Woodside Energy Group Ltd (WDS) 2019 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the Woodside Petroleum Half Year 2019 Results Briefing Conference Call.

(Operator Instructions) I must advise you that this conference is being recorded today, Thursday, the 15th of August, 2019.

 

I'd now like to hand the call over to your first speaker today, Mr. Peter Coleman.

Thank you.

Please go ahead.

Good morning, everybody, and thanks for joining us for our 2019 half year results.

As you would've seen this morning, we released our half-year report and the results briefing pack to the ASX.

 

Joining us on the call is our Chief Financial Officer, Sherry Duhe; and Chief Operations Officer, Meg O'Neill.

And as we've done in previous years, we'll make some introductory remarks before opening the call up to a question-and-answer session.

 

You'll see the standard disclaimer on Slide 2, and just a quick reminder that this presentation does include some forward-looking statements and that our reported numbers are all in U.S. dollars.

 

In the first half of the year, we laid the foundation for a continued strong performance in our operations while progressing our growth plans.

We completed the first major turnaround of Pluto LNG since the start of operations in 2012.

And this was, of course, a planned turnaround as we've spoken about before.

We told you it was going to happen and it did.

And of course, it's setting up this world-class facility for continued safe, reliable and efficient operations for many years to come.

 

So let me take you through some of the key financial and business achievements.

As you can see on Slide 3, our net profit was $419 million.

Our interim dividend for the half was USD 0.36 per share.

And to support our growth strategy, we've reactivated the dividend reinvestment plan, allowing our eligible shareholders to reinvest the dividends directly into shares at a discount.

 

Operating cash flow was almost $1.5 billion.

And we generated free cash flow of $869 million, more than double the free cash flow for the first half of 2018.

Our financial position is robust.

And we continue to build our balance sheet as we progress into a growth phase.

 

We achieved production of 39 million barrels of oil equivalent despite the planned turnaround of Pluto and disruption from Tropical Cyclone Veronica.

We met our commitments on both budget and schedule for Greater Enfield, which is now in the final stages of commissioning.

 

On Slide 4, production fundamentals were strong across our portfolio in the first half.

And we're on track to deliver our targeted annual production next year of approximately 100 million barrels of oil equivalent.

At Pluto LNG and the Karratha Gas Plant, we completed activities that will set up these facilities for the future, and as I've already mentioned, the first major planned turnaround that was completed at Pluto, and I'll discuss that in more detail in a moment.

 

We've also started FEED activities for Pyxis involving drilling and subsea construction.

And we've sold the first LNG from the Pluto truck loading facility as we built an LNG fuels market in the Pilbara.

And another step forward on our Burrup Hub growth plans, we've installed the tie-ins at Pluto for the interconnected pipeline to the Karratha Gas Plant.

 

At KGP, we've delivered efficiently -- efficiency and capacity improvements during the half.

The excellent news is that -- the way the North West Shelf Project has performed.

Really, production increased on the previous year despite increased cyclone activity in Q1.

And we've started FEED activities on the Greater Western Flank Phase 2 project.

 

Wheatstone had a good first half and is expected to deliver over 13 million barrels of oil equivalent in 2020.

And we've also completed significant work for our Australian oil business.

 

Let me give you some more detail on that as we turn to Slide #5.

At Greater Enfield, production from the existing Vincent wells recommenced in early July.

And we're expecting first oil from the Greater Enfield reservoirs this month.

I can also tell you that the drilling campaign is well ahead of schedule with 11 of the 12 development wells complete.

We were pleased with the comprehensive refit of the Ngujima-Yin FPSO in Singapore, and that this project is being delivered on budget and schedule with production expectations of around 40,000 barrels per day of oil equivalent after ramp-up.

Of course, that's a great achievement for the team on what's been a very complex project.

 

Let's take a closer look at the execution of the major planned turnaround of Pluto LNG on Slide #6.

The scheduled turnaround is always a case of short-term cost for long-term gain, as we know.

And we've outlined here some of those costs and the extent to which we were able to mitigate them.

Production would have been approximately 7 million barrels higher without the turnaround, so that's a one-off impact.

And we used all the tools at our disposal to manage it.

In recent years, we've had -- we've matured our trading capability, giving us some flexibility to source third-party cargoes and to continue to meet our obligations to customers.

The facility has performed well since production restarted in June, achieving a new daily LNG production record and a 99.9% reliability in the month of July.

This is important as Pluto generates the cash flow needed to support delivery of our growth strategy.

