Thank you for standing by, and welcome to the Woodside Petroleum Limited Scarborough final investment decision presentation. All participants are in a listen-only mode. There will be a presentation followed by a question-and-answer session. If you wish to ask a question, you will need to press the star key followed by the number one on your telephone keypad. I would now like to hand the conference over to 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 two 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 one 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 two months, in addition to negotiating the share sale agreement, 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 one.
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 two, advising that this presentation does include some forward-looking statements and that our reported numbers are all in US dollars unless otherwise indicated. Let's start with a summary of what the developments will deliver on slide three. 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 equivalent. 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 is 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 four contains a range of the key project data. The onshore development will process 5 million tons per annum of LNG through the new Pluto Train 2, plus up to 3 million tons per annum through the existing Pluto Train 1. The development also delivers 225 TJ per day of new domestic gas capacity.
In August this year, we announced an updated cost estimate of $12.0 billion on a 100% basis, comprising $5.7 billion for the offshore component and $6.3 billion for the onshore component. 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 developments.
Importantly, the internal rate of return for the integrated development is greater than 13.5%. As I've said before, Scarborough is 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 six years. Slide five contains a conceptual image of the full integrated development. The offshore development comprises the floating production unit, which will develop the large reservoir through eight wells initially and 13 over the field life. Scarborough gas will be transported by a new approximately 430 km trunk line 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 six, which provides a more detailed view of the optimized and mature offshore development and shows 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 seven. This contains a detailed view of the onshore development. Pluto Train 2 will run on Optimized Cascade operating on a lower emissions intensity, and we have already awarded the engineering procurement and construction contract to Bechtel. The onshore development utilizes the shared, existing 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 eight, 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 that 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 nine 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 three key pillars of our decarbonization strategy.
In many cases, it not only reduces emissions, but also cuts costs and increases production of saleable 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 kt 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 point 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 decisions. 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 costs. 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 five 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 project are McDermott for the FPU, Subsea Integration Alliance for the subsea hardware, risers and flowlines, Valaris for drilling, and EUROPIPE, Boskalis, and Saipem for 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 to rise and fall mechanisms for labor costs. 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 wanna 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 ton per annum development.
We have taken steps to de-risk 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 $5.80 per MMBTU, and an approximate six 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 development 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 this session to your questions.
The first question today comes from Tom Allen with UBS. Please go ahead.
Morning, Meg, and congratulations on the two announcements overnight. I was just hoping you could please clarify the change in the Scarborough economics that are arising from the FID. The IRR is 150 basis points 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. 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. We've gone from 100% to 51%, including the additional funding from GIP of approximately $835 million, significantly improves our economic metrics. We think it's a very attractive project.
Yeah, does make sense. Just making sure there was nothing else missing there. The high-level merger terms released overnight referred to certain legacy assets and liabilities from BHP's petroleum business that will remain with BHP. Could you please clarify what these are?
Yeah. 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. They've bought and sold assets over time. 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, thanks for that. Then just the last one was, with Scarborough now sanctioned and post-merger, Woodside will own a third of the North West Shelf, could you just share the plan to better utilize and backfill North West Shelf going forward? Following that five-year contract to accelerate Pluto via the interconnector across to the Karratha gas plant, interested also how that new pipeline might be utilized beyond that initial five years.
Yeah, it's a great question, Tom, and obviously with the offshore resource being now in decline for North West Shelf, we are very keen to keep the plant as full as we possibly can. Last year we signed the early ORO agreements between North West Shelf and Pluto and between North West Shelf and Waitsia to be able to start processing gas from those resource owners on a tolling basis through the North West Shelf. North West Shelf joint venture continues to actively solicit gas from other potential shippers. There's, you know, more conversations in that way, but the current terms that have been agreed are for that limited time period from Pluto.
Okay. Thanks, Meg. Congratulations again.
Thanks, Tom.
Thank you. Your next question comes from Mark Wiseman with Macquarie. Please go ahead.
Oh, yeah. Hi, Meg. Thanks for taking the question. 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 11.2 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?
Yeah, it's a great question, Mark. 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 2019 after we had taken over operatorship from ExxonMobil was to do really a from the ground up assessment of all the data. 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 have booked on a 2P basis.
