts. I note this data is shown at the end of 2019 and obviously excludes the ConocoPhillips acquisition, which we expect to complete around the end of the first quarter. At completion of the acquisition, we would book an additional 418 million barrels of 2C before any subsequent sell-downs. Assuming only our pre-acquisition 25% interest in Barossa, FID on just Barossa and Dorado would commercialize over 300 million barrels of resources to reserves. Of course, we expect Barossa add to be higher at FID as we are targeting an equity interest of between 40% and 50% in the project. We now expect Barossa FID in the second quarter post-completion of the ConocoPhillips acquisition. I'll talk more about our progress on Barossa later in the presentation. I would now like to address Santos' approach to climate change on Slide 8. For 65 years, Santos has been safely and sustainably exploring and developing natural gas resources and partnership with local communities and landowners. Natural gas today remains a crucial part of the energy mix if we're to solve the twin challenges of reducing carbon emissions while meeting growing demand for secure and reliable power generation. Only last week, Australia's Chief Scientist, Dr. Alan Finkel, said in a speech that natural gas is already making it possible for nations to transition to a reliable and relatively low emissions electricity supply. Dr. Finkel refer to Britain where coal-fired electricity generation has plummeted from 75% in 1990 to just 2% in 2019. In the same period, electricity from natural gas increased from virtually 0 to more than 38% of the grid. Renewables also increased their share to 27%. This combination of natural gas and renewables has led to a 50% reduction in the U.K.'s emissions from electricity generation since 2009. Santos is committed to a lower carbon future, and our climate change policy gave the company activities to reduce emissions. Santos is striving to contribute to the global aspiration to limit temperature rise to less than 2-degree Celsius. We have set medium-term targets that align to these objectives and have set a pathway to achieving our long-term aspiration of net zero emissions by 2050. The transition to a lower carbon future also creates opportunities for Santos, with natural gas expected to account for 1/4 of total global energy demand in 2040 according to the International Energy Agency. Today, we have released our 2020 Climate Change Report. The report, our third annual Climate Change Report, provides updated scenario analysis and reports progress against our medium-term targets. The report complies with the recommendation of the G20 Task Force on Climate-related Financial Disclosures and addresses our strategy, metrics and targets, governance and risk management. I would encourage you to read the report, which is available on our website, to learn more about the company's resilience as well as the opportunities in a lower carbon future. One of those opportunities is carbon capture and storage, which I will talk to you on the next slide. Carbon capture and storage, or CCS, is a critical technology to achieving the world's climate goals. CCS is already established as a safe large-scale permanent abatement solution. There are already 18 CCS projects larger than 400,000 tonnes per annum presently in operation worldwide, storing a total of 40 million tonnes per annum of CO2. This is the equivalent of the annual emissions of 7 million cars. Australia could be a world leader in CCS and create an exciting new industry supporting hydrogen production and ensuring the sustainability of existing industries. The Cooper Basin is uniquely placed for CCS and has the potential to store 20 million tonnes of CO2 per year. We have now taken a FEED-entry decision on a 1.7 million tonne per annum CCS project. Our goal is to be FID ready by the end of this year on Phase 1, which is a 300,000 tonnes per annum project. We think CCS is an exciting opportunity for Santos now and into the future. In summary, it was an excellent year for Santos, and we're in great shape to drive our growth forward and deliver shareholder returns. I will now hand over to Anthony Neilson to provide a detailed review of our financial results.