 

On Slide 7, because that growth strategy is timed well to meet the supply gap that -- we expect to emerge from -- in the 2020s.

The demand forecast continues to grow every year [amid] a strong appetite for LNG from China but also from South and Southeast Asia.

Indeed, in the space of just 2 years, projected demand by 2030 has risen by 88 million tonnes per annum, equal to the total of Australia's existing LNG capacity.

I've been saying for some time that pricing would come under pressure during this current period but in the longer term, the world clearly needs more LNG, and that's why we're pushing ahead with our growth projects.

 

On Slide 8, you can see some of the progress that's been made in the first half of the year on those key opportunities.

We've been hard at work to advance the relevant approvals and preliminary technical work to enable our final investment decisions.

At the full year results in February, you will recall that I said this is a year of the deal for Woodside, and our whole organization is working hard to deliver this.

 

Of course, with that overview, now I'll hand over to Sherry, who will talk about our financials in more detail and then I'll come back and take you through some of the milestones for the remainder of the year.

It's over to you, Sherry.

Thanks, Peter, and good morning, everyone.

 

Woodside's financial results for the half demonstrate our strong fundamentals and performance as we prepare for and deliver growth.

I'll start on Slide 10, which highlights the benefit of our diversified revenue streams with both North West Shelf and Wheatstone delivering strong production in the first half despite some cyclone activity in Q1.

As expected, Pluto production was down due to the planned turnaround and oil production was down due to the planned retrofit of the Ngujima-Yin FPSO for the Greater Enfield project.

With both Pluto and Ngujima-Yin now back online, we're very well positioned for a good second half.

Our advice remains that 2019 production is expected to be at the lower end of the 88 million to 94 million-barrel range as previously communicated to the market.

 

On to Slide 11.

Our first half profit reflects the production impact due to the Pluto turnaround and the Greater Enfield Project.

There was also the cost of executing the Pluto turnaround, which we were able to partially offset through the optimization activities of our LNG trading scheme.

This, together with our reduction in exploration expenditure, has resulted in a solid profit for the first half of 2019.

 

On Slide 12, a reduction in our breakeven cost has supported a 123% increase in free cash flow with our business remaining resilient to a range of oil price outcomes.

Our strong cash flows will help fund the execution of our growth plans.

 

Turning to Slide 13.

The LNG realized price was higher than in the corresponding period.

These higher realized contract prices were partially offset by an increased exposure to a soft spot market.

We do expect that in the second half of the year, around 20% of our LNG sales volumes will be exposed to spot pricing.

 

Our spot exposure is largely driven by 2 factors.

First, our strong LNG production is yielding extra cargoes, which we sell into the spot market; and secondly, our customers exercised some of their volume flexibility options this year and the affected cargoes are sold at spot.

 

Our unit production cost on Slide 14 speaks to the robust base business.

North West Shelf saw a small increase in maintenance spend in the first half in preparation for turnaround activities which are planned in the second half, but still remain very competitive at under $4 per barrel of oil equivalent.

 

At Pluto, nearly all of the production cost increase was due to the planned turnaround.

And Wheatstone showed anticipated improved cost performance with production costs reduced to $4.40 per barrel as the facility settled into steady-state operations.

 

Slide 15 shows that we continue to manage a strong gross margin of 38% across our portfolio.

Our high-margin, low-cost operations will generate cash flows that underpin delivery of our growth projects.

 

Moving to Slide 16, you will see that we are continuing to prudently strengthen our balance sheet and secure the funding required for delivery of our growth plans.

We took advantage of favorable market conditions to raise $1.5 billion from a Rule 144A/Reg S senior unsecured bond, which is the largest bond Woodside has executed in its history.

We received very pleasing support from the international debt market in that issuance.

 

Our competitive portfolio cost of debt, together with an increase in our portfolio average term to maturity of 5.3 years, is setting us up extremely well for delivery of our growth plans.

Our gearing increased as expected to 18%, which is primarily as a result of the new leasing standard, and our strong credit ratings with Moody's and S&P have both been reaffirmed.

 

Slide 17 provides a timely reminder of the impact of the new leasing standard.

This is an accounting change only with no net impact on cash.

Lease payments have simply shifted from operating expenses to depreciation and interest expenses, with our leases predominantly relating to LNG vessels and property.

 

Finally, on Slide 18, we have revised our full year investment expenditure guidance.

Our anticipated exploration expenditure during the second half of 2019 has decreased as we phase our preparations for the next Myanmar drilling program.

