Woodside Energy Group Ltd (WDS) 2018 Q2 法說會逐字稿

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'll 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 half year results.

As you would have seen this morning, we released our half year report and the results briefing pack 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 you to the slide pack, you'll see the standard disclaimer on Slide 2 and a quick reminder that this presentation does include some forward-looking statements and that our reported numbers are all in U.S. dollars.

Since our announcements at the full year results, we've been very busy, I must say.

We've had a productive first half, and we're delivering on our growth plans.

So let's run through some of the key financial and business achievements.

As you can see in the financial headlines 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 25% higher than the 2017 first half at over $1.5 billion.

And we generated free cash flow of $363 million while investing in growth and completing the Scarborough acquisition.

Our financial position is robust with low gearing and strong liquidity.

Our balance sheet is in good shape for the upcoming growth phase.

On Slide 4, we've spoken before about our clear plan across 3 timing horizons.

In the first half, we made good progress on horizon 1 and are preparing for horizon 2 and beyond.

We have a clear road map for growth, and it's underpinned by our outstanding base business.

Slide 5 further details that outstanding base business where you can see our facilities continue to perform strongly.

We delivered production of 44.3 million barrels of oil equivalent, which was 5% higher than the first half of 2017, and at Pluto LNG, we exceeded 99% reliability.

We've maintained a low unit production cost of $3.60 per barrel of oil equivalent at Pluto LNG in the North West Shelf Project.

We now have Wheatstone onstream with both Trains 1 and 2 exceeding nameplate capacity.

Based on the performance of Pluto, Wheatstone and our oil assets, we've increased our 2018 production guidance from 85 million to 90 million barrels of oil equivalent up to 87 million to 91 million barrels of oil equivalent.

We're delivering the committed growth that will underpin the targeted production of approximately 100 million barrels of oil equivalent in 2020.

As you can see on Slide 6, Wheatstone's expected to contribute in excess of 13 million barrels of oil equivalent by then, and next year, we'll be producing from both the Greater Western Flank 2 and Greater Enfield projects.

Greater Western Flank 2 is almost complete, and the final forecast cost is around 30% under FID budget, which, of course, is very pleasing to all of us.

On Slide 7, we had lots of activity in the first half across our priority developments, Scarborough, Browse and Senegal.

There's been significant progress since we announced the acquisition of an additional 50% in Scarborough in February this year and subsequently assumed operatorship.

We have awarded contracts for the concept definition phase at Scarborough and initiated contractor engagement for the front-end engineering and design phase.

The geophysical survey has been completed for the proposed export pipeline route.

The North West Shelf Project has reached alignment on key terms and pricing for tolling of third-party gas, and you can see that we expect the toll to be less than $2 per million BTU for 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.

The Senegal team has also 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 will now 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 volumes.

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 half of 2017 and Train 2 in June 2018 as well as strong Pluto performance further increased sales revenue by $204 million.

Moving on to 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 Wheatstone start-up, year-end 2017 Pluto reserve revisions 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 startup of Wheatstone, which reduced capitalized borrowing costs.

On Slide 11, the directors have declared an increase fully franked interim dividend of USD 0.53 per 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 as 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 costs for the North West Shelf Project and Pluto LNG were maintained at a 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 speaks to the strength of our underlying business and our ability to pass the benefit of rising prices onto our shareholders.

Turning now to Slide 15.

Woodside is in an excellent position as we continue to execute our strategy.

You can see that we have minimal near-term debt maturities, 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 Woodside's near-term debt, a 10-year $600 million unsecured bond was repaid and 2 5-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 the expected increase in our realized LNG price as a result of the improvements in lagged 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 3-month lag, so the impact of rising Brent on sales revenue was slightly delayed.

Finally, in Slide 17, our guidance on 2018 investment 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 owner's gas through the North West Shelf LNG facility.

We are executing our strategy with proposed developments 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 can expect on our major projects between now and the end of the year.