Thank you, Kevin. Hello to everyone. This is another strong result and clean set of numbers for the business. Our continued efforts to embed safe, low-cost, efficient operations across our assets, combined with the successful integration of Quadrant Energy, has led to record annual free cash flow generation. The balance sheet is also positioned to support the significant growth opportunities across our portfolio. Moving to Slide 11. The 3 key financial priorities for the business remain focused on driving shareholder value. These priorities are a focus on strong free cash flow generation, continued cost-out and efficiency gains and maintaining a balance sheet which is supportive of our growth strategy. Free cash flow is up 13% to $1.1 billion. This is a strong result and was delivered despite higher CapEx spend on our successful offshore West Australian drilling program and record onshore activity across the Cooper Basin and Queensland, and we were still able to reduce our 2019 free cash flow breakeven to around $29 per barrel before the impact of hedging. Our continuous focus on cost-out and efficiency gains has continued to flow through to the bottom line. Excluding the impact of PNG LNG earthquake repair costs in our OpEx, our normalized production costs are down 8% to $6.97 a barrel. As Kevin has stated, our production costs across all our operated assets and PNG are lower than last year. At 31st of December, our net debt was $3.3 billion, down 6% on year-end 2018, which included the recognition of a $425 million lease liability under AASB 16. The adoption of AASB 16 did not have a material impact on our reported P&L or cash flow. Gearing at year-end was 30% and Santos' balance sheet remains strongly supportive of our growth strategy. Moving to Slide 12. We have said before that we're running this business as a balanced portfolio that generates sustainable free cash flow through the oil price cycle. What we meant by balanced is in terms of our asset mix. It's balanced between our onshore and offshore. It's between natural gas and liquids, our conventional and unconventional. And of course, it's a balance between our oil and CPI-linked pricing. The Quadrant acquisition has increased our weighting to CPI-linked pricing. And as you can see from the pie chart, this is now about 35% of our sales and gives us a nice, natural hedge component in times of volatile oil prices. This underpinning cash flow is important as we begin to move into the major growth CapEx phase. Our balanced portfolio delivered $1.1 billion in free cash flow, up 13% on the previous year, and we reduced our free cash flow breakeven to $29 per barrel before the impact of hedging. Including oil price hedging, it was lower at approximately $24 a barrel. We will use oil hedging on an opportunistic basis within our policy guidelines to provide further downside protection during the high CapEx period. Importantly, every $10 increment in oil price above our free cash flow breakeven increases our annual free cash flow by between $300 million and $350 million before the impacts of hedging. Slide 13 shows how the operating model continues to drive the strong results across our operated assets. We've maintained our focus on low-cost and efficient operations with upstream production costs down 10% to $7.24 a barrel. Our low-cost operating model continues to deliver both the low portfolio free cash flow breakeven and also, all our assets are free cash flow positive at less than $40 a barrel. As can be seen from the chart, our unit production costs across all our operated assets have continued to decline, and our onshore well cost discipline has been maintained with continued improvement still being realized. The efficiency journey is not over yet, and we're going to remain focused on continuing to get even better at what we do and drive further efficiencies such as horizontal wells in the Cooper Basin. Slide 14 shows a very strong set of results for the key -- for the year across key metrics. Sales revenue increased 10% to $4 billion driven largely by higher sales volumes due to the acquisition of Quadrant Energy. These higher volumes, combined with cost savings and efficiencies but offset by lower average commodity prices, led to an EBITDAX of $2.5 billion, up 14%. Our underlying net profit after tax of $719 million was stable with last year, and our free cash flow was up 13% to $1.1 billion. Reported statutory profit was up 7% to $674 million. The before-tax P&L impact of AASB 16 for the year was immaterial to our P&L at $5 million. Slide 15 outlines the strong free cash flow generation from the business. The company achieved a 13% increase in free cash flow to $1.1 billion. And since 2016, the turnaround in annual free cash flow has been over $900 million, with the cumulative free cash flow generated over the 4 years of $3 billion. Operating cash flow increased 30% to over $2 billion. And investing cash flow, excluding asset acquisitions and divestments, major growth CapEx and lease payments, increased 59% to $908 million. This higher CapEx was mainly a result of the successful drilling program in offshore West Australia and higher onshore activity levels which have all been maintained within our operating model of less than $40 per barrel free cash flow breakeven. With our strong free cash generation, we are now well placed to continue to reduce net debt, reinvest for growth and fund the dividend. Slide 16 shows the trend in earnings metrics. Our focus on cost reductions and efficiency gains and the acquisition of Quadrant Energy drove EBITDAX higher. Underlying profit was stable primarily due to this higher EBITDAX being offset by lower prices, higher DD&A and net interest costs, largely following from the Quadrant acquisition. Slide 17 shows the diversified nature of our portfolio, outline the strength across our 5 core assets and the balanced nature of their contributions to EBITDAX and margins. PNG and Western Australia are our 2 highest-margin assets with strong, stable cash flows, lower costs and margins in excess of 70%. This highlights the successful impact of the Quadrant acquisition on our results. Overall, our group EBITDAX margin was 59%, and all our asset segments have margins of greater than 45%. All of our assets are free cash flow positive at an oil price of less than $40 a barrel. Slide 18 shows production and sales volumes. 