We have had our work very closely reviewed, so we had a number of ex-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. We have a great deal of confidence in our reserve booking.
Okay, thank you. Has BHP got access to that data or have they just taken a more conservative stance on some of the assumptions?
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 our reserves assessment with BHP. Some are what I'll call kind of housekeeping. 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 bases. Perhaps the points to note is the Scarborough fields are gigantic, 800 sq km in size. That's an area like the size of Singapore. When you make assumptions around sand distribution, you can end up with a bit of different views.
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, thank you. 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. Just on the DomGas marketing, I think you'd signed 125 TJ a day to Perdaman. I assume they're poised to take FID shortly now. What are your plans with the other 100 TJ a day of DomGas capacity?
Probably a couple of numbers just to make sure we're all clear on. Our commitment 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. One of the things that we need to be mindful of is we may not be ratably producing that 15%. The domestic gas plant capacity is actually bigger than the 15%. That's why the DomGas plant capacity is the 225 TJs.
Okay, great. Thanks very much.
Thank you.
Thanks, Mark.
Your next question comes from Mark Samter with MST. Please go ahead.
Yeah, morning, Sherry. I've got quite a few questions, so maybe I'll do three 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 upstream being 8 million tons and that Pluto 1 can take 3 million tons of it. Can you, A, confirm what the nameplate capacity of Pluto One will be post the work you're doing on it to be able to take Scarborough gas? Does that nameplate capacity drop? And should we expect Scarborough is gonna be producing 8 million tons into the two trains from day one, and therefore, as we model Pluto, we need to model a very slow dribble out of the Pluto upstream?
Thanks. Thanks, Mark. A good question. 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 'cause Train 2 is being designed for the Scarborough gas composition. When we start up and Pluto is still online, we'll have commingled 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 offline, we will be able to increase production from Scarborough up to the 8 million tons. So that's five in Train 2 and three in Train 1. At that point, we're actually limited by offshore capacity.
The, you know, kind of nameplate of Train 1 is a bit academic because you couldn't put more gas through it.
Obviously new set of facilities are being set up to take third-party gas. Would Train 1 be able to take incremental if you had gas from other resources flowing in?
Oh, absolutely. You know, it's a great question, Mark. We will absolutely be out. Now that we've got Scarborough behind us, we'll be out talking to other resources around gas backfill to Pluto Train 1.
Okay. I guess just 'cause obviously for the IRR you've calculated, you had modeled when Scarborough switches from 6 million tons to 8 million tons upstream. Can you share that with us?
Sorry, it's from seven to eight, and it ties with when Pluto comes offline, and we've not put a date out in the market.
Yeah, I guess it's just hard for us to back out what that RR really means without knowing the information you know. Okay, I'll go 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% is over your share, and it's only reasonably short-term contracts. Can you please spell out for us what volumes are under SPAs and what their durations are that Scarborough's gonna be selling into?
Yeah, Mark, I think we've probably communicated these contracts over the course of a few years. Let me start with our domestic gas commitment, that's with Perdaman Chemicals and Fertilisers. That's actually a 20-year contract, and that's a very significant contributor to meeting our domestic gas commitment. We've signed the agreements on the LNG side, three agreements that are relevant. One with Uniper, which is a 13-year agreement, one with Pertamina, which is a 15-year agreement, and one with RWE, which is a seven year agreement.
It's less than 60% of the 8 million tons of LNG, though, obviously, isn't it? You're kind of over-indexing the domestic contract. It's obviously only over your 73.5%, but you really own 100% of the molecules post-merger.
It's 60% of our 73% or 73.5% working interest today. Obviously, post-merger, if we're at 100%, it'll be a lower percent. We do continue with our efforts to sell down a stake in Scarborough, and our targeted final equity position is in around the ±50% range. Mark, that should give our shareholders a bit of confidence. You know, we wouldn't want to be over-contracted today with a sell down in process. We wanna make sure that we do have the ability to be exposed to spot market, and we do wanna have the ability to place additional LNG contracts over the intervening five years.