I'm -- so referring to Slide 19, we can expect concept select 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 preparatory information to allow us to advance into FEED in Q1 of next year.

For Browse, as we foreshadowed a significant milestone, we'll be reaching the preliminary tolling agreement between Browse joint venture and 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 our 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 our 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 MMBtu.

Can you perhaps give us an idea of how much downstream late life CapEx that Browse joint venture is paying out of the total?

Yes.

James, it's a good question.

So the toll is an expected toll over the life of the -- over the life of the facility.

So it's actually broken into 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 that gives the North West Shelf a 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 the North West Shelf to spend.

So for example, we have a 5-year forward-looking program for capital expenditure to keep the plant in good order.

That will be approved by the Browse participants.

The North West Shelf will then go and spend that money.

There'll be a small profit fee 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 for Pluto, I was wondering if you might be able to comment about how negotiations are going with the repricing of those contracts.

Do you feel comfortable that there won't be a material difference in realized price?

Yes.

I think we -- you may recall, James, we addressed -- tried to address this at Investor Briefing Day when we looked at the difference between renegotiating existing contracts through price reviews.

So recall, 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 spot market or in the short-term market at the moment.

We've not commenced discussions yet with the 2 parties, Tokyo Gas and Kansai Electric, but I don't expect there to be any change in our view.

And in fact, looking at the JKM number this morning at $10.40 and what we're seeing with China demand and so forth, I'm probably even firming my view that those negotiations will be satisfactory for us.

Got it.

Okay.

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

Yes.

I think -- that's a difficult question to answer, and the reason is the late life CapEx will be around do we develop WA-404-P or do we preferentially develop Jupiter, Thebe, which is just over -- roughly 2 Tcf, of which we hold 50% and bring that through to Scarborough platform.

So we've got optionality there.

We're also just beginning preliminary discussions with the owners of the outer Exmouth 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, that's the story that's [CH 1 followed] for us.

We just haven't worked that optionality [turn] to be quite frank with you, James.

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

Peter, first one is on Wheatstone.

So I understand that Wheatstone Train 1 operated around 10% above nameplate capacity in the June quarter.

I just want to understand, in terms 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 compressor upgrades.

And I've got one other question after that, please.

Okay.

Look, just quick 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 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's been performing better than Train 1, and we would expect that because we learned a lot of things as we went through Train 1. With respect to the increased capacity, you're correct.

We've indicated previously that we spent some capital monies on increasing the capacity in the compression train and the liquefaction train so basically, the drivers for the liquefaction.

We couldn't do that in Train 1 because it was too late in the construction process, but we're able to do it for Train 2. I'm kind of a little leery in giving you a forecast at the moment on where that is, but it's certainly north of the 10% that you've indicated.

So look, just high level, sounds like Wheatstone could [roll] run at 10%, 15% above nameplate capacity, which is a great outcome?

Just in terms of the tolling fee for processed third-party gas, can -- so should we assume that the tolling fee at Pluto Train 2 to processed gas from Scarborough is also going to be below $2 per MMBtu?

And then just want to understand, processing third-party gas at North West Shelf aside from Browse could -- will also be a different price based on those 3 criteria you talked about before in terms of covering operating cost and so forth.

Yes.

Look, we haven't set a toll yet at Train 2 for Pluto.

I would expect it would be higher than the $2 just based on the fact that it would be a brand-new train.

So you've got to look at the entire system in getting -- being able to get it to market.

So for those who choose to toll through that particular facility, the basis will be very similar, but that -- I think that second element, which was the profit element on the invested capital, will be higher, and then the third element, being the CapEx, will obviously be lower.

But to be honest, James, the team's actually running through that now but it'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've got to invest in that now.

Shareholders expect a double-digit return on those sorts of assets.

With respect to North West Shelf, the North West Shelf, it's an interesting question.

That's why it's so important that Browse, in fact, is the anchor tenants because Browse is -- they would have put so much volume then into North West Shelf.

