Woodside Energy Group - Earnings Call - Q2 2020
July 14, 2020
Transcript
Operator (participant)
Thank you for standing by, and welcome to the Woodside Petroleum Limited market update. On the participants, there will be 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 Mr. Peter Coleman, CEO and Managing Director. Please go ahead.
Peter Coleman (CEO, Executive Director and Managing Director)
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's maintained safe and reliable operations through what is really an unprecedented and challenging time, and of course, during that period, delivered record production. Production was 7% higher than the previous quarter at 25.9 million barrels of oil equivalent, contributing to a record first-half production of 50.1 million barrels of oil equivalent. That's a great result any time, 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, 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 at our assets to guard against infection and to ensure continuity of our operations. 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. Yesterday, we announced that we've taken a difficult decision to impair assets, expecting to write down their non-cash after-tax value by $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 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 $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. Oil 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, but the global LNG supply shortage is forecast later this decade. We also expect there will be opportunities in our targeted future products, such as ammonia and hydrogen, building on Woodside's strengths. We are 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 II from H2 2021 and on Browse from 2023.
A global LNG shortfall is forecast 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 within our companies, including Senegal, the drilling activities in Australia's northwest, the Texas hub, and Julimar-Brunello Phase II, and we've made progress with carbon management, including commencing three projects 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 (participant)
Thank you. If you wish to ask a question, please press star one on your telephone and keep your name from being announced. If you wish to cancel your request, please press star two. If you're on speakerphone, please pick up the handset to ask your question. Your first question comes from Adam Martin from Morgan Stanley. Please go ahead.
Adam Martin (Executive Director and Energy Analyst)
Yeah, good morning, Peter. Sherry, just on Scarborough, clearly the commodity outlook's 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 II, please?
Sherry Duhe (CFO)
Okay. Thanks very much for that question, and I think we've attended 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 dates for the offshore and the 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 a natural resource to come into the North West Shelf, and Scarborough is a natural resource to come into Pluto Train II, so those are the plans that we're continuing to optimize to.
Adam Martin (Executive Director and Energy Analyst)
Okay. Thank you. And just a second question. I see you've moved Browse definitely back to 2023. Can you just discuss the backfill opportunities for North West Shelf discussing when do you expect those concepts to be firmed up to keep that plant full prior to Browse, please?
Sherry Duhe (CFO)
Yep. Great question. And we continue to make good progress on early ORO discussions, one of those, of course, being Pluto. The Pluto interconnector and the expansion 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 the other early resource owners into the North West Shelf will set some of the principles that we've been trying to nut out on Browse as well. So that's all progressing at a pace even in the midst of the pandemic recovery spot.
Adam Martin (Executive Director and Energy Analyst)
Okay. Thanks, Sherry. That's all from me.
Operator (participant)
Thank you. Your next question comes from James Byrne from Citi. Please go ahead.
James Byrne (Director and Investment Analyst)
Hi. Thanks for taking my question. I have two burning questions this morning. The first is the realized LNG price this 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 cargo 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 bit more exotic in there, such as a clawback for a Pluto price review?
Sherry Duhe (CFO)
Okay. So I'll hit the last part of it first. 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 we don't expect anything exotic there. In regards to the actual pricing, there's a mix. There's JKM, some of their other indices that some of those prices come off of. Some of them have lagged, some of them do not. And we also did see some exercising of downward flex in our contracting mix in Pluto, which is just sort 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 spot is what's in that altogether.
James Byrne (Director and Investment Analyst)
Okay. That makes sense. So the sales side brief in February, after the results, Peter, you admitted that there was increased stranding risk for Browse that 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 commitment to building Pluto Train II for Scarborough, but Browse becomes stranded. And so you've effectively locked yourself into CapEx for perpetual liquefaction capacity.
Now, I might have preferred to have seen you use lower prices in COVID as a means to impair Browse and pivot to having Scarborough go into the North West Shelf, as Adam alluded to in his question. Now, don't get me wrong, I understand you need Pluto Train II to be a legitimate project to maximize the 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 landing 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's current Burrup Hub strategy still fit for purpose against that outlook?
