Thank you Meg, and good morning everyone. Starting off with Slide 21. Across the board, we have achieved very strong financial outcomes and 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, 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 delivered 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 a higher operating cash flow of $8.8 billion for '22. We are also putting this cash to use across oil, gas, and new energy projects with investing cash flow totaling $4.2 billion. And 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 I outlined at our Investor Briefing Day last year have been met. First, our ability to meet our investing expenditure commitment, mainly Scarborough and Sangomar. Second, our investment grade credit ratings were reaffirmed during the year, and 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%. Whilst gearing for the period was 1.6%, it is important to note that if the final dividend was added to the end of the financials, I should say, payment would have the effect of increasing the year-end gearing to 9%, which is just outside of our targeted range of 10% to 20% through the cycle. We may at times sit temporarily outside of this range. But 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 realised 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 in 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 of the balance sheet. And 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 removed the one off impact of the merger transaction costs, the benefits of de-recognizing the Corpus Christi onerous contract provision, Wheatstone impairment reversals, the Pluto PRRT DTO 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 five year comparison of operating revenue, EBITDA and underlying NPAT. As outlined previously the merger and market conditions along with a 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 $0.5 billion 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 cost for Scarborough and Sangomar. Moving to Slide 26, unit production cost has increased, but underlying cost performance remained 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 we'll 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 growth and cash margins. Our margins have remained resilient through the price cycle, the cash margin averaging approximately 80% over the last five years. This demonstrates the quality of our portfolio and the continued benefit of the merger. Slide 28 shows our five 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, but when we think about this figure in the context of the $6 billion to $6.5 billion of CapEx which we have forecast for '23, we are well covered. Our debt maturity profile has minimum near-term maturities and 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. The top-up payments resulting from our '22 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. And this demonstrates that higher prices do translate to higher taxes paid. I'll now hand back over to Meg. Thank you. Meg O’Neill: 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. And 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 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 intends 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. [Operator Instructions]. Your first question comes from Tom Allen with UBS.

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've seen that pressure. And 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? Meg O’Neill: So 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. So the comment on higher CapEx was really a year-on-year comment. The consultation requirements as I noted in the 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 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 that would affect the first LNG, which we remain targeting for 2026.

If I can please just ask one another question on the capital demands in the business. Is Woodside still assessing, so, let's say, mid-cap sized acquisition opportunities that could extend your Gulf of Mexico exposure? And in some cases even bring perhaps an onshore shale exposure in the US. Just keen to understand whether that's still a live assessment and something we should be considering when looking at the broader capital demands in the business for the year ahead? Meg O’Neill: Sure. So of course we remain opened 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'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. And if anything comes to fruition, we'll let you know. We will remain very cautious about onshore opportunities. 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. So we remain a bit cautious around the onshore that's a different skill set required to be successful in that space.

Your next question comes from Mark Samter with MST Marquee.

I didn't think I'd ever start with a question on depreciation in my life, but I'm just wondering if we could talk about FY '24 when we think about the fact Sangomar starts out with a pretty low 1P base may adopt to obviously these asset is going be depreciated over 1P basis. Obviously got higher production expected. But should we be thinking that group units D&A costs will be higher in '24 than in '23 on that logic. And obviously are going to target into the dividend after. Hopefully you can answer that question.

So, in the results announcement we have included a depreciation expense reconciliation for '23. And you will see our 2022 depreciation increase from $2.9 billion to $4.4 billion. The majority of that is driven by the additional five months of depreciation of the BHP heritage assets. And you will also see the breakdown in there, the change in the application of the depreciation policy. So of that movement $600 million is related to the change in the depreciation policy as well. So there is a reconciliation provided in the appendices of the results announcement.

But it's fair to say the assets will start, produce the added production is coming from assets that are relatively low 1P reserve basin relatively high CapEx means that, am I wrong in thinking that? Meg O’Neill: In '24.

