Thank you for standing by. Welcome to the Woodside Energy Group Limited Full Year 2022 Results Conference Call. All participants are in listen-only mode. There will be a presentation followed by a question-and-answer session. If you wish to ask a question, you will need to press the star key followed by the number one on your telephone keypad. I would now like to hand the conference over to Ms. Meg O'Neill, Chief Executive Officer and Managing Director. Please go ahead. Good morning, everyone, thank you for joining our 2022 full year results investor call. We are presenting the results today from Sydney, I would like to begin by acknowledging the traditional custodians of this land, the Gadigal people of the Eora Nation, and pay my respects to their elders past, present, and emerging. I also extend my respect to all other Aboriginal nations, the future generations, and their continued connection to country. As you would have seen this morning, we released our annual report and full-year results briefing pack to the market, along with our sustainable development report and our climate report. I would encourage you all to read these reports together as they provide a complimentary review of our business. I'm joined on the call with our Chief Financial Officer, Graham Tiver. Together, we will provide an overview of our 2022 financial, operational, and strategic performance before opening up the call to a Q&A session. Please take the time to read the disclaimers, assumptions, and other important information on slides 2 and 3. I'd like to remind you that all dollar figures in today's presentation are in US dollars, unless otherwise indicated. Moving on to slide 4. Woodside's strategy has delivered exceptional results in 2022. We transformed the company through the completion of the merger, which has provided increased scale and resilience and further strengthened the balance sheet. The addition of the Heritage BHP assets and the expanded global portfolio, coupled with strong operating performance and strong market conditions, are key drivers in delivering record net profit after tax of $6.5 billion. We have backed out some one-off items, which Graham will touch on later, to deliver an underlying profit of $5.2 billion. The directors have determined a final dividend of $1.44 per share, fully franked. This represents an 80% payout ratio of the second half underlying NPAT. The total full-year dividend is $2.53 per share, meaning we are returning $4.8 billion to shareholders at a full-year yield of over 10% based on Friday's closing share price. The outstanding performance from our business has set us up well to continue investment in oil, gas, and new energy projects. We are investing in a range of commodities for the next wave of growth and are fiscally well-positioned for this period of higher capital investment. Our 2022 performance speaks to the strength of the business, our ability to deliver results today, deliver projects for tomorrow, and return value to shareholders. Slide 5 provides an overview of key metrics underpinning our strong operational performance and how this translates to strong financial outcomes. In 2022, we achieved production volumes of 157.7 million barrels of oil equivalent, a record for Woodside. This includes production from the Heritage BHP petroleum assets for 7 months of the year. Operationally, we delivered outstanding performance in our operated LNG assets, averaging reliability of 98.5% from Pluto LNG and the North West Shelf project. We also delivered value from the Interconnector with 9.8 million barrels of oil equivalent produced at a time the world needs more LNG. Our unit production cost increased, impacted primarily by the inclusion of BHP Petroleum business and the Interconnector tolling fees. We had strong underlying cost performance in an inflationary environment. The realized price of $98.40 per barrel of oil equivalent reflects strong global demand for our products and the benefits realized by our marketing and trading business. This has translated to $16.8 billion in revenue and $6.5 billion of free cash flow. Our significant free cash flow is after investing $4.2 billion in the business and enables us to pay a healthy dividend. The free cash flow also allowed us to reduce gearing to ensure a strong balance sheet given our upcoming capital commitments. Moving on to slide six. We have now achieved the goals we set ourselves ahead of the merger, delivering initiatives expected to realize over $400 million per year of post-merger synergies. We've delivered subsea tieback and improvement projects across our Western Australian LNG assets and Gulf of Mexico assets, continuing to keep the plants full. On the sustainability side, we achieved an 11% reduction against the starting base in net equity scope one and two greenhouse gas emissions and are on track to achieve our 2025 target. Higher profits have translated to higher tax and royalties paid to the Australian government. For 2022, we paid a record AUD 2.7 billion, up 311% from our 2021 payments. We continue to advocate for a stable tax and fiscal environment in order to incentivize the large long-term investments that support energy security, decarbonization, and economic growth. Slide 7 summarizes our safety performance. Disappointingly, we failed to improve on our safety outcomes of 2021, with our total recordable injury rate increasing to 1.8 per million work hours. Environmental performance has been good, with just one tier 2 loss of containment events recorded in the first half of the year, which resulted in no impact on the environment. Safety is central in everything we do, and we've made it an imperative to return to leading performance in 2023. Slide 8 demonstrates the changing price environment over the last two years. The landscape has changed as energy security and affordability are now at the forefront of the energy challenge faced today. Even before Russia's invasion of Ukraine, we were seeing market volatility increasing, with the invasion accelerating the rerouting of energy flows and contributing to volatile energy prices. There are growing concerns over the amount of supply available to meet immediate demand, which is contributing to price volatility in the market. Slide nine demonstrates how we were able to capture value in these conditions. We actively positioned our portfolio through the year