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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Thank you for standing by, and welcome to the Woodside Petroleum Limited market update. [Operator Instructions] I would now like to hand the conference over to Mr. Peter Coleman, CEO and Managing Director. Please go ahead.
Good morning, everyone, and thanks for joining me on the call. Our CFO, Sherry Duhe, is with me this morning as well. This morning, we posted the Q2 results, and it shows that Woodside has maintained safe and reliable operations through what is really an unprecedented, challenging time and of course, during that period, delivered record production. Production was 7% higher than the previous quarter of 25.9 million barrels oil equivalent contributing to a record first half production of 50.1 million barrels of oil equivalent. That's a great result anytime, and it's even more impressive when you consider it was achieved at a time when the COVID-19 pandemic forced us to dramatically change the way we work for both our operational assets and our offices. And even before the global pandemic was declared, our facilities had been through a severe cyclone in the first quarter. When COVID-19 began to pose a very real risk, we rapidly overhauled our rosters and our assets to guard against infection and to ensure continuity of our operations. Our people adapted quickly. Some faced extended periods away from their families while many were working from home, juggling work and family responsibilities. In late March, we outlined how we were responding to the financial challenges, including cutting spending and delaying projects. And yesterday, we announced that we've taken a difficult decision to impair assets, expecting to write down their noncash after-tax value by USD 3.92 billion. As we noted yesterday, approximately 80% of the expected impairment losses of the oil and gas properties is due to the significant and immediate reduction in oil and gas prices up through 2025. Other factors influencing the decision to include greater uncertainty around longer-term demand and, of course, increasing risk of higher carbon pricing as we go out into the future. The financial statements also include a USD 447 million provision, recognizing the cost of meeting our future obligations under the Corpus Christi LNG contract. The impairments are a prudent decision reflecting the fact that our industry is confronted by a tsunami of challenges. Realized prices have dropped dramatically due to global oil oversupply and demand destruction from the pandemic. Our sales volume was up 13% from Q1, but the price plunge meant revenue was down. These are very difficult times for our industry, and some external challenges are just simply beyond our control. But these quarterly results confirm that we're doing a good job in managing those things that are within our control, and we are well placed to respond to the external challenges. Our base business is solid, and the fundamentals remain strong. You can see that we've taken a conservative approach on short-term oil pricing. Some analysts are more bullish, but we do see prices rising in the years ahead. And we think the medium-term outlook for natural gas is good, with the global LNG supply shortfall forecast later this decade. We also expect there will be opportunities in our targeted future -- for our targeted future products such as ammonia and hydrogen, building on Woodside's strengths. We're implementing the spending cuts that we committed to in March and are preparing our future growth projects to proceed when market conditions improve. In Q2, we submitted applications for production licenses and retention leases for the Burrup Hub, and Woodside is now targeting a final investment decision on Scarborough and Pluto Train 2 in H2 2021 and on Browse from 2023. The global LNG shortfall is forecasted from the middle of this decade, and the work we've done on our Burrup Hub projects means we're well positioned to take advantage of this. We've continued to progress committed activities, including in Senegal and drilling activities in Australia's North West for the Pyxis Hub and Julimar-Brunello Phase 2. And we've made progress on carbon management, including commencing tree plantings with Greening Australia. The Q2 report we've released today underscores that despite all of the unprecedented challenges of 2020, we continue to demonstrate the strength of Woodside's base business. With that, I'll now open it up for questions.
[Operator Instructions] Your first question comes from Adam Martin from Morgan Stanley.
Just on Scarborough, and clearly, the commodity outlook is currently quite challenging. Are you able to lower the cost structure further, either by reviewing the design concept, or considering Scarborough back to North West Shelf to save that 5 billion on the Pluto Train 2, please?
Okay. Thanks very much for that question. And I think we've mentioned this previously, we continue to use the opportunity that we have because of the delay in the FID schedule, given the market conditions that we're experiencing to optimize even further what the cost is on the total project, both on the onshore and on the offshore and as well the timeline. And it's -- also that opportunity to make sure that the RFSU date for the offshore and onshore are as close together as possible. In regards to the design concept, that is unchanged. We still are very much committed to our overall Burrup Hub strategy, where Browse is the natural resource to come into the North West Shelf, and Scarborough is the natural resource to come into Pluto Train 2. So those are the plans that we're continuing to optimize to.
Okay. And just second question, I see you've moved Browse FID back to 2023, can you just discuss how the backfill opportunities for North West Shelf are progressing? When do you expect those sort of concepts to be cleaned up to keep that plant full prior to Browse, please?
Yes. Great question. We continue to make good progress on early ORO discussions. One of those, of course, being Pluto, the Pluto interconnector and the sending facilities, as you might be aware, are under construction, and that is on target to achieve an RFSU of first half of 2022, so that's not changed. And the other benefit of those commercial agreements that we have ongoing with Pluto and one other early resource donor into the North West Shelf will set some of the principles that we've been trying to net out on Browse as well. So that's all progressing at pace even in the midst of the pandemic recovery response.
Your next question comes from James Byrne from Citigroup.
I have 2 burning questions this morning. The first is the realized LNG price for the quarter, down about 40% quarter-on-quarter despite having flat JCC oil price. So I can only assume that there's been very large losses on cargoes that you are trying to place into the spot market. Can you help us understand what happens with the realized LNG price and whether there's anything a little bit more exotic in there, such as a clawback for a Pluto price review?