It actually brings down the average cost for any other participant coming in.

Their prices, based on some of the scenarios we've run, will be around Browse but might be a slight bit higher just simply because the 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 there 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 the next incremental one would be lower, but the reality is it relies on Browse to come in there to keep it low because the North West Shelf goes into decline.

(Operator Instructions) Our next question is from Mark Samter from MST Marquee.

I've got 3 questions actually if I can.

Just the first one, probably more a question for Investor Day but I was in my garden.

I think you said at Investor Day that you were willing to sanction Scarborough with less than 50% of contracted volume.

But I guess, implicitly [above] that, you can't project finance the project or that by definition, certainly debt markets see that as a riskier proposition.

Can you just tell us, I mean, how do Woodside conceptualize that risk?

And should we think about it that you put a higher hurdle rates on a project with more volumes on contract?

How do you think about the balance sheet?

Do you have to keep lower gearing through that investment cycle as well?

Yes.

It's a good question, Mark, and welcome back from the garden.

The -- what -- this really relates interestingly to our view on 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 risk.

Because they're going to lean on (inaudible) of their portfolio.

We can do that, and we have developed the portfolio, but we'd prefer on balance to have a line of sight as to where it's going to.

So my comments at IBD were really aimed at the long-term contracts, those 15- and 20-year contracts that we've talked about, that the reality today says if you could give 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 though, 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 it 2 or 3 years of kind of pricing numbers that you've just seen recently to make sure that we don't get the company into trouble during that period of time.

So it doesn't come down to the project itself, but we look at it on a total company basis.

Just a quick question on the dividend.

It looks like the payout ratio this time was up closer to 90%.

Should we say that's a one-off anomaly?

Or do we think whilst be going through this period before the investment cycle starts again, we should think about the 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 our Investor Briefing Day pack was based on cash flow projections of $65 per oil -- $65 per barrel of oil 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 levels.

And the directors exercised discretion and judgment and decided that a $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 bank, our requirements in our view of what the next 6 to 12 months was going to look like, and Sherry indicated that when she mentioned that we've got a 3-month lag in our pricing.

So you can almost say our pricing for the next 3 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 match up with that revenue increase, and I think shareholders would expect to benefit from that.

Okay, great.

And then the third one's just a point of curiosity to be honest.

The -- you've spoken about scaling back exploration and being a lot more focused on your coal projects.

And then in the annex, there's a slide saying that you've gone into Bulgaria and I mean, I hopefully that field doesn't extend across the maritime 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 we're looking at, and I must say, we had some eyeball-to-eyeball moments with the exploration team as to do you really, really like this.

And they kept coming back and said this was the one.

If they only had one area that they were going to go into, this was it.

So it was -- to be honest, Mark it was on the back of the strength of what we think the prospectivity is of that particular block, so -- 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 oil focus as well.

(Operator Instructions) And the next question is from Andrew Hodge from Macquarie.

I've just got 3, hopefully, short questions.

The first one is about PRRT.

The guidance that was given in the quarterly was for a sort of lower PRRT credit, I think, most people have been forecasting.

I just want to get an idea about sort of relative PRRT balances and when you expect to pay PRRT.

Second one is about AASB 16.

Just we've already seen companies report sort of boost to EBITDA from this is sort of an artificial shifting down of costs, and I wanted to get an idea about that.

And then thirdly was just about -- Rio talked about pretty substantial cost increases happening through WA.

Just wanted to see what impact you've seen, if any, from your operations as well as from tendering for contracts.

Okay.

Andrew, I'll get Sherry to address the first 2, and then I'll come in and talk about the cost.

Okay.

So Andrew, on the first one and I think we've probably answered this one before.

On the PRRT, as you mentioned, the biggest asset that we have is related to the Pluto asset.

But we 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 happened in the period, that's the biggest factor that decreased our credit this time around.

But as you know, PRRT is quite a complex calculation around that.