to realize the benefit of higher commodity prices, utilizing our expanded global marketing presence and trading capability. Our trading team optimizes the value of our produced LNG, supplemented by the trading of third-party cargoes. The realized price for this third-party LNG was $166 per barrel of oil equivalent, more than doubling from the prior year. The price achieved for our produced LNG benefited from our planned exposure to gas hub indices, which was 23% in 2022. For this coming year, we are targeting to sell approximately 20%-25% of our produced LNG on gas hub pricing. We were also fortunate to bring the Interconnector online at the right time, which enabled the delivery of almost $1.2 billion of incremental revenue. Slide 10 shows Woodside's dividend performance over the last five years. The final dividend of AUD 1.44 per share has been considered and balanced against our capital commitments over the coming years. We are pleased to return AUD 4.8 billion of value to shareholders, being the AUD 2.1 billion interim dividend and the AUD 2.7 billion final dividend, while protecting the strength of the balance sheet. We have made very good progress on our major projects in 2022. Slide 11 summarizes our activities on the Sangomar field development in Senegal. 2022 was a great year as we progressed the project in preparation for targeted first oil later this year. We completed construction of the FPSO vessel and all sub-sea equipment. The drilling program continued, ramping up to 2 rigs. We commenced installation of sub-sea infrastructure. The FPSO has been relocated to Singapore, where it will complete topside integration and pre-commissioning. The image on the right of this slide is a close-up of the turret, which really gives you an idea of the scale of the project which we are undertaking. We will spend 2023 finalizing the execution activities and preparing for startup. First oil is expected in late 2023. On Slide 12, the Scarborough project is progressing across all work streams. We have commenced fabrication of all major facilities, including the offshore floating production unit topsides and hull, the Pluto Train 2 modules, sub-sea facilities, and the trunk line. Fabrication of both Scarborough and Pluto Train 2 is progressing well and will continue through 2023. Site works have commenced at the Pluto LNG site. In parallel, we are progressing the secondary approvals needed for certain offshore activities. Slide 13 highlights some changes in the Australian regulatory environment affecting our activities on the West and East Coasts. There have been some changes in offshore approval requirements, which require stakeholder consultation over a more extensive area. We have clear plans to consult in a manner aligned with the new requirements and are progressing those consultations. Our project execution schedules have been adapted to enable more extensive consultation. We do not anticipate an impact on first LNG from Scarborough, which remains planned for 2026. Regarding the intervention in the East Coast gas market, Woodside is supportive of the government's objective of access to affordable and reliable energy. We believe, as a supplier of energy, that increasing supply is the most effective way to address these issues in the market. Slide 14 demonstrates the breadth of projects that Woodside has across the oil, gas, and new energy commodities. You can see that we have a strong mix of sanctioned projects and a healthy pipeline of future opportunities. Our focus is on executing these sanctioned projects safely, on time, and within budget. For 2023, we are targeting final investment decisions on Trion and H2OK. Of course, a decision on sanctioning new projects must be made in line with our capital allocation framework, which is shown on slide 15. This framework is unchanged from what you've seen before, but it is always important to reiterate in the context of our pipeline of opportunities. We have to be disciplined in our investment decisions, which are guided by our targets for expected return, in addition to how they fit within the overall portfolio. Our corporate emissions reduction targets do not change with new investments, which must include the cost of abating incremental emissions. I'd now like to move on to Trion on slide 16. Trion is a deepwater development in the Mexican waters of the Gulf of Mexico. Trion provides us with the opportunity to leverage our deepwater Gulf of Mexico experience. The semi-submersible floating production unit would have a production capacity of up to 100,000 barrels per day of oil. The initial field development would include water injection and gas injection. We're very excited about Trion. The technical work is well advanced, as is the execution planning. In 2022, we completed front-end engineering design or FEED for the floating production unit. We issued key tender packages. We are now evaluating the responses. We expect to select the FPU contractor within the first half of the year ahead of an FID decision. Moving on to slide 17. We are also targeting a final investment decision on H2OK in 2023, which would be our first major new energy project. H2OK is a hydrogen opportunity in Oklahoma in the United States. H2OK is well-positioned given its proximity to a strategic transport and supply chain corridor in the US, close to customers who wish to adopt hydrogen as a fuel in the heavy transport sector. The potential fiscal incentives of the Inflation Reduction Act represents an opportunity for our H2OK project. In 2022, we completed front-end engineering design activities. We have awarded contracts for the electrolyzers and liquefaction equipment and will continue to progress approvals and customer offtake agreements in support of final investment decision readiness. On slide 18, we are delivering on our scope one and two targets, which have also now been expanded to the merged portfolio. Our Heritage Woodside-operated assets have identified plans for potential decarbonization opportunities, and if all our opportunities are implemented in full, this could result in a 300 kiloton of CO2 equivalent reduction in emissions in 2030. For 2023, our focus is on extending these plans to the Heritage BHP assets. On slide 19, we are also making progress on our investments in new energy and lower carbon services. We've now spent $100 million towards our new energy