Okay. So I'll hit the last part of it first, James. There's no clawback for a Pluto price review. Those conversations are still ongoing, and so we still have provisional pricing that is being applied to that, so no impact or anything exotic there. In regards to the actual pricing, so there's a mix, there's JKM, some of their other indices that some of those prices come off of. Some of them have lags, some of them do not. And we also did see some exercising of downward flex in our contracting mix in Q2, which is just part of the normal side of the contracting. So we've got Brent. We've got JCC, some JKM and then all the mix of that, plus additional spots is what's hitting that altogether.
Okay. Additional spot, okay, that makes sense. Okay. So at the sell-side briefing in February after the results, Peter, you admitted that there was increased stranding risk for Browse if it was delayed further. We're now looking at an FID in 2023. Between now and then, I mean, it's entirely conceivable that you see changes to carbon legislation that makes the baselines quite a bit more onerous. And if the FID is coming later, you kind of miss your opportunity to grandfather the project from those changes. So I guess where I'm starting to worry here is that you see an increasing risk of committing to building Pluto Train 2 for Scarborough but Browse becomes stranded. And so you've effectively locked yourself into CapEx for superfluous liquefaction capacity. Now I might have preferred to have seen you use low oil prices in COVID as a means to impair Browse and pivot to having Scarborough going to the North West Shelf as Adam had alluded to in his question. Now look, don't get me wrong. I understand you need Pluto Train 2 to be a legitimate project to maximize your negotiating leverage in the North West Shelf. But in a competitive LNG environment and that uncertainty on carbon, our thesis is that you should just maximize returns by having the cheapest gas landed at the beach for North West Shelf, which, in my opinion, is Scarborough, and that also alleviates any balance sheet pressure and need to raise equity for the Burrup Hub strategy. So why is that thesis wrong? And why is Browse or the current Burrup Hub strategy still fit-for-purpose against that outlook?
It sounds like more of a statement than a question, James. So let me help you with your thesis. And of course, I don't take issue with the basis of the thesis. And as we've discussed previously, we are looking at all of our development plans in light of what we're seeing out of COVID-19 and, in particular, what we're seeing in the changes of carbon, as you said, globally, what we're seeing our competitors do with respect to rebalancing their portfolios, particularly in the super majors. And there's been some significant announcements earlier this year with respect to rebalancing of portfolio, so we're not sure exactly what's happening in that regard or how they'll look at these sorts of projects in the future. And we're looking then at optimizing what our capital spend is. The reality is we don't need to make a decision now because we've got many months before we think we'll be seeing prices that are going to start to allow us to ramp up our engineering activities on these projects. So we're looking at all of those options at the moment. We've just got to stick to a base case. The base case is the Burrup Hub, it's still an attractive case. But there are other factors, and it might be minimizing CapEx becomes more important than maximizing NPV on the project. Those sorts of considerations are the things we need to look at. There's also just a practical part to it, as you mentioned. The commercial aspects of dealing with the North West Shelf. It's very difficult for me as a CEO to sit here and say that we have a pathway to completing any deal with the North West Shelf under its current equity ownership structure as evidenced by the difficulty we've had in completing the Browse gas processing agreement. So under any circumstance where you say, well, just simply switch it across and run different gas into North West Shelf, remember, we haven't even completed the other ORO activity as well, which is something that should be a very, very simple agreement but is extraordinarily difficult for us. So it'd be difficult for me to stand up in front of you and shareholders and say we've got a development plan that we are sure that we can deliver that requires an agreement with the North West Shelf under its current equity ownership structure. And I think that's just the nub of it, and that's the reality that we have to deal with.
Okay. I won't push you further in this forum on that. But I guess just -- sorry, a third quick question, Corpus Christi. At the AGM in May, you stated that there wasn't an intention in the short term to be lifting cargoes there. Oil prices appreciated quite a bit since then. So are you currently lifting cargoes? Or are you still taking the penalty there at $3.50?
Yes. James, I'll take that. So if you look at 2020, there are 3 cargoes that we have canceled. Those are May through July. And for the remainder of the year, we've sold all but 1 cargo. And then of course, we continue to actively monitor what's happening in 2021 and beyond, and we've sold several cargoes already in 2021.
Your next question comes from Mark Samter from MST.
Two questions, if I can please. Just first of all, obviously, the realized LNG prices was, I think, probably a surprise or hopefully a surprise to all of us. Can you just confirm? And I know, obviously, the adjustments, as you alluded to yesterday in the release, that you'll be excluding the adjustments from the impairment on the dividend payment. Obviously, with revenues so much weaker in second quarter than most people were expecting, can you confirm if you even are expecting an underlying positive NPAT to pay dividend off and whatever that dividend might be?
So I think that's a step too far from what I can confirm today. We'll have to see those results when they come out on August 13. I hope what will help you with your models is the line item guidance that we've given on quite a number of the items impacting P&L for the half.
Okay, okay. And then just, Peter, as you mentioned in response to...
Sorry. Sorry, Mark. I'm not going to let that one hang. We will have a positive NPAT in the first half. Let's not get it out there that Woodside is going to have a negative NPAT. On an adjusted basis, we'll have a positive NPAT.
