Woodside Energy Group Ltd (WDS) 2021 Q2 法說會逐字稿

Thank you for standing by, and welcome to the Woodside Petroleum Limited Half Year 2021 Results Conference Call. (Operator Instructions)

I would now like to hand the conference over to Meg O’Neill, CEO. Please go ahead.

Well, good morning, and thank you all for joining our 2021 half year results investor call. It is a pleasure to speak with you again following the investor update teleconference last night.

I would like to begin by acknowledging the traditional custodians of the land upon which we are presenting from today, the Noongar Whadjuk people, and pay my respects to the elders past, present and emerging. I also extend my respect to all other aboriginal nations, the future generations and their continued connection to country.

As you are aware, this morning, we released our half year report and results briefing pack to the ASX. I'm joined on this call by our Chief Financial Officer, Sherry Duhe.

I'd also like to recognize that this is my first investor results call as the confirmed CEO and Managing Director of Woodside. I am humbled that the Board has selected and entrusted me to lead our company. While we have an exciting 12 months ahead of us as we work to complete the merger announced yesterday with BHP's petroleum business, the ongoing strength of Woodside's business and progress on our commitments is equally important. We will continue our focus on running Woodside to be customer focused, low cost and low carbon, and this will continue once the merger is complete.

I will start with a brief overview of our financial and operational performance and progress achieved on our key growth opportunities. Sherry will then give a more detailed financial update, before I provide a closing summary and open up the call to a Q&A session.

Please note the standard disclaimer on Slide 2 advising that this presentation does include some forward-looking statements and that our reported numbers are all in U.S. dollars.

If we move to Slide 3, you can see that our low-cost operations have enabled us to take advantage of the strong rebound in market conditions following the challenges and uncertainties due to COVID-19 in 2020. With global energy demand recovering towards pre-pandemic levels, we reported increases in profit and revenue. We recorded a net profit after tax of $317 million and an underlying NPAT of $354 million, up 17% from the first half of 2020. The directors have declared an interim dividend of USD 0.30 per share, representing an approximately 80% payout ratio of underlying NPAT.

Moving to Slide 4. In the first half, we achieved solid production performance after the record production levels last year and higher sales volumes as we increased trading activity in response to favorable market conditions. The safety and well-being of our people remains our priority. We have robust measures in place to reduce the risk of COVID-19 to our workforce, and it was pleasing that we recorded no Tier 1 or Tier 2 process safety events.

On Slide 5, you can see we continue to deliver safe, reliable and efficient operations across our producing assets. There are a number of activities included on this slide, but I'd like to highlight a few.

First, Pluto LNG achieved a record daily production rate while also delivering efficiency improvements and emission reductions. Examples of this include improving our operating processes to reduce methane and other emissions during steady-state LNG processing.

At North West Shelf as well, we have achieved direct emissions savings by streamlining the process of trunk line depressurization for the turnaround at KGP. Ongoing emissions reductions are also being realized through automation and advanced process control optimization, which includes challenging and optimizing power generation and compressors to reduce fuel gas usage. Also during the period, the North West Shelf Project finalized arrangements to enable the processing of third-party gas, which was a major milestone in transforming the Karratha Gas Plant into a world-class tolling facility. Our Australia Oil business also achieved a record price premium to Dated Brent for crude produced from the Ngujima-Yin FPSO.

If we move to Slide 6, as the graph shows, during the first half of the year, the oil and gas market experienced a sustained price recovery after the volatility of 2021 -- sorry, after the volatility of 2020. We have seen this reflected in increased average realized price in the half. These market conditions have provided an appropriate environment for increased trading activities this half compared to first half last year.

Moving to Slide 7. We are making good progress toward our target of a 30% cost reduction for our operated assets over the next 3 years. This is essential for us to maintain cost competitiveness in a dynamic market. We are bringing improvements off the drawing board and deploying them in the field with a focus on streamlining our processes and utilizing technology to inform decision-making and automate routine tasks. We have also deployed low-cost field sensors on assets so we can more effectively monitor equipment and be more targeted with our maintenance.