target, which is to invest $5 billion by 2030. We expect spending against the target to ramp up over the coming years as the market for these products grows and we progress projects into the execute phase. I'll now hand over to Graham Tiver to discuss our financial performance in more detail. Thank you, Meg, and good morning, everyone. Starting off with slide 21. Across the board, we have achieved very strong financial outcomes in what has been an outstanding year. This is driven by higher operational reliability, higher prices, coupled with the active positioning in the market from the marketing team, the contribution of the former BHP assets to the portfolio, and the Pluto-KGP Interconnector. We've delivered record shareholder returns while retaining flexibility to meet our capital commitments and deliver future returns against the backdrop of global volatility. Returning value to shareholders is important to us, as is delivering the next phase of growth. Moving on to slide 22. We continue to deliver in line with our capital management framework, which you would be very familiar with. Our ability to generate cash and remain resilient through the price cycle is demonstrated by our high operating cash flow of $8.8 billion for 2022. We are also putting this cash to use across oil, gas, and new energy projects with investing cash flow totaling $4.2 billion. When we exclude the positive impacts of the merger completion payment and the contribution from Global Infrastructure Partners for Pluto Train 2, our three boundary conditions, which are outlined at our investor briefing day last year, have been met. First, our ability to meet our investing expenditure commitments, mainly Scarborough and Sangomar. Second, our investment-grade credit ratings were reaffirmed during the year. Third, our final dividend of $1.44 per share represents a payout ratio of 80%, which is at the top end of our targeted range. This represents a full year dividend yield of over 10%. While gearing for the period was 1.6%, it is important to note that if the final dividend was added to the end of the financial years or the financials, I should say, the payment would have the effect of increasing the year-end gearing to 9%, which is just outside of our targeted range of 10%-20% through the cycle. We may at times sit temporarily outside of this range, the low gearing provides us with the flexibility for future uncertainty, which is important when we consider the current volatile price environment as well as upcoming capital expenditure and future shareholder returns. Slide 23 shows the movement in our net profit. Each bar represents the increase or decrease in each category compared to 2021. The two largest increases are due to price and volume, with the combined effect of these two columns totaling over $9.8 billion. The boost to volume is primarily due to the contribution of the BHP assets post-merger, and the boost to price was primarily higher realized prices across all markets. The other positive contributor to income was the completion of the sale of Pluto Train 2 to GIP, which was completed in January 2022. The increase in the cost of sales is driven by changes to the business. This includes the cost of operating the BHP assets, which includes depreciation, higher royalties and excise linked to higher prices, and finally, the startup of the value accretive interconnector. Other costs are predominantly made up of the hedging losses, which were put in place for two reasons. First, to provide downside protection to the balance sheet, second, to lock in positions on our Corpus Christi contract. We also incurred significantly higher income taxes and PRRT as a result of the increased income. The BAR does include a credit of approximately $1.4 billion relating to the recognition of an increase in the Pluto PRRT deferred tax asset. This simply represents the recognition of additional off-balance-sheet credits available to Pluto, which reflects the strong 2022 profit and future view of profitability. The underlying NPAT figure removes the one-off impact of the merger transaction costs, the benefits of derecognizing the Corpus Christi onerous contract provision, Wheatstone impairment reversals, the Pluto PRRT DTA, and the Orphan Basin exit costs. As a result, we achieved an underlying NPAT of $5.2 billion, which is used as the basis for the dividend calculation, being a fully franked dividend equivalent to $1.44 per share. As Meg mentioned, this represents a full-year dividend payout of $4.8 billion. Slide 24 shows the 5-year comparison of operating revenue, EBITDA, and underlying NPAT. As outlined previously, the merger and market conditions, along with strong operational performance and the Pluto-KGP Interconnector, were key to driving increased profitability. Our underlying NPAT of $5.2 billion is our best full-year result ever recorded. Slide 25 demonstrates the cash generating capacity of our operations. Both the operating cash flow of $8.8 billion and free cash flow of $6.5 billion on this page include the impact of a collateral payment of approximately half a billion dollars against hedging activities. We are expecting to receive our money back in the second half of 2023. Without the collateral payments, operating cash flow would effectively been $9.3 billion and free cash flow would have been $7.1 billion. As mentioned, the statutory investing cash flow of $2.3 billion is positively impacted by the benefit of the $1.1 billion in cash received as part of the completion of the merger and the capital contribution by GIP to Pluto Train 2 of $0.8 billion. The key underlying drivers of the increase in investing cash flow are the project execution costs for Scarborough and Sangomar. Moving to slide 26. Unit production cost has increased. Underlying cost performance remains strong despite inflationary pressure. The addition of the BHP assets and the interconnector have added to our production cost base. We've included a waterfall highlighting the changes. Whilst the interconnector has contributed to unit production cost, it has delivered substantial value with incremental revenue of almost $1.2 billion. We are managing inflationary pressure on our assets and will continue to keep this in focus. The $0.50 cost increase is primarily driven by the Wheatstone turnaround and planned cyclical maintenance at Pluto. It is worth noting the unit