Okay, great. Then Peter, you mentioned in the answer to James' question or statement as you called it about the options in third-party gas deals and how hard things are to get done in the North West Shelf. I guess if we put ourselves in Chevron's shoes and there's potential buyers of their stake that obviously benefit from the vote on their decision of what comes through. But do you think it's even possible to get a third-party deal done before Chevron are out of the way? Or does logic say Chevron has got to be removed before you can make those deals go binding?
It's difficult for me to say, Mark. We're close to completing the deal on the other ORO, as Sherry mentioned, but it's still been a very difficult tortuous process. We are seeing changes in attitudes as people come to the negotiation table, but I think the reality is we've got a very short-term project in front of us. We've already committed to it. There's another player in the North West Shelf, would like to get their gas through it as well. So there's momentum on the positive side. But when you start lining up alternate very large resources like Browse and Scarborough going in there, you're into a different set of dynamics. And so I would say at this point, it's difficult for me to see with -- as I said, with the current equity ownership how we can come to an agreement that would be -- would satisfy everybody. At the end of the day, as much as people want to tell us that this is just about CapEx, the reality is everybody will do their back-of-the-envelope calculation of what's the cost of the alternatives to them, and that will be the price that they didn't target for their toll. So whatever the toll is that we've agreed for Browse today may not be the toll that's been ultimately agreed for Scarborough. And any value that we see in moving Scarborough across may be leaked away during those negotiations because people will then look at your alternative cost of development. So I think it's just a reality of commercial negotiations. So as I said in the answer to James, you have to be -- when you put those things up in front of your shareholders, up in front of your Board, you have to be very confident that you can deliver on them. And at the moment, the development concept is one that we believe we can deliver on. Any changes to those development concepts, we're going to have to see significant changes in the views and behaviors of others.
And I know this is probably a question for Chevron, but I guess the ramifications materially impact your shareholders. Is it -- any indication your view on how long this could all take to play out to get -- what, I guess, we would probably all describe as a more rational North West Shelf JV with Chevron out of it.
Look, you're probably best talking to Chevron about that. They haven't spoken to us about their timeline with respect to the potential sale of their equity. So I would expect over the next 18 months, that will play out, and we'll have a better line of sight to that, and we may see others over that period of time also form a view as to how long they wish to stay in the North West Shelf as well. So my personal view, without having spoken to any of the houses, is I think the next 18 months will be an opportunity for each of the equity owners to determine whether they're going to stay in the North West Shelf for the long term or whether it's time for them to exit and go and deploy their capital elsewhere.
Your next question comes from James Redfern from Bank of America.
Just want to confirm, can you please tell me what the proportion of spot LNG sales were in the quarter. And also the guidance for the full year is still 15% to 20% of LNG sales to be sold to the spot cargoes?
Sorry, can you repeat the first part of that question? You were -- the audio wasn't good.
Sorry. So yes, the question is can you please confirm the proportion of spot LNG sales in the quarter? And is the guidance for 2020 spot to account for 15% to 20% of total LNG sales?
So I'm just checking if I've got the number for the quarter on hand for you, but I'll answer the second part first, and hopefully we can come back to the first in just a second here. We will be slightly above the 20% for the year just due to a handful of cargoes that are being additionally put into the spot percentages because of the down flex that people are exercising on their contracts. And of course, that year-end number will be impacted by any additional activities really in the last quarter if that happens on additional down flex.
Okay. That's...
Yes. We'll come back on the spot number for the quarter itself.
No. That's fine. That's fine. And maybe just a quick question on the CapEx. The current CapEx guidance for Pluto Train 2 and Scarborough is around about $11 billion roughly. Just wondering -- just going back to Adam Martin's question. The -- we're seeing big cost inflation in the oil service industry because of the decline in global oil and gas CapEx. So I mean, any comments you can please make in terms of what, I guess, sort of CapEx deflation we could see for that $11 billion CapEx for Scarborough and Pluto Train 2 over the next 6, 12 months.
I think it actually goes in the other direction. Because of the slowdown that we're seeing in the global LNG set of activities, we see opportunity to at minimum hold and if not reduce, in particular, on some of the offshore activities and certain categories around that. But that's still very much in progress. But if anything, it's neutral to downside on the costs that we see opportunity for given this delay.
Yes. Yes, exactly, which is what I was saying. I was just wondering how much downside it might be to that to that CapEx forecast.
Yes. I think it's too early to quantify, but yes.
Your next question comes from Gordon Ramsay from RBC.
This may have been asked earlier, but just on LNG pricing, you got USD 5 per million BTU for the quarter, I mean that's just mirrored the oil price movement. You're saying roughly 20% will be spot. That still doesn't explain the numbers. Have we seen some lower kind of recontracted pricing come through in this quarter? And can you just give a little bit more granularity on why it's $5 and not higher?
Yes. So the spot for the quarter. I know we'll come back on the exact number, but it is above the 20%. So that's one piece of the impact. And then there is a mix in our cargoes on JCC, it's about half. We've got the one fixed contract that goes into China that is fixed, and then the remainder is Brent-linked. And then, of course, some of those have a lag and some of those do not. So that will give you the total in terms of that total delivered price.
Okay. And also, just one other question. The carbon cost that moved to $80 a tonne, previously $40, what drove that?
