Scarborough FID Teleconference Transcript
DISCLAIMER: This transcript has been prepared by a third party for Orient Capital Pty Ltd. It may not be accurate or complete and should be verified directly with the issuer. Orient Capital Pty Ltd is not responsible for any consequences of the use you make of the information contained in this transcript, including any loss or damage you or a third party might suffer as a result of that use. Company: Woodside Petroleum Ltd Title: Scarborough FID Teleconference Transcript Date: 23 November 2021 Time: 08:00 AWST / 11:00 AEDT Start of Transcript Operator: Thank you for standing by and welcome to the Woodside Petroleum Ltd, 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 and please go ahead. Meg O’Neill: 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 their elders past, present and emerging. I also extend my respect to all other Aboriginal nations, the future generations and their continued connection to country. 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 17 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 split, 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 2, advising that this presentation does include some forward-looking statements and that our reported numbers are all in US dollars, unless otherwise indicated. 2 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 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’ve 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 decarbonisation 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 US$12.0 billion on a 100% basis, comprising US$5.7 billion for the offshore component and US$6.3 billion for the onshore component. With the selldown of 49% of Pluto Train 2, Woodside’s share of the total capital expenditure has decreased to US$6.9 billion. The expected returns from this project are significant. Since the cost update in August and the selldown 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 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 5 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 kilometre trunkline to the Pluto LNG facility near Karratha in the north west 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. Onto Slide 6 which provides a more detailed view of the optimised 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 onto Slide 7. This contains a detailed view of the onshore development. Pluto Train 2 will run on Optimised Cascade technology operating on a lower emissions intensity and we have already awarded the engineering procurement and construction contracts to Bechtel. The onshore development utilises the 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 3 gas intensity compared to the international average and Australian average. We expect that LNG produced from Scarborough will be a contributor to the decarbonisation 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 three key pillars of our decarbonisation 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 kilotonnes 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 emphasise 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 realise a 15% reduction in net emissions by 2025 and 30% by 2030 even with adding Scarborough production to the portfolio. Onto 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 capitalise borrowing costs from FID to start-up, reducing net finance costs. Moving onto Slide 11. This is a stylised and indicative graph of what our capital spend will look like for Scarborough across the next five to six years with our first cargo targeted for 2026. The intention of this stylised chart is to demonstrate how peak capital spend in 2023 is matched to some of the key workstreams 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 at today, 90% of the total development contractor spend is lump sum or on a provisional sum basis [Clarification: lump sum or on a fixed rate basis]. Onto 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 of 2022 and we have agreed the rise and fall mechanisms for labour 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 de-risk the developments and are making strong progress as we move into the execute phase, targeting first cargo in 2026. 4 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 US$5.80 per MMBtu and an approximate six year payback period. This is expected to deliver significant cashflow 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 this session to your questions. Operator: Thank you. If you wish to ask a question, please press star 1 on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star 2 and if you are on a speaker phone, please pick up the handset to ask your questions. Your first question today comes from Tom Allen with UBS. Please go ahead. Tom Allen: (UBS, Analyst) 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? So the IRR is 150 basis points higher, the breakeven cost to supply to north Asia on a DES basis looks about 15% lower. I just wanted to confirm if it was the lower capex from the Train 2 selldown driving that change and if you could break out the moving parts please? Meg O’Neill: Well, thanks Tom. Great question. The key driver for the improvement in the economic metrics is the selldown of our participating interest in Train 2. So we’ve gone from 100% to 51% including the additional funding from GIP of approximately US$835 million, significantly improves our economic metric. So we think it’s a very attractive project. Tom Allen: (USB, Analyst) Yes, it does make sense. Just making sure there was 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? Meg O’Neill: 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’s shareholders from any assets that might have been sold in the past to ensure that we don’t have any exposure [Clarification: Certain liabilities in connection with certain specified assets sold by BHP will remain with BHP]. Tom Allen: (USB, Analyst) Okay. 