We'll probably leave it at that in terms of projections.

To go onto your AASB question, I think the important thing to consider for Woodside is that this is a non-material adjustment 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 impact that comes through in the notes of the financial statements in terms of what we adjusted around that.

(inaudible)

Not AASB 15, Sherry.

It's 16, the one that you have said is material.

Okay.

So sorry, on the leases, 15 versus 16.

Thank you.

So on 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 half of the year.

Yes.

Andrew, I'll break ranks.

It will affect gearing, of course, for us, and it will be noticeable on the gearing number.

But it would still -- we'll still end up within our gearing range and targets.

What will -- I know it certainly will not affect our 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.

It's simply where the liabilities reside.

And so you will get a different number, and it will be a few percentage points different on the higher side.

And we've just got to look then to see, as we go forward, whether we actually break our guidance or not and hopeful -- otherwise, it's -- it doesn't affect the way we work at all.

And just on that, I mean, we've seen people -- it will be moving operating leases, so things 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 -- be anything else that would be under a lease?

The majority will be in our ships, so that's 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 leases, that's also something that could come on as well.

So they're things that we're going to have to look at, the industry's going to have to look at because the AIPN standard JOA at the moment, joint operating agreements, will basically will push all of these liabilities onto the balance sheet of the operator.

And so some of those joint ventures are going to have to look at those structures because it's simply not fair for operator to take on all of those liabilities simply because they happen to operate.

So the industry's got some changes it's going to have to make as well.

Yes, yes.

I recognize a bit, it's across the entire industry.

And then the last point on -- just on cost.

Yes?

Yes, just costs.

Look, we're not seeing any significant costs.

We've just completed a couple of wage deals here.

[EBAs] had been completed by our major maintenance contractors, and they're kind of, I would say, CPI-plus type increases so in the 2 to 3 percentage points on those increases, so nothing large at the moment.

We're probably seeing more pressure in offshore drilling.

And particularly longer term 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 as we try to lock in some of those contracts, which is -- just points to the fact that we said we need to get into the market now and 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 2 years but are now starting to get filled up, believe it or not, by chemicals projects out of the U.S. So as costs have actually gone up on the Gulf Coast in the U.S., some of those chemical expansions for those major plants there are actually going offshore and being modularized in Chinese yards.

So we're watching some of that pretty closely as well.

And just on the CapEx then, I know Exxon's made a comment about, I guess, cost being slightly higher on 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 got a couple of unsolicited proposals, and so it tells us we're within the ballpark.

Certainly, the numbers that are coming in, they still 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 telephone question is from Mark from JPMorgan.

Just a couple of slightly dull questions if I may.

There's 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 Wheatstone depreciation, would that be reflective of both trains and therefore, a similar sort of level going forwards?

Okay.

Yes, Mark, I can take both 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 6 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 one 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 a recurring amount that's going forward in terms of just the onetime startup around that.

But indeed, you do see the flow-through of that activity increasing from 2017, where we didn't have Train 1 onstream or Train 2 as well.

Yes.

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

That's right.

And we did provide full year guidance to reflect that as well to help you with looking forward in terms of the 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 you're thinking, if I recall back to the acquisition, I think you implied a gross -- a 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, the operator at the time, Cairn, 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 appraisal drilling before sanctioning your development there.

Okay, look, on total resource size, our view hasn't changed.

What we have recognized, though, is that the upper 400 series of sands is quite complex.

We knew that going in, but of course, you never know the true degree of complexity until you start drilling wells.

The lower sands, the S500 series, is a nice blocky sand.

So we said, look, we've got a couple of things that we need to do.

To fully appraise the upper sands would take some time and capital that 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 under the PSC to ensure that we go have a 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 sands and probably never be satisfied.

So the best thing is put a low-cost development in, get it moving and then, at the same time, dedicate a number of wells to the upper sands and produce and learn as you go.

So it's really trying to derisk the forward capital for us.

