Woodside Energy Group Ltd (WDS) Earnings Call Transcript & Summary

Thank you for standing by, and welcome to the Woodside Petroleum Limited Scarborough Final Investment Decision presentation. [Operator Instructions] I would now like to hand the conference over to Meg O'Neill, CEO and MD. Thank you. Please go ahead.

Good morning, everyone, and thank you for joining us for this investor presentation. It is a pleasure to speak with you on what is a very exciting day for Woodside. I would like to begin by acknowledging the traditional custodians of the land upon which we are presenting today, the Whadjuk Noongar people and pay my respects to the elders, past, present and emerging. I also extend my respect to all other aboriginal nations, the future generations, and their continued connection to country. Joining me on the call is our Chief Financial Officer, Sherry Duhe. We issued 2 major announcements yesterday. The first one was for the signing of a binding share sale agreement for our proposed merger with BHP's oil and gas business, which was first announced on the 17th of August. The second one was for our final investment decisions for the Scarborough and Pluto Train 2 developments. I'll address the merger first. Our ASX announcement provides additional detail on key material terms in the agreement. The merger with BHP's petroleum business has a compelling strategic rationale and is a transformative transaction for Woodside. The merger creates a combined portfolio of impressive quality, which is more diversified by product splits, more diversified by geography and comprised of complementary long-life, high-margin Tier 1 assets. The transaction is expected to strengthen Woodside's balance sheet and cash generation, supporting our ability to deliver superior returns to shareholders and providing additional funding for our development pipeline as well as the energy transition. Over the last 2 months, in addition to negotiating the share sale agreements, we have also been undertaking integration planning, which has increased our confidence in securing synergies from the merger and the seamless incorporation of BHP Petroleum with Woodside from day 1. A joint integration planning team has been established with BHP and we have engaged specialist support as we develop a clear plan, resourced for successful integration from day one. I'd like to turn now to the investment decisions reached on the Scarborough and Pluto Train 2 developments and the presentation pack. I will provide a brief overview of the approved developments, outlining why this is a landmark achievement for Woodside and BHP, our joint venture partner in the offshore resource. We'll then open up the call to a question-and-answer session. Please note the standard disclaimer on Slide 2, advising that this presentation does include some forward-looking statements and that our reported numbers are all in U.S. dollars unless otherwise indicated. Let's start with a summary of what the developments will deliver on Slide 3. Scarborough is a world-class resource, a globally competitive project, and a game changer for Woodside. The development covers 11.1 trillion cubic feet of dry gas and as a result of the final investment decision, Woodside's overall corporate 2P reserves has increased by approximately 158% to over 2.3 billion barrels of oil equivalents. The development will leverage the existing infrastructure of Pluto LNG, expanding Pluto with the new efficient Pluto Train 2 and new domestic gas infrastructure. You would have seen last week that we announced Woodside has entered into a sale and purchase agreement with Global Infrastructure Partners for the sale of a 49% interest in Pluto Train 2, resulting in a significant reduction in Woodside's capital expenditure for Train 2. Approximately 60% of Scarborough capacity has been contracted. Scarborough was also an appropriate investment from a decarbonization perspective with approximately 0.1% carbon dioxide in the reservoir, and a new efficient LNG train at Pluto, it will be one of the lowest carbon intensity sources of LNG delivered into North Asia. The significant cash flow will contribute to shareholder returns, and funding of our developments, investment in new energy products and lower carbon solutions. Slide 4 contains a range of the key project data. The onshore development will process 5 million tonnes per annum of LNG through the new Pluto Train 2, plus up to 3 million tonnes per annum through the existing Pluto Train 1. The development also delivers 225 terajoules per day of new domestic gas capacity. In August this year, we announced an updated cost estimate of USD 12.0 billion on a 100% basis, comprising $5.7 billion for the offshore components and $6.3 billion for the onshore components. With the sell-down of 49% of Pluto Train 2, Woodside's share of the total capital expenditure has decreased to $6.9 billion. The expected returns from this project are significant. Since the cost update in August and the sell-down of Train 2, there has been positive movement in the investment metrics of the development. Importantly, the internal rate of return for the integrated development is greater than 13.5%. As I've said before, Scarborough was a globally competitive project with an all-in cost of supply of LNG delivered to North Asia of about $5.80 per MMBtu, which benchmarks well against other projects. The payback period is expected to be around 6 years. Slide 5 contains the conceptual image of the full integrated developments. The offshore development comprises the floating production unit, which will develop the large reservoir through 8 wells initially and 13 over the field life. Scarborough gas will be transported by a new approximately 430-kilometer trunkline to the Pluto LNG facility near Karratha in the Northwest of Western Australia. From there, the gas will be processed through the new Pluto Train 2, the existing Pluto Train 1 or the domestic gas facilities. On to Slide 6, which provides a more detailed view of the optimized and mature offshore development and show some key technical information. With the subsea layout providing flexibility for up to 20 