Woodside Energy Group Ltd (WDS) Q2 2018 Earnings Report, Transcript and Summary

Ladies and gentlemen, thank you for standing by, and welcome to the half year 2018 results teleconference. [Operator Instructions]. Please be advised that this conference is being recorded today, Wednesday, the 15th of August 2018. I would now hand the conference over to your speaker today CEO and Managing Director Mr. Peter Coleman. Thank you, please go ahead.

Look, good morning, everybody, and thanks for joining us for our 2018 have you results. As you would have seen already we release our half year report as results briefing back to the ASX. Joining me on the call is, our Chief Financial Officer, Sherry Duhe, and as we've done in previous years, we'll make some introductory remarks before opening up the call to a question-and-answer session. If I can take it they dislike back it was a distended disclaimer on-site during a quick reminder that this presentation does includes a forward-looking statements that are reported numbers are all in US dollars. Since our announcements at the full year results we've been replace the embassy we had a productive percent we are delivering on their growth plans some of the key financial and business achievements. As you can see, in the financial headline on Slide 3 our net profit after tax was $541 million and our interim dividend for the half was USD 0.53 per share, operating cash flow was when I percent how your than the 2017 first half we delivered $1.5 billion and regenerated free cash flow of $363 million while investing in growth and completing the Scarborough acquisition. Our financial position is Robo's endearing and strong liquidity balance sheet is in good shape to the upcoming growth phase. On Slide 4, we've spoken before about acquisition that across time Horizons. In the first half we made good progress on horizon 1 and preparing for horizon 2 and beyond Parco we have a clear road map for the growth and underpinned by her understanding base business. Slide 5 further details outstanding base business we can see our facility is continue to perform strongly. We delivered production of $44.3 million of oil equivalent, which was 5% higher than the first half of 2017 and our LNG of exceeded 99% reliability. We've maintained a low unit production cost of $3.60 per barrel of oil equivalent at , and we now have onstream both 1 and 2 exceeding capacity Parco based on performance of crude oil oil assets we increased our 2018 production guidance from 85 to 90 million barrels of oil equivalent then up to 87 to 91 million barrels of oil equivalent. We're delivering committed growth underpinned production of approximately 100 million barrels of oil equivalent in 2020. As you can see on Slide 6, Woodside to contribute an excess of 13 million barrels of oil equivalent by then and next year Greater Western Flank 2 and greater Enfield projects and final forecast is around 30% under FID budget, which, of course, very pleasing to all of us. On Slide 7 we have lots of activity in the first half across priority development Scarborough, Browse and Senegal. There's been significant progress since we announced the acquisition additional 50% in Scarborough in February this year and subsequently assumed operatorship or cope we awarded contract for the concept definition phase at Scarborough and initiated contractor engagement for in the finance, engineering and design phase. The geophysical survey has been completed for the proposed export pipeline route. The North West Shelf project has reach alignment on key terms and pricing a third-party gas, and you can see that we expect the total to be less than $2 per million BTU per Browse gas. As I discussed in the investor briefing day in May, cost reductions have been achieved on the subsea, well and pipeline scopes for Browse. Senegal seems also have been busy evaluating tender responses and we're seeing capital cost reductions at present approaching 10%. So we progressed well in the first half. Sherry Duhe will talk in some more details about our financials, and I'll come back at the end and run through some of our expectations for the rest of the year. So over to you Sherry.