Okay. Actually, that's a good segue into the last question I'll do for now. I mean, with the GIP deal, all you've really done is swapped CapEx for OpEx. Effectively, as Woodside, you're carrying 100% of the project costs 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 a $10 billion plus project where someone's taking 100% of it to FID. The closest we got was Pluto at 90%, and history's probably not judged that project too kindly. What did the industry miss? Why didn't they come in?
Did you agree that it's fair to say that no oil and gas business in the world would want to take a project to FID at effectively 100% interest? How did you get comfort around the risks around that?
Well, 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, you know, all of the sort of resource risk that any other downstream investor would take. And I think the industry has seen over time, you know, 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. While 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.
Yeah. Why weren't you able to sell some down pre-FID, and why was 100% of the upstream equity because of the merger? Again, can you think of an LNG project anywhere in the world that's done that? It's highly unusual. You know, on a market cap relative scale, this would be like Exxon sanctioning a $100 billion project, 100% owned. I'm keen to understand the risk lens that the business looked at this FID through and why you were happy to FID it pre-sell down.
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. You know, 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. We feel like the risk is very well managed. We do have the Scarborough sell down process underway. As we've said before, we wanna make sure that we do two things.
We want a partner that will be a good partner for us for the long term, and we wanna make sure that when we sell down Scarborough, it's in a manner that is value accretive for Woodside shareholders. We will be patient. 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 de-risked project.
Yeah. I guess I'll be keen to understand why you believe Scarborough's. I mean, every word you've just said is a cookie cutter of every LNG project that's been FID around the world for the last 15 years. They always have 10%-15% IRRs. They're always largely lump sum, and yet they've all been disasters. I guess the proof's gonna be in the pudding, but it's just hard to reconcile why we should truly believe Scarborough's different.
Yeah. Well, 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. You know, 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.
Okay. Thanks. I'm gonna hop back on the end of the call, so perhaps I'll get Alain back on.
All right. Thanks, Mark.
Thank you.
Thank you. Your next question comes from Nik Burns with Jarden Australia. Please go ahead.
Oh, thanks. Hi, Megan, team, and congratulations on the announcement late yesterday. Look, my first question, probably just following up on Mark around the upstream equity. Maybe on the flip side of that, you're obviously gonna end up with 100% upstream equity there following the merge with BHP. You just, I think mentioned you're gonna 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 looks like you could have 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, Nick. No, our intention is and remains to sell down. Again, our target equity position would be in that ±50% range. Couple of drivers for that, Nick. One is, we'd like to free up the capital to be able to invest in other opportunities. When you look at the portfolio of assets that BHP is bringing across in the merger, there are some wonderful opportunities there, so we wanna make sure we've got the money available to invest in those opportunities. We also wanna make sure we've got the cash available to invest in some of the new energy projects that we've been advancing. Our intention does remain to sell down. It also manages risk.
You know, again, having a partner in the field, I think, will be helpful in terms of having somebody who can, you know, hold us to account 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'll wait until after the merger is completed just to absolutely confirm you'll have 100% upstream equity before you look to complete a sell-down?
No, Nick. The process is underway. If, you know, 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 North West Shelf. You just mentioned that the plan from startup for Scarborough is to process 7 million tons 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 North West Shelf and allow it to move straight to 8 million tons at Scarborough? It seems like there's a lot of value opportunity there. I guess beyond the end of Pluto life, as you mentioned before, you'll have 10 million tons 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.
Why not do that rather than targeting ORO gas?
Great question, Nick. We start running into some physical constraints. When you ask the question, the first part of the question was Pluto, Scarborough blend in Train 1 and, you know, should you try to accelerate some to North West Shelf? We actually have some blending constraints that we need to work within. There are some physical constraints around how the plant would operate. 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. As it stands, we're installing the biggest diameter pipe that you can physically install, particularly in the deep water section. That ends up being a limiting factor for us.
Got it. Thanks, Meg. Cheers.
Thanks, Nik.
Thank you. Your next question comes from Adam Martin with Morgan Stanley. Please go ahead.
Morning, Meg, Sherry. Just back on the 6.8%-5.8%, 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 a delivered cost of supply to North Asia number, and so that factors in the full value chain.
Okay. We haven't touched on Senegal. You've got a divestment process underway. Can you just update on timelines, you know, appetite, how that's going, et cetera?