In '24. Meg O’Neill: Yeah, so Mark, I mean, you're correct that the assets that we'll start up in '23, and then have full year production in '24 are assets that will be depreciated on a 1P basis. And so as you would expect in those sorts of assets the unit depreciation rate is higher, the positive of course is that as we do infill drilling for example and continue to develop the full 2P resource, that additional resource comes in with limited incremental unit depreciation cost.

And I guess can we just roll back into how we're thinking about and you said you highlighted today [Indiscernible] gearing would be, I have lost the page, it was 8% or 9% take into account the final dividend. If we look back at the chart you gave us 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 [Indiscernible] pretty cash flow negative this year, so by the time we get to the interim dividend FY '23 gearing should be well and truly within that 10% to 20% gearing range. Can you talk through how you think about, A, do we think still 50% to 80% despite the change in depreciation policy is a sensible number we should base it up? And I guess at both ends of that range, I don't want to frame this as a negative question, what would you need to see happening to payout more than 80%, and what do you think we would need to see if you were to think about reducing that payout ratio below the 80%, but has been the standard for [Indiscernible]. Meg O’Neill: Yeah. As you know, our capital management framework has 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 payout 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 the 80% in this full year results. 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. Assuming Trion in Oklahoma, FIDs are successful. We just need to continue to have that disciplined approach to ensuring that we protect the balance sheet, we protect our ability to invest and we protect that ability to return value to shareholders.

Yeah, true. I hope this isn't pushing too much in the light, but when we think about, I guess three years ago, we would have thought $15 JKM is the greatest thing ever. But when we think about that pretty precipitous drop we've seen in JKM, as do you tend to think that just the low earnings from that is a balancing factor enough or do we think as that macro is potentially working and it could swing back the other way. Do we think you need to be more prudent assuming a much level of JKM persist for a while than you talked before or do you think just the 80% of a smaller number compensates for it? Meg O’Neill: Yeah. So 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 $15 JKM is pretty attractive. Three years ago we would have been ecstatic to be at that pricing level. So we do, as I said, we modeled a variety of price forecast going forward. We test our ability to pay out and we feel comfortable with the 50% to 80% range of payout is still appropriate as long as we also keep our eyes on that gearing ratio of the 10% to 20%. We were well-positioned this year, but we do have a period of significant capital ahead of us. And 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.

And I think Mark, it's worth pointing out that testing of the scenarios, we see the balance sheet as still quite resilient at our low price scenario as well. So we're comfortable where we are today, but we are conscious that times are quite volatile. But we do see ourselves resilient at the low gross.

Yeah, absolutely. Sounds very sensible to me. My second one really last quick question if I can probably a bigger-picture one, Meg, if we think broadly about the business in its biggest form scarred, but largely offset the declines in LNG production you'll see from North West Shelf and Pluto broadly-ish. It will be without new project sanctioned or M&A it will be pretty much 65% of the reserve base by the time it starts. When you think about the rest of the business and that's why Trion perhaps does an FID for whatever reason, do you see the need to replace reserves and keep the 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? Meg O’Neill: So 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, and 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. So we are open to continued investments in all three of these commodities. And we'll continue seeing what opportunities are out there, but we need to be disciplined about progressing those opportunities. So 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. But opportunities beyond that, we're looking at across all three commodity types.

Your next question comes from James Byrne with Citi.