2019 production and sales volumes were higher than prior corresponding period due to PNG LNG resuming full production following the impact of the earthquake, which was in early 2018, as well as the successful integration of the Quadrant Energy assets in Western Australia. We do expect stronger production and sales volumes in the current year although the first quarter continues to be impacted by a major gas customer outage in Western Australia. 2020's production guidance is maintained at 79 million to 87 million barrels and sales volume guidance at 99 million to 107 million barrels. This guidance assumes the Conoco acquisition and the expected sell-down of Bayu-Undan and DLNG both occur at the end of the first quarter and could change based on actual completion timings. Slide 19 shows that our focus on safe, low-cost, efficient operations is continuing to deliver with unit upstream production cost declining 10% to $7.24 a barrel. Excluding the impact of shutdowns and the PNG LNG earthquake repair costs, which are in our OpEx, our normalized unit production costs fell 8% from year-end 2018 to $6.97 a barrel. Unit upstream production costs were lower across all our operated assets, reinforcing the continued successful implementation of our low-cost disciplined operating model. 2020 production cost guidance is expected to be around 2019's level in the range of $7 to $7.40 a barrel for the base business. This includes all planned shutdown activity and PNG earthquake costs, which are included in our OpEx, but it excludes the impact of the Conoco acquisition. On a normalized basis, production costs are expected to be around the 2019 level of approximately $7 a barrel. Slide 20 outlines our CapEx. Our 2019 CapEx was just over $1 billion due mainly to the successful drilling program offshore Western Australia and the increased drilling activity in the Cooper Basin and Queensland. The exploration and appraisal program offshore West Australia reflected the successful appraisal of Dorado and Corvus. The high equity position in these wells provides flexibility to optimize our portfolio and farm down at a later date. Even with this additional CapEx spend in 2019, our free cash flow breakeven of $29/barrel before hedging was lower than in the previous year. As you can see from the chart on the right-hand side of the page, improved onshore efficiencies and productivity gains have led to increased drilling activity in both the Cooper Basin and GLNG during the year at lower average drilling cost per well. All of this activity is under a self-funded operating model at less than $40 a barrel for both the Cooper Basin and GLNG. Our 2020 CapEx guidance is maintained at approximately $950 million in the base business and approximately $500 million for the major growth projects. We have maintained our PNG expansion major growth CapEx of approximately $60 million in guidance at this stage. However, it is contingent on further discussions with our joint venture partners. Slide 21 shows the net debt at year-end was $3.3 billion and gearing of 30%. This debt and gearing includes $425 million of AASB 16 lease liabilities. Excluding the impact of the lease standard, gearing was 27%, which is down 6% from 33% on a like-for-like basis with the prior year. We have ample liquidity of $2.9 billion with cash on hand of $1 billion and undrawn bilateral facilities of $1.9 billion. S&P reaffirmed our investment-grade credit rating of BBB- in October, noting that the current balance sheet capacity can accommodate the Conoco acquisition. The balance sheet is healthy, and we have ample liquidity in order to deliver our growth opportunities moving forward. Slide 22 shows the expected gearing profile of around 35% at completion of the Conoco acquisition. Gearing is expected between 25% and 30% during the 2021 to '24 CapEx growth phase post the expected sell-down of interest in Barossa and Darwin LNG to our targeted 40% to 50% interest levels. We could still fund all our major growth in dividends while keeping gearing around 35% at a $60 barrel per oil price, even if there were no sell-downs of Barossa and DLNG. The projected gearing profile assumes FID for Barossa, Dorado and also includes PNG LNG expansion. Our major growth CapEx and dividends are expected to be fully funded from operating cash flow and debt. Dividend is to be maintained through the major CapEx growth phase, consistent with our sustainable dividend policy. We expect rapid de-gearing from 2025 onwards and retain flexibility to optimize the broader Santos asset portfolio through strategically aligned farm-outs and disposals. Slide 23 shows our debt maturity profile at 31st of December. Our total drawn debt is $2 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 is $2.7 billion. The $750 million Conoco acquisition debt is expected to be repaid with sell-down proceeds or refinanced post the completion of the Conoco acquisition. I'd like to finish by emphasizing the company's strong financial performance. This is another good quality and clean set of numbers. Our continued focus on safe, low-cost, efficient operations and the successful integration of Quadrant Energy provide a strong platform to deliver our significant growth opportunities across our 5 core assets. Thank you, and I'll now hand back to Kevin.