So that's just -- and that's a global number that we've introduced just to -- as we've said in our announcement yesterday, reflect the increased uncertainty and risk around increasing carbon pricing. Now that, as you'll be aware, is a very generic observation because if you look at the reality in Australia, in Canada, in other countries around the world, there isn't an effective or consistent carbon pricing mechanism that is in place, so we've just put that out there to note our global view on the uncertainty of that.
Gordon, it depends on whether you're a believer in the 2-degree scenario or the 1.5-degree scenario, but you can pick a range of prices that we'll say if you're really targeting 1.5 degrees, you need to be in around that $80 per tonne longer term for carbon pricing to get the sorts of changes that you need across the industry and also consumer behavior. So it's long term. We -- investors keep asking us about the sustainability of our projects and to carbon pricing. So we've put them in there even though it does not reflect government policy at this point in time, but we just think it's prudent that investors understand what the basis is that we're putting in our projects and in our current assets for future carbon because this could change very, very rapidly. We just don't want to be caught out by that. So that's the basis. The basis is just some work that's been done internationally around what sort of price range do you need. When BP came out, their number is $100. Ours is $80, which kind of -- there's a landing point in there somewhere. It's not precise at this point in time. And as Sherry mentioned, it certainly does not reflect policy either here in Australia or in Canada at this point in time.
And just lastly, Browse CO2 content is around 12%, correct?
It's actually -- average is about 10%. So it's reservoir-dependent, but it averages just on 10%.
Your next question comes from Stefan Hansen from Nikko Asset Management.
A couple of questions. Actually, just following up on the carbon price question. Sherry, you mentioned that the carbon price you put out there to note the uncertainty, but it's not actually applied given the lack of government policy. Is that correct, so you haven't applied this to the potential impact of, say, Browse, for example, which is relatively high CO2?
No, that's a great question. Let me clarify. It is applied. What we were trying to clarify is that, that is not in line with what actual government Policy is today. So for purposes of our economics and for purposes of impairment testing for our oil and gas assets, we do utilize that. E&E is a bit different when you relate it to Browse because the way that the accounting works around that is that you're not required to do an economic calculation. That being said, we do run our economics on Browse and even with that higher carbon price, it doesn't have a material impact to the economics of that project.
Okay. I also wanted to get some more detail on the Wheatstone write-down. I mean it was the most significant relative to the previous carrying value. You mentioned that 80% of the impact was due to -- of the overall write-down was due to oil price. Is that the same for Wheatstone? Or as some reports that came out overnight suggesting there's some changes to contract assumptions in the long term. Could you give us some more detail on that, please?
Yes. Okay. That's a great question. So I'll clarify for Wheatstone and for all of our oil and gas properties, when we do the impairment testing, what we do is we apply current contract pricing out to the end of that current contract pricing period and then we revert, for impairment testing purposes, to our long-term screening values. And so we assume that all of the pricing and all of the contracts across our assets go back to that value. And given the price deck that we've shared to you, that is a lower value than a number of those contracts today. So it's a conservative assumption for impairment testing purposes and to be consistent on that, but it's not a reflection of what we would, of course, go out and attempt to negotiate in those contract pricing reviews. So you see that hitting Wheatstone but you see that hitting the other assets as well, once we get to the end of the current price review.
Okay. No worries. So you're using the $8 per MMBtu and $65 long term throughout all assets from – well, I mean, they're 2020 numbers, but that's what you're applying, the deck that you gave us to all assets?
Yes. We've given you the deck for the Brent prices and for spot. We've not given you the LNG prices that go with that. For the contracted, yes, but it does revert to spot for those.
Okay. Sorry. So just to be clear, you don't revert all your LNG production -- sorry, all your LNG contract assumptions to, say, a single spot number. And for long-term -- you've got a separate long-term contract assumption as well?
No, we do post-contract. So for the contracted period, with -- under the current price review, then we utilize that agreed price. If they come off of contract, we use spot. And if they're in the next period of the price review, we also use spot.
All right. One final one, please. What's the status of the BHP Scarborough HOA? Has that expired? Or is that -- can that carry through given the COVID sort of breaking everything that we've had.
Yes, we actually did extend that HOA out until the end of the year, and we're making great progress on getting done with all of the commercial elements that go along with that. So that's not slowed down but we gave ourselves some space just given the delay in the FID date.
Your next question comes from Saul Kavonic from Crédit Suisse.
A few quick questions. Can you just come back to Scarborough development via Train 2, the base case as you put it? Last year, you highlighted that you saw that screening 12% hurdle rate under your $65 oil price assumption. Are you able to give us confirmation or clarity that you still see a Scarborough to Train 2 development clearing your 12% hurdle rate under, say, a mid-50s oil price and still using the recent LNG contract slope assumption?
Do you want to go for it? Okay. I mean I think the short answer is no. Whatever a project screens out at 65 is not going to be the same that it screens out at 55, all else equal. Pre-COVID, we've been consistent with talking about a couple of the price decks that we run, not exhaustive, a couple being 65 and 50. Of course, now we, like everyone else, are adjusting to the new world and the lower price deck that we put out there to understand how we optimize cost and optimize schedule to claw back as much of that robustness as possible in a lower oil price environment. And that's the work that's ongoing between now and 2021 when we get closer to FID to determine how much more competitive can we make that project so that it's still resilient as it can be in the current price environment.