Peter Coleman (CEO, Executive Director and Managing Director)
I'm more of a speculative question, James, so let me help you with your thesis, and of course, I don't see an 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 in carbon, as you said, globally, what we're seeing our competitors do with respect to rebalancing their portfolios, particularly the supermajors, and there's been some significant announcements earlier this year with respect to rebalancing of portfolios, 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 activity 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. But on 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 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, 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. It's extraordinarily difficult for us.
So it's 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.
James Byrne (Director and Investment Analyst)
Okay. I won't push you further in this forum on that, but I guess just curious, good question. Corpus Christi, at the AGM in May, you stated that there was 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 a penalty there of 350?
Sherry Duhe (CFO)
Yep. James, I'll take that. So if you look at 2020, there are three cargoes that we have canceled. Those are May through July. And for the remainder of the year, we've sold our one 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.
James Byrne (Director and Investment Analyst)
Okay. Great. That's helpful. Thanks very much.
Operator (participant)
Thank you. Your next question comes from Mark Emmett from MST. Please continue.
Mark Emmett (Director/Analyst)
Yeah. Morning, guys. Two questions, if I can, please. Just first of all, obviously, the realized LNG prices was, I think, a surprise, or hopefully a surprise, to all of us. Can you just confirm? And I know, obviously, the adjustment, as you alluded to yesterday in the release, that you'll be excluding the adjustment for the impairment on the dividend payment. Obviously, with revenue so much weaker in the second quarter than most people were expecting, can you confirm if you even are expecting an underlying positive impact on whatever that dividend might be?
Sherry Duhe (CFO)
No. I think that's a step too far for what I can confirm today. We'll have to see those results when they come out on August 13th. 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 the impairment for the first half.
Mark Emmett (Director/Analyst)
Okay. Okay. Thanks. And then just, Peter, as you mentioned in response to.
Peter Coleman (CEO, Executive Director and Managing Director)
Sorry, Mark. I'm not going to let that one hang. We will have a positive impact in the first half. So let's try and get out there which side's going to have an impact. On an adjusted basis, we'll have a positive impact.
Mark Emmett (Director/Analyst)
Okay. Okay. Great. Thank you. Then you mentioned in the answer to James's question or statement, as you called it, about the options of gas deals and how hard things are to get done in the North West Shelf. I guess we put ourselves in Chevron's shoes, and there's potential bars of their stock that obviously benefit from the vote on their decision of what comes through. 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 will be removed before you can make those deals go binding?
Peter Coleman (CEO, Executive Director and Managing Director)
Look, 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 and 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. We're waiting to get some gas through it as well. So there's momentum on the positive side. But when you start lining up 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, as I said, with the current equity ownership, how we can come to an agreement that 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 alternative to them. And that will be the price that they then 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 the reality of commercial negotiations.
So, as I said in the answer to James, is you have to be very confident when you put these things up in front of shareholders, up in front of the board, that you can deliver on them. And at the moment, the development concept is one that we believe we can deliver on. If it changes to those development concepts, we're going to have to see significant changes in the views and behaviors of others.
Mark Emmett (Director/Analyst)
And I know this is probably a question for Chevron, I guess, the ramifications, the impact for shareholders. Is there any indication, your view, on how long this will take to play out to get what, I guess, we would probably describe as a more rational North West Shelf JV with Chevron out of it?
Peter Coleman (CEO, Executive Director and Managing Director)
Look, you've probably heard us talking to Chevron a bit, but they haven't spoken to us about the 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.
Mark Emmett (Director/Analyst)
Okay. Great. Thank you.
Operator (participant)
Thank you. Your next question comes from James Redfern from Bank of America. Please go ahead.
James Redfern (Analyst)
Good morning, Tim and Sherry. Just want to confirm, can you please tell me what the proportion of spot LNGs that will grow in the quarter and also to guide for the four years to 15%-20% of LNG sales to be sold as spot cargoes? Thank you.
Sherry Duhe (CFO)
Sorry. Can you repeat the first part of that question? The audio wasn't good.