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 utilise and backfill North West Shelf going forward? So 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 utilised beyond that initial five years? Meg O’Neill: Yes, 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. So 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. So there is you know more conversations in that way, but the current terms that have been agreed are for that limited time period from Pluto. 5 Tom Allen: (USB, Analyst) Okay. Thanks Meg and congratulations again. Meg O’Neill: Thanks Tom. Operator: Thank you. Your next question comes from Mark Wiseman with Macquarie. Please go ahead. Mark Wiseman: (Macquarie Group, Analyst) Oh, yes. 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 11.1 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? Meg O’Neill: 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 - well, 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 have booked on a 2P basis [Clarification: Woodside booked on a 2P basis its 73.5% interest in the 11.1 Tcf field, being 1,433 MMboe]. 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 recognising the magnitude of the change we wanted to have that external view. We also had our reserves certified by GaffneyCline who does this full time. So we have a great deal of confidence in our reserve booking. Mark Wiseman: (Macquarie Group, Analyst) Okay, thank you and so has BHP got access to that data or have they just taken a more conservative stance on some of the assumptions? Meg O’Neill: 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 assessments of BHP’s. Some are what I’ll call sort of 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 bases. Perhaps points to note is the Scarborough fields are gigantic; 800 kilometres square in size. That’s an area the size of Singapore. So 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 GaffneyCline, who were very supportive of the conclusions that we’ve drawn. Mark Wiseman: (Macquarie Group, Analyst) 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? Meg O’Neill: Mark, we haven’t commented. We haven’t split out those differences. Mark Wiseman: (Macquarie Group, Analyst) Okay. Just on the dom gas marketing; I think you’d 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 dom gas capacity? 6 Meg O’Neill: So probably a couple of numbers just to make sure we’re all clear on. So 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 rateably producing that 15%. So the domestic gas plant capacity is actually bigger than the 15%. So that’s why the dom gas plant capacity is the 225 TJs. Mark Wiseman: (Macquarie Group, Analyst) Okay, great. Thanks very much. Operator: Thank you. Meg O’Neill: Thanks Mark. Operator: Your next question comes from Mark Samter with MST. Please go ahead. Mark Samter: (MST Marquee, Analyst) Yeah, morning Meg, 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 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 nameplate capacity drop and should we expect Scarborough is going to be producing 8 million tonnes 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? Meg O’Neill: Thanks Mark, they’re good questions. So the intention when we start up Scarborough is that the first 5 million tonnes 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 start up and Pluto is still online, we’ll have co-mingled production through Train 1 and we expect that we’ll be producing Scarborough at about 2 million tonnes 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 tonnes. So that’s five in Train 2 and three in Train 1. At that point we’re actually limited by offshore capacity. So the nameplate of Train 1 is a bit academic because you couldn’t put more gas through it. Mark Samter: (MST Marquee, Analyst) But obviously you said the facilities are being set up to take third party gas so would Train 1 be able to take incremental if you have gas from other resources flowing? Meg O’Neill: 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 out talking to other resources around backfill to Pluto Train 1. Mark Samter: (MST Marquee, Analyst) Just obviously for the IRR you calculated you have modelled when Scarborough switches from 6 million tonnes to 8 million tonnes upstream. Can you share that with us? Meg O’Neill: 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. Mark Samter: (MST Marquee, Analyst) Yes, I guess it’s just hard for us to back out what that IRR really means without knowing the information you know. Okay, I’ll go to the next question. We’ll 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 7 Can you please spell out for us what volumes are under SPAs and what their durations are that Scarborough is going to be selling into? Meg O’Neill: 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 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 agreement on the LNG side, three agreements that are relevant. So 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. Mark Samter: (MST Marquee, Analyst) Yes, okay. So it’s less than 60% of the 8 million tonnes of LNG that obviously isn’t it. You’re over-indexing the domestic contract and it’s obviously only over your 73.5% but you’ll really own 100% of the molecules post-merger? Meg O’Neill: 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 per cent. Though we do continue with our efforts to sell-down a stake in Scarborough and our targeted final equity position is around the plus or minus 50% range. Mark, that should give our shareholders