Two questions. Firstly PRRT-related, Slide 29, Graham, it came out almost pre-emptively swinging on many 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 sort of see you put out a slide like this that really defends your position of paying higher taxes during higher commodity prices. And Meg, you're obviously very -- falls with API, are you sort of lobbying against PRRT actively at the moment for changes? Meg O’Neill: 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 payout 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. But part of why we had that slide in there is just to help communicate more effectively that's when Woodside is profitable, many of our shareholders benefit. Our shareholders benefits and the government of Australia benefits. $2.7 billion is really a phenomenal contribution. And if you think about how far that stretches in terms of aged care, education, infrastructure investments, 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 theses secondary approvals to Scarborough, are you able to sort of say what court cases there are sort of outstanding against the project. And in that context when you do your workshops with nOPSEMA, do you feel really comfortable that you're aligned with nOPSEMA to get those secondary approvals. If we saw a Barossa style for the delay to Scarborough and the rig was idle, I'm also wondering how expensive the contingency budget is at the moment to absorb any sort of delay to the project. Meg O’Neill: Look, I'll start with the fact, so outstanding court cases we have two. One is in the Supreme Court of Western Australia 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 court. 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. And for Scarborough, we have three environmental plans that we're progressing, one for seismic -- sorry, three related to Scarborough, one for seismic, one for drilling and one for the pipeline installation. As I said in my opening remarks, we are consulting in accordance with consultation plan that aligns with that nOPSEMA guidance. So it's a much broader consultation than we historically would have performed. But we are getting after it. The teams 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. And as I said, we remain on track for first LNG in 2026.

Your next question comes from James Redfern with Bank of America.

I guess question is going to follow on to Mark Samter question just around the dividends. I mean, the presentation the last 12 months, to be fair to special dividends and buybacks with regard to increasing shareholder returns. But I guess the prudence of conservatism you've shown today suggest that we should not be assuming any special dividends or buybacks in the foreseeable future given the oil price outlook and also the CapEx coming up. And so, I guess the best we could expect is the 80% dividend payout ratio, which is fine, but just wanted to check if that's consistent with your thinking? That's the first one please.

So, the way we look at it at a point in time, at the time of assessing the dividend and declaring the dividend, so it's a bit early to call that out just yet, but 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 to $6.5 billion. And I guess the market volatility and how the overall market is 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. So 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. Meg O’Neill: James, 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. But at this point in time as Graham noted with the capital spend ahead in the next year plus, we're being prudent.

Second question is just a housekeeping question, with regards to Sangomar. If we see first production later this year, the expected production expected 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 will the ramp up be and what are you seeing in terms of that plateau that actually in terms of years. Meg O’Neill: Look, 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. But for purposes of the production guidance, we have not assumed anything material in the production guidance for this year. In terms of the pace of ramp up, look that's something that we are working on. It will depend a bit on how we manage the flow assurance, this is a deepwater development with pretty complex subsea infrastructure. So it will be ramped-up over the course of a few months. Plateau, 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 our production guidance at a point that's appropriate in time for that particular asset.

Your next question comes from Dale Koenders with Barrenjoey.

Just I guess going back to prior questioning, the free cash flow outlook you presented for the business at the Investor Day, is just under $1 billion or thereabouts in '23 and about $4 billion in '24 before thinking about a couple of billion dollars for Trion and H2OK CapEx. Oil price has fallen off. Can you just confirm we are right to think about 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 business?

So Dale, the '23 or the free cash flow graph that we put forward, an indicative position for the future at the IBD was using forward curves, and it does take into account the drop in prices. However, 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 where 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. And as I touched on with Mark, our low price sensitivity analysis does prove that 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 will 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. But 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.

And then just finally can I check my math, it looks like Greater Enfield gas were 2P reserve downgrade in the order of 200 Bcf. Can you talk through that, is that Wheatstone? Meg O’Neill: We'll have to follow-up with you on that, Dale.

Your next question comes from Saul Kavonic with Credit Suisse.

Quick question on the Sangomar drilling results that were referred today as part of which factored into some of the reserves changes to Sangomar, can you give us an update on what the latest drilling results, what they are, what the implication is for Sangomar and particularly Sangomar Phase 2 if there's any read through for that? Meg O’Neill: So the Phase 1 results actually have been really close to prognosis throughout. The only well that I think we've commented on specifically was one of the exploration wells, which was this SNE North-2 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 two main reservoir horizons that we're targeting the S500 sands. And 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. Then we've got the S400 sands, which are laterally extensive high in place. But questions about connectivity and we won't be able to really understand Phase 2 until we get some of that dynamic data, particularly in the S400 section. So it's still open questions around what Phase 2 would look like. But if you look at 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, but we do need that dynamic data to figure out exactly what those look like.