Great. Also, I think you've applied for production licenses for 2 of the Browse deals despite it being 3 years ahead of your target FID date. What's the driver of pursuing production licenses given FID is so far away?
No, it's pretty simple, Saul. We had a decision point at the beginning of the year with respect to our ability to apply for retention leases over those resources. That window is closed. So we actually don't have an option anymore. So the joint venture chose that they would go to production licenses on them with -- and the expectation that we would develop. So that's the background. So we're just moving forward with production licenses. The history of production licenses in Australia was the regulations have a time limit. The history is if you are underdeveloped those production licenses will be extended. So that was the case for other major projects. So we expect that to be the same case for Browse.
Just to follow up on that. So under the terms of the production licenses, does that encompass an FID in 2023? Or this is something that has to -- is subject to renewal or more frequent dates up until FID date?
No, we have to have a plausible development concept that the regulator believes is economic under their price deck and their tests. So you can't justify for a production license. You do have to have a plausible development concept.
Great. And just lastly, can you just provide a bit more color on how you applied the higher carbon tax assumptions when doing the impairment testing that you released overnight and particularly just highlight what the baseline assumptions used are for that?
Well, the North West Shelf, as you know, already has a baseline to it. And so what we indicated is that we have also assumed a decline in that baseline. We haven't published what we think that decline is, but we do believe government policy will continue to evolve in Australia, and that will include a reduction of current baselines in line with Australia's Paris commitments, so you can do the math on that. And that's the decline that we've built into it. And of course -- anything above the baseline, that carbon tax is applied to that. And then on the new projects, Saul, there's a discussion paper out at the moment for government as to where the baselines should be set. Woodside's view is that those baselines should be set at the median of industry. And so we've made assumptions in that regard with respect to the baseline should be -- where it should be on Browse and Scarborough. Scarborough, as you know, has quite de minimis emissions. And so it's not very sensitive at all to baseline assumptions or to carbon price.
[Operator Instructions] Your next question comes from Mark Wiseman from Macquarie.
Yes, Peter and Sherry. Thanks for the update today and last night as well. I just have a question on the balance sheet. You've commented last night that post provision and the impairments, your gearing ratio would go up to 19%. I realize that's probably not what the banks or credit rating agencies would focus on as a metric, but have you had any comments from Standard & Poor's or Moody's since that update last night? And also, could you just comment on what level of balance sheet capacity you have to conduct acquisitions such as the stake in the North West Shelf, if you were to make an acquisition there?
Okay. That's a good question. I think the short answer is, no, there hasn't been any explicit feedback overnight from S&P or Moody's. That being said, we talk to them very, very regularly. And so things like impairments, et cetera, that have an impact on gearing are things that are quite normal for them to understand and pull into their metrics. And there is no -- when you think about how low our gearing is right now, going to 19% is still very close to the bottom end of our gearing capacity, and you'll be aware that we've got over $7.5 billion of total liquidity right now. Over $4.5 billion of that in cash and over $3 billion of undrawn facilities. So we've got significant capacity on our balance sheet on a cash plus uncommitted facilities perspective to fund our base operations, to fund the growth activity that is still ongoing even in our cash preservation mode. And of course, also to consider any opportunistic M&A activities.
Look, I think the answer to that question is it will depend. It will depend on timing, and it will depend on what else has been happening. It will depend on oil price between now and then. So if you start adding a lot of things up -- you can't just pick one out. If you start adding a lot of things up and you say, well, you've got Browse potentially coming through. You've got Scarborough coming through. You've already got committed activities at Sangomar and so forth and then you load on top of that an acquisition, it's all going to be dependent on timing. We've already indicated that we can't do Scarborough and Browse together without needing to go back and raise equity at some point. And so -- but we've also said that any of those will need to stand on their own 2 feet. So we're not going to hide a project by drawing down on cash in the first instance and then going to investors with the really nice one, having just hidden the other one by using cash out of the bank. So we'll be very transparent on that, that each project will need to stand on its own. With respect to acquisitions, of course, they all have a different characteristic. And so acquisitions that are flowing barrels with minimal CapEx in front of it have a completely different profile when you start to look at some of those ratios that the ratings agencies look at compared to one that is kind of mid-development still requiring a lot of CapEx capital and some years away from first production.
Your next question comes from Joseph Wong from UBS.
Just 2 questions from me. I guess one is on the dividend. And given the impairment coming through this half and the guidance yesterday saying, depreciation will drop in the second half, what's the view to change dividend policy, given there should be, all else being equal, a lift in dividend in the second half because of this lower D&A costs?
Yes. Look, Joseph, good question. And just going back to the question that Mark asked. I expect that we will have a positive profit in the first half. I've got to say expect because, of course, it hasn't been approved by the Board yet. With respect to dividend, I also expect that we'll pay a dividend in the first half. With respect to payout ratios, time is very important to us, so we haven't formed a view. We've obviously had a discussion with the Board. We needed to have that discussion because we indicated in yesterday's announcement that any dividend that will be paid for the first half will be net of these extraordinary items with respect to the impairments. So we've discussed it with the Board. But the way oil prices have been moving, we need to see -- get confidence around demand returning into the market. And another month of driving data out of Europe and out of the U.S. and China will be extremely important. And that seems to be very positive at the moment. So if you look at the miles being traveled, they're getting back to pre-COVID levels pretty quickly. Probably the biggest unknown in the market at the moment is airline travel. And I think expectations on airline travel now are lower than what they would have been a month ago, and that has an impact of roughly 3 million barrels per day in the market with respect to demand and the question is when that comes back in. So there's a lot of moving parts. And all I would say is in a month's time when we announced our first half profit results, we will be much better informed because Q3 is a very important quarter because it's the first quarter that everybody is predicting that supply and demand will come back into balance, in fact, demand will exceed supply. All of the Brent numbers at the moment are on a forward expectation, 6 weeks ahead that, that will occur. And I think as we look out into the future, we'll see whether it actually has occurred, and that will give us some confidence with respect to our ability then to pay the dividend, not only in the first half, but also the second half.