Thank you, Peter, and good morning, everyone. I'll start on Slide 9 where you see that our strong base business delivered a 25% increase in net cash from operations compared to the first half of 2017. Sales revenue increased due to higher pricing and higher sales volume. An 18% increase in the average realized price resulted in $279 million of additional revenue. New production following the startup of Wheatstone Train 1 in the second have of 2017 and Train 2 in June 2018, as well as strong performance further increase sales revenue by $204 million. Moving onto Slide 10, our net profit after tax increased to $541 million. Our strong sales revenue was impacted by the timing of exploration activities, depreciation and financing costs. A significant exploration drilling program was completed in the first half of this year. With this now behind us, we are expecting reduced exploration spend in the second half of the year. Depreciation increased due to weak start-up, year-end 2017 Pluto reserve provisions and higher production from Pluto. Net finance costs were impacted by one-off events associated with the early bond redemption in May, foreign exchange hedging costs related to the equity raising and the start of Wheatstone which reduced capitalized borrowing costs. On Slide 11, the directors have declared an increase fully franked interim dividend of USD 0.53 share. The interim dividend has been determined having regard to the half 1 2018 underlying NPAT of $566 million and our strong operating cash flow in the half. The total value for the interim dividend is $496 million, which is up 20% on the same period of last year. The strength and performance of our base business is reinforced in Slide 12, which outlines the strong gross margins achieved by our operating assets, accompanied by sustained competitive production costs. Our unit production cost from the North West shelf project and Pluto LNG were maintained at globally competitive $3.60 per barrel of oil equivalent. Then on Slide 13, you can see that our shareholders are receiving the value of improving market conditions. As average realized price has increased, production and other cash costs associated with production have remained steady. Slide 14 further demonstrates our capital and operating discipline with the free cash flow breakeven price per barrel remaining stable as the average Brent price increases. This once again to the strength of our underlying business and our ability to pass the benefit of rising prices onto our shareholders. Turning out to Slide 15, we're excited and in excellent position as we continue to execute our strategy. You can see that we have minimal near-term debt maturity, and our debt maturing from 2025 complements the significant cash flow generation targeted from our key developments. We are well positioned to fund growth. In order to prudently manage Westside's near-term debt, a 10-year $600 million unsecured bond was repaid and two five year bilateral facilities totaling $200 million were canceled during the period. Bilateral facilities were reduced by a further $500 million after the 30th of June 2018. On slide 16, we see that expected increase in our realize LNG price as a result of the improvement and JCC and spot prices. Our second quarter realized prices were impacted by the proportion of spot sales, the delivery basis of our cargoes and customer mix. As you know, LNG contracts typically have at least a three month lag, so the impact of rising brand on sales revenue was slightly delayed. Finally, on Slide 17, armor guidance on 2018 and directed expenditure remains unchanged from February. Exploration expenditure is expected to reduce as we prioritize capital allocation to the development of the high quality resources within our portfolio. As Peter also highlighted, a significant milestone was achieved subsequent to the period with alignment between the North West Shelf project participants on key commercial terms and pricing for processing Browse and other resource and as gas to the North West Shelf LNG facility. We are executing our strategy with proposed development that utilize our existing LNG infrastructure to develop new globally cost-competitive natural gas resources. I'll now hand you back to Peter to outline our key priorities for the second half of the year.

Okay. Thanks, Sherry . Look, to summarize, I want to talk you through what you expect on our major projects between now and end of the year. I'm -- so referring to Slide 19, we can expect concept for Scarborough and Pluto Train 2. We then move into concept definition phase and what we call feed readiness. So really, by the end of the year, we are finalizing the information to allow us to advance into feed in Q1 of next year. For Browse, as we foreshadowed, a significant milestone will be reaching the preliminary agreement between Browse joint venture in the North West Shelf Project in Q3 and as we progress to concept definition entry, we'll also commence key contracting activities to address the technical development of the project. In Senegal for the S&E development, the team will be submitting key regulatory documents for primary approvals in anticipation of feed entry in Q4 to support FID in 2019. And then finally moving to Slide 20, our outstanding base business continues to be the engine room and has enabled us to increase our production guidance range. Pleasingly, we've maintained low operating costs and our key financial metrics are very strong. Moving to the next pillar, we're on budget and schedule for near-term projects and it's great to see Wheatstone performing so well. Together, these outputs will contribute to targeted production of about 100 million barrels by 2020. This is really a significant year for our material growth opportunities. The progress we make will position us to capture the current cost market and the expected LNG supply gap in the early 2020s. Importantly we're delivering value for our shareholders. We've increased cash flow and accordingly, we've increased out distributions to shareholders. So with those introductory remarks, I'll now hand over and welcome your questions.

[Operator Instructions]. Our first question is from James Byrne from Citi.

Firstly, just on the preliminary toll for Browse in the North West Shelf, which you've described as being less than $2 in MM BTU. Can you perhaps give us an idea of how much downstream like CapEx Browser joint venture is paying out of the total?