a bit of confidence. We wouldn’t want to be over contracted today with a sell- down in process. We want to make sure that we do have the ability to be exposed to the spot market and we do want to have the ability to place additional LNG contracts over the intervening five years. Mark Samter: (MST Marquee, Analyst): Thanks for that and that’s a good segue into the last question I’ll do for now. With the GIP deal all you’ve really done is swapped capex for opex, so effectively as Woodside, you’re carrying 100% of the project cost for all intents and purposes. I’ve never seen it and correct 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 has taken 100% of it to FID. The closest we got was Pluto at 90% and history has probably not judged that project too kindly. What did the industry miss? Why didn’t they come in? Do you agree that it’s fair to say that no one gas business in the world would want to take a project to FID at effectively 100% interest and how did you get comfort around the risks around that? Meg O’Neill: 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 resource risk that any other downstream investor would take. I think the industry has seen over time - look at the US LNG business for example, you’ve got players who are really only focused on that processing side of the business. 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. Mark Samter: (MST Marquee, Analyst) Yes, so why weren’t you able to sell some down pre-FID and why was 100% of the upstream, pseudo,because of the merger? Again, can you think of an LNG project anywhere in the world that’s done that? It’s highly unusual. On a market cap relative scale, this would be like Exxon sanctioning a $100 billion project, 100% owned. I’m just keen to understand the risk lens that the business looked at this FID through and why you’re happy to FID it pre sell-down. 8 Meg O’Neill: Look Mark, we have great confidence in the quality of the project. It starts at 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 two 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 de-risked project. Mark Samter: (MST Marquee, Analyst) Yes, I guess I’d be keen to understand why you believe Scarborough is - I mean every word you’ve just said is a cookie cutter of every LNG project that’s been FID’ed around the world for the last 15 years. They always have 10% to 15% IRRs. They’re always largely lump summed 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 why we should truly believe Scarborough is different. Meg O’Neill: Yes, 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 US, 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. Mark Samter: (MST Marquee, Analyst) Okay, thanks. I’m going to hop back on the end of the call, so perhaps I’ll get allowed back on. Meg O’Neill: All right, thanks Mark. Operator: Thank you. Your next question comes from Nik Burns with Jarden Australia. Please go ahead. Nik Burns: (Jarden Australia, Analyst) Thanks, hi Meg and team and congratulations on the announcement late yesterday. Look, my first question just on the - probably just following on from 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 - it looks like you could have some very strong cash flows coming in from BHP Petroleum’s assets. Are you more tempted to hold onto higher levels of equity upstream? Meg O’Neill: 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 Nik; one is we’d like to free up the capital to be able to invest in other opportunities. 9 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 and also manage risk. Again, having a partner in the field I think will be helpful in terms of having somebody who can 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. Nik Burns: (Jarden Australia, Analyst) That makes sense. 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? Meg O’Neill: No, Nik the process is underway. If we get the right offer from the right partner we would be happy to progress before the merger is completed. Nik Burns: (Jarden Australia, Analyst) Okay. That makes sense. My second part is around the interplay between Pluto, Scarborough, and North West Shelf. You just mentioned that the plan from start-up for Scarborough is 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 Interconnector to North West Shelf and allow you to move straight to 8 million tonnes 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 will 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? Meg O'Neill: Great question, Nik. We start running into some physical constraints, so when you asked the question, the first part of the question was Pluto Scarborough blend in Train 1 and should you try to accelerate some to North West Shelf. Well, we actually have some blending constraints that we need to work within, so there are some physical constraints around how the plant would operate. 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 linepipe capacity. As it stands, we are installing the biggest diameter pipe that you can physically install, particularly in the deep-water section, and so that ends up being a limiting factor for us. Nik Burns: (Jarden Australia, Analyst) Got it. Thanks, Meg. Cheers. Meg O'Neill: Thanks, Nik. Operator: Thank you. Your next question comes from Adam Martin with Morgan Stanley. Please go ahead. Adam Martin: (Morgan Stanley, Analyst) Morning, Meg, 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 the owning more of upstream versus downstream with different returns in the upstream? Meg O'Neill: No, that's a delivered cost of supply to north Asia number, and so that factors in the full value chain. Adam Martin: (Morgan Stanley, Analyst) Okay. Then we haven't touched on Senegal. You've got a divestment process underway. Can you just update on timelines, appetite, how that's going, et cetera? Meg O'Neill: Yes. It's an ongoing process, Adam. We do have potential investors in the data room. Obviously, we got the process kicked off in the middle of this year after we had closed the transaction with FAR. That selldown process is 10 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. We continue to work on that selldown opportunity. Adam Martin: (Morgan Stanley, Analyst) Okay. Final question just on the 13.5% IRR. 