As Slide 8 shows, we have made significant progress towards our final -- our targeted final investment decision before year-end on the Scarborough development and Pluto Train 2 expansion. Scarborough is a globally competitive development with the potential to deliver significant value to our shareholders while supporting the world's transition to lower carbon energy.

You'll see on Slide 9 that technical work to support execution readiness for Scarborough is complete, and the majority of the key regulatory approvals have been secured. It was particularly good to receive the Nearshore environmental approval last week, which authorizes the installation of an approximately 32-kilometer section of the Scarborough trunk line within state waters and the associated activities required to construct the trunk line.

We completed and announced earlier this month the Scarborough cost update, which incorporates value-accretive scope changes to deliver an approximately 20% increased offshore processing capacity. This provides the cost certainty we need ahead of FID and supports the sell-down processes for Pluto Train 2 and Scarborough. In the first half, we secured state ministerial approval of an update to the Pluto Greenhouse Gas Abatement Program, supporting the development of Pluto Train 2. The proposed merger with BHP's petroleum business announced yesterday provides a clear path towards achieving our targeted FID this year.

Moving to Slide 10. Work on the Sangomar field development Phase 1 is progressing to schedule, and we are on track to deliver targeted first oil in 2023. Support facilities in Dakar have been commissioned, enabling the commencement of the 23-well development drilling campaign in July. Subsea equipment fabrication is progressing, and equipment is already arriving in Senegal, as you can see from the photos on the slide. FPSO conversion activities are well underway on the VLCC oil tanker. We have commenced the formal process to sell down our equity in Sangomar and are seeing positive interest from the market.

In summary, it has been a strong and productive first half, and we will be maintaining this momentum through the second half of this year. Sherry will now take us through the financial update.

Thank you, Meg, and good morning, everyone. Before I begin, I'd like to congratulate Meg on her well-deserved appointment as the CEO and Managing Director, and I'm looking forward to continuing under her outstanding leadership.

Starting off with Slide 12. Meg has already discussed the sustained price recovery, and the waterfall chart shows the impact of strengthening commodity prices have had on our profit this half. Sales revenue due to improved oil and gas pricing was up $387 million from the first half 2020, and we had higher revenue due to sales volumes as a result of increased Corpus Christi volumes and trading activity. We recognized lower depreciation and amortization expenses, which reduced due to lower asset values following the impairments in 2020 and lower production due to planned maintenance and weather events. With increased trading activity, associated trading costs have also increased in the half.

The other items is showing an increase of $166 million from the first half of 2020, and this relates primarily to costs associated with our Kitimat exit, which was announced in May 2021, hedging activities and new energy and operational transformation projects. We've realized the final closeout of commodity hedges, which were placed in 2020, and the mark-to-market valuation of new hedges placed on Corpus Christi volumes in the half. This has resulted in a first half reported net profit after tax of $317 million and an underlying NPAT of $354 million.

Moving to Slide 13. Our operating revenue has increased by 31% in the first half of 2021 compared to the first half of last year. This is underpinned by the improved pricing and higher trading activity I mentioned in the previous slide. We have also had higher shipping and other revenue due to an increase in shipping subchartering.

On Slide 14, I'd like to talk about our operational cost performance. As you can see, we've maintained flat production costs from the first half of 2020. However, unit production cost has increased to $4.9 per BOE as a consequence of lower production volumes and planned maintenance activities, including our turnarounds at KGP's LNG Train 4 and the Goodwyn A platform.

Slide 15 puts our unit production costs into the context of our cash margin. We've maintained a cash margin above 80%, and our cash margin has increased by $8.60 per barrel in the half. These margins continue to support our strong balance sheet.

Moving to Slide 16. We've continued to prepare our balance sheet ahead of a targeted Scarborough and Pluto Train 2 final investment decision later this year. Our balance sheet is characterized by a well-managed debt maturity profile and high liquidity. Our gearing has decreased to 23.3% from 24.4% at year-end 2020, and we continue to manage our near-term debt maturities and maintain a low cost of debt. Pleasingly, our credit ratings were reaffirmed in the half, and we continue to maintain our target liquidity cover of 12 to 18 months.