James, it's a good question. So the total is an expected toll over the life of the facility. So it's actually broken into the 3 components. One is an operating component. So that component basically shares the operating cost with the North West Shelf on a prorated capacity basis. So for example, if Browse takes half the capacity of North West Shelf, then it actually reduces the cost to the North West Shelf participants of their operating expense by 50%. And Browse will pick up that 50%. There's a profit element in there as well because the North West Shelf by return on the value of the current assets there and then, the third element then is the future capital requirements. Now that future capital requirement will be on an amortized basis. So we've amortized it within the toll based on a rolling number that will be approved by the Browse joint venture for North West Shelf to spend. So for example, we have five year forward-looking program for capital expenditure to take the plant in good order. That will be approved by the Browse participants. The North West Shelf will then go and spend that money, more profit on that and then, that amount will be amortized into the toll on a yearly basis, and it will be a rolling amount. So the number I'm talking about, $2, is not a fixed amount, it will be a -- it's less than that but it will be an average over the period of the life of the facility.

Okay. That's really helpful. And just on the foundation contracts so wondering if you might be able to comment about how negotiations are going with repricing those contracts. Do you feel comfortable that there won't be a material difference in realized price?

I think we you may recall James, which is try to address Investor Briefing Day when we looked at the difference between renegotiating existing contracts through price reviews. So we called the existing contract is still in place this is simply reviewing the pricing in that contract. And then new contracts brand-new greenfield contracts, so to speak. And in this instance, of course, those pricing review outcomes are somewhat bound by average land prices in Japan, which is substantially higher than what you would get on the our spot market or in the short-term market at the moment. We've not commenced discussions yet with the two parties, Tokyo Gas and Kansai Electric, but I don't expect to be any change in our view in the fact that we're looking at the JKM number this morning at $10 what we're seeing China demand and so forth probably affirming my view that those negotiations will be satisfactory for us.

I mean In the context of Scarborough coming into that facility and obviously, the expansion as well, I'm wondering if you could perhaps comment on how should we should be think about the life CapEx being deferred at Pluto with Scarborough coming in, acknowledging that there's still a range of how much that upstream contributes from Scarborough.

Yes, that's a difficult question to answer and the reason is the late life CapEx will be around till we developed [indiscernible] or do we preferentially develop, which is roughly 2 Tcf, of which we hold 50% and bring that to Scarborough platform. So good optionality there. We're also just beginning preliminary discussions with the owners of the [indiscernible] assets around what their preferences would be. They've clearly Indicated they would like to come through that Scarborough facility at some point when capacity is available in the future. So I would say that's the story that CH 1 followed for us. We just haven't worked that optionality to be quite frank with you James.

And the next question is from James Redfern from Merrill Lynch.

First one is on Wheatstone. So I understand that Wheatstone Train 1 operated around about nameplate capacity in the June quarter. I just want to understand in case of Train 2, how long will Train 2 be shut down for in August to replace the strainers and then what is the effective capacity of Train 2. As I recall, it's higher than Train 1 due to the compressor upgrades. And I've got one other question at that please.

Just on Train 2, we think it'll be a couple of weeks. We've actually just started that process. So for those of you who watch LNG cargo and movements and so forth, I know you do, out of the ports, that work has just commenced. So we expect it to be a couple of weeks. And as we've mentioned in the notes, in fact that train has been performing better than Train 1, and we would expect that because we learned a lot of things us we went through Train 1. With respect to increase capacity are correct indicated previously that we spent some capital moneys increasing the capacity and the compression train. And the liquefaction train, so basically, the drivers for the liquefaction. We couldn't do that in Train 1 because it's too late in the construction process but we're able to do with Train 2. I'm kind of a little eerie in giving you forecasts at the moment on where that is but it's certainly north of 10% that you've indicated.

So just high level, could we run it above nameplate in capacity, which is a great outcome. Just in term of the tolling fee for gas. So should we assume that the tolling fee at Pluto Train 2 to process gas at Scarborough is also going to be below $2 per MBTU and then, just want to understand processing gas at North West Shelf aside from Browse, will also be a different price based on almost three in terms of covering operating cost and so forth.