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 a seller's market regarding gas, but just your assumptions behind that please. Meg O'Neill: So Adam, we've not put out our comments around what we think slopes will be, but in the pack you will note the oil price that we've used to calculate that rate of return. Adam Martin: (Morgan Stanley, Analyst) Okay, so no detail. That's all right. All right, thanks for that. That's all from me. Meg O'Neill: Thanks, Adam. Operator: Thank you. Your next question comes from Adrian Prendergast with Morgans Financial. Please go ahead. Adrian Prendergast: (Morgans Financial, Analyst) 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 would be back in a position where you can look at other acquisitions that maybe complement the BHP portfolio or just fit the Woodside strategy? Meg O'Neill: It's a great question, Adrian. I think our M&A team is pretty well stretched, actually, with the work that we've done for the selldown on GIP, with the BHP merger, and with the two selldown processes that are underway. Obviously, if somebody rings up and says we've got something pretty to look at we'll take a look but our plate is pretty full for the very near term. Adrian Prendergast: (Morgans Financial, Analyst) Yes, that's helpful. Just one final further knock-on question from some of the earlier ones around risk profile on that return profile for Scarborough and Pluto Train 2. Just in terms of - it looks like you're combating risks around potential inflationary pressures really well, but obviously a project upstream and downstream of this scale can have quite a lot of slip even just in scope. Just in general terms, not really asking for intricate detail, but how conservative have you been because of some of those factors? You mentioned the sheer footprint for Scarborough. Does that just lead you to be more conservative as an approach or do you think it's really just a balanced approach that's similar to other projects that we've seen? Meg O'Neill: Adrian, I think we've taken a pretty balanced approach, but I say that in the context of particularly the last year. You will 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. Adrian Prendergast: (Morgans Financial, Analyst) Great, and 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 - previously we were moving to more shorter-term contracts but do you think we're going to get multi-decade type offtake? Is that going to ever be realistic again or is it more in that five to low-teen year maturities? Meg O'Neill: 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 had a 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, there have been some longer duration contracts signed recently. It's a bit hard to say. I think we'll see a 11 combination over time. We'll see those five, 10-year deals probably becoming a little bit more prominent than the historic 20-year deals. Adrian Prendergast: (Morgans Financial, Analyst) Thanks, Meg. That's great. Operator: Thank you. Your next question comes from Dale Koenders with Barrenjoey. Please go ahead. Dale Koenders: (Barrenjoey, Analyst) Good morning. A couple of questions firstly, just on the guidance around an extended asset life for Pluto Train 1. Can you give a steer for how much of your historical depreciation is onshore and subject to that extension? When we look at the reserves life of 10 years on Train 1 and 20, 30 years on Scarborough, is that the sort of right extension we should be thinking? Meg O'Neill: Dale, we haven't split out our depreciation mix and we wouldn't be disclosing that today. Dale Koenders: (Barrenjoey, Analyst) Can you confirm then that the change in depreciation rate is from FID, so there's very little impact to '21? Meg O'Neill: That is correct. It is from FID so there will be a little bit of effect in 2021 but a bigger effect of course next year and onwards. Dale Koenders: (Barrenjoey, Analyst) Okay. It could be quite material. On the BHP merger... Meg O'Neill: Dale, just a quick comment. When we issue our Q4 results we will provide 2022 guidance and so you will get a flavour for the impact at that point in time. Dale Koenders: (Barrenjoey, Analyst) Excellent. Then on to dividends and DRP, noting there is obviously an adjustment mechanism for cash payments from BHP Petroleum through to Woodside premised on the amount of dividends you're paying and also share count adjusted to DRP. Should we assume DRP continues and should we assume dividends at a minimum level to really hold onto cash through the merger? Meg O'Neill: 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 1 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. 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. Dale Koenders: (Barrenjoey, Analyst) 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 the net cash flows considering the dividend would make good payment and I think the $150 million FID payment which is paid to BHP Petroleum comes back towards you as well. Do you think there'll be something big, something small that comes towards yourself? Meg O'Neill: It's a bit premature to guesstimate that, Dale. 