Thank you, Anthony. Let me start yet again by acknowledging Anthony and his team for the excellent job they've done to position the balance sheet to support our growth plans. Now let's take a look at our assets, starting with offshore on Slide 25. The acquisition of Quadrant transformed the scale of our offshore business. The Conoco acquisition will take it to the next level. It's a strongly cash-generative business for 2019 EBITDAX of almost $800 million. Offshore Western Australia production costs have fallen 28% over the past 2 years to $7.30 per BOE. We have a high-quality portfolio of all premium production assets, near-field 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 26, we have a rich portfolio of short-cycle infill and tieback opportunities across the offshore business. Following the successful Phase 1 infill project at Van Gogh, the Board has approved FID on Phase 2. This will involve 3 dual lateral wells targeting undrained parts of the field with first oil targeted for late 2021. We are also assessing further infill drilling at Pyrenees. Our WA crudes from Van Gogh and Pyrenees are earning material premiums in the market to dated Brent as our ideal feedstock for very low sulfur fuel oil which is mandated under the IMO 2020 regulations to support marine emissions reduction targets. We recently sold the Pyrenees March lifting at a premium of over $30 a barrel to dated Brent, highlighting very strong demand from refiners for our product. Consequently, this makes Van Gogh Phase 2 infill a very high rate of return project as it is a relatively straightforward tieback to existing infrastructure. At Bayu-Undan, successful infill drilling increased liquids production by over 60% in 2019. With our joint venture partners, we're progressing upside opportunities for further infill drilling to extend the life of the field and optimize the period between production ending and Barossa starting up. We are looking forward to assuming operatorship of both assets at completion of the ConocoPhillips acquisition. Moving to Slide 27 and the Barossa project. We continue to make excellent progress towards FID, which we now expect in the second quarter following completion of the ConocoPhillips acquisition around the end of the first quarter. There is no change, however, to the expected Barossa first gas date in 2024. Our technical assurance processes are well advanced, and key contracts for the FPSO, subsea production system and gas export pipeline are all awarded. Evaluation of tenders for remaining packages is progressing well. Although I am bound by confidentiality conditions, I can't inform you that the Barossa and Darwin LNG partners are in advanced discussions to finalize the process agreement and toll for Barossa gas to support an FID decision. What I really like about Barossa is that it's a low-risk brownfield project with liquids and is positioned at the right end of the supply cost curve as a relatively straightforward offshore scope tied into an existing pipeline and LNG plant. On the marketing front, we continue to have discussions with multiple LNG buyers. However, the coronavirus outbreak has impacted our ability to have face-to-face discussions with various parties, which has resulted in a slowing down of the close-out of our marketing activities. On LNG prices, I believe they will improve even at the states that we're able to play in. The cost of supply will ultimately determine the longer-term floor. And right now, spot prices are significantly below the actual cost of supply. So although we will continue to seek to market a significant amount of our equity LNG before FID, we are conscious of not locking in too much volume at the bottom of the market. 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 some LNG projects, particularly greenfield, to slip which I believe will further strengthen LNG prices over the next few years. And while we are on LNG markets, I will remind you that more than 95% 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. Some of our long-term contracts are currently in price reviews. While I cannot comment on individual contracts, I will say that the scope for change is modest and limited by contract terms. Slide 28 addresses the disciplined process we have undertaken to assure that Barossa is a technically robust project ready for FID. Santos has worked alongside ConocoPhillips over the last few years to ensure that this project has been subject to a rigorous assurance and governance process, which we describe as 3 layers of insurance. The first layer is utilizing ConocoPhillips extensive corporate assurance processes as operator. I'd like to acknowledge the excellent job Conoco has done in getting Barossa FID ready. The second assurance layer is external reviews by independent experts such as IPA and RISC. And the third layer is our own project assurance process at Santos in accordance with our project management systems and processes. Consequently, I am confident that we are now technically ready to progress to FID. Moving to Slide 29 and Dorado. Following the very successful appraisal campaign in 2019, we are targeting a FEED entry decision on a Dorado liquids development in the second quarter. The appraisal campaign greatly de-risks future development of the field and confirmed high-quality reservoirs and fluids. The project is underpinned by a high-quality liquids resource of over 150 million barrels 2C. The shallow water depth and compact reservoir footprint allows for a relatively straightforward wellhead platform and FPSO development. A newbuild FPSO option would allow for initial production rate of up to 100,000 barrels per day. The preferred development concept is an initial phase of oil and condensate development followed by a future phase of gas export. The initial phase is expected to need only 8 to 10 wells. CapEx estimates are unchanged and will be refined during FEED, depending in part on the FPSO option chosen. Moving to Slide 30 and our onshore business. We have an integrated business across 3 states and the Northern Territory serving both domestic and export markets. I am proud of the fact that we are Australia's lowest cost onshore operator. Anthony showed you earlier, the significant cost reductions and efficiency improvements that have been delivered, onshore over the past few years. I'll focus more on the growth opportunities in the business, starting with the Cooper Basin on Slide 31. 