On to Slide 17. We have taken a number of proactive measures to ensure we manage price risks across our portfolio. We have placed hedges on our unsold Corpus Christi volumes. And as of the 16th of August of this year, we have reduced our pricing risk on approximately 85% of our 2022 cargoes and 25% of our 2023 Corpus Christi volumes as a result of the hedging and fixed price term sales.

In the half, we've seen an increase in trading and optimization activity driven by favorable market conditions. This activity is opportunistic and includes the purchase and on-sale of third-party cargoes to extract additional value from flexibility within Woodside's contract portfolio. Trading and optimization activity is managed within a robust risk management framework and is expected to generate average margins of up to 5% of cost. This reflects the value accretive but relatively low risk nature of this type of trading.

The cost of purchasing third-party cargoes and Corpus Christi volumes is presented in trading cost in the profit and loss statement, and the associated revenue from the on-sale of these cargoes is presented within LNG revenue. Given the current market factors and improving LNG spot prices, we expect full year trading cost, including the Corpus Christi volumes, to be between $1.1 billion and $1.3 billion. Approximately $800 million of this is expected to be third-party traded in nature, subject to market conditions and opportunities.

To protect against downside pricing risk, we are also looking to hedge up to 20% of oil-linked exposure in any 1 year. Subsequent to the half, we have placed a number of hedges in 2021 and 2022 production at Brent pricing above $70 per barrel. To date, we have hedged 2 million barrels of our 2021 production at an average price of $73.68 per barrel and approximately 6 million barrels of our 2022 production at an average price of $71.72 per barrel. Where appropriate, we will continue to lock in prices to provide pricing certainty.

Moving to Slide 18 and 2021 full year guidance. In addition to the trading cost range I mentioned on Slide 17, we are providing guidance on expected production costs of between $450 million and $550 million and expected general and administrative costs of between $150 million and $250 million. Our expected production cost incorporates higher planned maintenance activities and foreign exchange assumptions compared to 2020, and expected general and administrative cost incorporates higher spending on sell-down and growth-related activities.

In our fourth quarter report earlier this year, we provided investment expenditure guidance of $2.9 billion to $3.2 billion. This remains unchanged as the Sangomar equity position of 82% was already incorporated previously. Our production guidance range for 2021 has narrowed to 90 million to 93 million barrels, and our guidance on uncontracted production remains unchanged at 10% to 15%.

I'm pleased to say we continue to maintain a strong balance sheet as we head towards our targeted Scarborough and Pluto Train 2 final investment decision and have positioned our company well for the next 12 months as we progress towards the merger with BHP's petroleum business that we announced yesterday.

I'll now pass back to Meg for her summary.

Thank you, Sherry. If we move to Slide 20, many of you have heard me speak on the importance of Woodside being both low cost and low carbon and the action we are taking to ensure this. On the left hand of the -- left-hand side of the slide, you can see our corporate targets for emissions reductions, which we have previously announced. To be clear, we are taking action today towards our near- and medium-term targets in support of our aspiration of net 0 emissions by 2050 or sooner. We will achieve these targets by avoiding emissions through the way we design our projects, reducing emissions by the way we efficiently operate our projects and originating and acquiring quality offsets for the remainder of our targets.

We have previously announced we will be putting our climate reporting to a nonbinding advisory vote of shareholders at our 2022 Annual General Meeting. We understand the level of interest in this area and the importance of transparent reporting. We have been engaging with our major shareholders on our climate reporting and look forward to sharing further our approach to the energy transition in the lead-up to next year's AGM.

On the right-hand side of this slide, we have highlighted our ongoing focus on growing our new energy business, which includes further maturation of our portfolio of hydrogen and ammonia. We are also progressing renewable power opportunities in the Pilbara and investigating carbon capture and storage options.

Moving to Slide 21. I want to take this opportunity to reinforce our priorities for the remainder of the year and our commitments to becoming a low-cost, low-carbon company. These priorities remain and complement the activities we announced yesterday afternoon as part of our proposed merger with BHP's petroleum business. We are focused on maintaining a disciplined approach to expenditure. We are assessing what we do and how we do it, transforming our business to reduce costs and increase efficiency.