wells, and the floating production unit also having allowance for future tiebacks, we have the infrastructure to process other nearby resources. Moving on to Slide 7. This contains a detailed view of the onshore developments. Pluto Train 2 will run on Optimized Cascade® technology operating on a lower emissions intensity, and we have already awarded the engineering procurement and construction contracts to Bechtel. The onshore development utilizes the shared -- existing shared infrastructure from the Pluto foundation project and we will make some plant modifications and upgrades to support the processing of Scarborough gas. The existing world-class Pluto LNG facility has proven high reliability, and we expect minimal disruptions to the existing operations with these modifications. If we move to Slide 8, it is increasingly important that new developments contribute to a lower carbon future. The Scarborough gas field contains only around 0.1% carbon dioxide, so reservoir carbon emissions are very low, especially in comparison to other Australian projects. Onshore, the proposed design of Pluto Train 2 will have a lower greenhouse gas intensity compared to the international average and Australian average. We expect the LNG produced from Scarborough will be a contributor to the decarbonization efforts of our customers in Asia, particularly given the increased push away from coal. You'll see on Slide 9 that we have been hard at work reducing our emissions through our design of facilities. Designing out emissions is always our first preference and one of the 3 key pillars of our decarbonization strategy. In many cases, it not only reduces emissions, but also cuts costs and increases production of salable gas. For example, the waste heat recovery process in the offshore design eliminates fired or electrical energy sources for the closed-loop heating system. This leads to a saving of approximately 27 kilotons of CO2 equivalent every year. These design improvements add up, and we are also investigating a number of other opportunities to reduce emissions, such as Woodside's proposed solar project near Karratha. I want to emphasize the points that we can both develop Scarborough and achieve our emissions reduction targets. We believe our carbon business will develop at a scale, which will allow us to offset sufficient emissions across our business to realize a 15% reduction in net emissions by 2025, and 30% by 2030, even with adding Scarborough production to the portfolio. On to Slide 10, which provides supplementary information such as the commercial agreements, which underpin the processing of Scarborough gas through Pluto LNG facilities. On the equity sale of Pluto Train 2 announced last week, we are delighted to welcome GIP to the joint venture, and we're looking forward to a long and mutually beneficial relationship. Importantly, here are some of the accounting benefits of taking the final investment decision. One outcome will be an increase in useful life for the Pluto onshore assets, resulting in a reduction in annual depreciation expense. In addition, we will be able to capitalize borrowing costs from FID to startup, reducing net finance cost. Moving on to Slide 11. This is a stylized and indicative graph of what our capital spend will look like for Scarborough across the next 5 to 6 years with our first cargo targeted for 2026. The intention of this stylized chart is to demonstrate how peak capital spend in 2023 is matched to some of the key work streams on the project to give an indication of the integrated project schedule. This CapEx profile also includes the cost of Train 1 modifications. The key contractors for the offshore projects are McDermott for the FPU. Subsea integration lines for the Subsea Hardware risers and flow lines, Valaris for drilling and, Europipe, Boskalis and Saipem the trunkline pipe. Our relationships with the contractors are strong, and we have high confidence in the contracting strategy used for the project. As of today, 90% of the total development contractor spend is lump sum or on a provisional sum basis. On to Slide 12. We are in a strong position as we move into the execute phase of the development. We have taken a number of steps to mitigate risks, front-end loading the scope definition and execution planning in order to improve outcome certainty. For example, commodity risk is being mitigated by locking in 75% of steel pricing, which will be achieved by the first quarter 2022 and we have agreed the rise and fall mechanisms for labor costs. Our primary regulatory approvals to support FID are in place, and we have proven experience in working around any dynamic COVID challenges, which may occur, particularly given our recent experience, developing our Sangomar oil project. If we move to Slide 13, I want to take this opportunity to once again highlight that the final investment decisions will set Woodside on a transformative path. We are developing a world-class resource with 11.1 trillion cubic feet of gas and an 8 million tonne per annum development. We have taken steps to derisk the development and are making strong progress as we move into the execute phase, targeting first cargo in 2026. The integrated development will provide long-term returns with project economics of greater than 13.5% for internal rate of return, a cost of supply of about USD 5.80 per MMBtu, and an approximate 6-year payback period. This is expected to deliver significant cash flow and enduring value to shareholders. As we look to the future, our customers are looking for affordable, clean energy. The Scarborough developments will be amongst the lowest carbon intensity projects for LNG delivered to North Asia. Importantly, our corporate emission reduction targets remain unchanged. With the proposed merger with BHP's petroleum business underway, final investment decisions for Scarborough and Pluto Train 2 and all of our recent announcements on new energy investments, I am very excited about this company's future. We will continue to maintain this momentum to deliver lower carbon and low-cost energy in the decades to come. I'd now like to open up the session to your questions.