We've also phased some spend on our major projects into 2020.

Our capital intensity in the second half will be greater than in the first half as we ramp up activity on Scarborough, Pluto Train 2, Browse to North West Shelf and of course, SNE in Senegal.

We expect the investment expenditure for 2019 to be in the range of $1.45 billion to $1.55 billion.

 

On that note, I'll now hand you back to Peter to provide us a final summary and look ahead.

Thanks, Sherry.

 

Look, to summarize on Slide 20, we've spoken about our strategy many times before.

We really have world-class long-life production assets that are performing really well and generating the cash to underpin a -- the delivery of our growth plans.

We're looking forward to a strong second half with Pluto and Ngujima-Yin back online, and we're on track to deliver our 100 million barrels target by -- in 2020.

Of course, our project delivery has been on schedule and on budget, which has been very pleasing, particularly in the last 12 months with the success of Greater Enfield and the Greater Western Flank project.

And of course, we have a suite of growth opportunities well suited to our capabilities, which we're progressing.

 

If we move to Slide 21, you can see the work ahead of -- that sets us up for a year of decisions in 2020.

We're working hard to exercise the gas tolling agreement for Scarborough and complete the FEED activities at both Scarborough and Pluto Train 2 by the end of this year.

This sets us up for FID in early 2020 and an RFSU a few years later.

 

For Browse, the joint venture's committed to finalizing the gas processing agreement with North West Shelf this year, and there's only a handful of key issues to resolve.

And the joint venture is aligned on commencing FEED by the end of 2019, so we all want to get on with this project.

 

And of course, in Senegal, this is the first [cab off the rank] as we're positioning to take FID in the second half of this year.

And earlier this week, the joint venture submitted an updated exploitation and development plan to the Senegalese regulator in Dakar.

We're securing key approvals and, of course, finalizing project funding solutions with the joint venture.

So across the business, we really are prepared for the next steps.

We're ready technically and financially, and the Pluto turnaround is thankfully behind us.

We still have some hurdles to clear with the commercial agreements, and we're working hard to do that.

So I'm looking forward to updating you on that later in the year.

 

So with those opening remarks, I'll now open it up to your questions.

(Operator Instructions) Your first question comes from the line of James Byrne from Citi.

My first question is just around the Burrup Hub.

Now at the site trip a few months ago, Peter, you'd stated you expect low double-digit IRRs for these projects at current LNG contract prices.

But you also stated that you're quite positive on the commodity.

What I wanted to ask is when you and the management team go to the Board to sanction these projects, is there an assumption of a higher commodity price that you're able to achieve over time through periodic price reviews?

Or are you going to be able to sanction these projects based on their economic merits at current LNG project prices of mid-11s percent slope?

Thanks, James.

Well, the -- let me reiterate, I think, some guidance we've provided before around the way we sanction our projects.

Of course, we have what we call a net point pricing forecast.

We call that our net PEA.

That has the real escalation in price over time, and we use that as a basis for understanding some of the financial flex we have in the business.

When we sanction projects though, we use a different pricing deck, and that's a $65 flat real pricing deck.

And the reason for that is historically, over time, we've seen oil prices fluctuate around that $65 level, so we think we if can sanction the project at $65 flat real, then it means that investors get to enjoy the upside in projects as prices rise.

You don't want to build into your investment returns an assumption of rising prices because investors [never actually enjoy] the uptick in commodity prices over time.

So we want to make sure our projects are robust.

 

With respect to slopes, at the moment, we've adjusted our slopes downwards.

So over the last couple of years, our slopes are -- certainly, in the medium term, so over the next 5 to 8 years, we've adjusted them downwards in our modeling simply to reflect where we think the market is today.

And of course, we're hopeful that they'll increase, but the low double-digit rate of return that I quoted you during the investor tour reflects a $65 flat real price and a lowering of our short to midterm slope expectation.

And so no, we don't need to make any adjustments at all.

These projects today, we believe, are economically attractive to move forward with.

Got it.

Okay.

That's really clear, Peter.

The second question is just around balance sheet.

Ahead of CapEx, I've noted you've turned on the DRP, which presumably is just getting that balance sheet ready.

But also would you look to cut your exploration guidance in the medium term of $200 million to $250 million?

And then also related to the balance sheet is just whether your prior statements around only having to raise equity if you don't farm down, is that still relevant given turning on the DRP and also the extent to which LNG prices have fallen, not only in the spot market but also with respect to some of the risks around repricing of your existing contracts?