production cost is also consistent with our pre-merger expectations of approximately $8 per barrel of oil equivalent, as outlined in our merger documentation. Slide 27 demonstrates the resilience of our gross and cash margins. Our margins have remained resilient through the price cycle, the cash margin averaging approximately 80% over the last 5 years. This demonstrates the quality of our portfolio and the continued benefit of the merger. Slide 28 shows our 5-year liquidity and 10-year debt maturity profile, both of which speak to our strength of the balance sheet and our preparedness for the upcoming committed capital expenditure. Our liquidity remains high at $10.2 billion. When we think about this figure in the context of the $6 billion-$6.5 billion of CapEx, which we have forecast for 2023, we are well covered. Our debt maturity profile has minimum near-term maturities, our low gearing of 1.6% provides additional flexibility for future uncertainty. Our net debt position is strong at under $600 million. With this robust balance sheet, I am confident of our ability to meet our investment expenditure commitments and continue to return value to our shareholders. Slide 29 demonstrates overall tax contributed to the Australian government. This isn't a non-cash number. This is genuine cash paid to the government in the form of a number of different taxes, which are listed on the right-hand side of the chart. This is a record tax contribution for Woodside. Taxes designed to capture the upside, like PRRT, are working. With top-up payments resulting from our 2022 full year profits, we can also expect our 2023 tax contribution to continue to be strong. We are proud of the contribution that we make back to the Australian economy. This demonstrates that high prices do translate to higher taxes paid. I'll now hand back over to Meg. Thank you. Thanks, Graham. I'd like to close by providing a quick overview on how market demand remains resilient across our products, as shown on slide 31. It's clear that the global energy transition can take many pathways. What the last two years has demonstrated is that the energy transition is unlikely to be a smooth, linear progression. An enormous amount of investment is required in all forms of energy in the coming decades to meet demand under these scenarios. For example, analysts such as Wood Mackenzie expect global LNG demand to grow by more than 60% in volume between 2021 and 2040. More LNG projects will be required to ensure adequate supply from the late 2020s. Woodside is positioning itself with opportunities across these three products and remaining prepared to supply the world with the energy it requires. Slide 32 lists our key priorities for 2023. First, in our core business, we need to focus on safety performance, an imperative for maintaining high performance in both day-to-day operations and when executing maintenance campaigns. Whilst the merger is complete, there are a number of integration activities such as integration of systems and SOX compliance. Second, in our major projects, we will look to continue to safely deliver Sangomar and Scarborough. We will continue to progress opportunities that deliver value to shareholders consistent with our capital allocation framework. Following the merger, we have the benefit of a broad set of potential investment opportunities, and we will be disciplined and selective in moving opportunities forward. Third, we need to progress our decarbonization opportunities, extending the asset decarbonization plans to Heritage BHP operating assets. We also need to mature our new energy growth opportunities. All of these priorities support our strategy to be a low cost, lower carbon, profitable, resilient, and diversified supplier of energy. We are delivering today and intend to deliver these priorities. The whole organization is focused, and we are excited about the year ahead. We will now open the question and answer session. Thank you. If you wish to ask a question, please press star one on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star two. If you're on a speakerphone, please pick up the handset to ask your question. Your first question comes from Tom Allen with UBS. Good morning, Meg, Graham, and the team. The presentation references higher CapEx incurred on Scarborough and Sangomar. Can you please provide some color on the magnitude of that and which work packages you see in that pressure? Also share some color, please, on how the Australian offshore regulators expanded consultation requirements might impact the drilling schedule or costs generally for Scarborough over the next couple of years. Thanks for the questions, Tom. When we said a higher CapEx for Scarborough and Sangomar, that was 2022 versus 2021. I know there is a lot of concern about inflationary pressures. What we're seeing in both of these projects is they are both tracking to the FID spend. Sangomar, as we noted, is working towards first oil later this year. Scarborough, we continue to execute. We're about 25% complete, and we do expect Scarborough to remain on budget. The comment on higher CapEx was really a year-on-year comment. The consultation requirements, as I noted in the pack, NOPSEMA has provided the market with guidance on what is expected. The court was very clear in their ruling around the sorts of activities that proponents need to be providing to, you know, relevant parties. We have put together a very detailed consultation plan that aligns with that guidance from NOPSEMA, and the team is off executing it. We've done a number of things to provide ourselves with a bit of additional flexibility in the schedule, so we do not anticipate any impact on Scarborough activities that would affect the first LNG, which we remain targeting for 2026. Okay. Thanks, Meg. If I can please just ask one another question on the capital demands on the business. Is Woodside still assessing, let's say, mid-cap sized acquisition opportunities that could extend your Gulf of Mexico exposure? And in some cases even bring about perhaps an onshore shale exposure in the U.S. Just keen to understand whether that's still a live assessment and something we should be considering when looking at the broader capital demands on the business for the year ahead. Sure. Of course, we remain open to M&A kinds of opportunities, and we are quite interested in continued growth