[Operator Instructions] The first question today comes from Tom Allen with UBS.

Congratulations on the 2 announcements overnight. I was just hoping you could please clarify the change in the Scarborough economics that are arising from the FID? So the IRRs is 150 basis higher. The breakeven cost of supply to North Asia on a DES basis looks about 15% lower. Just wanted to confirm if it was the lower CapEx from the Train 2 sell-down driving that change? And if you could break out the moving parts, please?

Well, thanks, Tom. Great question. The key driver for the improvement in the economic metrics is the sell-down of our participating interest in Train 2. So we've gone from 100% to 51% including the additional funding from GIP of approximately $835 million, significantly improves our economic metrics. So we think it's a very attractive project.

Yes, that makes sense, just making sure there's nothing else missing there. The high-level merger terms released overnight refer to certain legacy assets and liabilities from BHP's petroleum business that will remain with BHP. Could you please clarify what these are?

Yes. Tom, we haven't disclosed any of those specifics, but you'll be aware that BHP has been in the petroleum business for many decades. This is -- and they've bought and sold assets over time. So this really just protects Woodside shareholders from any assets that might have been sold in the past to ensure that we don't have any exposure.

Okay. Okay. And then just the last one was with Scarborough now sanctioned and post-merger, Woodside alone, 1/3 of the Northwest shelf. Could you just share that the plan to better utilize and backfill Northwest Shelf going forward? So following that 5-year contract to accelerate Pluto by the interconnector across to the Karratha Gas Plant. Interested also how that new pipeline might be utilized beyond that initial 5 years?

Yes. It's a great question, Tom. And obviously, with the offshore resource being now a decline for Northwest Shelf, we are very keen to keep the plant as full as we possibly can. So last year, we signed the early oral agreements between Northwest Shelf and Pluto and between Northwest Shelf and Waitsia, to be able to start processing guests from those resource owners on a tolling basis through the Northwest shelf. Northwest Shelf joint venture continues to actively solicit gas from other potential shippers. And so there's more conversations in that way, but the current terms that have been agreed are for that limited time period from Pluto.

Your next question comes from Mark Wiseman with Macquarie.

I just wanted to ask on the reserve booking. If you could just clarify, it looks like your 1P booking sort of approximates BHP's P50 number and your 2P booking looks like it's the full sort of 11.1 Tcf. Could you maybe just talk through how difficult it is to estimate resource size at the field and what the key drivers will be?

Yes, it's a great question, Mark. So I think everybody on the call will be aware that the Scarborough field was discovered more than 40 years ago and has had a number of wells drilled over time. One of the things that Woodside did in 2018 -- in 2019 after we had taken over operatorship from ExxonMobil was to do really a ground floor assessment of all the data. So we used the most modern seismic processing technology, which is called full waveform inversion seismic processing technology. We looked at all of the raw data and we integrated that into our analysis of the resource. One of the outcomes of that is the 11.1 Tcf that we had booked on a 2P basis. We have had our work very closely reviewed. So we had a number of ExxonMobil folks come in and take a look at the work that our team had done again, just recognizing the magnitude of the change, we wanted to have that external view. We also had our reserves certified by Gaffney, Cline, who does this full time. So we have a great deal of confidence in our reserve booking.

Okay. And so has BHP got access to that data or have they've just taken a more conservative stance on some of the assumptions?

So BHP absolutely has access to all of the work that we have done. Look, I think it's probably worth noting that there are a couple of reasons for the difference in reserves assessment with BHP. Some are what I'll call housekeeping. So the way we handle fuel and flare is a little bit different. The conversion rate that we use is different, again, because of just different reporting basis. But perhaps the points to note is the Scarborough fields are gigantic, 800 kilometers squared in size. That's an area like the size of Singapore. And so when you make assumptions around sand distribution, you can end up -- end up with a bit of different views. And I'll just reiterate, Mark, that we have had our estimates reviewed by Gaffney, Cline who were very supportive of the conclusions that we've drawn.

Okay. I just had a couple of other quick questions. One, just on the lump sum portion of the contract. I think you've said greater than 90% is lump sum or fixed rate. I was wondering could you confirm how much is truly lump sum?

Mark, we haven't commented. We haven't split out those differences.

Okay. Okay. And just on the Domgas marketing, I think you signed 125 terajoules a day to Perdaman. I assume they're poised to take FID shortly now. What are your plans with the other 100 terajoules a day of Domgas capacity?

So probably a couple of numbers just to make sure we're all clear on. So our commitments with the state is to market and make available 15% of our domestic gas. We do have a contract with Perdaman and we look forward to them taking a final investment decision. But one of the things that we need to be mindful of is we may not be ratably producing that 15%. So the domestic gas plant capacity is actually bigger than the 15%. So that's why the domgas plant capacity is the 225 TJs.

Your next question comes from Mark Samter with MST.

I've got quite a few questions, and maybe I'll do 3 at first and then hop on back at the end of the queue. The first one is, can you just -- we keep talking about Scarborough stream of 8 million tonnes and that Pluto 1 can take 3 million tonnes of it. Can you, a, confirm what the nameplate capacity of Pluto 1 will be post the work you're doing on it to be able to take Scarborough gas? Does that capacity drop? And should we expect Scarborough's going to be producing 8 million tonnes into the 2 trains from day 1, and therefore, as we model Pluto, we need to model a very slow dribble out of the Pluto upstream?

Thanks, Mark. Good question. So the intention when we start up Scarborough is that the first 5 million tons will go into Train 2 and the intention is we will really bias the Scarborough gas flows towards Train 2, because Train 2 is being designed for the Scarborough gas composition. When we started the Pluto, it was still online. We'll have co-mingled production through Train 1. And we expect that we'll be producing Scarborough at about 2 million tons through Train 1 in that time period where Pluto is still flowing. Now when Pluto goes off-line, we will be able to increase production from Scarborough up to the 8 million tons. So that's 5 in Train 2 and 3 in Train 1. At that point, we're actually limited by offshore capacity. So the kind of nameplate of Train 1 is a bit academic because you couldn't put more gas through it.