Yeah, it's an ongoing process, Adam. You know, we do have potential investors in the data room. You know, obviously, we got the process kicked off in kind of the middle of this year after we had closed the transaction with FAR. That sell-down process is underway. You know, 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. We continue to work on that sell-down opportunity.
Okay. Final question, just on the 13.5% IRR, I mean, are you assuming slopes stay where they've been the last two or three years, or are you assuming they're improving? Because it looks like we are maybe moving to seller's market regarding gas, but just your assumptions behind that, please.
Adam, we've not put out our comments around what we think slopes will be, but in the back, you'll note the oil price that we've used to calculate that rate of return.
Okay. No detail. That's all right. All right. Thanks for that. That's all for me.
Thanks, Adam.
Thank you. Your next question comes from Adrian Prendergast with Morgans Financial. Please go ahead.
Yes, thanks, Meg and team, and great announcements. I guess just switching gears a little bit, you obviously can't pick when you know great asset markets open and close in terms of opportunities for acquisitions. Obviously, we're seeing a lot of opportunities now for you know 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 fit 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 two sell down processes that are underway. Obviously, if you know, if somebody rings 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.
Yeah, that's helpful. I guess just one final further knock-on question from some of the earlier ones around risk profile on the that return profile for Scarborough and Pluto Train 2. Just in terms of looks like you're combating, you know, risk around potential inflationary pressures really well. Obviously a project upstream and downstream of this scale can have a lot of slip even just in scope. Just in general terms, I'm not really asking for the internal detail, but yeah, how conservative have you been because of some of those factors? Like you mentioned that the sheer footprint of Scarborough. Does that just lead you to be more conservative as an approach?
Do you think it's really just a balanced approach that's 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. 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. In terms of the quality of the work that underpins this final investment decision, we're in a very strong position.
Great. Just one last quick one. Just in terms of the offtake you've 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, you know, previously we were moving to more short-term contracts, but do you think we're gonna get sort of multi-decade type offtake? Is that gonna ever be realistic again, or is it more in that sort of 5 to sort of low-teens type year maturities?
Yeah, it's a great question, Adrian. You know, a lot of even the longer term contracts that were historically placed had price review mechanisms in them. If you kinda think about that as a chance to renegotiate, you scratch your head a little bit about, do I want a long contract with a price review or am I better off just having a shorter contract? If you look at the market, you know, there have been some longer duration contracts signed recently. I think it's a bit hard to say. I think we'll see a combination over time. You know, we'll see those, you know, five, 10-year deals, probably becoming a little bit more prominent than the historic 20-year deals.
Thanks. That's great.
Thank you. Your next question comes from Dale Koenders with Barrenjoey. Please go ahead.
Good morning. A couple questions. Firstly, just on the guidance around an extended asset life, so Pluto Train 1. Can you give a steer for how much of your historical depreciation is onshore and subject to that extension? And when we look at the reserves life of 10 years on Train 1 and 30 years, you know, 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 that then that the change in depreciation rate is from FID, so there's very little impact to 2021?
That is correct. It is from FID. There'll be a little bit of effect in 2021, but a bigger effect, of course, next year and onwards.
Okay. Could be quite material.
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. On to dividends and DRP. Noting there's obviously an adjustment mechanism for cash payments from BHP Petroleum through to Woodside, premised on the amount of dividends you pay and also share count adjusted to DRP. Should we assume DRP continues? Should we assume dividends at the minimum level to really sort of hold on to cash through the merger?
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 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. It's probably worth, Dale, putting a bit of context. The merger effective date is the first of July 2021. 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. We, you know, wouldn't want to be doing anything that would, you know, 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. Can you give 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 flows, considering the dividend make good payment and the I think $150 million FID payment which stays with BHP Petroleum, so comes back towards you as well. Do you think there'll be something big, something small that comes towards yourself?
It'd be premature to guesstimate that, Dale. As you might imagine, since the effective date was this past July, all of the revenue that BHP Petroleum business and all of the costs that are accruing 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, you know, do get appropriate compensation. But it would be premature to guesstimate what the net outcome will be.
Okay. Thanks, Meg.
Thanks, Dale Koenders.
Thank you. Your next question comes from Daniel Butcher with CLSA. Please go ahead.