Look, we haven't set a toll yet at Train 2 for Pluto. I would expect it would be higher than $2 just based on the fact that it would be a brand-new train. So you've got to look at the entire system except for those who choose to show will do that particular facility, the basis will be very similar. But -- so I think that second element, which was the profit aliment on the invested capital will be higher and then third element being the CapEx will obviously, be lower. But to be honest, James, the team's actually running through that now, but that's certainly north of the $2 number and I wouldn't expect it to be the same to give us an adequate return because we invested in that now shareholders return on those sorts of assets. With respect to North West Shelf, the North West Shelf, it is an interesting question that's and why it's so important that Browse in fact is the anchor tenants because Browse is I would put so much volume in the North West Shelf, it actually brings down the average cost to bring the other participant coming in. Their prices, based on some of the scenarios we've run, will be around Browse but might be slight a bit high you just simply because percentage of OpEx and so forth that they'll be sharing will be a little bit higher just simply because of the volume numbers. If Browse doesn't come in for this, then the cost for other participants will be significantly higher. So there's a huge incentive for all parties to get Browse in their first so that they can underpin the North West Shelf for some period to come. So it's a formula, it's not always intuitive you'd think incremental one would be lower but the reality is Browse to come in there to keep it low because North West Shelf goes into decline.

[Operator Instructions]. Our next question is from Mark Samter from SMT Markey.

You said it Investor Day that you were section Scarborough with that less than 50% of contracted volumes. I guess, you can't project financed by definition certainly debt markets see those a riskier proposition. Can you just tell us how do Woodside conceptualize that risk? Should we think about it that you put a higher hurdle rates on a project with more volume uncontracted and how do you think about the balance sheet you have to keep lower gearing through that investment cycle as well?

It's a good question, Mark, and welcome back from the Guardian. The -- what this really relates interestingly to our view of the liquidity of the market and the debt of the current LNG market. You can almost say the super majors, the big players are doing it now because they do it under the veil of portfolio. And really what they're saying when they put volumes into portfolio they're willing to take on market is going to the selling it out of their portfolio. We can do that, and we have developed a portfolio that we prefer on balance to have a line of sight to where it's going to. So my comments really aimed at the long-term contracts, those 15 and 20-year contract that we've talked about. That the reality today is said if you can get 50% of it away on long-term contracts, you'd be doing fairly well. And then the mix of it will be short and medium-term contracts. So it's just our view of where we think the market is heading and the liquidity and depth of the market. From a risk point of view. No, we don't change anything on the balance sheet or the way that we risk the project. We do run different scenarios, to be quite frank with you. So as we look at our forward cash requirements, particularly cash out of the business and the commitments of cash, we do stress test the balance sheet by putting into a 2 or 3 years of kind of pricing numbers that you've just seen recently to make sure that you don't get the company into trouble during those period of time. So it doesn't come down to the project itself but we look at it on a total company basis.

A quick question on the dividend. It looks like the payout ratio this time was up close to 90%. Should we say that's a one-off anomaly or do you think was we're going to through this period before the investment cycle starts again, we should think about payout ratio could be sustainably that bit higher.

Look, it's a good question. I'm sure everybody's trying to work that math out and then trying to work out whether this is also a projection of what we think the profit will be for the year. No, it's really reflecting a couple of things. One is we had stronger cash flows in first half than we expected. So you may recall in our Investor Briefing Day was based on cash flow projections at $65 per oil -- $65 per barrel of flat average pricing during first half has been above that. So we've actually had more cash. Revenue was up 25% on the corresponding period year-on-year. So we looked at all of that, and we then looked at our activity level is and the directors exercised discretion and judgment and decided that $0.53 dividend was appropriate. So it was those sorts of things. So I would say it was not formulaic at all, but it was taking into regard the strength of the cash flow, the amount of money that we had currently sitting in the bank, our requirements and our view of what the next 6 to 12 months is going to look like and Sherry indicated that when she mentioned that we've got a three month lag in our pricing. So you can almost say our pricing for the next three months is already locked in. So all of those things gave us confidence to increase the dividend as a payout ratio. So it was all in that. And I think then you look at it in that total bucket of distributions because that's per share as you know, you looked at the dilutive effect of the equity raising and you can see that the total distributions were up about 20%. So they kind of matchup with that revenue increase and I think shareholders should expect to benefit from that.