opportunities in the Gulf of Mexico. Nothing to signal beyond that. You know, you'll note that we have been doing a bit of exploration work, and we do have more exploration planned. We picked up some blocks in the most recent lease sale in the Gulf of Mexico, so we're looking at both organic and inorganic opportunities there. If anything comes to fruition, we'll let you know. We will remain very cautious about onshore opportunities. You know, I think, when you look at the capabilities of Woodside, we're an organization that's really well designed for the risk and the capital intensity associated with offshore. We remain a bit cautious around the onshore. The majority of that is driven by the additional five months of depreciation of the BHP Heritage assets. You'll also see the breakdown in there of the change in the application of the depreciation. The added production is coming from assets that are relatively low 1P reserve base and low. Assets that will be depreciated on a 1P basis. As you would expect in those sorts of assets, you know, the unit depreciation rate is higher. The positive, of course, is that as you do infill drilling, for example, and continue to deplete. Continue to develop the full 2P resource, that additional resource comes in with limited incremental unit depreciation cost. Yeah. Cool. Thank you. Can we just roll that into how we're thinking about, and then you said, you highlighted today since we've been having gearing would it be, I've lost the page, was it 80% or 90%, take into account the final dividend. If we look back at the chart you gave us at Investor Day on free cash flow pre-dividends through the course of this year, I mean, if you mark to market for the current futures curve in JKM, I think that would have you free cash flow negative this year. By the time we get to the interim dividend, the FY23, the gearing should be well and truly within that 10%-20% gearing range. Can you talk through how you think about, A, do we think still 50%-80% despite the change in depreciation policy is a sensible number we should base it off? And I guess at both ends of that range, I don't wanna frame this as a negative question. What would you need to see happening to pay out more than 80%? What do you think we would need to see for you to think about reducing that payout ratio below the 80% that has been the standard for so long? Well, thanks for the question, Mark. As you know, our capital management framework's been unchanged for a period. There are a few things that are really fundamental for us. First off is protecting investment-grade credit rating, and we're very pleased that the ratings agencies have reaffirmed our strong credit rating over the course of the year. The second thing that's important, and we hear this quite consistently from our shareholders, is the way they value our dividend. We've done extensive modeling to understand our ability to pay out, and the dividend policy remains very firm at that 50% payout ratio as the policy. Of course, we've been paying out at 80% for the last few years. The market conditions this past year and the profitability of the business allowed us to pay out at that 80% in this full year results. You know, as we play the year forwards, as Graham noted, we do have significant capital expected for this year. As the Scarborough project continues into next year, we'll have a significant capital investment there as well. You know, assuming Trion and Oklahoma FIDs are successful. We just need to continue to have that disciplined approach to ensuring that we protect the balance sheet. The greatest thing ever. When we think about that pretty precipitous drop we've seen in JKM, do you tend to think that just the lower earnings from that is a balancing factor enough? Or do we think as that macro potentially worsens, and it could swing back the other way, do we think you need to be more prudent, assuming a much lower level of JKM persists for a while than thought before? Or do you think just the 80% of a smaller number compensates for it? Yes. Mark, I think it's probably worth highlighting that whilst JKM has fallen from its heady levels of last year, it's still at levels that are well above historic. You know, $15 JKM is pretty attractive. Three years ago, we would have been ecstatic to be at that pricing level. You know, as I said, we model a variety of price forecasts going forward. We test our ability to pay out, and we feel comfortable that the 50%-80% range of payout is still appropriate, as long as we, you know, also keep our eyes on that gearing ratio of the 10%-20%. We're well positioned this year, but we do have a period of significant capital ahead of us and, you know, that's why we've been, I think, quite prudent in balancing the desire to give shareholders good returns this year with protecting the balance sheet and the ability to invest. I think, Mark, it's worth pointing out, you know, that testing of the scenarios, we see the balance sheet as still quite resilient at our low price scenario as well. We're comfortable where we are today, but we are conscious that times are quite volatile. We do see ourselves resilient at the low price. Yes, absolutely. Thank you. Sounds very sensible to me. Might as second one really last quick question if I can. Probably a bigger picture one, Meg. If we think, yeah, broadly about the business in its biggest form, Scarborough largely offsets the declines in LNG production you'll see from Northwest Shelf and Pluto, broadly-ish. It will be without new projects mentioned or M&A, it'll be pretty much 65% of the reserve base by the time it starts. When you think about the rest of the business, and let's say Trion perhaps does an FID for whatever reason, do you see the need to replace reserves and keep a business of scale outside the LNG portfolio? Or is there a scenario where Woodside just becomes ever more an LNG business, and you're happy for the rest of the portfolio to be in runoff mode? Mark, one of the things that we do extensively is take a look at scenarios around how the world's energy mix might change over time. It's probably shown on that slide 31, that's got those graphs on it. Which shows that in all scenarios, oil continues to be an important part of the energy mix for the next 30 years. Gas is important. Whilst our foundation is LNG, the BHP Petroleum acquisition really does give us a lot of strengths