We will create and protect value by achieving our targeted final investment decision for Scarborough and Pluto Train 2 in the second half of the year and delivering the Sangomar Field Development Phase 1. We will build our sustainable future by delivering value through the energy transition, continuing the safe and reliable supply of energy to customers, diversifying our business streams and working with our communities to realize positive outcomes.

Thank you for your ongoing interest in our company. We will now move to the Q&A section.

(Operator Instructions) Your first question comes from Saul Kavonic with Credit Suisse.

Meg, obviously, still quite a lot to digest here. But my main question upfront is the 30% cost reduction you're talking about in the operated assets. Can you provide some color on how we should think about that? I mean, does that fundamentally mean we should be looking at the, for example, that $8.50 per BOE cash costs that you mentioned here could drop by 30%? How exactly should we think about this if you want to start ascribing a kind of $1 million per annum number to this?

Look, Saul, we've probably not set out those targets. So one of the things we're very mindful of, of course, is that our production mix is changing. North West Shelf, of course, has gone into decline. So we now have haulage in the plants, and we're very much focused in the operational part of the business on driving absolute costs down. So the 30% cost reduction is a target we've set for the operational part of the business, and the team is really making great progress in terms of changing how we do our activities to achieve those goals. That's a goal that we've set, of course, over a 3-year time period, and we'll continue to keep you posted as we move forward down that journey.

Great. Again, back on the proposed merger last night, is it possible to get any kind of indication of the scope of the $400 million kind of synergies? Just roughly what proportion of that is exploration high-grading versus the other items that were listed?

Yes. Saul, I think it's premature to provide any more detail. We've talked about 3 kind of core categories where we see synergies. One is corporate costs, of course. You don't need the same super structure to run 1 company that you would to run 2. The second, of course, is through the assets where we've got opportunities to really take a look at the growth offer and make sure that we're kind of efficiently prioritizing activities in the growth offer. And then the third is exploration and making sure that we've got the right focus in the exploration business, thinking long term about what are the sorts of things that we want to bring in the hopper. But it'd be premature to give you any more detail at this point in time.

All right. And then lastly, and I think it's a follow-up on the question from yesterday, the decline in Woodside base business that was shown for 2024, I want to get an understanding. Does that include a decline beginning in Pluto in the 2024 to 2027 window? Or are you expecting Pluto to remain full, absent the Scarborough FID, into the -- well into the second half of this decade?

Saul, we don't provide forward-looking statements on an asset-by-asset basis.

Your next question comes from Gordon Ramsay with RBC Capital Markets.

Meg, I'm just going to ask a question about the merger. Under what -- I mean, you're targeting FID for Scarborough before the end of the year. I just don't understand how BHP is not going to exercise its option on Scarborough. FID is going to be taken before December 15, presumably. So you're going to have to pay BHP $1 billion for taking Scarborough. So what am I missing?

Yes. That's not the right way to think about it, Gordon. So the option can only be exercised by BHP Petroleum in the second half of 2022. So we've got alignment with BHP to take a final investment decision this year. If that is successful, then the option comes into play. The only scenario where it would be exercised is if the merger doesn't complete. And when we look at the value that Scarborough brings to Woodside shareholders, both the Woodside shareholders today and the Woodside shareholders in the future merged company, we see Scarborough as a very compelling investment.

So it really is just a kind of option for BHP in the event that the merger doesn't progress. Assuming the merger is successful, the option just goes away. And we are able to progress the projects for the benefit of all of our shareholders.

Got it. My mistake. And then just on abandonment costs in Bass Strait, the -- there's been studies that imply that the net cost to BHP could be up to about $5 billion. Can you confirm that?

So Gordon, I don't want to provide any specific numbers about decommissioning costs for any particular asset. I think it is worth highlighting a few points. So in our due diligence, decommissioning was absolutely one of our key focus areas because of the studies that you've pointed to. And so we had a very significant part of our team looking at Bass Strait, trying to understand the assets, trying to understand the decommissioning plans and the costs to execute those plans. We, obviously as an experienced offshore operator, have experience in this, and we've had some of our best people digging into it. So we've got a good understanding of what Bass Strait decommissioning costs are likely to be.