Right.

Well, let me deal with the DRP first.

We've decided to turn on the DRP for a couple of reasons.

Firstly, it is to start preparing the balance sheet, so we wanted -- we said we wanted to signal these things early before we get it ready.

But it's also a sign that the executive and the Board are confident that we'll be moving forward with our growth projects in the time frame that we've outlined for you.

So we decided this was an appropriate time to turn on the DRP.

It's not underwritten.

And we've got some historical data that tells us what sort of uptake that we would expect at the discount rate that we've offered.

Now we'll only know that, of course, after we've gone through the offer period, but we've got some estimates based, as I said, on historical performance that would lead us to believe that we'll get some certain outcomes.

And of course, as you know, there are certainly Australian-based investors who find it advantageous to participate in DRP programs.

Whether it's -- so that's basically getting the balance sheet ready.

And you've seen -- you heard from Sherry that we've already done a lot around increasing our liquidity.

And we've been out to the bond market earlier this year and raised another $1.5 billion.

So liquidity is in good shape, and this is just topping that off.

With respect to exploration, I'd -- I would say the guidance is towards the low end of that number.

So we said $200 million to $250 million, where we're tracking today is around $200 million, is a sustainable number for us.

It will fluctuate slightly around that but it's more towards the $200 million on that.

 

And then, of course, on equity, the guidance still remains the same.

It's really -- the equity position that we hold in the projects is critical to what our funding requirements will be.

And so if we decide to maintain our current equity positions, as we've said before, that by -- around the time we get to Browse FID or depending on oil prices and so forth, would be the point in which we would be looking to raise additional equity.

But -- so that's still some time out for us.

But it's really going to depend on oil prices and what happens between now and that point in time.

Your next question comes from the line of Joseph Wong from UBS.

Just a question I had on the Pluto North West Shelf interconnect.

Can you provide some commentary on the startup now in first half '22?

I guess the prior guidance just over the last 12 months has been 2021 and that was meant to accelerate Pluto gas.

Yes, I can.

I can, Joseph.

The 2021 startup was always really a Q4 startup, so it's just a couple of months into the beginning of 2022.

So we wanted to provide some guidance that basically gave us enough running room there.

And now, of course, we hope we can execute faster, but that's the slip in the guidance.

So it's not a material change at all in our expectations.

That's really been driven around the approvals process that we've had, but we've got approvals -- environmental approval requirements with the state and the federal governments and, of course, negotiations with the North West Shelf joint venture around the facilities that they'll need to build on their side of the fence to accommodate the interconnector.

So there's been really no change at all with respect to the timing, at least not a material change.

 

Now of course, we were going to use that for early gas coming across from Pluto.

We haven't modeled that, to be honest with you, Joseph, because there's still some question as to how much [oil leaks] there will be in the North West Shelf plants at that point in time.

We're not -- to be honest, our models aren't accurate enough at this point to be able to predict the actual decline dates that -- when North West Shelf will go into decline.

But there is an expectation that it will be sometime in 2021 that we'll start to see some capacity free up in the plant.

But there's differing views between each of the partners as to how quickly that will free up.

So I would say at this point, everything is pretty much on track and the environmental approvals are going through as we expected.

And so that's good news.

Yes.

And that's great to hear.

And the other question I had is if I look back at the investor presentation last year, you had, I guess, guidance of about 20% of your LNG sales portfolio for uncontracted.

Where do you see you're positioned now?

And where do you think is a comfortable position to be in as you kind of see the LNG markets, I guess, quite weak in the next few years?

Look, that's a good question.

And it comes down to -- Sherry mentioned some of the customers have exercised the downward flex, and so we're also going to look at the way we put together our annual delivery program and our ability to be able to source cargoes in the market itself should we fall short on the delivery point of view.

So it's one of those balance things that -- the market's become more liquid, we have more ability to be more aggressive in our forecasting with respect to our commitments.

So we'd like to be -- we've always said we'd like to be in that under 20% range, 15% -- anywhere between 10% to 15% for spot in this particular market is where we'd rather be targeting.

And so you can kind of assume that we'll be building our annual delivery plans around that and trying to target that 10% to 15% level.

And the reason for that, of course, if you'd ask me this question 5 years ago, we would have said we'd had more spot because spot prices have gone up to $20 per MMBtu.

Today, you can see that there's quite a difference between contracted and spot pricing in the market.

And as we've spoken about previously, we're seeing far more seasonality in the market these days.

And it's being exacerbated this year as new projects have started to stream.