But obviously, new Scarborough facilities are being set up to take third-party gas. So would Train 1 be able to take incremental if you have cash flow other resources lower?

No, absolutely. And it's a great question, Mark. So we will absolutely be out. Now that we've got Scarborough behind us, we'll be talking to other resources around backfill to Pluto Train 1.

Okay. And I guess just because obviously for the ARR you've calculated, you have modeled when Scarborough switches from 6 million tonnes to 8 million tonnes upstream. Can you share that with us?

Sorry, it's from 7 to 8. And it ties when Pluto comes offline and we've not put a date out in the market.

Yes, I guess it's hard for us to back out what that ARR really means about information. Okay. I'll go on to the next question. We keep talking about 60% of volumes being contracted. I found it very hard this morning to trace back through what moved from an HOA to an SPA and obviously, the 60% over your share is on reasonably short-term contracts. Can you please put out for us what volumes are under SPAs and what their durations are that Scarborough is going to be selling into?

Yes, Mark. So I think we've probably communicated these contracts over the course of a few years. Let me start with our domestic gas commitments, so that's with Perdaman chemicals and fertilizers. That's actually a 20-year contract. And that's a very significant contributor to meeting our domestic gas commitments. We've sign the agreements on the LNG side, 3 agreements that are relevant. So 1 with Uniper, which is a 13-year agreement, 1 was Pertamina, which is a 15-year agreement and 1 with RWE, which is a 7-year agreement.

Okay. Okay. So it's less than 60% of the 8 million tonnes of LNG then obviously, is you're kind of over-indexing the domestic contract, and it's obviously only over your 73.5%, but you're really on 100% of the molecules post merger?

So, it's 60% of our 73% or 73.5% working interest today. Obviously, post merger, if we're at 100%, it will be a lower percent. But we do continue with our efforts to sell down our stake in Scarborough, and our targeted final equity position is in around the plus or minus 50% range. And Mark, that should give our shareholders a bit of confidence. We wouldn't want to be over contracted today with the sell-down in process. We want to make sure that we do have the ability to be exposed to spot market, and we do want to have the ability to place additional LNG contracts over the intervening 5 years.

That's a good segue into the last question, I'll do for now. I mean with the GIP deal, you've really done a swapped CapEx for OpEx. So effectively is Woodside you're carrying 100% of the project cost to all intents and purposes. I've never seen it, correct me if you've seen it elsewhere. I've never seen an LNG project anywhere in the world or really any mega project in oil and gas, where you're talking about $10 billion plus project where someone's taken 100% of it to FID. The closest we got was Pluto at 90% and history has probably not judged that project too currently. What did the industry miss? Why didn't they come in? Do you agree that it's fair to say that now on gas business in the world would want to take project to FID at effectively 100% interest? And how did you get comfort around the risks around that?

Let me be really clear, Mark, we're not taking 100%. GIP has come in as a full equity partner at 49%. So they're taking all of the sort of resource risk that any other downstream investor would take. And I think the industry has seen over time look at the U.S. LNG business, for example, you've got players who are really only focused on that processing side of the business and GIP is taking a full 49% equity position. Whilst you can argue that with the merger BHP's views are aligned, if you look at their statements, you look at the rate of return, you look at the delivered cost of supply, and it remains a very competitive project.

Yes. And why weren't you able to sell some down pre-FID? And why is 100% of the upstream shutout because of the merger? Again, can you think of an LNG project in around the world that's done that? It's highly unusual. On a market relative scale, this would be like Exxon sanctioning a $100 million project, 100% owned. I just am keen to understand the risk lens that the business looked at this FID to and why you're happy to FID it, presell them?

Look, Mark, we have great confidence in the quality of the project. It starts with the resource. So we've got great confidence in the quality of the resource, all of the technical work, the execution planning, the detailed design is well underway. We've received feedback from a number of external parties that the maturity for a final investment decision actually is well advanced versus where many other projects would take the decision. So we feel like the risk is very well managed. We do have the Scarborough sell-down process underway. But as we've said before, we want to make sure that we do 2 things. We want a partner that will be a good partner for us for the long term. And we want to make sure that when we sell down Scarborough, it's in a manner that is value accretive for Woodside shareholders. So we will be patient. But one of the things that I think is quite positive is now that we've taken FID, we've got a very clear message to the market that this is a derisked project.

Yes. I guess I'd be keen to understand why you believe Scarborough -- I mean, everywhere as you just said, it's a cookie cutter of every LNG project that's been FID around the world for the last 15 years. They always have 10% to 15% IRRs. They're always largely lump sum and yet they've all been disasters. I guess the proof is going to be in the pudding, but it's just hard to reconcile what we should truly believe, Scarborough's different?

Yes, look, that's -- I actually disagree with your assertion. If you look at Bechtel and you look at how Bechtel has delivered, particularly in the U.S. where they have signed up for those lump-sum turnkey contracts, they have hit the ball out of the park. They deliver on CapEx and they deliver typically ahead of schedule. We've also spent a tremendous amount of time. The COVID pause last year was really useful for us in terms of advancing the design, advancing the procurement strategy, working through the execution planning. So we've got a very, very mature project at the FID gate, which is far ahead of where many other projects would have taken that decision.