Hi, everyone. Got a few, if that's okay. Just the first one's on the CapEx of Pluto 1 of $700 million. Maybe you clarify for us, Meg. I was under the understanding that the reason or part of the reason the gas didn't go to Northwest Shelf was because it would need modification to take nitrogen rich gas, which would cost a bit of money. It looks like Pluto 1 needs that anyway. Is that $700 million in nitrogen or something else?
Daniel, it's worth. Let me clarify. Gas is not gas, and I think it's you know, you sort of look at the landscape on the Burrup, and you think you can put any gas in any facility, and unfortunately, it's not that simple. Whilst there are nitrogen content similarities between Scarborough and Pluto, the Scarborough gas is extraordinarily dry. The modifications to Train 1 are to be able to handle that extremely dry gas. We've looked many times at the possibility of taking Scarborough across to North West Shelf. The plants modifications required to do that at volume would be extensive. You know, 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.
The other issue, of course, with NorthWest Shelf is the commercial complexity of trying to negotiate a processing arrangement there. 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. Thank you. 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 resource centers. I'm just trying to reconcile those two statements as well. I mean, is 404P economic and never coming in or and not coming in or what's the sort of situation there?
404P, 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 thresholds at that point in time. One of the things that Scarborough actually helps unlock is it puts a pipeline right past 404P. There'll be a point in time where we think 404P would be backfill coming in through that Scarborough pipeline. We do, of course, retain that resource, and we will continue to look at means to commercialize it. That might be one of the options to come in behind Pluto, but a lot of it depends on the kinda technical attributes of that potential development.
Okay. That's helpful. Thank you. And maybe just one. I mean, following on what Mark was asking about, I have the same question. It looks like with the structure of the GIP sale, that quite logically for an infrastructure fund demanded, you sort of hedge them a bit on the construction cost, because you'll give back probably $835 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 does it step down over time once you get past 1P reserves onto producing 2P reserves, for example?
Dan, we haven't released details of the toll, and that is commercial in confidence. I'll reiterate the point that GIP has taken an equity position. 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. 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 two-way street. If we come in under, GIP will top up their payment to us.
Well, that was my point. I mean, they basically have a fixed entry price for the CapEx, but, never mind. I've got other questions. I'll jump back into queue, though. Let someone else have a go. Thanks.
Thanks, Daniel.
Thank you. Your next question comes from Gordon Ramsay with RBC Capital Markets. Please go ahead.
Oh, thank you very much. Great announcements, Meg. Just coming back to the cost of supply from Pluto, I think it's $5.8 or $5.9. You got two numbers in the presentation. Just on that, I just wanna confirm, 'cause you wouldn't answer on the LNG price, but on the oil price, are you using U.S. $65 a barrel from 2022 and then just inflating it onwards?
That's correct. It's $65 a barrel real terms 2022.
Okay. I'm just gonna jump to Scarborough and on cost risk in developing that field. You know, full waveform inversion integrated with the well information, get all that. You've mapped the sand distribution, but you don't have any new well information that delivered that reserve upgrade. 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, you know, what the view is on that. You just sound extremely confident in the number, and I just find it amazing that you've got such a big reserve upgrade without drilling any new wells.
I guess the question comes down to how you're gonna manage that risk going forward if there are cost overruns or increases for additional wells required, if, for instance, the sand's not distributed to the degree you expect or the, you know, the seismic hasn't defined it properly.
I mean, it's a good question, Gordon, resource risk is kind of one of the core attributes of the oil and gas industry. Resource, there is a range of resources, and as we get more data, we will learn more about the field. 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. 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. As part of the project, we're going to shoot another seismic survey very early on ahead of any drilling.
That'll allow us to even further sharpen the pencil 'cause we'll shoot at a higher resolution than the historic seismic data we have. We will, you know, as we start drilling wells and producing the field, we'll get more information that'll help us you know, narrow the range of uncertainty and sharpen the ultimate estimates.
Okay, thanks. Just one last one from me. Just on, I know I've asked you this before. I'm just trying to understand how much Pluto gas is gonna go to the North West Shelf, 'cause you seem to imply today that, you know, equivalent of 5 million tons will go to Pluto Train 2 and then another three to Pluto Train 1, but you didn't make any comment about the North West Shelf and isn't there capacity to take 1.5 million tons equivalent to North West Shelf, and won't you use that?
