Woodside Energy Group Ltd

So if we look at many of the competing U.S. Gulf Coast or even the Mexican Gulf Coast projects, there are very few that have that attribute. So we've got everything fully locked in with Bechtel from a pricing perspective. It is for three trains. And the marketing we've been doing with our potential partners is focused on that foundation development of three trains. Now, the mechanics with which we progress to full notice to proceed The first notice will be for Trains 1 and 2, and there'll be a subsequent notice for Train 3. But again, the pricing is based on three trains, and our expectation and the expectation we're communicating to all of our prospective partners is that the plan is to move ahead with the foundation.

Got it. Thanks, Meg. And my second question, just picking up on Graham's comments that Woodside would consider additional shareholder returns post the start-up of Scarborough, should we interpret that comment to mean they expect gearing to peak just after the start-up of the Scarborough project? Thank you.

Thanks, Nick. So I guess if we take a step back, we've discussed about our three near-term growth and positive MPV projects being Sangamah delivering very well, You've seen delivered $950 million cash to Woodside in the first seven months of operations. That's 24, 26. We have Scarborough coming online, which will start to deliver significant cash flow. 28 is Trion. So in terms of our debt profile, as that cash starts to flow, yes, we do see the turning point in our gearing, if you want to call it. and also having the ability to have excess cash available to us from 27 onwards. So 25 and 26, we will see our net debt grow based on a positive FID for Louisiana.

But once those Scarborough flows start to kick in, it does give us flexibility and optionality as we move forward.

That's great. Thanks, Graham.

Thank you. Your next question is from Saul Covernage from MST. Go ahead. Thank you.

Hi. First question. It's reported in the press that Louisiana's sell-down process is advancing and data rooms have been closed, et cetera. So I might assume you've had some early indications of bids coming in. Meg, can you give us some more colour on that process, and particularly, I think you made some comments last year that you're expecting a premium for any sell-down price. Are you still expecting a premium? And if so, are we talking very modest premiums, or should we be looking at valuations implied by some of the US LNG analogues?

Well, thanks for the question, Sol, and thanks for also highlighting the valuation that our U.S. peers in this space, companies like Chenier and Venture Global, are attracting. We view ourselves as warranting the same sort of premium. So we do see a lot of opportunity with Louisiana LNG to bring in quality partners. To your question on the sell-down, so we are well advanced in that process. We have a number of high-quality counterparties with whom we are negotiating as we speak. The pricing point we will communicate in due course. But bear in mind, Saul, that the key thing that we're focused on with the sell-down is making sure we have those co-investors to share the capital investments. There is still quite a bit of spend facing us ahead as we move forward into this investment. So we're focused on getting partners who will share the capital, see that same long-term value that we see, and we'll be getting a price that we think is attractive and fair for our shareholders.

Thank you. Can I also ask about... phase two progress. The update last week seemed to de-risk phase two. There's potentially a few hundred million barrels of resource there that could become reserves. Can you give an indication of when we might get an update on reserves for phase two and how we should think about value in that regard?

Sure. So as we've said probably since pre-FID The 500 sands are the high-quality reservoirs, and we're really seeing outstanding production from those reservoirs. Where there is quite a bit of in-place oil is in the S-400s, which are geologically more complex. What we've seen thus far is enough connectivity to remove some of the low-side cases off the table. But we do need to get more production performance and more data from the wells that we have in place to understand what exactly does phase two look like. And we've said we probably need 12 to 24 months of data to inform decision-making in that space. We will continue to book reserves as data comes in. You would have seen we booked reserves late last year. That was based on the initial production performance. As we get more information on water injection, we will continue to migrate reserves from 2P to 1P. And so, it's worth reminding the audience here that with our U.S. secondary listing, we report 1P reserves in a manner that's defined by the SEC. So, it's a very rigorous and tight process for defining 1P and very tight rules for migrating. So we still believe that we'll recover the full 2p that we sanctioned at the time of FID, but the migration to 1p will follow those SEC rules, and it links to reservoir performance.

Thank you.

Thank you. Your next question is from Tom Allen from UBS. Go ahead. Thank you.