in the oil side of the house. We are open to continued investments in all three of these commodities. We'll continue seeing what opportunities are out there, but we need to be disciplined about progressing those opportunities. You know, I think we're open to a variety of investments. We're pleased with our LNG position today. Scarborough will allow us to continue to have a strong LNG position into the future. Opportunities beyond that, we're looking across all three commodity types. Brilliant. Thanks. Thanks, Meg. Thank you. Thanks, Mark. Your next question comes from James Byrne with Citi. Good morning. Two questions. Firstly, PRRT related. Slide 29, Graham, you came out almost preemptively swinging on any sort of higher taxation in the future. I'm wondering, are you aware of any potential changes to PRRT that could be coming up in the May budget that would, you know, sort of see you put out a slide like this that really defends your position of paying higher taxes during higher commodity prices? Meg O'Neill, you're obviously, you know, very involved with APPEA. Are you sort of lobbying against PRRT actively at the moment for changes? James, I think we've been really consistent in our public messaging for a very long period, which is, for us to make the big investments that we make, which pay out over or generate revenue over 20 plus years, we need stable fiscal and regulatory regime. The fiscal framework with PRRT has been in place for decades. The federal government has had a number of reviews of the PRRT. Part of why we had that slide in there is just to help communicate more effectively that when Woodside is profitable, many of our shareholders benefit. Our shareholders benefit, and the government of Australia benefits. You know, AUD 2.7 billion is really a phenomenal contribution. If you think about how far that stretches in terms of, you know, aged care, education, infrastructure investments, you know, we're a very significant contributor to Australia. The investments that we're making in things like Scarborough will allow us to continue to make that sort of significant financial investments for decades to come. Okay. Second question then just around are these secondary approvals for Scarborough. Are you able to say what court cases there are outstanding against the project? In that context, when you do your workshops with NOPSEMA, you know, do you feel really comfortable that you're aligned with NOPSEMA to get those secondary approvals? If we saw a Barossa style delay to Scarborough and the rig was idle, I'm also wondering how expansive your contingency budget is at the moment to absorb any delay to the project. Okay. That's a wide range of questions there, James. Look, I'll start with the facts. Outstanding court cases, we have two. One is in the Supreme Court of Western Australia, it was from CCWA related to Pluto LNG Train 2 construction. The hearing on that matter was heard in August, and we're awaiting an opinion from the courts. The Australian Conservation Foundation commenced proceedings last year related to Scarborough environmental approvals broadly. That matter continues to progress through the court system. When it comes to NOPSEMA, we have a very active discussion, and NOPSEMA has been very forthcoming publicly and with a number of proponents on how the results of the Barossa court case influence their thinking when they're reviewing environmental plans. For Scarborough, we have 3 environmental plans that we're progressing. Three related to Scarborough: 1 for seismic, 1 for drilling, and 1 for the pipeline installation. As I said in my opening remarks, we are consulting in accordance with a consultation plan that aligns with that NOPSEMA guidance. It's a much broader consultation than we historically would have performed. We are getting after it. The team's got a lot of enthusiasm and is out talking to a wide variety of potential relevant persons. We've got flexibility in the schedule to be able to accommodate this longer consultation period. As I said, we remain on track for first LNG in 2026. Thank you. Your next question comes from James Redfern with Bank of America. Hi, Meg, Graham. Good morning. I guess question's going to follow on from Mark Samter's question, just around the dividends. I mean, the presentation, you know, the last 12 months referred to special dividends and buybacks, in, with regards to increasing shareholder returns. I guess the Prudence or conservatism you're showing today suggests that we should not be assuming any special dividends or buybacks in the foreseeable future, given the oil price outlook and also the CapEx commitments coming up. I guess the best we could expect is the 8% dividend payout ratio, which is fine. Did just want to sort of check that that's consistent with your thinking. That's the first one, please. Thank you. Yeah, thank you. Look, the way we look at it at a point in time, at the time of assessing the dividend and declaring the dividend. It's a bit early to call that out just yet. I guess where we are today, with the dividend at the 80%, it takes into account two things. One is the CapEx that we have in front of us and nothing new there, the $6 billion-$6.5 billion. I guess the market volatility and how the overall market's playing out as well. When we get to the half year, we'll be making the same assessment. We'll be looking forward, looking at the global economic scenarios, how our operations are performing. We'll be looking at it in the context of how our capital, programs are playing out. I certainly wouldn't be in a position to say there'll be no additional returns in any shape or form moving forward. We'll make that point. Well, that decision at that point in time, based on the overall performance of the business and global macro. James Okay. I think it's important to keep that really front and center in our capital management framework. Just to remind the market that we do have additional tools at our disposal. If the market conditions allow us to use some of those tools, we're prepared to. At this point in time, as Graham noted with the capital spend ahead in the next year plus, we're being prudent. Yeah, no, I understand. Thank you. The second question is just a housekeeping question with regards to Sangomar. If we assume first production later this year, the expected plateau production is about 75,000 barrels a