You've spoken about scaling back exploration and being a lot more focused on your go projects and then in the Annex here there's a slide saying that you've gone in terms of Bulgaria extend across the border into Turkey at the moment, I suspect. Can we just put that move into Bulgaria in context of being more focused?

Yes, it's a really good question. It's an oil play that or looking at and I'm I must say, we had some eyeball to eyeball moments with the exploration team as to do you really, really like this. We they kept coming back end said this is the one. They only had one area that they're going to go and into this was it. So to be honest market was on the back of the strength of what we think was prospectivity is of that particular block. And the fact that we've got an excellent operator there with Shell. So we felt comfortable in being able to go into that block. But it gives us some more focus as well.

[Operator Instructions]. And our next question is from Andrew Hodge from Macquarie.

Three hopefully short questions. The first one the guidance that was given in the quarterly lower PRRT credit I think most have been forecasting. I just wanted to get an idea about sort of relative PRRT balances and when you expect to pay PRRT. Second one is about AFFB 16, just we've already seen companies report sort of boost to EBITDA from this as sort an of artificial shifting down of costs. an idea about that. And then thirdly, has talked about pretty substantial cost increases happening through WA, just wanted to see what impact you've seen, if any, from the operations as well as from tendering contracts.

Andrew, I'll get Sherry to address the first and then, I'll come in and talk about the cost.

On related to the really don't make a prediction around when and how that asset might come off of the balance sheet or reduce in time it's really dependent on a lot of factors most importantly being the oil price around that. So indeed when you look at increasing revenue that happen in the period that's the biggest factor that decreased I our credit this time around. But as you know, PRRT is quite a complex calculation in terms of projection. To go onto you AASP question, I think the important thing to consider for Woodside is that this is a non-material just for us over the period. It truly is a timing issue and we took a call when looking across at what our peers were doing and what our auditors were telling us and have moved from the entitlement to the sales method. And you can see that impacts that comes through in the midst of the financial statement adjusted around that.

AASP '15, '16 the one you have said is material.

Okay. Sorry, on the leases, on the leases, '15 versus '16. From the leases, that will be material. We're still in the process of working through that in the second half of the year. And we aren't in a position yet where we're giving a projection on that. So we'll come back with that in the second have the year.

I will break ranks, it will affect gearing, of course, for us and it will be noticeable on the giving number, but it would still -- will still end up within our gearing range and targets. What we'll, have, I know it certainly will not affect investment rating. What we need to do then is consider as a board, once we see that finalized, whether we want to provide different guidance as to what our target gearing range will be. Because it doesn't actually, affect the cash flows of the company, as you know, simply where the liabilities beside. So you will get a different number, and will be a few percentage points different on the higher side, and we've just got to like then to see as we go-forward whether we actually, break out guidance or not in social because otherwise it's it doesn't affect the way we work at all.

Just on that , we've seen people move in operating leases which would currently be in OpEx. I was trying to work out what you guys would have under that at the moment, would that be on the shipping side or is there anything else of would be under lease.

The majority will be in our ship the LNG carriers is where the majority of that is. Equally though as we start to look at things like Senegal and so forth, when you're looking at long-term FPSO releases, that's also something that could come on as well. So there are things that we're going to have to look at -- the industry is going up to look at because the standard JOA at the moment joint operating agreements will basically will push all of these liabilities on the balance sheet of the operator. And so some of those joint ventures are going to have structures because it's simply not therefore operator to take on liability simply because they have to operate. So the industry has got some changes it's going to have to make as well.

I recognize it's across the entire industry and then. And then the last point on cost.

Yes, just cost. Look, we're not seeing any significant cause. We've just completed a couple of wage deals being completed by major maintenance contractors and they're kind of I would say CPI plus type increases, so in the 2 to 3 percentage points increases, so nothing large at the moment. We're probably seeing more pressure in offshore drilling and particularly longer turn as we start to look at programs post 2021. We're starting to see that the offshore drillers are starting to increase their cost forecast there was we tried to lock in some of those contracts, which is just points to the fact that we into the market now and that go after these things. We are also seeing yards start to fill overseas so we are watching closely the yards in China, for example which have been empty for the last two years but are now starting to get filled up, believe it or not, by chemicals projects out of the U.S. So as the costs have actually, going up on the Gulf Coast in the U.S., some of those chemical expansions larger plans there actually, going offshore and being modularized in China. So we're watching some of that pretty closely as well.