So we're hoping to see a firming of spot prices as we come into the Northern winters, but we're also mindful that some of the storage is getting full, particularly in Europe.

And so it may take -- the shoulder of that may be a little longer.

Or it may take a little bit longer to see spot prices increase as we get into December.

Your next question comes from the line of Adam Martin of Morgan Stanley.

First question, just -- look -- cost looks like it's going to become more important.

It's, obviously, always important.

But how are you sort of thinking about potential of Scarborough across North West Shelf?

Is that a realistic option?

Can you sort of talk through that, please?

That's the first question.

Adam, just let me clarify, are you thinking Scarborough instead of Browse?

Or it's Scarborough and Browse?

Yes, probably just Scarborough instead of Browse, bringing Scarborough across the North West Shelf.

Yes, we're not really thinking about it.

The -- we've thought about it, of course, at length over the last 3 or 4 years as we've looked at optimizing which resources will go through North West Shelf first.

It's been clear every time we've looked at that, both as Woodside and then as the joint ventures, that Browse is the best project to underpin development -- or future development of North West Shelf, and for a number of factors, but one of them is simply the resource size.

One's 14-plus Tcf and the other one's about 7 to 8 Tcf.

So we've looked at that.

And there's also some gas compositional advantages for Browse over Scarborough in going through North West Shelf.

So at the moment, the base case remains for Browse to go through there.

The North West Shelf is committed to that.

And the North West Shelf is negotiating a gas processing agreement at the moment, pretty much exclusively with the Browse partners.

That's where the resources are being spent on.

It's not -- certainly not with the Scarborough joint venture.

Scarborough joint venture's just solely looking Train 2 at Pluto.

 

So there are options, obviously.

If for any reason, Browse did not get developed, then of course you'd have to have a look again at Scarborough and the potential to go through North West Shelf.

But that's a very, very low potential at this point in time.

In fact, I can't see a circumstance in which Browse would not be going through North West Shelf first.

Okay.

And second question, just -- you've obviously outlined that you're looking to sell some of the Scarborough assets.

Can you provide an update there with how that process is going with you back in the -- back on with that, [et cetera]?

Can you just provide an update there, please?

Yes.

We've actually had to slow down that process.

We've had a number of unsolicited proposals for participation both on an integrated basis, upstream and downstream equally, just upstream alone and then, of course, a couple of interested parties just in the downstream.

But we've had to slow that down, and the reason for that is we still haven't finalized the toll that will be paid to process the gas through Pluto Train 2. And until that's finalized, you really can't progress the discussions in any meaningful way with people around what the price may be for those assets.

So we've had people in the data room that's seen the base data, but we've just had to put it on hold until we finalize the negotiations with BHP around the toll.

And those -- when are you trying to target that?

Is that year-end, around the toll?

We'd like to get it done sooner than year-end, but certainly no later than year-end would be our target.

Look at -- in -- so it's in the lap of the commercial guys at the moment to work that through.

I think the key here is we're reaching a point, both at North West Shelf and Browse and, of course, with Scarborough going through Pluto, where -- and of course, each house is taking their own position with respect to the particular returns they need.

But we're fast reaching a point where people are going to have to put self-interest to the side and start to look collectively at the development of the resources.

And once you start to do that, it's just sensible to move forward.

These projects, each one of them, are economically sound at the pricing decks that we have, the tolls that are currently being offered and discussed.

And of course, we're in a point in the market where costs are very, very competitive for construction.

And we've got to kind of look past some of the individual wants and needs and move collectively.

And so we're in a competitive world here.

We've got other projects around the world, in other countries that are wanting to move forward and get into that same market space that we're targeting.

And so we're talking to our joint venture partners to make sure they see the big picture and don't get too focused on small stuff.

Your next question comes from the line of James Redfern from Merrill Lynch.

Three quick questions, please.

So the first one in relation to FID for Scarborough early 2020.

Can I just please confirm that Woodside is seeking to contract 50% of the LNG volumes from Scarborough before FID?

I mean if we -- and if we should assume a slope of 11.5% for those volumes based on the heads of agreement signed with ENN back in April, which is a 10-year agreement for 1 million tonnes.

And I've got 2 more after that, please?

Well, 2 things, James.

We'd like to, obviously, contract more than 50%, if we can, it will just really depend on the market conditions.

And I think our view was -- is firming over time that it's best, at least in this market, to probably contract more rather than less given some of the uncertainties and the overhang that starting to be created in the market with some projects going to FID without any sales.