Your next question comes from Nik Burns with Jarden Australia.

Congratulations on the announcements late yesterday. Look, my first question is just on the -- probably just following up on Mark about the upstream equity. Maybe on the flip side of that, you're obviously going to end up with 100% upstream equity there following the merger with BHP. You just, I think, mentioned you're going to target upstream equity of 50% longer term, and you're obviously testing the market as we speak, but you do have pretty buoyant LNG markets at the moment, and you've got some, looks like, you put some very strong cash flows coming in from BHP Petroleum's assets. Are you more tempted to hold on to higher levels of equity upstream?

Great question, Nik. No, our intention is and remains to sell down. And again, our target equity position would be in that plus or minus 50% range. A couple of drivers for that. One is we'd like to free up the capital to be able to invest in other opportunities. And when you look at the portfolio of assets that BHP is bringing across in the merger, there are some wonderful opportunities there. So we want to make sure we've got the money available to invest in those opportunities. We also want to make sure we've got the cash available to invest in some of the new energy projects that we've been advancing. So our intention does remain to sell down. It also manages risk. Again, having a partner in the field, I think, will be helpful in terms of having somebody, who can hold us to accounts and give us a bit of that constructive challenge that you get on the technical front from having a joint venture partner.

That makes sense. Is it -- in terms of timing, is it likely you wait until after the merger is completed, just to absolutely confirm you will have 100% upstream equity before you look to complete a sell-down?

No, Nik. The process is underway. And if we get the right offer from the right partner, we would be happy to progress before the merger is completed.

Okay. That makes sense. Look, just my second part is around just the interplay between Pluto Scarborough and Northwest Shelf. So you just mentioned that the plan from start-up of Scarborough to process 7 million tonnes per annum of Scarborough gas until Pluto goes offline and increase it to 8. Why not just push more Pluto gas through to the interconnect to Northwest Shelf and allowed to move straight to 8 million tonnes at Scarborough? It seems like there's a lot of value opportunity there. And I guess beyond the end of Pluto Life, as you mentioned before, you'll have 10 million tonnes of capacity at Pluto. Have you thought about accelerating or expanding your own Scarborough supply? It seems like you could add some pretty low cost LNG capacity for Scarborough there. So why not do that rather than targeting ORO gas?

Great question, Nik. We started running into some physical constraints. So when you asked the question, the first part of the question was Pluto Scarborough blend and Train 1 and should you try to accelerate some to Northwest shelf. Well, we actually have some blending constraints that we need to work with them. So there are some physical constraints around how the plant would operate. And then when you get to the point in time where Pluto is offline, we've actually got physical constraints as well in the upstream with the line pipe capacity. And as it stands, we're installing the biggest -- kind of the biggest diameter pipe that you can physically install, particularly in the deepwater section. And so that ends up being a limiting factor for us.

Your next question comes from Adam Martin with Morgan Stanley.

Sherry, just back on the $6.80 to $5.80. I assume that's due to the CapEx carry, but is that also due to the relative ownership in owning more of upstream versus downstream with different returns in the upstream?

No, that's -- so that's a delivered cost of supply to North Asia number, and so that factors in the full value chain.

Okay. Okay. And then we just -- we haven't touched on Senegal. You've got a divestment process underway. Can you just update on time lines, appetite, how that's going, et cetera?

Yes. It's an ongoing process, Adam. We do have potential investors in the data room. Obviously, we got the process kicked off in kind of the middle of this year after we had closed the transaction with bar. So that sell-down process is underway. And similar to the comments I just made on Scarborough, our goal is to bring in the right partner in a manner that is value accretive to Woodside shareholders. So we continue to work on that sell-down opportunity.

Okay. And final question, just on the 13.5% IRR. I mean are you assuming slopes stay where they've been the last 2 or 3 years? Or are you assuming they're improving, because it looks like we are maybe moving to sales market regarding gas, but just your assumptions behind that, please?

We've not set announced our comments around what we think slips will be. But in the pack, you'll note the oil price that we've used to calculate that rate of return.

Your next question comes from Adrian Prendergast with Morgans Financial.

Yes. Thanks, Meg and team and great announcements. I guess just switching gears a little bit. You obviously can't pick when great asset markets open and close in terms of opportunities for acquisitions. And obviously, we're seeing a lot of opportunities now for global capable players with a bit of balance sheet behind them. How quickly do you think you'd be back in a position where you could look at other acquisitions that maybe complement the BHP portfolio or just bit the Woodside strategy?

It's a great question, Adrian. Look, I think our M&A team is pretty well stretched actually with the work that we've done for the sell-down on GIP with the BHP merger and with the 2 sell-down processes that are underway. Obviously, if somebody brings up and says we've got something for you to look at, we'll take a look. But our plate is pretty full for the very near term.