So just to clarify, is that discussion on the actual payout ratio, but no, I guess, decision on actually changing the policy more to a cash -- free cash flow rather than NPAT?
Yes. So the payout ratio policy is 50%. The custom and practice since 2013 has been 80% payout ratio. It's been based on NPAT. NPAT has been -- has worked well for us. We've obviously looked at other ratios and continued to review whether other ratios are appropriate. But every time we look at it, to be quite frank with you, we come back and say, at least for our business, NPAT is working for us. You can argue there are other ratios that are more appropriate for different businesses. But for ours, at this point in time, NPAT continues to be in our view the best ratio to use.
Got it. And just one final one, just to clarify that Wheatstone impairment. Is the contract that you've got, you're assumes your forward-looking estimates, that 12% slope you mentioned at the Investor Day as your assumption for the contracts?
I didn't hear the last part of that sentence. Could you just repeat the very last part?
Just for the Wheatstone impairment. So do you use that common assumption you put out at the IBD last year, that 12% sloping? Or has that changed as well?
So, sorry, that's not the sloping that we've used. We don't disclose what the exact sloping is that we have used. What we do, just to be absolutely clear, is that for Wheatstone and for our other oil and gas assets, anywhere where we've got a current contract with a current pricing period, we use the actual agreed amount for that. If a contract is rolling off, and therefore the volumes are uncommitted, we'll use a spot price. Also if the contract goes over into a new contract pricing period, we'll use a spot price. And all of that, we've got a fairly complex model that we review in detail with management and with the Board to match that up to our view on supply/demand in each and every year for those long-term pricing forecasts. The 12% was a number that we used at IBD just to notionally talk about what's competitive or average in the market. So that's a different number altogether.
Right. And look, the reason we do that is just simply, we've been moving more and more towards a portfolio plan. So we look at all of our volumes now in the context of the portfolio and where we moved them to. It's a simplification that we use. The reality is each contract has terms in it with respect to how much price can change or slope can change at each price review. And sometimes they're better than the assumptions that we've made, but we just think from a total portfolio point of view, at least we have a common baseline for each one of our contracts, and it's just easier for us to be able to communicate and understand that.
Your next question comes from Mark Busuttil from JPMorgan.
I just wanted to get a sense for some of the costs that you've guided to last night and this morning. How much of that is going to be included within underlying profit and how much is not? The way you've highlighted your costs on Slide 7, it seems like the Corpus Christi onerous contracts will be included in underlying, the way you've sort of highlighted within the trading cost line item. But then you've got an income tax benefit, which presumably will be excluded because that's on the basis of those impairments that you announced yesterday.
So the way that we will look at it when we adjust back to underlying is to remove all of the impact of the transaction. So it's both the adjustments themselves as well as any income tax impact, we'll move all of that out, so that you have an underlying as if the impairment and as if the onerous contract provision had not happened.
Okay. So if we have a look at that Slide 7 then, the income tax benefit, that would be on the reported, not the underlying?
So all of the line item guidance as reported. So yes, we always guide from a line item guidance perspective is what will actually show up in the financials. We'll then take that for purposes of determining the appropriate dividend to pay, subject to the Board guidance and do an off-line calculation, which is not a financial statement calculation, it's a management calculation for purposes of determining the dividend. So everything in this guidance includes both the impact of the impairment and of the onerous contract provision.
Okay. So out of those items on Slide 7, were the only 2 that need to be adjusted to get an underlying number and again, for presumably purposes of calculating the dividend, will be the trading cost and the income tax? The others would be relevant for an underlying number.
So all of the accounts that get hit form the P&L perspective, onerous contract will hit cost of sales. So that's in the training cost line item. Other expenses will be hit, and you see that as the offsets from a P&L perspective to the actual asset balances being adjusted. And then you will see an impact of PRRT. You didn't mention that, but there is a PRRT net impact. So that PRRT benefit does include the impact of both the O&G and the E&E assets. And then last but not least, as you said, income tax will be impacted by that. So those are all of the income tax or P&L statements that get hit -- or P&L balances that get hit by these 2 provisions.
Your next question comes from Jodie Barns from ACSI.
I'm just wondering how the new figures for oil gas -- for oil, LNG and carbon compared to the scenario analysis you undertook against the sustainable development scenario and if this changes the relative edge, Woodside would have had compared to the figure in the low carbon economy.