So we are -- we're basically saying that 50% was guidance from us as kind of a minimum that we want.

Historically, of course, we've contracted in excess of that.

So if we can contract in excess of it, we will, but we've certainly got line of sight to that 50% today.

That -- the 50% is not the issue.

The question is just how quickly we want to sign up the rest.

 

With respect to slope -- I'm not sure we've given guidance on slopes, so thanks for slipping that one in.

The -- I think we did give a range though of where we were seeing slopes in the market at the moment.

I think the key one on slopes is more around price reopeners.

And we are seeing some contracts out there being agreed without price reopeners.

Woodside has not signed any of those contracts, for sure.

That is quite concerning to us because, as you know, that's basically saying you can predict the future in a perfect world.

So we're ensuring that we do have price reopeners in all of our contracts as we go through that.

So your point on slope was we're -- the slopes are reflecting market conditions, that's probably all I can tell you at this point.

But we're maintaining all of the other terms in our contracts, as I said, to make sure that as prices do increase over time, we're able to take advantage of that.

And just another one was in relation to SNE in Senegal.

Just what -- I mean, are you still targeting FID by the end of this year?

I'm just wondering if you can please provide some more color on the various issues there regarding arbitration with FAR, the reported sell-down by FAR and Cairn in the project and then project financing.

Yes.

Look, I think the main issue at the moment with SNE is the financing of the project.

Everything else is going very, very well, to be quite frank.

We've got the tenders in.

You can see we've been letting contracts subject to final FID.

We've got the all-star team, in our view, of the contractors to execute this project, to execute it really well.

So we're really pleased with what we've been able to do with our contracting and development plans.

And as I mentioned, we've just resubmitted the field development evaluation plan or exploitation plan.

So all of the things that you control are going very well.

The biggest issue for us at the moment is financing and it's -- of course, this is not an issue that is germane to Woodside but, of course, are partners are looking for financing as well as the national oil company is.

We've been out assisting them in project financing but, of course, we continue to get feedback from the project financiers that the arbitration between FAR -- with FAR is causing some uncertainty in the market.

 

To be honest with you, James, it's not clear to me how FAR is going to resolve this at this point.

The arbitration has been heard, but the ruling itself is unlikely to come down before the end of the year.

If it does, it would be very late in the year.

We have a PSC that expires in early December, so any ruling that comes down after the PSC expires is kind of the useless ruling anyway, so I'm actually not quite sure.

And I flipped it back into their quarters to how they're going to actually solve the problem that they've caused here for the joint venture.

Very good.

And just one last really quick one.

Just want to check, 20% of the LNG sales in the second half of this year will be spot.

How is it looking for 2020, please?

No, it will be less than 20%.

It will be in that range, but it will be between 15% to 20%.

It will be less than 20% in the second half of the year.

In the next year, of course, ADPs are set in the April time frame, that's the annual delivery plan.

And of course, we'll be -- as I mentioned previously, we'll be looking to be sub-15% on the spots there, to the extent we can through that ADP process.

Your next question comes from the line of Mark Samter from MST.

A couple questions, if I can.

First of all, a point of clarity: We often talked about the Scarborough volumes and that you want the contract 50%.

Can we just be absolutely clear that it will be -- the target is 50% based on initial annual production rather than reserves?

Because, obviously, you can be signing 5-, 10-year deals and you do 50% but you're actually only talking about 20% of bodies being contracted?

Or is the Board wanting to see 50% of total reserves contracted?

It's a good question, Mark.

No, it's just simply on production volumes, it's not on total reserve.

Okay.

Okay.

The -- just on the cost side, and you say it's still a very friendly cost environment.

Does that surprise you?

And when do we think that turns because there's an awful lot of LNG capacity that's already being sanctioned?

There's an awful lot that's either ahead of you or alongside you in the queue.

I mean, traditionally, this wouldn't be seen as a time when you're going to be getting bargains on the cost side of things.

Just wondering if you could help me understand why the cost environment is so friendly towards you.

I think there's 2 parts to it.

One is the offshore cost environment is very friendly.

So if you look at the mix on the spend on the projects, about half the project spend is still in the offshore part of it.

And then, of course, I think you might be referring to the LNG plant side of it.

So the offshore market is still a very poor market, particularly around drilling and subsea, so we're getting still very competitive costing in that area.

Having said that, we are starting to see early signs of escalation.

So some recent tendering that we've gone out with on other projects are starting to indicate the expectation of escalation starting to come into the market.