James Redfern (Analyst)
Sorry. So the question is, can you please confirm the proportion of spot LNG sales in the quarter? And is the guidance for 2020 for spot to account for 15%-20% of total LNG sales?
Sherry Duhe (CFO)
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. 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 percentage 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.
James Redfern (Analyst)
Okay.
Sherry Duhe (CFO)
Yeah. We'll come back on the number for the quarter itself.
James Redfern (Analyst)
That's fine. That's fine. Thank you very much. And maybe just a quick question on the CapEx. The current CapEx guidance for Pluto trains doing Scarborough is around about $11 billion, roughly. Just wondering, just getting into Adam Martin's question, we're seeing big inflation in the oil service industry because of the declining global oil and gas CapEx. So I mean, any comments you can please make in terms of what, I guess, sort of CapEx inflation could be for that $11 billion CapEx to scale and put a train to over the next 12 months?
Sherry Duhe (CFO)
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, 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 maybe to the downside on the cost that we see opportunity for given this delay.
James Redfern (Analyst)
Yeah. Yeah. Exactly. Yeah. Yeah. This is what I was saying. I'll come Monday morning and I might see downside in my opinion to those CapEx forecasts.
Sherry Duhe (CFO)
Yeah. I think it's too early to quantify it, but yeah.
James Redfern (Analyst)
Yeah. Okay. Thank you, Mad. Thank you for your hand, Adam.
Operator (participant)
Thank you. Your next question comes from Gordon Ramsay from RBC. Please go ahead.
Gordon Ramsay (Research Analyst)
Thanks for that. Something I've been asked earlier, but just on LNG pricing, you got $5 per million BTU for the quarter. I mean, that's just near the oil price movement. You were saying roughly 20% will be spot. That still doesn't explain the numbers. Have we seen some lower 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?
Sherry Duhe (CFO)
Yeah. 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 fixed number of cargoes on JCC as a path. We've got 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.
Gordon Ramsay (Research Analyst)
Okay, and also, just another question, the carbon costs will move to $80 a ton, previously $40. What's with that?
Sherry Duhe (CFO)
So that's a global number that we've introduced just to, as we 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 in place. So we've just put that out there to note our global view on uncertainty of that.
Peter Coleman (CEO, Executive Director and Managing Director)
Gordon, it depends on whether you're a believer in the two-degree scenario or the one-and-a-half-degree scenario, but you can pick a range of prices that will say if you're really targeting one-and-a-half degrees, you need to be in around that $80 per ton longer term for carbon pricing to get the sorts of changes that you need across industry and also consumer behavior. So it's long-term. We've had investors asking us about the sustainability of our projects and the carbon pricing. So we've put that 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 it could change very, very rapidly. And we just don't want to be caught out by that. So that's the basis.
The basis is just some work to be done internationally around what sort of price range do you need. We came out. Their number is $100. Ours is $80. 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.
Gordon Ramsay (Research Analyst)
Just lastly, Browse CP content is around 12%, correct?
Peter Coleman (CEO, Executive Director and Managing Director)
It actually averages about 10. So it's reservoir dependent, but it averages just on 10.
Gordon Ramsay (Research Analyst)
Yeah. Thank you very much.
Operator (participant)
Thank you. Your next question comes from Stephen Hanson from Maitri Asset Management. Please go ahead.
Stephen Hanson (Analyst)
Yeah. Hi. A couple of questions, actually, just following up on the carbon price question. Sherry, you mentioned that the carbon price is 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, or to the potential impact of, say, Browse, for example, which is relatively high CO2.
Sherry Duhe (CFO)
No. That's very good. So 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.
Stephen Hanson (Analyst)
Okay. Thank you. 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-downs 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? Just could you give us some more detail on that, please?
Sherry Duhe (CFO)
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 trading 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 point that we shared to you, that is a lower value than the 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 testing reviews.
So, you see that hitting. We see that hitting the other assets as well once we get to the end of the current price review.
Stephen Hanson (Analyst)
Okay. No worries. So you're using the $8 per MNPTU and $65 long-term throughout all assets from 2025. I mean, they're real 2020 numbers. That's what you're applying, but it's a deck that you gave us to all assets.