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 a renewed focus on the rocks, is delivering improved reserves replacement as well as higher production. These higher activity well -- levels, combined with successful appraisal at Moomba South, delivered 183% 2P reserves replacement in the Cooper. This is the first time since 2012 that the Cooper has more than replaced its annual production, and this has been done within the capital constraints of our disciplined operating model which sees all assets free cash flow positive at an oil price of less than $40. Production is growing again as you can see in the chart, and we expect further growth this year. A notable milestone was hit in January when the Cooper achieved the highest daily gas production rate in almost 5 years. As David Banks spoke about at the Investor Day in December, we are adding 6 horizontal wells to the program this year. While this will reduce our overall well count compared to last year, we expect efficiency benefits in production rate and development costs. All of this means we are on track to our target of between 17 million and 19 million BOEs of production in the Cooper by 2025. Moving to Slide 32. What really excites me about the Cooper is the hopper of growth opportunities that are emerging now that we have significantly reduced the cost base of the asset. Moomba South is just the first of several large-scale project appraisal programs focused on resource to reserve conversion. Following the success of Moomba South Phase 1, which delivered an 18 million BOE 2P reserve add in 2019, we have taken FID on the Phase 2 development of a further 8 wells. And we have the emerging opportunity in the Granite Wash play, which flowed gas in the Moomba South appraisal wells and confirm the productive capacity of this new play. We expect to further appraise this play with 2 wells this year. We are also progressing projects in our Energy Solutions business including evaluating compression, electrification with renewables, which would free up more gas for sale and reduce emissions, gas that comes with no upstream risk and no decline curve. We're also working on further oil beam pump conversions to solar and batteries. Our CCS project has moved into FEED, as I mentioned earlier, and we also brought online a 2-megawatt solar project at our Port Bonython facility at Whyalla. It's a very exciting team for the Cooper Basin, and it's great to see so many projects emerging as a result of our lower-cost operating model and competing for investment capital. Moving to Queensland on Slide 33. We see a similar upstream cost discipline and efficiency story to the Cooper. This efficiency focus, combined with better-than-expected reservoir performance, has enabled us to increase our GLNG sales guidance to 6.2 million tonnes per annum from this year. I am pleased to say we have started the year well, and these are slightly above our target. I'd like to take this opportunity to thank our partners at GLNG, PETRONAS, Total and KOGAS, for their support over the last couple of years. Upstream production continues to build particularly at Roma as you can see in the chart on the top right. Another great example of our operating model in action is shown in the chart on the left. The team has done a great job of doubling the average time between well workovers over the past 2 years. Once again, I believe this is industry-leading performance. Development projects at Roma East and Arcadia are proceeding well with the final new compressor at Arcadia due online this quarter, and as the Santos disciplined approach to operations and development that we will bring to Narrabri, which I will touch on in the next slide. In New South Wales, the assessment of Narrabri gas project is continuing by the New South Wales Department of Planning, and we look forward to moving to the next phase. We expect a determination on the project in the first half of this year. We have already committed 100% of Narrabri gas for the domestic market should the project be approved. Gas customers are very keen for Narrabri gas to come into the market, and we've announced a number of gas offtake agreements subject of course to project sanction. Moving to Slide 35 and the onshore territory. In January, we were pleased to report a gas discovery in the Beetaloo Sub-basin. The discovery was confirmed following the successful completion of a 4-stage stimulation program in the Middle Velkerri shale gas play in the Tanumbirini-1 vertical well. Gas flow rates of over 1.2 million standard cubic feet per day were observed during production testing, which remains ongoing, exceeding initial expectations for the vertical well. Results from the stimulation program were very encouraging and an important step in our appraisal of the potential of the Velkerri shale in the Beetaloo Sub-basin. The well has provided critical data to inform the next phase of appraisal, which is expected to include the drilling and multi-stage simulation of 2 horizontal wells commencing in the first half of this year. We have also farmed into an extensive new operated exploration play in the South Nicholson Basin, which straddles the NT and Queensland border. We believe this play has multi-Tcf potential, analogous to the Beetaloo. Our position in these basins has a potential to support the domestic gas market and/or backfill and expansion of Darwin LNG. In summary, on Slide 36, our clear and consistent strategy to focus on long-life assets and generate sustainable free cash flows through the oil price cycle is delivering consistent and clear results. Record financial performance, good cost control, reserve growth at the Cooper, successful integration of Quadrant and the ConocoPhillips acquisition highlight a very good year for Santos. We are working hard to deliver on our promise to continue to transform, build and grow the company. 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]. Our first question is from James Byrne of Citi.