I think it's important to bear in mind that those costs are spread out over probably 20 years, and Bass Strait continues to be an asset that will be very productive and generate value for the merged company over the very near term and the decades to come. So the valuation that's built into the merger ratio fully accounts for those decommissioning obligations.

Okay. I'll leave it then. Best of wishes. Congratulations on a great deal.

Your next question comes from Mark Samter with MST.

Yes. Three questions, I think, if I can. Just to come back to the contingent payments to BHP, and I appreciate it, I think you explained it well on the call last night as well, Meg. But I'm just keen to understand how you guys approach the balance sheet leading into it. Are you going to set the Woodside balance sheet with the assumption that the merger happens? Because correct me where I'm wrong, but it feels like once you've taken FID on that, if the balance sheet is in a position where it assumes the merger is completing, I mean, in fact, if you hold a gun to a shareholder's head, where it would be? I think it's impossible to vote the deal down because your alternative to the deal not happening is you suddenly got to pay $1 billion out, and you own 100% of the upstream. So would the balance sheet be reflective of the business you think it becomes? Or do you feel like you need to capitalize Woodside to reflect the fact the deal could fall through when you FID?

Mark, I'll have Sherry deal with that question.

Yes. No, Mark, thanks for that. I think the first thing, from a context perspective, to keep in mind is we think shareholders will vote for this deal because it's a great deal and because we're better together with this combined portfolio for all the reasons that we talked through yesterday. And I'm sure we'll have the chance to unpack that more for you in the coming months as we lead up to that vote.

To your point, we've been very clear, and that's why we launched the processes for the sell-down activities for Scarborough, for Sangomar and for Pluto Train 2. Obviously, in the background, we knew that this transaction was going ahead. So we'll continue to run both scenarios in terms of how we think about funding our balance sheet up to the point of a vote next year but also beyond.

And I think Meg spoke about it very clearly yesterday that now that we understand that this is happening and we can talk about it publicly, then we'll be talking to potential investors in the data room for Scarborough, in particular, because, in theory, we may have more equity that we might have available to share with them at the right point in time. We've had very productive, confidential conversations with the rating agencies up until now, and we'll continue to follow that through as we leap forward. So we feel like we've got really robust plans both before and after the vote and in light of this potential put option that could come into play at the back end of next year.

And then just a quick question to, I guess, slightly follow Saul's question but answer it probably a slightly different way on the cost side of things. I mean, obviously, we saw -- I mean, the 30% target, that's targeting everything, CapEx, OpEx, other costs. So probably the important one, North West Shelf's declining, so of course, you're going to see a reduction in costs when an asset's declining.

The flip side is you've got a reasonable amount of fixed cost in -- or a lot of fixed cost in that asset. So do you think you can see declines in unit production costs over the next 3 years or it's obviously picked up in the first half of this year? Or is that going to be a much harder challenge to see genuine unit cost, production cost savings?

Yes. Look, Mark, it's a great question. Obviously, when an asset goes into decline, it is a significant challenge to try to drive that cost out of the system. One of the things that will help us in the Karratha Gas Plant, of course, is getting more gas through the plant. And our agreements that we signed with Pluto and with Waitsia late last year to bring gas in starting in 2022 from Pluto and 2023 from Waitsia helps keep the plant full and manage those unit costs, although there'll be some accounting quirks that we'll have to kind of talk our shareholders through since it's not our gas that will be going through.

At the end of the day, I've got a lot of experience running mature assets, and I've seen great examples of what you can do to drive cost out of the business. And I have complete confidence in the team here that we'll be able to drive those costs down to keep KGP and the North West Shelf very profitable until the end of life.

And that's a great segue into my last question because are we still absolutely 100% categorically ruling out any scenario where Scarborough comes in the North West Shelf? I'm cognizant Chevron's stake was announced, and nothing has ever happened. Is there any scenario whatsoever where plans could switch for Scarborough or we're 100% locked its -- to Pluto?