Sherry Duhe (CFO)
Yes. We've given you the deck for the Brent prices per spot. We've not given you the LNG prices to go with that.
Stephen Hanson (Analyst)
Okay.
Sherry Duhe (CFO)
For the contracted. Yeah. But it does revert to spot for those.
Stephen Hanson (Analyst)
So just to be clear, you don't revert all your LNG contract assumptions to, say, a single spot number?
No. That's right.
Long-term. You've got a separate long-term contract assumption.
Sherry Duhe (CFO)
No. We do post-contract. So for the contracted periods within the current price review, then we utilize that agreed-up 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.
Stephen Hanson (Analyst)
All right. Thank you. One final one, please. What's the status of the BHP Scarborough HOA? Has that expired, or is that going to carry through with the COVID sort of break and everything that we've had?
Sherry Duhe (CFO)
Yep. 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. But that's not fully out. We gave ourselves some space just given the delay in the FID date.
Stephen Hanson (Analyst)
All right. Okay. Thank you very much.
Operator (participant)
Thank you. Your next question comes from Saul Kavonic, Credit Suisse. Please go ahead.
Saul Kavonic (Senior Energy Analyst)
Hi. A few quick questions. Can we just come back to the Scarborough development via the trains to the Pluto as you put it? Last year, you highlighted that you still have screening at a 12% annual rate under your $65 oil price assumption. Are you able to give us confirmation or clarity that you still see the Scarborough development clearing your 12% annual rate under, say, a mid-50s oil price and still using the recent LNG contract assumption?
Sherry Duhe (CFO)
Anyway, do you want me to go for it? Okay. I mean, I think the short answer is no. Whatever a project screens at 65 is not going to be the same that it screens at 55, all else equal. Pre-COVID, we've been consistently talking about a couple of the price decks that we run, not exhaustive, but a couple being 65 and 50. Of course, now, we, like everyone else, are adjusting to the new world and the lower price decks that we've put out there to understand how we optimize cost and optimize schedule to hold back as much of that revenue as possible in a lower oil price environment.
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.
Saul Kavonic (Senior Energy Analyst)
Great. Thanks. Also, I see you've applied for production licenses to two of your Browse fields, despite it being three years ahead of your target FID date. What's the driver of pursuing production licenses, given FID so far away?
Peter Coleman (CEO, Executive Director and Managing Director)
It's very simple. 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. We actually don't have an option anymore. The joint venture chose that they would go to production licenses on them within the expectation that we would develop. That's the background. 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 under development, those production licenses will be extended. That was the case for other major projects. We expect to see the same case for Browse.
Saul Kavonic (Senior Energy Analyst)
Just to follow up on that, so in terms of the production licenses, does that encompass FID in 2023, or is this something that is subject to renewal on more frequent dates up until that day?
Peter Coleman (CEO, Executive Director and Managing Director)
So you have to have a plausible development concept that the retention lease is economic under their price deck and their tests. So you can't just apply for a production license. You do have to have a plausible development concept.
Saul Kavonic (Senior Energy Analyst)
Great. Thanks, and just lastly, could 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? Just highlight what the baseline assumptions used are for that.
Peter Coleman (CEO, Executive Director and Managing Director)
The North West Shelf authority has a baseline to it. So what we indicated is that we have also assumed a decline in that baseline. We haven't published what we think the decline is, but we do believe government policy will continue to evolve in Australia. That will include a reduction of current baselines in line with Australia's Paris Agreement. You can do the math on that. That's the decline that we built into it. Of course, then anything above the baseline, the carbon tax is applied to that.
Saul Kavonic (Senior Energy Analyst)
Great. Thank you.
Peter Coleman (CEO, Executive Director and Managing Director)
Yeah. And then on the new projects, so there's a discussion paper out at the moment for government as to where the baseline should be set. Woodside's view is that those baselines should be set at the median of industry. And we've made assumptions in that regard with respect to the baseline 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 the current price.
Saul Kavonic (Senior Energy Analyst)
Great. Thank you.