Kevin and Anthony, congratulations on the ongoing momentum in the business. I was hoping you might be able to help us reconcile your OpEx guidance here. So the normalized unit OpEx, you're effectively saying it's going to be flat year-on-year, and yet the message from the presentation is that all of your segments are continuing to improve, which is inconsistent with that guidance. So should I assume that something like volume then production decline against fixed costs in DLNG or one-offs like planned shutdowns are seeing that unit costs be higher than what's implied by your remarks on how the segments are actually performing?

Well, thanks for that, James. Look, I think, first of all, I'll hand this one over to Anthony. But just before I do, one of the things I would say is we don't -- year-on-year, we don't book -- we don't forecast savings until we can see line of sight how we're going to achieve those. But what we generally do across the business is continue to set targets for our operating divisions to continue to drive OpEx down. And year-on-year, so far, continue to do that. And so that's the philosophy we approach to our OpEx target setting across our organization. Maybe, Anthony, you want to add some color to that.

Yes. Thanks, James. Yes, look, I think from a normalized OpEx perspective, the way to look at it, as I said, we're aiming for around $7, which is consistent with this year. We're obviously guiding to that. We obviously are embedded in that. It doesn't include the Conoco acquisition of course. So we are going to have to update our OpEx guidance including the normalized post the Conoco acquisition. And yes, you're right with your comment around Bayu-Undan. It is a higher OpEx field that sits in that underlying OpEx as it declines. So it does drive some of the higher OpEx. It doesn't mean that our other operated assets aren't efficient and still getting savings.

Okay. That makes sense. Kevin, just picking up on your remarks around what you're seeing in the industry on cost pressure. Where is that manifesting? Is it labor, contractors, shipping rates, dislocation, supply chains, et cetera? And for how much longer do you think you can continue to outperform before Santos begins to see reflation in its cost base?

Well, look, James, I think there's a number of factors that drive that unit cost, and one of them is volume. So as we continue to drive volume up, I'd expect my unit cost to come down. And obviously, our forecast show a big volume increase in 2025. And I expect my unit cost to be significantly lower when we get to that point in time. In the meantime though, year-on-year, we continue to drive efficiencies and look for synergy benefits across our business. And I know that when we announce an acquisition such as the Quadrant acquisition or the Conoco acquisition and we talk about synergy targets, most people think that, that means head count. But in actual fact, we've made very significant synergy benefits by scaling up our business and being able to get better service arrangements with some of our larger contractors that work across all of our business, whether it be in the offshore business and the onshore business, and get rates that reflect the increasing scale of our business. We now have, I expect, the largest operating footprint of any oil and gas company in Australia with the number of assets that we operate. And that does give us the opportunity to drive better contractual arrangements. In terms of inflation, we have not seen any significant inflation across all operations because of some of the factors I just mentioned, but also because we didn't take the approach back in 2016 to slash and burn our contractors as a means of reducing costs. We work very closely and collaboratively with our contractors to find the innovations and the efficiencies that you've seen coming through across all of our operations. And that's been a big factor of our unit cost improvements, and we'll continue to try and do that.

Okay. Great. I wanted to now ask about East Coast gas markets. I think the equity market here is forming a view over the last few weeks that while gas producers are saying, we're largely contracted, a lot of our contracts are CPI-linked, et cetera, we're not really affected by low spot prices, I think the view that's forming here is that there is an indirect impact of low spot prices to producers that are contracted. And that manifests through DQT, so customers opportunistically flexing down on contracts, by cheapest spot. So I wanted to understand, to what extent are you seeing downward nominations in your gas contracts on the East Coast? And can you perhaps give us an idea of how you might be able to actually offset that by using things like your storage position and your trading to actually turn cheap spot prices into an opportunity?

Yes. Well, look, I mean, I think, first of all, I think in times of the low end of the price cycle, that highlights the need to be focused on a low-cost operating model. And I've always said and I've always maintained that in a commodity business, your only true advantage is you got a supply. And that's why we focus on that. That helps us maintain margins through the lower parts of the cycle. In terms of the DQT aspect of your question, no significant changes there. We've set our delivery plans for 2020, and we're on track to deliver those. And so they are set for the year, and we are working to those for this year, and we gave that guidance in December. And so we've seen no real impact there. Anthony, is there anything you want to add to that?

No. I think you're right, Kevin. It's our low-cost operations, but also the other point to note there, James, is even in the event of what you're saying, if it were to occur, we've got a great portfolio. We've got storage availability as well, so we can flex our portfolio with storage and push it to different parts of the year and phase it to where we want to sell it to as well. So I think we've got a lot of flexibility in our portfolio.

Our next question is from Joseph Wong of UBS.

Congratulations on a good result. One thing if I kind of look at is Narrabri. Can you provide an update on, I guess, the path to market? Earlier this week, AP had announced Western Slopes, but there are kind of different paths to market for that gas.

Thank you, Joseph. Look, there are different paths. And we are keeping all of them open at this point. There's a couple of different pipeline options, and there's some local customer supply options. And so we are keeping all of those options open at this point in time. Our focus really right now is just on the approvals process for the project itself. And so we don't want to preempt what that's going to be because we want it to be a very robust process. And as I said in my notes earlier on, we expect that to go into the next stage of the process very shortly and expect a determination on the project in the first half of this year. And so we're looking forward to that.

Yes. Okay. Maybe if I kind of move to Northern Territory. You mentioned, I guess, the success in the resource booking there. But what, I guess, haven't come across clearly is could the gas move into GLNG? Because I guess you mentioned the gas moving into NT? Is there an opportunity where it kind of moves east? Or the discussions on tolling, have they kind of, I guess, been eliminated now?