Yes, that's helpful. And I guess just 1 final further knock-on question from some of the earlier ones around risk profile on the debt return profile for Scarborough and Pluto train 2. Just in terms of -- it looks like you're combating risk around potential inflationary pressures really well, but obviously, a project upstream and downstream of this scale can have quite a lot of slips even just in scope. Just in general terms, I'm not really asking for the integral detail, but how conservative have you been because of some of those factors? Like you mentioned that the share footprint of Scarborough, does that just lead you to be more conservative as an approach? Or do you think it's really just a balanced approach, similar to other projects that we're seeing?

Look, Adrian, I think we've taken a pretty balanced approach. But I say that in the context of particularly the last year. So you'll recall we were working towards an FID in the first half of 2020. We have used the last, call it, 18 months since we put the project on hold when COVID hit last year to do tremendous work maturing the design. So in terms of the quality of the work that underpins this final investment decision, we're in a very strong position.

Great. And just 1 last quick one. Just in terms of the offtake, you started to secure over time for Scarborough Gas. Obviously, we're starting to see some strength coming back into that contracting market, which is great. Just the long-term outlook for the market, do you think -- previously, we were moving to more shorter-term contracts. But do you think we're going to get sort of multi-decade-type offtake? Is that going to ever be realistic again? Or is it more in that sort of 5 to sort of low-teen-type maturities?

Yes, it's a great question, Adrian. A lot of even the longer-term contracts that were historically placed had price review mechanisms in them. And if you kind of think about that as a chance to renegotiate, you scratch your head a little bit about do I want a long contract with the price review or am I better off just having a shorter contract? If you look at the market, there have been some longer duration contracts signed recently. But I think we'll -- it's a bit hard to say. I think we'll see a combination over time. We'll see those 5-, 10-year deals and probably becoming a little bit more prominent than the historic 20-year deals.

Your next question comes from Dale Koenders with Barrenjoey.

A couple of questions. Firstly, just on the guidance around an extended asset life Pluto Train 1. Can you give us a steer for how much of your historical depreciation is onshore and subject to that extension? And when we look at the reserve life of 10 years on Train 1 and 30 -- 20, 30 years on Scarborough, is that the sort of right extension we should be thinking?

Dale, we haven't split out our depreciation mix, and we wouldn't be disclosing that today.

Can you confirm then that the change in depreciation rate is from FID, so there's very little impact to '21?

That is correct. It is from FID. So there'll be a little bit of effect in 2021, but a bigger effect, of course, next year and onwards.

Okay. It could be quite material. On the...

And Dale, just a quick comment. When we issue our Q4 results, we will provide 2022 guidance. And so you'll get a flavor for the impact at that point in time.

Okay. Excellent. Then on the dividends in DRP, noting there's obviously an adjustment mechanism for cash payments from BHP Petroleum through the Woodside premise on the amount of dividends you pay and also share count adjusted DRP. Should we assume DRP continues? And should we assume dividends at the minimum level to really sort of hold on to cash through the merger?

So Dale, our dividend policy remains unchanged. And so our policy is a 50% payout ratio. We've recently been paying out at a higher level than that, but of course, that's subject to Board's discretion. We have used the DRP quite successfully. I don't see any reason to turn that off. We think that is an option that many of our shareholders value. And it's probably worth still putting a bit of context. So the merger effective date is the first of July 2021. So everything we do today is for the interest of our shareholder base that includes today's Woodside shareholders and tomorrow's Woodside shareholders, who are the BHP shareholders of today. So we wouldn't want to be doing anything that would risk loss of value to them. Our shareholders do value the dividend. And so our expectation is that we will continue to follow the dividend policy that's in place.

Okay. And can you give us a steer in terms of, I guess, the wording of the release suggested that there could be a payment from Woodside back to BHP Petroleum. What's your outlook for, I guess, the net cash flow, considering the dividend made good payment and I think the $150 million FID payment, which stated by BHP Petroleum, so it comes back towards you as well. Do you think there will be something big, something small that comes towards yourself?

It'd be premature to guesstimate that, Dale. So as you might imagine, since the effective date was this past July, all of the revenue that is accruing in the BHP Petroleum business and all of the costs that are growing there will be for the merged company's accounts. The dividends that we're paying, we do need to true up, so that the shareholders, who haven't received those payments, do get appropriate compensation, but it would be premature to guesstimate what the net outcome will be.

Your next question comes from Daniel Butcher with CLSA.

I got a few of that, okay. But just the first one is on the CapEx of Pluto 1 of $700 million. Maybe you can clarify first, Meg, I have the understanding that the reason [indiscernible] the gas and go to Northwest Shelf was because it would need modification to take nitrogen rich gas, which would cost a bit of money. So it looks like Pluto 1 is out anyway. Is that -- that's $100 million in nitrogen or something else?

So Daniel, it's worth -- let me clarify, gas is not gas. And I think it's -- you sort of look at the landscape on the Burk and you think you can put any gas in any facility. And unfortunately, it's not that simple. So whilst there are nitrogen content similarities between Scarborough and Pluto, the Scarborough gas is extraordinarily dry. And so the modifications to Train 1 are to be able to handle that extremely dry gas. Now -- and we've looked many times at the possibility of taking Scarborough across to Northwest Shelf. The plants modifications required to do that as volume would be extensive. And for those of you who are concerned around CapEx risk when you're doing that sort of complicated modifications on a live plant, the capital risk is tremendous. So the other issue, of course, with Northwest Shelf is the commercial complexity of trying to negotiate a processing arrangement there. So when we look at it all in, we feel very confident that taking the Scarborough gas across Pluto sites, even with these Train 1 mods is the best investment decision for our shareholders.