Operator (participant)
Thank you. Once again, if you wish to ask a question, please press star one on your telephone and wait for your name to be announced. Your next question comes from Mark Wiseman from Macquarie. Please go ahead.
Mark Wiseman (Research Analyst)
Yeah. Good morning, Peter. Sherry, thanks for the updates today and last night as well. I just had a question on the balance sheet. You've commented last night that post the 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 comment 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 sale of the North West Shelf, if you were to make an acquisition there?
Sherry Duhe (CFO)
Okay. That's a good question. I think the short answer is 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, etc., that have an impact on gearing are things that are quite normal for them to understand and pull into their metrics. 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 undrawn facilities perspective to fund our core operations, to fund the growth activity that is still ongoing, even in our cash conservation period, and of course, also to consider any opportunistic M&A activities.
Peter Coleman (CEO, Executive Director and Managing Director)
Yeah. 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, or 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, 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 that's also 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 we've also said that any of those will have to stand on their own two feet.
So we're not going to hide a project while we're drawing down on cash in the first instance. And we're going to investors with a really nice one, having just hidden the other one by using cash out of the bank. So we'll be very transparent on 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 rating 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.
Mark Wiseman (Research Analyst)
All right. Thank you.
Operator (participant)
Thank you. Your next question comes from Joseph Wong from UBS. Please go ahead.
Joseph Wong (Equity Research Analyst)
Hi guys. Just a few questions for me. One's on the dividend. And given the impairment coming through this half and the guidance yesterday saying depreciation will happen in the second half, what's the view to change dividend policy, given there should be all things being equal, a lift in dividend in the second half because there's now a dividend paying cost?
Peter Coleman (CEO, Executive Director and Managing Director)
Yeah. Joseph, quick 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 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. 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 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 that we've traveled, we're getting back to pre-COVID levels pretty quickly. Probably the biggest unknown in the market at the moment is airline travel. And the expectations on airline travel now are lower than what they would have been a month ago. And that has an impact of roughly three 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.
All I would say is, in a month's time, when we announce our first half profit results, we will be much better informed because the Q3 is a very important quarter because it's the first quarter that everybody's 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 forward expectation. Six weeks ahead, that will occur, and that will give us some confidence with respect to our ability then to pay dividend not only in the first half but also the second half.
Joseph Wong (Equity Research Analyst)
So just to clarify, that discussion on the actual payout ratio is no decision on actually changing the policy model for cash for its cash flow. Is that correct?
Peter Coleman (CEO, Executive Director and Managing Director)
Yeah, so the payout ratio policy is 50%. The custom and practice since 2013 has been 80% payout ratio. It's been based on NCAT. NCAT 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, NCAT 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, NCAT continues to be, in our view, the best ratio to use.
Joseph Wong (Equity Research Analyst)
Got it. Just one final one. Just to clarify that Wheatstone impairment, you've got you're assuming your forward-looking estimates that 12% slope you mentioned has the investor base as your assumption for the contracts?
Sherry Duhe (CFO)
I didn't hear the last part of that sentence. Could you just repeat?
Just to clarify that.
Joseph Wong (Equity Research Analyst)
The Wheatstone impairment. So do you use that kind of assumption you put out at the IBD last year, that 12% sloping? Or has that changed as well?
Sherry Duhe (CFO)
Oh, 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 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.
All of that, we've got a fairly complex model that we review in detail with management and with the board to match that 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 when we did to additionally talk about what's competitive average in the market. That's a different number altogether.
Peter Coleman (CEO, Executive Director and Managing Director)
Right. And look, the reason we do that is just simply we've been moving more and more towards a portfolio. So we look at all of our volumes now in the context of a portfolio and where we move 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. 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 help communicate and understand that.
Joseph Wong (Equity Research Analyst)
Yeah. Thanks. Thanks, Peter. Thanks, guys.
Operator (participant)
Thank you. Your next question comes from Mark Busrett from J.P. Morgan. Please go ahead.