So we are reaching the end of that window, I believe.

And I think we thought that was going to happen a year ago and then we -- it got pushed out a bit, but we're starting to see that -- the end of that.

So it is critical for us to move forward with these projects now and be able to lock in these costs.

In the onshore side of it, it's a little different.

We're not seeing a lot of pressure.

For us, of course, in the Australian market, there's 2 parts to it.

One is the onshore plant will be modularized and will be built in a yard somewhere in Asia.

That will be up to the contractors to decide finally where that yard is.

And then, of course, the construction costs in Australia are still quite manageable, particularly compared to what it was during the mining boom.

So we -- whilst there is a lot of infrastructure work happening on the East Coast, which is drawing labor, we haven't seen that flow through to unit labor prices yet and were not expecting that it will in any material way.

But I think it's kind of a bathtub.

We just went down into the bathtub.

We've been on the bottom for a while.

I think these costs are starting to rise.

Everything out there would indicate that cost rises in the market are not far away.

And you're right, there are a lot of projects getting ready to move forward, but there are not that many that are actually physically being built.

There's some being completed such as Cameron and Freeport in the U.S. And there's a backlog of projects that want to move forward but they haven't gone to FID yet or moving forward.

And it's still early days with respect to Mozambique and so forth with respect to the labor and cost requirements.

So I just think it is coming, Mark, but we haven't seen it yet.

Okay.

But then just one final quick question, if I can, and particularly when we think about the risk you're taking on the uncontracted part of the portfolio.

And the chart on Page 7, and I'd, of course, never suggest that Wood Mackenzie get anything wrong, but that chart and the LNG market seem to be mutually exclusive because 11% slopes, and maybe a lot of people think falling lower than that, doesn't suggest a 50-million-tonne surplus in 2025, which you're fundamentally trying to market into at the moment.

So do you not think they are kind of mutually exclusive?

Or why aren't they mutually exclusive?

No.

I think the demand's there.

Low slopes and low oil prices, particularly low Henry Hub.

You've seen the TTF pricing as well, which is down around $3.50.

In fact -- and you've seen the profit results of the U.S. Gulf Coast manufacturers have been heavily hit by European pricing.

So that should increase demand.

And we've seen a lot of buyers now coming into the market, trying to lock in long-term contracts to increase demand.

I think what that then says is that it's going to put pressure on projects to actually move forward to FID.

So I think that's the issue, in my mind, at the moment with slopes.

Now how long is that going to last?

I don't know.

But no, I don't think growth and low slopes are mutually exclusive.

I think that's more of a supply issue, to be honest with you, than a demand issue at this point.

I just have a really, really quick last question.

Just with your U.S. volumes coming very soon, do you think we could be talking about paying and not taking with those U.S. volumes?

Oh, look, we -- we're looking at those volumes very closely.

About half of the near-term volumes are already contracted, so we've got options for that.

So if you think about the first 3 years of those volumes coming out, roughly half of that commitment that we have, have already been contracted in place.

So we're talking about a small number of cargoes coming out.

If you look at those cargoes today on the forward pricing curves, of course, they're quite marginal or just slightly out of the money.

So of course, you can imagine, our gas marketers are working very closely with our treasury function to look for opportunities in the market when they arise to place those cargoes.

And so we expect over next 12 months or so that we'll place more of those cargoes into the market as the forward curves work in our favor.

Your next question comes from the line of Hayden Bairstow from Macquarie.

Just a couple for me.

On -- just circling back to your earlier comments around the negotiations with the Browse and Scarborough JV partners.

I mean are we -- can you give a little bit more color on sort of where they're at?

Is there a broad agreement now about where the molecules actually go and, as you say, Browse before Scarborough into the North West Shelf?

Or -- and we've just moved on to sort of try to work out what the agreed tolling treatment charges are going to be?

Obviously, with BHP sitting in the North West Shelf at lower rates at the moment, I presume they're having to pay more if they're going through Pluto.

Is that still where those discussions are at?

Are we still in the earlier phases of working out where the molecules are going to go?

That's a good question, Hayden.

Yes, it depends on who you talk to.

If you talk to the majority of partners, it's all pretty clear that you probably picked up on one who still thinks there's an option and still keeps coming back and says we need to work out sequencing.

Sequencing was put in -- well, it's 2 years old, so it's done.

There's an agreement in -- a draft agreement in place based on certain sequencing, it's done.

There is no about-turn on this.

So anybody with that kind of noise out there is -- to be honest with you, I think they're in la-la land.