Good morning, Meg, Graeme, and the broader team. I was hoping you could please provide a comment just on the production outlook for the producing U.S. oil projects. Just noting that we saw a very modest 2P reserve cut to Mad Dog in the release last week. It's just a little bit surprising just given that the big Mad Dog Phase 2 development and Argos platform is still fairly new. Was there anything that you're seeing in the subsurface that looks challenging that BP's found at Mad Dog? Or anything across those three US producing assets?

Yeah, thanks, Tom. So you would be aware that we took an impairment on Shenzhen in 2023. We saw some disappointing performance out of the Shenzhen North development in particular. With Mad Dog, it's really a matter of timing for getting wells online, and that was a bit of the factor that underpinned the reserve adjustment there. We do still have quite a bit of drilling ahead of us, And as we look forward, we do see the U.S. Gulf as continuing to be a very important part of our portfolio well through the 2030s. For example, we still have the Mad Dog Southwest development to bring on. We have other satellite developments at Atlantis. So particularly those two big assets, we do see continued development ahead of us, and those will be part of our portfolio for the long term.

Thanks, Meg. For my second question, just a comment, please, on the outlook for the Northwest Shelf. Now that the asset swap with Chevron's been executed, obviously supports better alignment in the Northwest Shelf joint venture to spend money pursuing potentially other resource to backfill the plant or pursue tolling options. So looking, hopefully, for a comment on the opportunities that the joint venture see there that you might go after over the next couple of years.

Yeah, so we're excited about Northwest Shelf. It's an asset we know extremely well. We have every intention of squeezing as much gas out of the field as we possibly can. Last year, we sanctioned the Lambert West development. That's an infill tieback that'll be drilled this year. We also sanctioned a project to lower the back pressure on the Goodwin platform with some modifications to the compressor. Again, that's to get more gas through the system, get more gas out of the reservoirs. We're working, scoping some additional subsea tiebacks. It would be packaged together as Greater Western Flank Phase 4. So, continued work to figure out how do we squeeze more gas out of this reservoir. One of the things, though, that's going to be important is getting that federal government approval for Northwest Shelf life extension. I'm sure as everyone on the call knows, our current approval is valid until early 2030. So we do need to get that approval to give ourselves confidence in investing for the long term. The second phase of focus for Northwest Shelf is tolling, and we continue to talk to players in the onshore Perth Basin about bringing some of their gas through the plants. And then the BROWS resource is the biggest tolling opportunity. And the BROWS and Northwest Shelf Joint Ventures continue to have discussions about what's the best way to develop the BROWS gas.

Thank you, Meg.

Thanks, Tom. Thank you. Your next question is from Dale Coenders from Baron Joey. Go ahead. Thank you.

Morning. I was just interested in the comment around delivering $150 million cost reductions in 2025. Wondering about the scope of works, the basis year, and how much of this is already included in production guidance?

Dale, thank you for the question. What we're talking about here, the $150 million, a portion of it is factored into the unit cost, but the majority of it relates to expenditure that will not factor into the UPC calculation. So we're talking around exploration. Meg spoke in her speech around focusing the new energy business in on B&A as a Beaumont New Ammonia example. So a small portion in the unit costs. We'll continue to keep really tight control on our unit costs and we'll continue to manage them closely, but the majority of this is separate and is related to exploration, new energy and corporate costs.

Thanks, Graeme. And then just in terms of, I guess, thinking about those Beaumont cash cost guidance, and thanks for providing that, Meg, just wondering, what are you assuming in terms of Henry Hub price or price range within that?

Yeah, so it is a range and that's why we've provided the range, but it's similar to what it has been over the last six to nine months, Dale. So let's just say around the low threes.

Okay, and then if I can just sneak one more in. It seems to be the market's a bit worried about you FIDing Louisiana LNG without a sell-down, which seems to be an FID date that's fixed given the limited notice to proceed. Should we be, I guess, not worried and think that a case like Scarborough could proceed where you've already got partners all but locked in? I saw the comment of marketing with possible partners would suggest it's pretty progressed. High conviction in the quality of those partners, but just a need to keep moving forward until final approval is signed off.