day. Just wondering, how quickly do you think Sangomar will ramp up and to that 75,000 barrels a day? How quickly would the ramp up be? What are you assuming in terms of that plateau production in terms of years? Thank you. Thanks for the question, James. What we've said, I guess just to make sure we're all on the same page, is that we expect first production in 2023. For purposes of the production guidance, we've not assumed anything material in the production guidance for this year. In terms of the pace of ramp up, that's something that we are working on. It'll depend a bit on how we manage the flow assurance. This is a deepwater development with pretty complex subsea infrastructure. It'll be ramped up, you know, over the course of a few months. Plateau, you know, I think we'll want to reserve commentary on plateau period until we get a bit more confidence in how the reservoir is going to perform. We've certainly modeled it, and we'll put out production guidance at a point that's appropriate in time for that particular asset. Okay. Thanks, Megan. Appreciate it. Your next question comes from Dale Koenders with Barrenjoey. Morning, Meg O'Neill, Graham Tiver. Just, I guess, going back to prior questioning, the free cash flow outlook you presented for the business at the Investor Day, was just under $1 billion or thereabouts in 2023 and about $4 billion in 2024. Before thinking about a couple billion dollars for Trion and H2OK CapEx. Oil price has fallen off. Can you just confirm we are right to think about a negative free cash flow this year at current forward curves before thinking about dividends and probably more break even next year? Is that the right way to think about the business? So Dale, the 23 or the free cash flow graph that we put forward, an indicative position of the future at the IBD, was using forward curves, and it does take into account the drop in prices. However, you know, I would just point you back to the overall strength of the balance sheet, our overall gearing and the flexibility we have. We have the ability to be able to continue our capital programs, in particular Scarborough and Sangomar, and we have the ability to continue to maintain strong shareholder returns into the future. The balance sheet is in great shape. Yes, cash will be lower this year because of the CapEx spend, and there has been a drop in prices. We think we've captured that. As I touched on, you know, we, with Mark, our low price sensitivity analysis does prove that, you know, we can robustly get through 2023. How do you think about the preference between maybe pulling back your dividend payout to 50%, restarting the DRP or delaying FIDs? Yeah, look, once again, it's similar to what we answered to James. We'll assess that at the point in time of making the decision on the dividend, looking at the overall balance sheet, global macro trends, performance of the business, Dale. Every time we have a discussion with the board on capital management, these are the kinds of conversations we are having on how we set the business up and how we distribute shareholder returns. Okay. Then just finally, can I check my math? It looks like Greater Enfield Gas 2P reserve downgrade in the order of 200 BCF. can you talk through that? Is that Wheatstone? We'll have to follow up with you on that, Dale. Okay. Thanks. Our next question comes from Saul Kavonic with Credit Suisse. Hi, team. Hope the connection's okay. I'm just calling from overseas. A quick question on the Sangomar drilling results that were referred to there as part of which factored into some of the reserves changes to Sangomar. Can you give us an update on what those latest drilling results, what they are, what the implication is for Sangomar, and particularly Sangomar phase two, if there's any read-through for that? Yeah, great question, Saul. The phase one results actually have been really close to prognosis throughout. The only well that I think we commented on specifically was one of the exploration wells, which was this SNE North, number two well, which was a potential near field tieback opportunity. And that encountered gas and we abandoned it as was part of the initial drilling plan. We'll continue to assess whether or not there's opportunity there. As we've talked about from the beginning with Sangomar, there's, you know, two main reservoir horizons that we're targeting, the S500 sands. As I said, the drilling results there have been coming in really close to prognosis. That's the, call it the sweet spot of the field. We've got the S-400 sands, which are laterally extensive, high in place, questions about connectivity. We won't be able to really understand phase 2 until we get some of that dynamic data, particularly in the S-400 section. It's still open questions around what phase 2 would look like. If you look at, you know, our kind of history in fields like this, I would fully expect that there will be infill opportunities and there will be future phases of development. We do need that dynamic data to figure out exactly what those look like. Thank you. One more, I guess following on from a lot of balance sheet questions, but perhaps I'll just ask quite a specific one. I guess, is Woodside willing to go above its 10%-20% gearing target for a single year in a high CapEx year in order to kind of smooth out and maintain an overall dividend payout? Is that something you'd consider, you know, for, you know, particularly the 2023 year? Yeah, absolutely, Saul. You know, I think Graham described it well by talking about us being on the low side of the range this year. You know, if we'd paid out the dividend last year, we would've been at 9%. The 10%-20% is a gearing target range through the cycle. There may be periods where we fall below, and there may be periods where we go above. I would use that as a soft guardrail, not as a hard limit set. Thank you. That's all for me. Thanks, Saul. Your next question comes from Mark Wiseman with Macquarie Group. Good day, Meg. Good day, Graham. Thanks for the update. I had a couple of questions. One on the Bass Strait, in the context of the government intervention. I was just wondering if you could provide a bit of an outlook for the investments in the Bass Strait and the reduction in capacity at the Longford gas processing plant. Could you maybe just help us understand how much of that capacity is gonna be, you know, permanently