Gordon, just to clarify, are you asking about Pluto gas to North West Shelf or Scarborough gas?
Sorry, Scarborough. Well, both, sorry. Yeah, 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 1, Train 2 and 1. You're gonna accelerate Pluto gas into North West Shelf as well, up to 1.5 million tons. Just trying to understand that mix, how it evolves over time.
Yeah. Let me start with. Let me work through it chronologically. 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 North West Shelf that runs for four years. 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. The pipe, of course, will be in place, but we do not currently intend to take any Scarborough gas down the pipeline. 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.
Okay. Thank you.
Thank you.
Thanks, Gordon.
Your next question comes from Saul Kavonic with CS. Please go ahead.
Good morning, Meg. Congrats on the FID. A few quick questions, if I may. The main question I'd have is, I think, you know, with Scarborough being probably a cornerstone growth project plank for Woodside over the last five years, what's next in terms of growth projects after this one? You know, Browse still seems on the back burner. Most of the Woodside portfolio still seems on the back burner. Where's the next growth the market should get excited about, and what timing for announcements and catalysts from that can we next expect over the next two, you know, 12-24 months?
Well, thanks, Saul. We'd actually like to just sort of celebrate the moment of Scarborough and Pluto for a day or two. 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 a kind of comparative assessment of how those different opportunities stack up to help inform our decisions around what is next.
All right. Thanks. Is it possible to get any 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 till after the merger closes in the second half of next year until we can get more clarification on the priorities on the growth funnel?
Saul, 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. 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. I think it'd be premature for us to, you know, put dates out in the market saying we wanna take Project X or Project Y to a decision point at a particular point in time.
Thanks. I guess my second question is just confirming on the economics you put out on Scarborough last night for break-evens and MIRRs. Can I just confirm, those are incremental economics, but after factoring in any impacts, negative or otherwise, on the Pluto production profile, et cetera?
Saul, it absolutely is incremental. 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. It is differential, and it does look at the totality of our business.
Thanks. 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 from you, if you were to contract those remaining volumes in Scarborough today under term deals versus over the last 12-24 months, you know, would you be getting better pricing contracting that today than, you know, doing it, when there was pressure to do so in 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 out in the market now. I mean, it's a bit of human behavior. 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. What we're seeing now, of course, is a significant tightness in the market. Prices are at unprecedented levels and have remained at those unprecedented levels. You know, 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, you know, we feel pretty good about our contracting position today.
You know, if we get a really compelling opportunity from a quality buyer, you know, we'll take a real hard look at that. With the sell down in process, you know, we do need to make sure we don't get over-contracted on the sales side.
I think we've got time.
That's it. That's it for me.
Sorry. I think we've got time for about one last question.
That's it for me. Congrats again. Yeah, and do celebrate with some good margaritas.
All right. Thank you, Saul.
Thank you.
Your final question is a follow-up question from Mark Samter with MST. Please go ahead.
Thanks. Just two quick questions, if I can. First of all, Meg, I guess it's no great secret about some of the conflicts with the North West 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 North West Shelf, which I would personally argue is gonna be harder to do after decision to take Scarborough to Pluto is obviously gonna irritate some of them. When is the Woodside view that we'll have to start closing trains at the North West Shelf with no incremental third-party gas through it?
Mark, Fiona answered this question in last year's investor briefing that 2024 notionally is when we would likely be shutting in a first train. I think it's worth you know maybe correcting the records or kind of being clear. I think the North West 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. I think we're at a point now where we've got a good understanding of what everybody's 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. I feel pretty good actually about how things are going in the North West Shelf today.
Thanks. Just a final one maybe for Sherry. 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 me that would our shareholders be better off if you paid no dividend in February because of the split that would go to it? Is there a contractual commitment to BHP to have to pay a level of dividend in February?
Mark, thank you for that. I think, you know, Meg has probably already halfway answered that one earlier by saying that the effective date for the transaction really is in the middle of 2021, and so we'll be looking to fairly and equitably reward all shareholders of the combined entity as it comes together over that period. 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.
Okay. Cool. Thank you.
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 eighth 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.