Yeah, Dale, it's worth noting what we've said is we want to be FID ready from the first quarter of this year, and the teams are working very hard to that objective. But we would not take FID without confidence that we have partners either signed up already or extremely close to signing up. I think Scarborough Pluto Train 2 is a fantastic analogy. So with the whole Scarborough development, we were able to secure a sell-down of 49% of Pluto Train 2, kind of coincidence with FID. And then we were patient to bring in other partners to the offshore resource. So look, we've seen great interest. I think there's potential for us to have the whole 50% sold down by FID. But again, it is complex commercial negotiations, so we will be certainly well-advanced, if not signed with one key partner, and then continue to be progressing. But the team's certainly got their skates on. We're deep in negotiations with a number of, as I said, high-quality counterparties, and we'll let the market know when we've got something announceable.

Okay, brilliant. Thanks for that, Megan.

Thank you. Your next question is from Jennifer Hewitt from Australian Financial Review. Go ahead, thank you.

Oh, good morning. I was just wondering what would happen. You talked about the fact that you were very disappointed that it had taken six years to get state government approval for north-west shelf expansion. Are you disappointed by the federal government delay? And if, in fact, there is a minority Labor government, Do you think that would mean further delays and what would be the significance of that for your thinking in terms of investment?

Thanks, Jenny. Look, I continue to be pretty frustrated that it's taken more than six years to grant approval to extend the life of an asset that's been operating for 40 years when we're not planning to do anything that's outside the fence line we've already established. You know, we're at the point where we're looking at business decisions that are ahead of us, things like drilling new wells to bring new gas to the markets, particularly the domestic gas market, which needs it as early as 2028. We're having to ask ourselves, can we make that decision with confidence, not knowing if the federal approval is going to be granted? Look, we're disappointed that they continue to request more time. I think it's a proof of some of the challenges that Australia faces in the approvals environment that you've got things like reconsideration requests that come in at the 11th hour where proponents who have no skin in the game can ask the minister to review decisions that were made 40 years ago. So, you know, and we think about what does this mean for our workforce up in Karratha? What does this mean for workforce at the mine sites that depend on our gas to keep going? You know, there's families whose lives are at stake. So very frustrated. You know, I'll leave it there. Hopefully we'll get an approval before the election.

If you don't get an approval before the election, will that make it more dicey, do you think, given the likelihood of a minority Labour government dependent on Greens and Teals?

Look, I think the outcome of further delays means more coal in the energy mix longer. So if you're serious about the environment, you'd approve this.

Thank you.

Thanks, Jenny.

Thank you. Your next question is from James Byrne from Citi. Go ahead, thank you.

Good morning, team. Okay, so Louisiana LNG, just thinking about the sell-down process, assuming you do quite well out of that and there's a gain on sale, this is obviously a catalyst that we're all sort of focused on, as a market, how do we think about that gain? Because you actually, you know, bought the corporate entity of Tellurian as opposed to buying project equity. So what's the base there that we should think about for a gain on sale? And then just to be clear, when we think about the 12% hurdle rate, will you take into account gains on sale into that calculation or is it like a pure project IRR that we should be considering?

Yeah, I want you to take that one. Thanks, James. So, look, the gain on sale will be exactly the same as what we treated for the likes of the sell-down of Scarborough to Jira and LNG Japan. Same concept, you know, there's accounting rules. Obviously, you've got the acquisition price of Tellurian. And then we would have to look at the additional capex and funding that's continued post the acquisition, so normal standard accounting rules. Yeah, so I'm not sure if I'm missing something in your question, but yeah.

So maybe, Graham, the pointer is for accounting purposes, the acquisition was treated as asset accounting. So in the financial statements, and the team can follow up with you later on the exact page number, you'll see there's a file note in the financial statements.

Yeah, it's very clear in our financial statements what the acquisition costs were, and then we would take into account the additional funding post that, and then the portion of that would be recognised against the gain on sale, against the proceeds.

And with respect to IRR calcs, as we did with Scarborough, we do account for that. We've done the legwork and money coming in. If it's revenue that's accelerated through sell-down, that counts.