On -- with respect to the actual negotiations over the gas processing agreement, we did have a point here, 6 or 8 weeks ago, where the North West Shelf partners and a couple of partners in that, what we'll call the unaligned partners, basically said, "It started to drift away from where we think it should be, and we just want to reset." There were 31 items in that agreement.

We were able to turn that around very quickly, and we're now down to about 6 to 7 items that we need to resolve.

So I would say now, that agreement is with -- is very close, and we're starting to get -- once we get down to 2 or 3 items, we're at a point where we'll be able to close that pretty quickly.

Okay.

Great.

And just on the dividend, I mean is there anything you can sort of provide in terms of a minimum level we should think about in terms of payout ratios as you go through this rising CapEx cycle in the next few years?

It's -- and again, it's a good question.

It's a healthy tension we have within the organization around this, the purists that exist within our finance group, and then the practitioners who are a lot more practical and shareholder friendly.

So it's one of those ones where -- I'm getting lots of faces [pulled] at me.

But it's one of those ones where at the end of the day we've always had a commitment, and certainly since I've been here and before me, that we need to meet the needs of our shareholders first and foremost.

And we've taken on a challenging path in having an 80% payout ratio, but equally, it provides a discipline within the organization.

And we've always trusted ourselves, and it's a big trust, that if we need additional monies, then we should have growth plans in place that our shareholders, both existing and potentially new, will back.

I think that was the case last year when we raised equity, when we acquired ExxonMobil's interest in Scarborough, and that was, as you know, very well supported.

So that was kind of a testament to that process.

I think we're going to keep on that path, to be honest with you.

There are certainly tax advantages in Australia for Australian resident shareholders, for us to maintain our current payout ratio.

We -- as you know, we have a franking credit balance that is extremely healthy and unlikely to be drawn down in the short term.

And so once you put all of those factors in, it says that you go down a particular path that may not be the normal path that companies would go down if they were working in a different jurisdiction.

So we understand we're different.

We're very happy and fine with that.

And we know the mix of our shareholder base, particularly those who rely on our dividend.

Remember, we've got over 200,000 moms and dads on our register, so we're not like some of our peers, particularly U.S.-based peers who don't have moms and dads in any great proportion on their register.

So we always need to be mindful of that as well as [the -- those] as we think about our dividend policy and so forth.

Your next question comes -- all right, sir, no questions at this time.

I would now like to hand the conference back to today's presenters.

Please continue.

Well, thanks, everybody, for joining us in the call this morning, and particularly thanks for your questions.

I hope that we're able to provide further clarity to you.

I think the real message for us in the first half, we executed a very difficult turnaround on our major asset, which is Pluto.

The turnaround itself primarily was executed on time and on schedule.

Unfortunately, as we went to restart the plant, we found a piece of equipment that we'd actually replaced as a preventative action.

It was not able to be restarted, so we had to tear it apart again.

Very disappointing for us, I know disappointing for our shareholders as well.

But nonetheless, it was done very quickly, very efficiently and most importantly, safely.

And I'm proud to sit here today saying that the plant's producing above its nameplate capacity prior to the turnaround.

So the things we control, I think we've done well.

I think our marketing organization responded extremely well to be able to go out in the cargo commitments.

So that's really the operating business.

If you look at each asset, whether it be North West Shelf, whether it be Wheatstone and whether it be Pluto today, they're all operating extremely well.

 

With respect to the growth projects, there's a clear path.

We're in that difficult negotiation -- commercial negotiation phase.

What I'd say to you, though, is the next 6 to 7 months is going to bring together a lot of those negotiations.

So things that have kind of been out there for the last 1.5 years and are all moving to a single point over the next 6 months, and the organization and certainly our Board is ready for the decisions that we need to make in that period of time.

So you'll continue to -- I think you'll continue to see news out of us over the next few months as we progress our way through that.

And then, of course, we're getting to execution phase.

And as I mentioned, all of the technical work, execution work, the procurement, tendering, environmental approvals, government approvals work is all on track for the dates that we've said to you.

We have no delays in that at all.

The only thing that's holding us up making the announcements that we need to at the moment is just finalizing some of the commercial negotiations.

So we know what we need to do.

We know our -- where our boundaries are.

We've got the team in place to do it.

And we look forward to giving you more of an update on that as we get to our investor briefing day later this year.

So thanks very much for joining us.

Ladies and gentlemen, that does conclude our conference for today.

Thank you for participating.

You may now all disconnect.