And 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% to 20% gearing target for a single year, high CapEx year in order to kind of smooth out and maintain an overall dividend payout. Is that something you'd consider for particularly the 2023 year? Meg O’Neill: I think Graham described it well, while talking about us being on the low-side of the range this year. If we paid out the dividend last year we would have been at 9%. The 10% to 20% is a gearing target range through the cycle. So there may be periods where we fall below. And there may be periods where we go above. So I would use that as a soft guardrail, not as a hard limit set.

Your next question comes from Mark Wiseman with Macquarie Group.

I have 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 [Indiscernible] gas processing plant. Could you maybe just help us understand how much of that capacity is going to be permanently closed in terms of gas processing. And just on the government consultation pace, are you able to provide a bit of colour just on how those discussions are going? Are you getting more confident that the government is -- realizes the impact that they're having on the market and perhaps could we end-up with a more reasonable outcome here? Meg O’Neill: So Bass Strait, there's probably a few projects to talk about and you'll be aware that the joint-venture and this was pre-merger sanctioned the Kipper compression project that was sanctioned in October '21, targeting RFSU in '24, so that project is underway. But 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. And so 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 costs of running these assets. Yeah, obviously, we'd keen to continue to bring new gas to market in the East Coast of Australia. You'll be aware we were looking at some opportunities for bringing LNG across. With the government intervention, there is 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 is this residual uncertainty around the prices that we'll be able to get for our commodities. But I think it is a certainty that the production from 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 want to signal too much. I guess your probably best question posed to the government around, are they going to be thinking about different solutions than what's been tabled thus far. But 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. And we're keen to continue to support that market. We know households and small businesses depend on it.

And 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 those PSE discussions going and how you're thinking about the concepts at this point in time? Meg O’Neill: Yeah. So 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. So the venture is going to conduct those technical studies. The PSE 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 governments that they are keenly interested in this opportunity progressing. And I think that government's engagement, and the government's desire to move things forward is something that's very positive and something that's I think will catalyze a bit of action in the venture. But still going to be a long road ahead for us. The technical work is part of it, the commercial work is part of it, the government negotiations are part of it, and we'll just keep pushing on all those fronts. And hopefully be able to move this opportunity forward.

Your next question comes from Nik Burns with Jarden Australia.

Just couple of questions from me. The first one, one of the shining lights in 2022 looking at the segment data from your marketing team from right, I think profit before-tax was up 140% versus the prior year. We said we've seen the strong LNG trading margins coming through in your quarterly reports. Feels like LNG markets are less volatile right now versus last year. And if we take look ahead, so that lower level of volatility continues through this year, does that mean the arbitrage opportunity available this year will be less and should we expect lower margins coming out from that team this year? Meg O’Neill: So if we look at '21 versus '22, we actually did a lot more trading in '21. '22 the market was in -- was extraordinarily tight. And so, there was a lot less pure trading going on. What you do see in our segments earnings is the benefit of optimisation. So 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, and 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, and we are seeing 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 going to happen in Europe, they appear to be finishing the winter with storage in a pretty good position. But prices are now at the point where we may start to see some coal to gas switching. So 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, but where we can really make a big difference and you certainly saw it in the segment note this year is in the [Technical Difficulty].

I will now hand back to Ms. O'Neill for closing remarks. Meg O’Neill: All right. I hear from the team that there is still a few folks in the queue. And apologies that we didn't get around to answer everyone's questions. We know who you are and so our team here will follow up offline. Appreciate everyone for joining us on the call today. And I look forward to meeting with many of you in the coming weeks. Thank you.