Perfect, thanks. Okay, second question just for you, Meg. I'm interested in how you think the dynamic is changing for US LNG under a second Trump presidency term. So on the one hand, I think there's a little bit of concern in equity markets that there's this big reduction in red tape that's coming. We saw Commonwealth LNG get its approval recently, which was earlier than what I anticipated, and then whether that would increase competition for off-take and equity. Perhaps on the other side, though, there's this... almost US exceptionalism where Trump's pressuring allies to buy more US LNG. And I'm wondering whether you think that would result in a contract premium in the US versus the rest of the world. And lastly, there's talk now of the Ukraine peace deal and whether that might mean that there's more gas flows probably into Eastern Europe as opposed to Western Europe. I don't think anyone expects the same amount of volume is exported, but nonetheless, prices are set at the margin, so it would have a deflationary impact and might make us question the economics of Louisiana. So again, red tape, contract prices in the US and Russia, I guess.

Sure. Thanks, James. So I think on many fronts, Trump is changing the landscape. The thing that's really striking for me is all of the competitive advantages that Louisiana LNG has. We've got all of the permits we need. We have a priced contract with Bechtel, and I can't overemphasize how important that is. All of the other projects in this market will have to go back and get repriced. The other thing that sets us apart is the fact that we are able to progress this between ourselves and our partners, funding on balance sheets. So many of the U.S. developers still have to go through the sequential process of securing LNG offtake, using that to then secure financing, in parallel repricing contracts in an inflationary market. I just do not have confidence that there's going to be as much competition as simply streamlining the red tape might imply. So we're at least a year ahead of everybody else in the U.S., And we continue to attract a premium from many players who are interested who are seriously interested in US LNG In terms of price premium look LNG is a highly fungible commodity. I wouldn't expect any price premium we may be able to attract off takers who come from nations that are looking to restore the balance of trade and But I think we've seen this in a number of ways in the past. Things like low carbon LNG, people don't pay more for that. So we'll continue to negotiate very competitive pricing. I think Woodside's reputation sets us apart. The way we partner with companies and customers sets us apart. Some of the flexibilities we offer customers, which is different from other suppliers, sets us apart. And those are the sorts of things that'll get us better pricing than others in the marketplace. And Russia, Ukraine, look, that's a bit of a wild card. Look, physically, not as much Russian gas will be able to enter Europe as was flowing in 2021. There may be a bit of gas coming into the marketplace. But again, when we look at LNG demand growth forecasts for the long haul, and that's for the latter 2030s and, sorry, the latter 2020s and the 2030s, Asia's the engine. So Asia is going to be the engine room of energy growth. Asia is going to be the engine room for LNG growth. And it doesn't materially change our thesis.

Thank you. Appreciate it.

Thanks, James. Thank you. Your next question is from Rob Coe from Morgan Stanley. Go ahead. Thank you.

Good morning. First question for me, I guess, is in relation to the derivative item that went through the P&L, and that was not a surprise because you talked to us extensively beforehand. But just wanting to understand, A, should we be looking for that gas price derivative volatility going forward, or is this more of a one-off adjustment? And then secondly, is there any kind of natural hedges within the business that we could think about to offset that item?

Thanks, Rob. So, yeah, look, I think you've captured it. We've provided insight on this for the last couple of years in our accounts. And even though this is a non-cash item, the really important point here is we strongly believe the contract has significant expected value, right? So selling... the gas linked to a urea price we think is good for the business in the long term as opposed to a domestic price. There will be the nature of the fair value accounting required under an embedded derivative.

Sorry, I think he was asking about the Henry Hub. Rob, are you asking about the Henry Hub TTF hedging or are you asking about the urea pricing?

the urea pricing that Graham was just talking about.

Yes, okay. So, sorry, I'll just get back to my train of thought now. Yes, as a part of that, we have to recognise the embedded derivative. We have to value that component on a half-yearly basis in our half-year accounts and full-year accounts. But what we will do going forward, Robb, is we'll provide an update on the movement in the embedded derivatives in the quarterly production report, similar to what we do with our hedging derivatives. So the market will be able to keep up to speed with it. So it will continue to be revalued through the life of the embedded derivatives.