Okay. That makes sense. I guess the second one just quickly was, I think you might have demoted WA-404-P from reserves to resource a while ago, because it was being deferred by Scarborough gas. Then now you're saying you need extra gas for Train 1 from other resources. I just trying to reconcile those 2 statements as well. I mean there's 404-P economic and never coming in and not coming in or what sort of situation there?

So 404-P, we moved from reserve to resource last year. A bit of that was in the context of COVID. When we looked at the price outlook, we decided that it was not likely to meet the commerciality threshold at that point in time. One of the things that Scarborough actually helps unlock is it to put the pipeline right past 404-P. So there'll be a point in time where we think 404-P would be backfill coming in through that Scarborough pipeline. So we do, of course, retain that resource, and we will continue to look at means to commercialize it. And that might be one of the options to come in behind Pluto, but a lot of it depends on the kind of technical attributes of that potential development.

Okay. That's helpful. And maybe just 1 -- I mean, probably what Mark was asking about. I had the same question. It looks like with the structure of the GIP sale, you've quite logically for intact fund demand, you're sort of hedged a bit on the construction cost, because you'll be back to probably Act 35, if there's a blowout. So it looks like you haven't really mitigated your CapEx risk at all. You've just got funding from them. I'm just sort of curious, with the toll they charge, is that based -- is it front-loaded? Or is it step down over time once you get past 1P reserves on to producing 2P reserves, for example?

So Dan, we haven't released details of the toll, and that is commercial and confidence. I'll reiterate the point that GIP has taken an equity position. So they do remain exposed to all of the uncertainty around the gas that will be coming through the Train. One of the things that we have with the Bechtel contract is we have a contract where we have high confidence in being able to deliver the project on budget and on schedule. And that was agreed with GIP that since we had agreed that contract, we were the party best placed to manage that risk. I think it's important to also highlight that the cost risk is a 2-way street. So if we come in under, GIP will top-up their payment to us.

Well, that's my point. I mean they are basically fixed entry price to the CapEx, but -- never mind.

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

Great announcements, Meg. Just coming back to the cost of supply from Pluto. I think it's 5.8 or 5.9. You've got 2 numbers in the presentation. Just on that, I just want to confirm because you wouldn't answer on the LNG price, but on the oil price, are you using USD 65 a barrel from 2022 and then just inflating it onwards?

That's correct. It's USD 65 a barrel real terms 2022.

Okay. And I'm just going to jump to Scarborough and on cost risk in developing that field for waveform analysis integrated with the well information, get all that with maps and distribution. But you don't have any new well information that delivered that reserve upgrade. And I guess my big concern regardless of gas decline and others looking at it, is that you do have some risk in terms of reservoir distribution and productivity and quality of those sands as you develop that field. I'm just wondering what the view is on that. You just sound extremely confident in the number, and I just find it amazing that we've got such a big reserve upgrade without drilling any new wells. So I guess the question comes down to how you're going to manage that risk going forward, if there are cost overruns or increases for additional wells required if, for instance, the sand is not distributed to the degree you expect or the seismic hasn't defined it properly?

I mean it's a good question, Gordon. But resource risk is the -- one of the core attributes of the oil and gas industry. So resource -- there is a range of resources. And as we get more data, we will learn more about the field. But I think it really is important to highlight that the work our team has done is orders of magnitude, more sophisticated than what had been done by the previous joint venture. The -- whilst there were no wells -- no new wells drilled, the seismic reprocessing really does give a very different picture of the reservoir than using data that was more than a decade old. And as part of the project, we're going to shoot another seismic survey very early on ahead of any drilling that will allow us to even further sharpen the pencil, because we'll shoot at a higher resolution than the historic seismic data we have. And we will -- as we start drilling wells and producing the field, we'll get more information that will help us narrow the range of uncertainty and sharpen the ultimate estimates.

Okay. And just 1 last one for me. Just on -- and I know I've asked you this before, the this before, I'm just trying to understand how much Pluto gas is going to go to the Northwest shelf, because you seem to imply today equivalent of 5 million tons will go to Pluto Train 2 and then another 3 to Pluto Train 1, but you didn't make any comment about the Northwest shelf and is there a capacity to take 1.5 million tons equivalent to Northwest Shelf and won't use that?

Gordon, just to clarify, are you asking about Pluto gas to Northwest Shelf or Scarborough Gas?

Sorry, Scarborough or both, sorry. Yes, I'm just trying to understand the mix and how that's going to work going forward. Initially, it sounds like all the Scarborough gas is going to Pluto Train 2 and 1. And you're going to accelerate Pluto gas into the Northwest Shelf as well, up to 1.5 million tons. Just trying to understand that mix, how it evolves over time.

Yes. So let me start with -- let me work it through chronologically. So we will start flowing Pluto gas down the interconnector next year at a rate of approximately 1 million tons per year. We have a contract between Pluto and Northwest Shelf that runs for 4 years. So we'll be able to take gas across and increase our revenue during the period of high capital spend for both Sangomar and Scarborough. After that, there's no agreements in place. So the pipe, of course, will be in place, but we do not currently intend to take any Scarborough gas down the pipeline. And as I commented to your previous question, there are some technical complexities around how much gas we can flow through various pipes at various points in time.