And just on the CapEx side, made a comment about they cost been slightly higher than the rates that they receive from some of the projects. I'm just kind of curious from your perspective about the rates you guys have been receiving at an early stage for Scarborough.

Pretty good. We've got some -- we've actually, go couple of unsolicited proposals in -- so it tells us we're within the ballpark. Certainly, the numbers are coming in these haven't got to where we think they need to. So we've got some arm-twisting and negotiating to do, but it's pleasing because the trend's in the right direction at this point.

The next question is from Mark of JPMorgan.

Just a couple of slightly dull questions, if I may. There is an $87 million exploration write-down that you've included in underlying earnings in the half. Just wondering if you can explain where that came from and how likely it is to be recurring. Obviously, that's up a lot from where it was last year. And then the second one, just in terms of depreciation, would that be reflective of both Trains and therefore, some of level going forward.

Okay. Yes, Mark, I can take but of those questions. So on the first one in terms of the exploration write-off, that is related back to the comments that we shared as we went through the call. We had six wells that we drilled during the period, and several of those were written off due to the results of those wells, and we would not expect that to happen going forward. I think Peter has mentioned it as well, we've got 1 appraisal well in Myanmar to complete in second half and also the well in Peru. So indeed, that was an unusual concentration of that activity in the first half of the year. In terms of the Wheatstone depreciation, I don't think that we would expect that to be recurring amount that's going forward in terms of just the onetime start-up around that. But in flow-through of that activity increasing from 2017 where we didn't Train 1 onstream or Train 2 as well.

So on that one, Mark, of course, it's the straight-line depreciation that will change and as Train 2 comes whereas the doesn't change because of the offshore.

And we did provide for your guidance to reflect that as well to help you with looking forward in terms of annualized amount.

And the next question is from Ben Wilson from the Royal Bank of Canada.

I just had a quick question on your Senegal activities. Firstly, on the resource size that your thinking, if I recall back to the acquisition I think implied a gross resource of about 560 million barrels. Firstly, whether there's any thoughts post appraisal drilling on that initial resource estimate in your mind. And secondly, for the operator at the time about a year ago gave some pretty detailed figures or outlook about development, scope, plans and costs and whether you've got any thoughts on how those may have changed. And lastly, whether you foresee any requirement for any further of appraisal drilling before sanctioning a development there.

Okay, look on total resource size our view hasn't changed. What we recognize though is that the upper 400 series of sands is quite complex. We knew that's going in but of course you never knew the until you start drilling wells. The lower sands, the 500 series is a nice. So we said look, we've got a couple of things that we need to do. To fully appraised the upper sands will take some time and capital but we just said can be deployed else -- better deployed elsewhere. We want to make sure we locked in these low costs in the market and also, of course, we do have some requirements to ensure that we go development plan in by early next year. So with all of those factors, we said, we could spend a lot of time trying to understand the upper sand probably never be satisfied. So the best things is put a low cost development and get it moving and then at the same time, dedicated number of wells to the upper sands and produce and bring as you go. So it's really trying to de-risk the capital for us. I think we've talked about that initial development will be just over 200 million barrels or thereabouts of 560 million barrels. That's well underway and the cost that I mentioned in pack is basic around packages, subsurface and so forth for that particular development. There will be then another Phase II development that will be some time later after we've basically have long-term production test and so forth of these upper sands to work out the best way to produce them. So that's how we're thinking about it. Can is very aligned on that. We've just had the resource independently certified and of course, Woodside's numbers are starting to move closer to the operators' numbers. So we started off in a more conservative position then were starting now to move to where has been projecting their numbers. So our differences are changing there. What's changed? So do we need to drill any other wells? The answer is no. We believe the field is fully appraised for this first phase of development so we don't expect drilling further wells. We do have plans a view that we need to drill an appraisal on [indiscernible] and the discovery, you may recall we made the discovery and then, which will do well quite some distance south of FAN. That well was unsuccessful but it did not delineate appraise the FAN discovery itself. And so we're working with the government of Senegal and the regulator there to secure [indiscernible] drill that appraisal well. That then would be a tie into base development for Senegal.