Okay. All right. Thank you. And then my next question, and It may be that you'll be telling this at your climate briefing in, I think, early April, you said. But I know you've got a small element of your cost reduction is focused on new energy. You haven't reiterated the kind of $5 billion investment aspiration by 2030. Can you just maybe give us a sense of how you're evolving on your climate ambition?

Yeah, Rob, nothing has materially changed. And we put another document out today called the Climate Updates. What has changed is we've made a $2.3 billion acquisition of a low-carbon ammonia plant. So instead of a pathway that would have had us organically pursuing potentially multiple pathways for growth of this new energy and low-carbon business, we've taken a material step forward with this single acquisition that we created. believe is profitable. We believe it meets our investment targets. We believe it's even got upside potential. So we're very much focusing on delivering shareholder value from the acquisition we've made, and that's going to cause us to reduce some of the other new energy-related business development that we would have been doing over the past few years.

Okay, great. Thanks very much, and all the best with it.

Thanks, Rob. Thank you. Your next question is from Adam Martin from A&P. Thank you.

Yeah, morning, Meg. Graham, I suppose first question just on Woodside's equity, I suppose. Look, it's underperforming global and local peers in the last 12 months. Just wondering on your view on that and sort of any changes or how you're responding, please, and then we'll come back with a second.

Sure. Well, look, I mean, at a headline, one of the things we're emphasizing in our full year results is the quality of the base business. You know, we have Absolutely world-class assets, you know, starting with Northwest Shelf, which is the marquee LNG development in Australia. Pluto, which has been an absolutely phenomenal asset for us since we started up in 2012. Bass Straits, you know, continues to be a significant cash generator. And then the U.S. Gulf properties. But as you would have noticed in the chart on slide... Slide... 30, no, not 37, sorry. Sorry, slide seven. You'll see that many of our mature assets are declining. And so we're in a period of investing in that next wave of profitable assets for Woodside. But the quality is uncompromised. I mean, the same thing, Sangomar, Freon, Scarborough, Louisiana LNG, Beaumont are all tier one phenomenal assets. And once we get through this high investment phase, we're going to be in a period of generating substantial free cash flow. So that's the message that we hope shareholders take away from this presentation today. We know there's been some questions around the acquisitions, and I think that's probably a little bit why our share price has been a bit suppressed. But the reality is we've got absolute world-class assets. We've got a world-class team. We deliver strong operations. We deliver on our project commitments. That allows us to deliver shareholder distributions through this high period of capital investments and well into the future.

Okay, thank you. That makes sense. Just a technical one maybe for Graeme. Just on these abandonment liabilities or restoration liabilities, it seems to have fallen on the balance sheet in 24 versus 23, but I've also got the greatest spend in 2025 versus historical guidance. Just wondering how often do you update for things like Bass Strait? Clearly, there's uncertainty on what Bass Strait's going to cost. I mean, Exxon's still working with the regulator. But yeah, just perhaps you could talk through that, please.

Yeah, so, Adam, as a part of our processes, we will update the provision formally every year towards the end of the year. But obviously, you know, we have a DCOM team in the US and also in Australia, and they're working these projects. And if anything was to come that was unexpected or not necessarily included in the plan, we would update ordinarily. But generally, it's an annual process. In terms of... the accounting side. So I don't want to get confused with the cash, which is what the slide is talking about on the accounting side. If the operation is operational, it'll be reflected through the balance sheet and asset and liability, and that will be updated on a regular basis. And so when you come to the time of decommissioning, you've got the liability ready to go, the provision available to cost against. For closed sites, such as Stybaro, Minerva, etc., that will cost any update to the provision will be charged directly to the P&L, and you see that in the A1 note under other expenses, and that's clearly laid out there. And I just think I just want to sort of re-emphasise we shouldn't get confused with the P&L impact of the provision update for closed sites versus the underlying cash outflow, which is what the slide relates to.

Okay, thank you very much. That's all from me.

Thank you. Your next question is from Henry Mayer from Goldman Sachs. Go ahead, thank you.