Mark Busuttil (Head of Australian Infrastructure, Utilities & Transport Research)
Good morning, everybody. 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 in slide seven, it seems like the Corpus Christi onerous contract will be included in underlying the way you've sort of highlighted it within the trade and cost line item. But then you've got the interest tax benefit, which presumably will be excluded because that's on the basis of those impairments that you announced yesterday.
Sherry Duhe (CFO)
The way that we will look at it when we adjust back to underlying is to remove all of the impacts of the transaction. It's both the adjustment as well as any income tax impacts. We'll move all of that out so that you have underlying as if the impairment and as if the onerous contract provision had not happened.
Mark Busuttil (Head of Australian Infrastructure, Utilities & Transport Research)
Okay, so if we have a look at that slide seven then, the income tax benefit, that would be on the reported, not the underlying?
Sherry Duhe (CFO)
That's on the line item guidance as reported. So yes, we always guide from a line item guidance perspective to 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 offline 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.
Mark Busuttil (Head of Australian Infrastructure, Utilities & Transport Research)
Okay. So out of those items on slide seven, the only two that need to be adjusted to get an underlying number, and again, for the purposes of calculating the dividend, would be the trading cost and the income tax. The others would be relevant for an underlying number?
Sherry Duhe (CFO)
All of the accounts that get hit from the P&L perspective, the onerous contract will hit cost of sales. That's in the trading cost line item. Other expenses will be hit. You see that as the offset from a P&L perspective to the actual asset balances being adjusted. Then you will see an impact of PRRT. You didn't mention that, but there is a PRRT net impact. That PRRT benefit does include the impact of both the Greater Pluto and the E&E assets. That's the only thing that income tax will be impacted by that. Those are all of the income tax or P&L statements that get hit or P&L balances that get hit by these provisions.
Mark Busuttil (Head of Australian Infrastructure, Utilities & Transport Research)
Okay. Great. Thanks so much.
Operator (participant)
Thank you. Your next question comes from Uncertain from ACSI. Please go ahead.
Jody Ponds (Analyst)
Thanks for your time this morning. I'm just wondering how the new figures for oil, LNG, and carbon compare to the scenario analysis you undertook against the Sustainable Development Scenario. And if it changes, the relative edge Woodside would have had compared to their peers in a low-carbon economy?
Peter Coleman (CEO, Executive Director and Managing Director)
Look, it's a good question. With respect to the scenario analysis, well, obviously, that's how we set our carbon pricing going out into the future, and applied it in that way. With respect to being competitive against our peers, as I indicated in yesterday's announcement, there will still be adjustments across the sector with respect to the carrying value of assets, and 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 I think there'll be a leveling across the board pretty quickly in that regard. But 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 and see with interest. China comes out with the next five-year plan. That will be announced early in 2021. That will give us some guidance as to what they're thinking.
The early indications are that gas will continue to be an increasing percentage of their mix, but of course, they'll start to increasingly 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 pricing over time.
Operator (participant)
Thank you. Your next question comes from Daniel Butcher from CLSA. Please go ahead.
Daniel Butcher (Head Analyst)
Yeah. Hi. 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 do you need to get a couple of others out as well? And if so, would you have appetite to buy those as well or at least consider it strongly?
Peter Coleman (CEO, Executive Director and Managing Director)
Hey, 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 two partners who will have differing views from the rest. It just happens to be at the moment that Chevron has been in focus. But I think it's not fair 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 in 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 the 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's 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, not a view I'm willing to share. But as I said, in answer to a previous question, I think the next 18 months, we'll very likely see other partners indicate their long-term intentions with respect to their North West Shelf ownership.
Daniel Butcher (Head Analyst)
Right. Okay. Thanks. Second question is just the country risk for Senegal. I'm just wondering why you've got that premium on the country. Is that partly to do with the risk of fiscal terms changing? Or is there something else there that you see that enhances the risk of that offshore project?
Peter Coleman (CEO, Executive Director and Managing Director)
Look, it's a good question. We actually see Senegal as a very low risk, particularly in Africa. In fact, it's arguably 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. in changing the fiscal terms than you do in Senegal. So we're very comfortable with the 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 to apply that country risk. Our view is the Senegalese have been very good up to this point to work with. 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.