No. Look, I mean I think our view on the East Coast and the center, if you like, through Darwin, Northern Territory, is that it's moving towards a connected integrated system. And so we would look at -- depending on scale, the company needs scale. And that's what our appraisal program is going to test in 2020. But we talked and I speak earlier on about the South Nicholson Basin as well which we see analogous to the Beetaloo. There's been production in that area previously, and we've just assumed a large equity position across a large acreage play. And in South Nicholson, we'd look to test that over the course of the next few years as well. And of course, we've got increasing production coming from the Cooper Basin. And so we just see all of it as an integrated and connected network. And the reason we bought Darwin was not to get more of Barossa. It was for the future and the potential expansion opportunities we see at Darwin in the years ahead because of the large resource position, proven resource position both offshore and onshore in that region.

Okay. Maybe just one last question. If I kind of look at the carbon capture. Can you provide, I guess, how we should look at the economics? When you look at the Australian carbon credit unit, the price is around $14 to $15. I think you previously mentioned the cost for Moomba was about $25 a tonne. So just trying to, I guess, reconcile the economics of that as you move to FID by the end of this year.

Look, your numbers are right. And you can look at CCS in 2 ways. You can look at it, first of all, as a defensive play to protect our base business into the future. And if you look at it that way, you look at it as a cost. We look at it not only from that perspective but as a revenue-earning potential for the future. We believe that the cost of carbon will go up, and we're very confident the cost of our carbon sequestration projects in the Cooper will come down. And there's a point where that's going to cross over, and that's going to be valuable for us. We're working hard at all levels of government to encourage the accreditation of CCS projects in Australia for carbon credits. And we're confident that at some point in time, in the not-too-distant future, that will be the case. Article 6 of The Paris Agreement allows for bilateral arrangements between countries where you can trade credits. So companies that want to buy credits off of CCS projects or even invest in those projects can then be exposed to the credits or the value of the credits in their own country. And if I give you an example of Japan where those credits could trade for up to EUR 35 per tonne, that becomes very different economic equation. So we're very confident this will only go one way. And we've got an asset, because of the storage capability across the Cooper Basin, which we believe will be a very valuable asset in the future.

Our next question is from Mark Samter of MST.

Just a question for you, Kevin, I guess, all of us have listened to the results from AGM and Origin over the last week or so, and they both talked about the value of storage for gas. And to be honest, they don't have access to storage or they don't have gas to put into storage necessarily at times. If you look at something like Moomba's got -- for the JV has got about 50 PJs of spare capacity and storage. And I don't even know whether the spot cargoes going out of Queensland from the other projects, $2.50 FOB, you've got a Horizon contract from the Cooper that's selling into Gladstone. I mean are you -- have the ability to swap out a cargo of LNG and put it into Moomba? And if not, do we not feel like Moomba storage is under-earning like it should be in this market?

Well, look, I think -- thanks for that, Mark. And look, I think your point in storage is right. It's undervalued, and it's underutilized. We talked about the focus on infrastructure at our Investor Day in December and how we use storage is a big part of our focus. And there's a lot of work going on inside the organization right now to set our infrastructure -- or to sort of maximize and optimize the use of our infrastructure and how we get value from that infrastructure going forward. And look at it in a different way to how traditionally what we did -- our infrastructure as part of our integrated oil and gas assets. Storage is a big part of that. And there's a lot of work going on in that play. At this point in time, the storage transactions you're talking about can be quite difficult because there's multiple joint venture partners involved and all of that. And historically, we haven't thought that way. And I see initially, rather than sort of short-term reactions because the market is pretty soft in the LNG space right now, joint ventures probably would move too slow to take advantage of those situations. However, in the longer-term, strategies that involve the use of storage for such situations, I think, are very much part of what that needs to look like going forward.

Our next question is from Ben Wilson of Royal Bank of Canada.

I just had a quick question about Barossa as you head into FID. And specifically, your tolerance or objectives around forward LNG contract coverage before FID. Are you able to provide a sense of what you're thinking of that? And what's the minimum you'd look for before sanctioning that project?

Well, Ben, the conversations we're having with the various off-takers just now given me confidence that if I wanted to, I could contract all of our volumes. I just wouldn't necessarily want to, given where we are in the market today. And so previously, we've given some guidance. We'll continue to review that as we get closer to FID. And -- but what I would say, I'd still be wanting to contract significant volumes before taking an FID decision. And I think I said in my notes this morning that we've got to be careful or cognizant of not locking ourselves in at the bottom of the market. I think just as importantly is we don't want to lock ourselves out of upswings or the upside opportunities as the market rebalances and pricing strengthen. And so it's getting that balance right. And without putting a specific number on it, we still want to have offtake arrangements for a significant portion of our volumes in place by the time we take FID which as we said today is in Q2, targeting Q2. But I wouldn't like to put a specific number on it right now.