So I think we've talked about that initial development will be just over 200 million barrels or thereabouts of that 560 million barrels.

That's well underway and the cost that I mentioned in the pack is basically around the FPSO joint packages, subsurface and so forth for that particular development.

There'll be then another -- a Phase 2 development that will be some time later after we've basically had long-term production tests and so forth on these upper sands to work out the best way to produce them.

So that's how we're thinking about it.

Cairn's 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 operator's numbers.

So we started off in a more conservative position and we're starting now to move more towards where Cairn 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 to drill any further wells.

We do have in plans a view that we need to drill an appraisal well on FAN, and the FAN discovery, you may recall, we made the discovery and then we drilled a well quite some distance south of FAN.

That well was unsuccessful, but it did not delineate or appraise the FAN discovery itself.

And so we're working with the government of Senegal and the regulator there to secure rights to be able to go and drill that appraisal well.

That then would be a tie into base development for Senegal.

And last question from Glyn Lawcock from UBS.

Peter, it's Glyn.

Just couple of questions.

One, I know it's very early days in the China-U.

S. trade dispute, but just wondering how that's impacting customers' thoughts, 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 you talk about.

Is that focus driven, opportunity driven or -- and how do you think about -- how should I think about that in terms of your comment earlier regarding rig rates lifting, how -- I think you made some comments about you're trying to lock them in now.

Is there risk on the exploration spend as well looking out?

Look, firstly, on the trade dispute, we haven't seen anything come through yet that's material between the U.S. and China.

Now of course, as you know, there are some U.S. companies signed MOUs with China earlier this year for offtake.

We haven't seen -- our view is, of course, that's -- they're going to be made more difficult to finalize those SPAs.

There was an announcement earlier this week of an SPA 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 that they will pay.

At the moment, they'd probably go to assume that any price they pay for gas 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 where the U.S. gas will go, that -- obviously, Europe, the forecast now is that Europe is going to start to take more and more gas, I think, that LNG, not just pipeline gas.

I think that's a positive, and you're seeing that because Groningen and other fields, the U.K. North Sea, are all going into fairly significant decline.

So that was naturally going to occur anyways.

So that will just -- that will go over there.

It may affect shipping rates because the transit of shipping will be a little less.

You'll 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 it's 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 give us another year or so to see that play out.

On exploration, I would say the change here is to be focused.

We went broad.

We took an opportunity as prices crashed 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 after -- we made a number of discoveries.

Unfortunately, some of them were noncommercial and just -- 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 operator is [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 would be.

And it's focused and we just naturally had to do it because, as we look at the opportunities in front of us, pulling $100 million a year out of exploration for 5 years is not small money.

It's $0.5 billion over 5 years, and I think our shareholders would want us to spend that on our known growth projects at 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, the exposure longer term on exploration rates, we're starting to see a little firming more in the seismic market than anything else.

They will firm over time because the super majors have not been exploring, and at some point, we'll have to move away from acquisitions and get back into exploration.

So all of those things will start to put a little bit of pressure on exploration budget over time.

But I can't tell you what that will be.

We may keep the cap on the budget.

Just means we drill those wells 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's no further questions, so please continue.

Yes.

Okay.

Well, 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 and so forth.

So we appreciate the time you've spent with us this morning.

We appreciate your support and the effort that you put into understanding Woodside's story.

We are moving things forward.

I'm not going to say I'm excited because I'm working too hard to be excited at the moment, but as you can see, we've made some significant progress on things that most people thought were probably immovable objects.

We started the momentum and now what we've got to do is just keep the shoulder to the grindstone, just keep these things moving, moving, moving.

So our heads are down at the moment and working very hard, but the opportunities are in front of us.

And you can see we're starting to move them through the decision gates, which is very, very important.

So again, thanks for your time this morning, and we look forward to catching up over the next few days and weeks.

Ladies and gentlemen, that does conclude the conference call for today.

Thank you all for participating.

You may all disconnect.

Goodbye.