Daniel Butcher (Head Analyst)
Sure. And just to follow that up, how do you sort of think about the relative impact of buying out FAR or even part of Cairn Energy when they have trouble funding it versus a Browse North West Shelf or even Scarborough or Pluto?
Peter Coleman (CEO, Executive Director and Managing Director)
We look at all of our assets. I think 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 are flowing are more attractive and will be more attractive to investors. So that's what we look at. We kind of look at our 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.
Daniel Butcher (Head Analyst)
All right. Thank you. I might ask you one final question if you don't mind. Just based on the Wheatstone's terms of contracts, can I confirm that the opening is sort of late 2022? Is that fair to assume?
Sherry Duhe (CFO)
If you want me to come back on that one, just to make sure we're absolutely accurate on the next timing on that, we'll leave this closed.
Daniel Butcher (Head Analyst)
Okay. Thank you.
Operator (participant)
Thank you. Your next question is a follow-up from Mark Samter from MST. Please go ahead.
Yeah. I was just hoping to ask about Pluto and the concept of WA for a company. I mean, obviously, the current working plan is still Scarborough comes to Pluto. But I don't think I'm misquoting you to say that you've discussed in the North West Shelf conversation that there is a concept where Scarborough comes to North West Shelf as well. But more importantly, the LNG market's 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 producing asset if the growth option doesn't happen. So in a world where Scarborough doesn't come to Pluto, is the growth option life of the contract? How should we think about it now in the context of that 20% of reserves getting written down yesterday?
Peter Coleman (CEO, Executive Director and Managing Director)
So Mark, are you referring to the Kansai allocation and Tokyo Gas contracts?
Mark Emmett (Director/Analyst)
Yeah. Well, yes. Exactly. Just now that Woodside's reserves have been written off. In a world where Scarborough doesn't come into Pluto, what do we think the profile and longevity of Pluto production looks like?
Peter Coleman (CEO, Executive Director and Managing Director)
Yeah. Look, we can't see a world where Scarborough doesn't come into Pluto. But I think the world that you're thinking of as a world where change does not happen. So our view is that Scarborough will come into Pluto 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 by the connector 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 five years. There's a current oversupply in that market. There's more demand coming in with the potential of the Perdaman and urea plant moving forward. And there's other suppliers dropping off in the market.
So it could be that that gas doesn't go in LNG in the long term. 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, I guess in the context of Pluto looming as well, you're saying FID and next 12 months or so on Scarborough. What are we thinking on the amount of volume you would want contracted to go to?
Look, normally we 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 the market, whether we want to be on the long-term contracting or whether we're happy to still have a decision there in the spot market. I would point, and 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 go to FID on theirs.
Although my 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 others, it's not just about the Canadians. 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 brought up in the market here where new suppliers aren't coming in on a regular basis.
Just one really quick follow-up as well. Just to talk to clear about that 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 the acquisition?
I've always said I'd prefer more pipeline gas in my mix, particularly when you have a 100% payout ratio on 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 much less volatility with respect to impact, 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, and of course, that contract's now dropped off, so we're pleased that we're pushing more equity gas into the marketplace, but it's 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'll be up to the builders of the pipeline to determine whether it is or not. But again, if there are 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, in our understanding, is still moving forward at a good pace with respect to expected next year. So we are diversifying our mix already without needing to go to the acquisition part.
Thank you.
Operator (participant)
Thank you. There are no further questions at this time. I'll now hand back to Mr. Coleman for closing remarks.
Peter Coleman (CEO, Executive Director and Managing Director)
Look, thanks everybody this morning for joining the call. There was a lot of you joining the call this morning. So obviously, there's a lot of interest, a lot of change happening in the marketplace. Thanks for your questions. I thought 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, 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 run at the very best reliability that they can. So again, thanks very much for your questions. I think the next 12-18 months are going to be extremely important in the industry. It's going to be important for Woodside 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 as we've talked about this morning is we do have a lot of optionality in what we do.
We'll be making sure we exercise that optionality to get the best outcome for our shareholders. Again, thanks very much.