[Operator Instructions].Our next question comes from Saul Kavonic of Crédit Suisse.

A couple of questions quickly if I may. Just on the first one, is it possible to get an indication of what percentage of LNG sales out of Darwin this year linked to the spot market as opposed to contracted?

Zero, all contracted.

Great. That was easy. Second one is with regards to PNG. Oil Search have made an announcement a couple of weeks ago talking about a change of focus to development of Papua without P'nyang. Is this change of focus something Santos supports as a member of the joint venture?

Well, look, I mean, we'll have to go through those conversations within our joint venture, Saul. Obviously, the agreements we had in place in terms of tolling arrangements and stuff were all part of a 3-train integrated development. And so we'll have to revisit what all that looks like if we have a 2-train development because, obviously, in that scenario, we wouldn't have the same level of alignment that we had with the previous plans. But until this, we've got a clear sort of line of sight into what that looks like. There's not much more I can say at this point in time.

One quick last one. I just wanted to check, is there any update on Western Australia gas and the potential to see additional volumes or an uplift in prices through an export deal with North West Shelf.

Well, look, I mean, I think as you're well aware, we've got an awful lot of gas behind play, probably the lowest cost of supply gas in Western Australia that we would like to get to market. And the current spot market prices in the West are pretty low. Although I have to say, I'm very confident in the contract, the longer-term contract pricing in the West over the course of the next couple of years. And we sell some into the spot market, but predominantly, most of our gas in the West is on long-term contracts and at significantly higher prices than the current market spot prices. Look, we've been in discussions with any facility that either wants to look at gas swaps and/or tolling arrangements. But as we announced at our Investor Day in December, we're also doing concept studies at this point in time. And hopefully, that will lead to a FEED decision throughout this year, but concept studies at this point in time, at small-scale LNG export opportunities, where we're very confident we can have a very low-cost project that would give us additional export options if proved too difficult to get access through other people's facilities.

Our next question is from Daniel Butcher of CLSA.

Okay. I just want to sort of follow up on -- in WA. The Alcoa contract, I think, comes on in the second half of this year. And there's other contracts that are rolling off but maybe not quite as soon. So can you just confirm there's going to be a bit of bump in WA production in the second half? And have you had any luck in extending other contracts that might be rolling off since we saw you at the Investor Day?

I'll hand that one to Anthony because he loves talking about the Alcoa contract. So why don't you go ahead, Anthony?

So yes, you're right, Dan. So second half of the year, we will see a bump as the Alcoa contract comes on, and then that holds for a bit. And then you're right, some other contracts start to roll off in the short to medium term. In terms of contracting, I'll touch on it quickly. Kevin can add if I miss anything. Yes, we're constantly looking at contracting in the market. And we're in discussions on some contract extensions at the moment with existing suppliers.

Yes. Look, I mean, Dan, the reality, I think I've said it before, there's something like 50% of existing contracts up for renewal between 2020 and 2024. It's a very significant volume of contracts that are up for renewal. And we naturally are in discussions on some of those. And we're very confident that we're going to see stronger prices during that period. And across those periods, obviously, we'll announce things as we get concrete agreements in place. But you should see significant recontracting over the course of the next 2 or 3 years. Now I think we've got time -- Dan, if you had any more questions before we go.

Just one quick one, if you don't mind. I know we're short on time. Just one on Ben's question on Barossa, that 40%, 50% final interest in -- are you going to sell before or after FID, do you think, most likely, given the timing of discussions you've got so far?

Well, look, I think the sell-down would be on FID. So we'd like to have the arrangements in place pre-FID, but the -- our condition precedent, the deal would be likely FID. I think it's too difficult to try and complete all of these processes pre-FID. So in other words, we do the deals pre-FID, and we're in discussions on those now, but they would be subject to FID to complete. But I think the key message, as Anthony said earlier, is that in terms of going forward, we don't have to sell them, from a balance sheet perspective. I really want to emphasize that. The balance sheet is strong. And someone asked the question earlier about selling down in the West as well. And the reality is that until we take all our FID decisions, we don't want to kind of make all those decisions about what we sell and what we don't. We want to know what's in front of us, and we'll take those sell-down decisions at the right time and at the right point in the cycle, but there's plenty of interest in equity both in Darwin and Barossa. So there's no shortage. If anything, we'd be oversubscribed on the Barossa sell-down equity request at this point in time.

Sounds good. Look forward to seeing good price then or looking to it.

Okay. Thank you, Dan. And look, I think that's the last question. And again, I thank everybody for taking the time to join us this morning and look forward to catching up with many of you on our road shows over the next few weeks. Thank you very much.

That concludes today's call. Thank you for joining us. You may now disconnect your lines.