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 occurring 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 12 who haven't received those payments do get appropriate compensation. It would be premature to guesstimate what the net outcome will be. Dale Koenders: (Barrenjoey, Analyst) Okay. Thanks, Meg. Meg O'Neill: Thanks, Dale. Operator: Thank you. Your next question comes from Daniel Butcher with CLSA. Please go ahead. Daniel Butcher: (CLSA, Analyst) Hi, everyone. I've got a few, if that's okay. The first one is on the capex at Pluto 1 of $700 million. Maybe you can clarify for us, Meg, I was of the understanding that the reason, or part of the reason the gas didn't go to North West Shelf was because it would need modification to take nitrogen-rich gas, which would cost a bit of money, but it looks like Pluto 1 needs that anyway. Is that $700 million in nitrogen or something else? Meg O'Neill: Let me clarify, gas is not gas. You 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 and so 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 plant's modification required to do that at 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. The other issue of course with North West 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 to the Pluto site, even with these Train 1 mods, is the best investment decision for our shareholders. Daniel Butcher: (CLSA, Analyst) Okay. That makes sense, thank you. 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, but now you're saying you need extra gas for Train 1 from other resource owners. I'm just trying to reconcile those two statements as well. Is 404-P economic and never coming in - and not coming in, or what's the situation now? Meg O'Neill: 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 thresholds at that point in time. One of the things that Scarborough actually helps unlock is to put the pipeline right past 404-P. So, there will 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 commercialise it. 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. Daniel Butcher: (CLSA, Analyst) Okay, that’s helpful. Thank you. Maybe just one, I mean it’s probably more what Mark was asking about, I had the same question, it looks like with the structure of the GIP sale, they’ve quite logically for an infrastructure fund demanded that you sort of hedge them a bit on the construction costs because that’s part of the US$835 million 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 curious, with the toll they charge, is it front loaded or does it step down over time once you get past 1P reserves onto producing 2P reserves, for example? Meg O’Neill: So 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, so they do remain exposed to all of the uncertainty around the gas that will be coming through the trains. 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 13 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, so if we come in under, GIP will top up their payment to us. Daniel Butcher: (CLSA, Analyst) That was my point, they’ve basically got a fixed entry price for the capex, but never mind. I’ve got other questions. I’ll jump back in the queue though and let someone else have a go, thanks. Meg O’Neill: Thanks Daniel. Operator: Thank you. Your next question comes from Gordon Ramsay with RBC Capital Markets. Please go ahead. Gordon Ramsay: (RBC Capital Markets, Analyst) Thank you very much. Great announcement to make. Just coming back to the cost to supply from Pluto, I think it’s 5.8 or 5.9, you’ve got two numbers in your presentation. Just on that, I just want to confirm because you wouldn’t answer on your LNG price, but on your oil price are you using $65 a barrel from 2022 and then just inflating it onwards? Meg O’Neill: That’s correct, it’s US$65 a barrel, real terms 2022. Gordon Ramsay: (RBC Capital Markets, Analyst) Okay and I’m just going to jump to Scarborough and on cost risk in developing that field, full wave form analysis, integrated with the well information, get all that, you mapped the sand distribution. But you don’t have any new well information that delivers that reserve upgrade. I guess my big concern, regardless of GaffneyCline 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 you’ve got such a big reserve upgrade without drilling any new wells. So I guess the question comes down to how are you going to manage that risk going forward if there are cost overruns or increased additional wells required if, for instance, the sands not distributed to the degree you expect or the seismic hasn’t defined it properly? Meg O’Neill: It’s a good question, Gordon, but resource risk is one of the core attributes of the oil and gas industry. So 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. Whilst there were 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 will allow us to even further sharpen the pencil, because we’ll shoot at a higher resolution than the historic seismic data that we have. We will, as we start drilling wells and producing the field, we’ll get more information that’ll help us narrow the range of uncertainty and sharpen the ultimate estimate. Gordon Ramsay: (RBC Capital Markets, Analyst) Okay, thanks. Just one last one from me, just on – and I know I’ve asked you this before, the company this before, I’m just trying to understand how much Pluto gas is going to go to the North West Shelf, because you seem to imply today the equivalent of five million tonnes 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 their capacity to take 1.5 million tonnes equivalent to North West Shelf and won’t you use that? Meg O’Neill: Gordon, just to clarify, are you asking about Pluto gas to North West Shelf or Scarborough gas? Gordon Ramsay: (RBC Capital Markets, Analyst) 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 