Your next question comes from Saul Kavonic with CS.

Congrats on the FID. A few quick questions, if I may. But the main question I'd have is, I think with Scarborough being probably a cornerstone growth project plan for Woodside over the last 5 years. What's next in terms of growth projects after this one? Browse still seems on the back burner, most of the Woodside portfolio still seems on the back burner. Where is the next growth? The market you get excited about and what timing for announcements and catalysts and that can we next expect over the next 12 to 24 months?

Well, thanks, Saul. We actually like to just sort of celebrate the moment of Scarborough and Pluto for a day or 2. But look, in terms of what's next, one of the things we're doing as part of the integration planning work is pulling together the opportunities that are in the BHP Petroleum hopper, integrating those with the opportunities that are in the Woodside hopper. And doing a bit of kind of comparative assessment of how those different opportunities stack up to help inform our decisions around what is next.

All right. Is it possible in just kind of timing on when we might be able to get more color on that? Is that something we'll get more color on in the investor briefing next month. We need to wait for after the merger closes in the second half of next year until we can get more clarification on the priorities on the growth funnel?

So in the investor briefing in December, one of the things we want to talk about is strategically, how are we going to think about the business. We'll want to talk about our capital allocation philosophy. And that should hopefully give the market a bit of a framework to understand how are we thinking about things and how will we assess them. But I think it would be premature for us to put dates out in the market saying we want to take Project X or project Y to a decision point at a particular point in time.

I guess my second question is just confirming on the economics you put out on Scarborough last night. The breakeven as those are incremental economics that after factoring in any impact negative or otherwise on the Pluto production profile, et cetera?

So Saul, it absolutely is incremental. So if you sort of run our business as it stands and then you run the differential case of Scarborough coming in with -- there is a bit of Pluto curtailment when Scarborough starts up, of course. So it is differential and it does look at the totality of our business.

And last question is just on the LNG contracting. Obviously, we constantly get a lot of questions on it. And we all have different views on the LNG versus oil outlook, but I just want to get a sense of you, if you were to contract those remaining volumes in Scarborough today under term deals versus over the last 12 to 24 months, would you be getting better pricing contracting that today than doing it with there's pressure to do so over the last 2 years? Has it been worthwhile waiting on those contracts?

Well, based on where the LNG market was last year versus now, I'd rather be on the market now. I mean it's a bit of human behavior. So last year, what we saw during COVID was more supply than demand, and prices fell and buyers probably got a little complacent thinking the market was infinitely deep. But what we're seeing now, of course, is significant tightness in the market. Prices are at unprecedented levels and have remained at those unprecedented levels. So certainly now is a better time to be contracting. And there are buyers who last year told us that they were less interested, who are calling. But the reality is we feel pretty good about our contracting position today. We get a really compelling opportunity from a quality buyer, we'll take a real hard look at that. But with the sell-down in process, we do need to make sure we don't get over contracted on the sales side. So I think we've got time for about 1 last question.

Your final question is a follow-up question from Mark Samter with MST.

Just 2 quick questions, if I can. First of all, Meg, I guess it's no great secret about some of the conflicts with the Northwest Shelf and your predecessor called a couple of them in La La land last year, I think it was. Can we just very explicitly say if we get no more gas into the Northwest Shelf, which I would personally is going to be harder to do after decision to take Scarborough to Pluto is obviously going to irritate some of that. When is the Woodside view that we'll have to start closing trains at the Northwest Shelf with no incremental from Scarborough gas?

So Mark, I answered this question in last year's investor briefing that 2024 notionally is when we would likely be shutting in the first train. But I think it's worth maybe correcting the records or kind of being clear, I think the Northwest shelf today is working very effectively together as a venture. It was a challenging road for us to get those early ORO deals in place. But I think we're at a point now where we've got a good understanding of what everybody is looking for out of the venture. I think there is clarity that we do need to be out in the marketplace looking for additional gas to come through the plants. So I feel pretty good actually about how things are going in the Northwest Shelf today.

And then just a final one maybe for Sherry and Sherry, congratulations on the new role. Just on the dividend and the need to pay BHP a commensurate proportional dividend. My logic could be flawed, and I'm happy to be told my logic is flawed. But it strikes to me that Woodside shareholders will be better off as you pay no dividend in February because of the splits that would go to. Is there a contractual commitment to BHP to have to pay a level of dividend in February?

Mark, thank you for that. And I think Meg has probably already have answered that one earlier by saying that the effective date of the transaction really is in the middle of 2021. And so we'll be looking to fairly and equitably reward all shareholders of combined entity as it comes together over that period. So we won't be looking to play any tricks there to try to optimize in the short term, we'll be looking at the long term and what is the best dividend for our combined shareholder base.

All right. Thanks, everyone, for taking the time to participate in this call. As an early advertisement and a note for your diary, we will be holding an update on Woodside's strategy and value proposition on the 8th of December. This will be a virtual event, and further details will be released to the ASX closer to that date. I look forward to speaking with you then, and thanks again for your interest today.

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