Look, it's a good question. The -- with respect to the scenario analysis -- well, obviously, that's how we set our carbon pricing going out into the future so -- and apply it in that way. With respect to being competitive against our peers, as I indicated in yesterday's announcement, I think you'll see adjustments across the sector with respect to the carrying value of assets. So others -- some others have already come out and indicated that they'll be adjusting their carrying values. With respect to the application of carbon pricing globally, I think there's a reality that at some point, carbon pricing will come into the market. In our view, the question is not a matter of if, it's just simply when. And our view is that carbon pricing won't simply apply to developed nations, which is where you may get a direct pricing put on carbon. But it will also apply to undeveloped or developing nations who may not have those policies. But you will find over time, customers will put an additional cost or price on products coming out of those particular countries or projects. So we think there'll be a leveling across the board pretty quickly in that regard. Look, the long term is still quite strong for the industry. And it's one of those ones where it's not clear when demand will peak. But demand is still going up. As people switch, they use natural gas as a transition fuel. They see that. There's some questions at the moment as to whether COVID-19 will accelerate the transition to renewables. We'll wait. We'll then see with interest what China comes out with their next 5-year plan as that will be announced early in 2021. That will give us some guidance as to what they're thinking. Their early indications are that gas will continue to be an increasing percentage of their mix. But of course, they'll start to increase their push into the use of electric vehicles and so forth. They have dropped off their subsidies to solar, but they'll be looking at other energy sources such as hydrogen and even nuclear. So all of those, there's a lot of moving parts to it at the moment with respect to what companies will need to do. I think the reality, though, is you can't sit still on these things, and we need to make the right choices for us. But we are very good at what we do, and we'll continue to invest in this part of the industry but also look at diversifying our product mix over time.
Your next question comes from Daniel Butcher from CLSA.
Just a couple of quick follow-ups, please. Just wondering, I mean you mentioned the current JV structure at North West Shelf, it's very hard to do a tolling agreement. Do you think if Chevron was out, that alone would be enough to make it significantly easier or if you need to get a couple of the others out as well? And if so, would you have appetite to buy those as well or at least consider it strongly?
Look, Daniel, I don't think it's fair to kind of just focus on one partner in the North West Shelf. I think over time, you'll find there'll be one or 2 partners who will have differing views from the rest. It just happens to be at the moment that Chevron as being in focus. But I think it's unfair to point the finger and say that Chevron is the impediment to moving forward. I think these things just change. Our view -- and I mentioned this some 18 months ago is that the ownership structure of the North West Shelf will change. I think if it changes, it will be positive because those coming in will have a particular investment thesis. And that thesis will be to maximize the throughput of the North West Shelf, and they'll be singularly focused on maximizing the value of that asset rather than that asset being simply part of a global portfolio of many different assets. So I think in my view, just in general, ownership change is positive from the point of view that whoever is coming in will be very much aligned with accelerating development plans and getting tolling agreements in place as a priority. Whether others choose to leave or not, I can't predict. We obviously have a view on it. It's not a view I'm willing to share. But as I said in an answer to a previous question, I think the next 18 months is we'll very likely see other partners indicate their long-term intentions with respect to their North West Shelf ownership.
Right. Second question is just the country risk for Senegal. I'm just wondering why you've got that put on the country risk. Is that partly to do with risk of fiscal terms changing? Or is there something else there that you see and had to do with the offshore project?
Look, it's a good question. We actually see Senegal as a very low risk, particularly in Africa. In fact, it's arguable, you have high risk in states in the U.S. than you do -- in fact, you do have higher risk in states in the U.S. and changing their fiscal terms than you do in Senegal. So we're very comfortable with contract structure and so forth. However, our external auditors, based on their rules, require us to apply a country risk to places like Senegal. So it was just appropriate then to apply that country risk. But our view is the Senegalese have been very good up to this point to work with. We -- there's obviously issues, always issues as countries start to develop significant resources for the first time as they work through their fiscal and banking systems and so forth. But the reality is that we haven't seen any issues that, to be honest with you, would be any more difficult than what we have to deal with in Western Australia for development. So that's where our view is. But it's appropriate at this time to put that country risk on it. That's just a general accounting standard, and we fit in with what our external auditors are seeing, others are doing in countries like Senegal.
Sure. Just following up, how do you sort of think about the relative attractiveness of buying out FAR or even part of Cairn’s stake? You may have trouble funding it versus a Browse, North West Shelf or even Scarborough, Pluto investment.
Well, we look at all of our assets, and I think we've -- I've already indicated previously that, clearly, at this point in time, in the investment cycle, assets that are known to us are either under development or I think are more attractive and will be more attractive to our investors. And so that's what we look at. So we kind of look at Senegal assets in the same context. They're an asset that's currently under development. It still has development risk associated with it so it's got a different profile than a flowing asset in Western Australia, but they're still attractive assets for us to look at should they come to market.
All right. One final question, if you don't mind. Just on Wheatstone's contracts, can I confirm that the next reopener is sort of late 2022? Is that fair to assume?
We will need to come back on that one just to make sure we're absolutely accurate on the next timing on that, what we've disclosed.
Your next question is a follow-up from Mark Samter from MST.
Yes just hoping to ask about Pluto in the context of WA-404-P and obviously, the current working plan is to have Scarborough come to Pluto but I don't think I'm misquoting you, Peter to say that you've discussed in North West Shelf conversation that there is a concept where Scarborough comes to North West Shelf as well, but more importantly, I mean the LNG market is still incredibly challenged. So I presume when you have an existing asset and you haven't sanctioned another project, you have to have an alternative plan for the producing asset if the growth option doesn't happen. So in the world where Scarborough doesn't come to Pluto, if it goes past life of the contract, how should we think about it now in the context of that 20% of reserves getting written down yesterday?