14 2 and 1 and you’re going to accelerate Pluto gas into North West Shelf as well, up to 1.5 million tonnes, just trying to understand that mix, how it evolves over time. Meg O’Neill: 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 one million tonnes per year. We have a contract between Pluto and North West Shelf that runs for four 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 [Clarification: the agreement is to process 3.0 million tonnes of LNG in aggregate in the period 2022-2025]. After that, there’s no agreements in place, so the pipes 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. Gordon Ramsay: (RBC Capital Markets, Analyst) Okay, thank you. Meg O’Neill: Thanks Gordon. Operator: Thank you. Your next question comes from Saul Kavonic with CS. Please go ahead. Saul Kavonic: (Credit Suisse, Analyst) Good morning Meg, congrats on the FID. A few quick questions if I may, but the main question I’d have is with Scarborough being probably a cornerstone growth project plan for Woodside over the last five years, what’s next in terms of growth projects after this one? Browse still seems on the backburner, most of the Woodside portfolio still seems on the backburner. Where’s the next growth the market should get excited about and what timing for announcements and catalyst from that shall we next expect for the next 12 to 24 months? Meg O’Neill: Thanks Saul. We’d actually like to celebrate the moment of Scarborough and Pluto for a day or two. But 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 comparative assessment of how those different opportunities stack up to help inform our decisions around what is next. Saul Kavonic: (Credit Suisse, Analyst) All right, thanks. Is it possible, any timing on when we might be able to get more colour on that? Is that something you’ll get more colour on in investor briefing next month or we need to wait until after the merger closes in the second half of next year until we can get more clarification on the priorities on the growth funnel? Meg O’Neill: 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 also 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’d 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. Saul Kavonic: (Credit Suisse, Analyst) Thanks. I guess my second question is just confirming on the economics you put out on Scarborough last night for breakeven IRRs, can I just, those are incremental economics that after factoring in any impacts, negative or otherwise on the Pluto production profile, et cetera? Meg O’Neill: So Saul, it absolutely is incremental. So if you run our business as it stands and then you run the differential case of Scarborough coming in, there is a bit of Pluto curtailment when Scarborough starts up of course, so that is differential and it does look at the totality of our business. 15 Saul Kavonic: (Credit Suisse, Analyst) Thanks and last question is just on LNG contacting, obviously you would get constantly 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 deal versus over the last 12 to 24 months, would you be getting better pricing contracting that today than doing it when there was pressure to do so over the last two years, so has it been worthwhile waiting on those contracts? Meg O’Neill: Saul, 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 behaviour, so last year what we saw during COVID was more supply than demand and prices fell and buyers probably got a little complacent thinking that 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. 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. If 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. Saul, I think we’ve got time for about one last question. Saul Kavonic: (Credit Suisse, Analyst) That’s it from me. Congrats again, yes and do celebrate with some good Margaret River wine. Meg O’Neill: All right, thank you Saul. Operator: Thank you. Your final question is a follow-up question from Mark Samter with MST. Please go ahead. Mark Samter: (MST Marquee, Analyst) 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. 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 going to be harder to do after the decision to take Scarborough to Pluto is obviously going to 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? Meg O’Neill: So 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. But I think it’s worth 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. 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 plant. So I feel pretty good, actually, about how things are going in the North West Shelf today. Mark Samter: (MST Marquee, Analyst) Thanks 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 me that Woodside shareholders would 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? Sherry Duhe: Mark, thank you for that and I think Meg has probably already halfway answered that one earlier by saying that the effective date for the transaction really is 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. So we won’t be looking to play any tricks there to try to optimise in the short term, we’ll be looking at the long term and what is the best dividend for our combined shareholder base. 16 Mark Samter: (MST Marquee, Analyst) Okay, thank you. Meg O’Neill: All right, thanks everyone for taking the time to participate in this call. As an early advertisement, so a note for your diary, we will be holding an update on Woodside’s strategy and value proposition on 8 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. Operator: Thank you. That does conclude our conference for today. Thank you for participating. You may now disconnect your lines. End of Transcript
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