And last question is from the Glyn Lawcock from UBS.

Four questions, one, I know it's been early days in the China-U.S. trade dispute. Just wondering how that's impacting customer thought discussions you may be having in the marketplace at the moment and any thoughts you might have looking forward. And then, just secondly, on exploration, I note the spend drop going out over the next couple of years it talked about focus driven opportunity-driven and how do you think about -- how should we think about that in times to come into earlier regarding rig rates I thank you made some comments about [indiscernible] is there risk on the exfoliation spend as well looking out?

Look firstly, on the trade not dispute we haven't seen anything come through yet that's material ériel between the U.S. and China now, of course, as you know, there are some U.S. companies signed MOUs for China earlier this year for offtake. We haven't seen -- our view is of course that's going to be made more difficult to finalize those SPAs. There was an announcement earlier this week of an the SBA with CPC in Taiwan being finalized. They're obviously not part of that trade dispute. So in general, I would say this works in Woodside's favor with respect to the confidence of the Chinese buyers and actually, what price will they pay. At least they know if they do a deal with us the price they will pay. At the moment, They've probably going to assure them that any price they pay from guess coming out of the U.S. will have a tariff on it, whether that tariff remains at 25% or whether it's something different I don't know. We'll see how that brinkmanship plays out over the next few months and whether that tariff even stays in place. So it's just too early for us to tell. But directionally, I think it favors gas coming out of Australia. There's no doubt about that. With respect to whether you U.S. gas will go? That obviously, you group for guess now Europe as good a start to take more and more gas I think LNG, not just pipeline gas, I think that's a positive, and you're seeing that because growing in other fields U.K. North Sea or all going to significant decline. So that was that should go into a good anyways and that will just go over there may affectionately race because the trends shipping will be a little less. Yet have less cargoes coming out of the U.S. into Asia, at least into the China market for growth, but that China market wasn't a big part of the market anyway. Some of that is going to Japan. So we haven't seen that play out at the moment, but it will. There's no doubt it will in my mind. But gives us another year or so to see that play out. On exploration, I would say the change here is focus we went forward we took an opportunity prices crash to get into some acreage areas that we coveted. We couldn't do that before when price was at $100 per barrel. We've gone out we made a number of discoveries unfortunately, some of them were noncommercial and so we found oil but not enough. And we've opted to exit a couple of those areas just simply because, and by the way, the operators just stayed based on the view that we just don't want to put more money into something that we're just not sure what the outcome will be and it's folk is not naturally had to do it because as we look at the opportunities in front of us $100 million a year out of exploration for five years it's not small, but it's $0.5 billion over five years, and I think I shareholders with one is to spend on our were growth projects of the moment. So that's how we're looking at it, refocus the exploration, exit those areas where we can see commerciality is not going to play out and give us the returns we want. And then, exposure longer-term on exploration rates. We're starting to see yellow firming more in the seismic market than anything else they will firm over time big is measures have not been exploring in some point we'll have to move away from that acquisition and get back into exploration for goes or all of those things will started to be but a little bit more pressure on the exploration budget over time. But I can't tell you what that will be. We might keep a cap on the budget this remains the drill those wills or we may increase it depending on the opportunity. But that's next year's conversation. What we want to do is give you guidance now as to where we think this is going to play out over the next 3, 4, 5 years.

There are no further questions. So please continue.

Okay. Look, thanks everybody, for joining us this morning and thanks for the quality of the questions. We'll be around talking to investors next week and obviously, providing some more insights to where we think things are going so forth. So we appreciate the time you've spent with us this morning. We appreciate your support and the effort that you've put into understanding Woodside story. We are moving things forward for crime not SAM excited because I'm working too hard to be excited at the moment. But as you can see, we've made significant progress in thing is that most people will probably immovable objects. We started the moment to them just keep the shareholder to the grindstone just keep these things moving. So our hazards and of the moment are working very hard by the opportunities in front of us and you can see were starting to move June decision gauge, which is very, very important precursor get best for your time this morning, and we look forward to catching up over the next few days and weeks.

Ladies and gentlemen, does that conclude the conference call for today. Thank all for participating. You may all disconnect. Goodbye.