So Mark, are you referring to the Kansai Electric and Tokyo Gas contracts?
Yes. Well yes, just now that WA-404-P has been -- the reserves have been written off, in a world where Scarborough doesn't come into Pluto, what do we think the profile of longevity of Pluto production looks like?
Look, we can't see a world where Scarborough doesn't come into Pluto. But I think the world that you're thinking of is the world where Train 2 is not built. So our view is that Scarborough will come into Pluto and with some modifications to the existing train that we can fill that train with Scarborough gas. Any excess gas under that particular scenario, which I will reiterate is not our base case, would then flow via the interconnector and potentially across the North West Shelf or into domestic gas. And of course, we're working hard to build our domestic gas market and that domestic gas market pricing is expected to firm out over the next 5 years. There's a current oversupply in that market, but there's more demand coming in with the potential of the Perdaman urea plant moving forward, and there's other supply dropping off in the market. So it could be that, that gas doesn't go into LNG in the long term. It may -- a good portion of it actually may go into the domestic gas market as the pricing firms up in that market as well. So I just can't see a scenario at this point, that would have us shutting down Pluto in totality. But I can see a scenario where there's different gas going in different places.
And then just to confirm and I guess, in the context of Qataris moving as well. I mean you're saying an FID in the next 12 months or so on Scarborough. Do you still -- what are we thinking on the amount of volume you would want contracted to take FID?
Look, normally, we'd prefer as much as we can. We've indicated previously that 50% contracted would be fine for us. We're going to have to look at that again in the context of what we're seeing happening with spot pricing at the moment. We expect spot pricing will improve, but we've got to see the reality of that, and that will drive our view then on that mix, to be honest with you, Mark, whether we want it in kind of long-term contracting or whether we're happy to still have it sitting there in the spot market. I would point, I'm glad you raised Qatar, in the context of, there have not been any FIDs in industry this year on LNG projects. And the major ones keep getting kicked out in time. The Qataris are yet to get FID on theirs, although our understanding is the offshore work is actually quite well advanced, but they still haven't gone into the trains yet. We expect some of that will move forward. The question in my mind will be whether all of it moves forward or whether it's actually phased over time and differently to what the current concept is. But there are other -- it's not just about the Qataris, as you know there's other major projects that have been deferred as well. And our expectation is that will continue. We do not expect projects on the U.S. Gulf Coast to move forward in any meaningful way in the near future at least. And so there is a situation being built up in the market here where new supply is not coming in on a regular basis.
Just one really quick follow-up if I can probably just -- you talked a fair bit about potential for acquisitions. Would you like a bit more balance in your product mix, you're very WA LNG-centric at the moment, and would you consider expanding beyond LNG in acquisitions?
I've always said I'd prefer more pipeline gas in my mix, particularly when you have a 80% payout ratio in your dividend. So you want to make sure that you've got something in there that is more predictable. With respect to dividends, I think investors appreciate kind of less volatility with respect to NPAT. So we've been consistent in that, and that's been a challenge for us ever since the North West Shelf contract changed equity from 50% to 16% here a few years ago. Of course, that contract is now dropped off. So we're pleased that we're pushing more equity gas into the marketplace, but still a small market for us here in WA. So we've been clear about that over time. We've also said publicly, if the government builds a pipeline from West to East, then we'd be happy to compete for putting gas into that pipeline, depending on the conditions of it. So we're not here to say whether that pipeline is economic or not because we're not building it. That will be up to the builders of the pipeline to determine whether it is or not. But again, if there were other options, then we'd do that. Now I will point out that we do have a HOA in place with Perdaman to take all of the Scarborough domestic gas plus a little bit more. And that project and our understanding it's still moving forward at a good pace with an FID expected next year. So we are diversifying our mix already without needing to go down the acquisition path.
Thank you. There are no further questions at this time. I'll now hand back to Mr. Coleman for closing remarks.
Look, thanks, everybody, this morning for joining the call. There was a lot of you who joined the call this morning. So obviously, there's a lot of interest, a lot of change happening in the marketplace. Thanks for your questions, they were very well thought through. I hope we've been able to answer them for you in a way that gives you the information that you need to be able to make your own analysis and communicate that to others. Again, we really appreciate the support that you have for Woodside. And I just, again, want to thank Woodside's -- our employees and our contractors for the outstanding work they've done in the first half of this year in being able to deliver our operating results in what has been extraordinary circumstances. We've delivered record production. We've delivered outstanding safety results during this period. We haven't taken our eye off the ball and people have been having to do extraordinary things. So again, let's put these results into context. We don't control pricing, unfortunately. What we do control, though, is how we respond to it. And I think we've responded very well with respect to reallocating of our capital, reducing our operating expenses and ensuring that our facilities are run at the very best reliability as they can. So again, thanks very much for your questions. I think the next 12 to 18 months are going to be extremely important in the industry. It's going to be important for Woodside as to what our growth plans look like. And all I would say is our plans will reflect the reality of the marketplace, but the great thing is we've talked about this morning is we do have a lot of optionality in what we do, and we'll be making sure we exercise that optionality to get the best outcome for our shareholders. So again, thanks very much.