Good morning, Megan Graham. Thanks for the update. Scarborough and Pluto train to continue to make good progress. Could you expand on the remaining scope and schedule for FPU fabrication, DNC progress and plant construction? And as we're getting closer to potentially first calligraphy, maybe one year from now, give a view to narrow the expected startup timing?

Sure. So a couple of key milestones for us. So the flooding production unit, which is scheduled critical pass, is being built in China. The hull and top sides are at two separate yards. So an important milestone for us will be mating the two structures together. That will happen in the second quarter of this year. Then the facility or the FPU will go to another yard for integration work. We expect we'll start towing from China before year end. And then we go through the hookup and commissioning phase. And we need to hook up the mooring lines, hook up the risers, get everything commissioned on the facility, start flowing gas to the beach. Then there's a period of getting the gas through train two. Train two is at the stage where we're Completing construction, as I said, all the modules are on site. So we're completing construction. We'll move into commissioning this year. Drilling and completions, that's progressing very well. All the wells will be drilled and completed. All the wells we expect in this first phase will be done by the end of this year. So we're making extremely good progress. The activities offshore are weather sensitive, and so those are the key factors that we're going to be watching that will drive the exact timeline for getting gas to the floating production unit, then gas to the beach, and then LNG. But I thought in one of the notes we updated that our expectation is for first LNG in the second half of 2026. So that's the timeline we're on towards for Scarborough Pluto Train 2.

Excellent. Thanks, Meg. And to expand on some of the previous comments on US LNG exports and Commonwealth, which is making progress towards FID in September, targeting first gas in early 2029, similar to Louisiana. Presumably, you'd rather lift your own Louisiana cargoes. Are you still committed to the two, two and a half million tons from that project if it's sanctioned and comes online? And similarly for Mexico Pacific?

Absolutely. As we think about building a portfolio of quality LNG position, being able to get attractively priced offtake is part of the strategy. We have what I think is a pretty fantastic contract with Commonwealth, so we would be absolutely keen to include that in our portfolio of LNG offtake, as well as Mexico Pacific. I'm sure you've seen some of the news about some of the changes that are affecting that organization. So, you know, we sign those agreements with the hope that FID comes and that we get the LNG. But, you know, one of the things we offer to our buyers is a lot of confidence that with the capability we have, both in project development, operations, and marketing, that they will get the LNG they want when they want it.

Great. That's clear. Thanks, Nick.

Thank you. We have a further question from Saul Covenitch from MST. Go ahead, thank you.

Thanks Meg, Graeme. One last one, just coming back to the dividends because Woodside got punished quite strongly last week for a dividend miss which was less than $200 million in payout but it's probably knocked $1 billion off the share price. you've now got a dividend payout which can move a few hundred basis points either way based on a urea contract, based on forward urea pricing, right? Which adds this level of uncertainty here. Can you perhaps give us some colour as to why this wasn't normalised out for dividend purposes? And can you give us a level of colour and comfort towards the concerns that ultimately the balance sheet couldn't withstand an extra $200 million payout here?

Yeah, so thanks, Saul. Good question. Look, what we do is we remove... Moving from our statutory net profit to underlying, it's more based on non-recurring items. This is a 20-year contract that starts in 2027. It was recognised upon FID of Pertman. It is a part of our business that will be around for quite a period of time, so we don't believe it appropriate to normalise, if you want to call it. And I'll just bring back to my opening comments in the previous question from Rob, is that the contract is a good contract and we think it will add significant expected value to the business by having it linked to an underlying contract. you know, global urea price versus a domestic price. So we're very happy with the contract itself. We're dealing with the accounting technicalities of it, if you want to call it. It is ongoing, but what we are committed to doing going forward is providing an update on the embedded derivative component of this contract in our quarterly production report, similar to what we do with our other derivatives, and they're related to our hedging positions.

Thanks very much. There are no further questions at this time. I'll now hand back to Ms. O'Neill for closing remarks.

All right. Thanks, everyone, for listening in and participating today. I look forward to speaking to many more of you at other upcoming events and continuing to share how we are delivering on our strategy to thrive through the energy transition. Thank you.

Thank you very much. That does conclude our conference for today. Thank you all for participating. You may now disconnect your lines.