closed in terms of gas processing? Just on the government consultation piece, are you able to provide a bit of color just on how those discussions are going? Are you getting more confident that the government is, you know, realizes the impact that they are having on the market and, you know, perhaps could we end up with a more reasonable outcome here? Well, thanks, Mark. Bass Strait, there's probably a few projects to talk about. You'll be aware that the joint venture, and this was pre-merger, sanctioned the Kipper Compression Project. That was sanctioned in October 2021, targeting RFSU in 2024. That project is underway. When you step back and look at Bass Strait in aggregate, we are in a mature basin. These fields are mature and production is declining. We're working very closely with the operator to define projects to ensure we have the capacity that fits the production that's flowing through it, to make sure that we're managing the cost of running these assets. You know, obviously we'd be keen to continue to bring new gas to market in the East Coast of Australia. You know, you'll be aware we were looking at some opportunities for bringing LNG across. With the government intervention, there's great uncertainty and so we've paused and you'll be aware that the Bass Strait joint venture for this year only approved a six-month budget because of the uncertainty. It's very difficult to make investment decisions when there's this residual uncertainty around the prices that we'll be able to get for our, for our commodities. I think it is a certainty that, you know, the production for Bass Strait is declining and as that happens, we need to make sure we're managing the cost as well and managing the capacity of the facilities. From a government consultation perspective, we've been having a lot of discussions, as have many other members of the industry. Look, I think there is an understanding of the complexity of the market. I don't wanna signal too much. I guess your probably best question posed to the government around are they gonna be thinking about different solutions than what's been tabled thus far. I do feel pretty positive about the quality of the conversation we're having about the recognition that our business, the Bass Strait business, all we're selling to is the domestic market. You know, and we're keen to, you know, continue to support that market. We know households and small businesses depend on it. Okay. That's great. Thank you. Just finally from me, just on the Sunrise project. In the last couple of updates, it has sounded like you're getting a little bit more positive on that asset. I was just wondering, how are those PSC discussions going, and how are you thinking about the concepts at this point in time? Mark, we announced to market, it was probably a few weeks ago, that the Sunrise joint venture has agreed to start some formal work on concept select, looking at options to process the gas in Australia as well as options to process gas in East Timor. The venture is gonna conduct those technical studies. The PSC discussions are continuing. The thing that's probably most encouraging for us is we do have a real clear signal from both the Australian government and the East Timor government that they are keenly interested in this opportunity progressing. I think that government engagement and the government's desire to move things forward is something that's very positive and something that I think will catalyze a bit of action in the venture. Still gonna be a long, a long road ahead for us. You know, the technical work's part of it, the commercial work's part of it, the government negotiations are part of it. We'll just keep pushing on all those fronts and hopefully be able to move this opportunity forward. That's great. Thank you. Our next question comes from Nik Burns with Jarden Australia. Oh, thanks, Meg Graham. Just a couple of questions from me. The first one of the shining lights in 2022, looking at the segment data, from your marketing team, if I'm right, I think profit before tax was up 140% versus the prior year. We've seen the strong LNG trading margins coming through in your quarterly reports. It feels like LNG markets are less volatile right now versus last year. If that lower level of volatility continues through this year, does that mean the arbitrage opportunity available this year will be less? Should we expect lower margins coming out from that team this year? Thanks. Yeah, it's an interesting question, Nik. If we look at 21 versus 22, we actually did a lot more trading in 21. 22, the market was in, well, it was extraordinarily tight. There was a lot less pure trading going on. What you do see in our segments earnings is the benefit of optimization. Our marketing team was able to come up with a lot of creative ways to increase the value of our produced LNG business. The second aspect to the marketing business, of course, is our Corpus Christi position. You'll see that that's also turned the corner last year to be quite profitable, and that's profitable even after the hedge loss. The outlook going forward, look, we are seeing more liquidity in the markets. We are seeing, you know, prices, of course, have fallen off a bit. China, we expect to come back into the market. There's still a bit of an open question around what's gonna happen in Europe. They appear to be finishing the winter with storage in a pretty good position. Prices are now at the point where we may start to see some coal to gas switching. I think the volatility that we've seen over the past years is likely to persist into the coming years. The marketing team is ready to go. What we've, I think, historically guided is that for the pure trading part of our business, that the margins normally are quite slender. Where we can really make a big difference, and you certainly saw it in the segment note this year, is in the optimization I will now hand back to Ms. O'Neill for closing remarks. All right. I hear from the team that there's still a few folks in the queue. Apologies that we didn't get around to answer everyone's questions. We know who you are. Our team here will follow up offline. Appreciate everyone for joining us on the call today. I look forward to meeting with many of you in the coming weeks. Thank you. That does conclude our conference for today. Thank you for participating. You may now disconnect.