No. Mark, I think I said this a few months ago, the ship has sailed on that option, and we've talked about it before in a fair amount of detail. There are technical reasons why it's difficult to process Scarborough gas through North West Shelf, and the complexity of the modifications are quite extensive. None of that technical work has been progressed. It's commercially complex.

And when you look at it from a shareholder's perspective, we're going to be able to get far more value by taking Scarborough gas through a brand-new train at Pluto. When you look at the life of the assets, having that new energy-efficient and emissions-efficient train, it's going to deliver better outcomes from a cost and carbon perspective. So the ship has sailed on Scarborough and the North West Shelf.

Your next question comes from Dale Koenders with Barrenjoey.

I was hoping you could help me decipher Slide 21 a little, just on the $1.1 billion to $1.3 billion of full year trading costs. Multipart question. Firstly, what hedging and forward sales have been completed for these volumes in second half '21, if any?

Yes. I can take that, Dale. Those are just simply buy and sell transactions. There is no hedging activity that's related to that. So what we've done is taken a look at the number of cargoes that we think will optimize opportunistically in the second half and then included Corpus Christi in those volumes. There are hedging activities that are in place for the Corpus Christi volumes but not for those extra spot cargoes that we're just buying and selling with no open exposure risk around them.

Okay. Can you provide some color on the Corpus Christi hedging that's occurred in the second half? I guess Platts is reporting U.S. netbacks of USD 10 MMBtu or almost 100% on lifting costs for that asset at the moment. Are you going to realize all of that value? Or have you sort of missed out on some of that because you hedged early?

Look, we can't get into the details of each specific cargo and what we hedged around it. I think what I can just reiterate is what we put in the presentation pack that when you look at the periods that are covered, we really have looked at 2022. And we've hedged or sold at a fixed price 85% of our volumes and then 25% for 2023. And we'll continue to actively monitor that, in particular, for 2023 and beyond.

Okay. And is this level of, I guess, trading activity expected to be the new norm for Woodside on a go-forward basis?

Look, it's a great question. I would say that the norm will be driven by the market conditions. And so we've chosen that word opportunistically very carefully. There could be times where you see us doing very little or no activity in that area, and there could be times like now where you see an elevated level of activity, where we see the opportunity to make sure that we get some margin out of that. We don't take those opportunities where we would have a loss-making position, and we have a robust risk management framework around looking for that opportunity.

Okay. So this trading cost we should assume is, there will be a positive margin on all but except for maybe Corpus Christi, depending on the market at the time?

That's correct. And the Corpus Christi, we've noted that in the financials. Just because of the nature of those hedges, they're not receiving hedge accounting treatment. So you will see volatility coming through the P&L this year for next year ahead, and we'll call that out clearly as we've done in this period as well.

Okay. And then just finally, just on the transaction last night, it was very kind to explain around the merger ratio being a relative net asset valuation between the 2 companies. I was just hoping you could talk about the synergy. Was that taken into account in setting those net asset valuations? And was it shared equally between the 2 parties if it was?

Look, Dale, it's a great question. We do expect to see synergies come from both individual parts of the merger. It is not accounted for in the merger ratio. So we see that as upside that the shareholders of the merged company will benefit from.

Your next question comes from Daniel Butcher with CLSA.

Look, just first question is just on Scarborough and Pluto tolling. I think, if I remember, you've got the draft toll arranged. But you won't be able to get full control of the asset to change tolling arrangement or optimize it before you have to go to FID under the merger. So I'm just curious how to think about the optionality to optimize the toll between the upstream and downstream that attract you [such] buyers and so forth.

Yes. Daniel, the tolling agreements actually are sufficiently mature that we are confident in progressing the sell-down activities and working towards the final investment decision. So we have alignment between all of the parties, and I think we've talked before about this is not just one agreement. It's a whole suite of agreements involving -- just involving the Scarborough joint venture on one side, involving Pluto Train 2, which currently is ourselves, but we're looking to bring a partner in on and the Pluto side. So we've got a number of different commercial agreements, all of which are very well matured. And we'll be ready to finalize those when we get to the FID decision point.

Right. I guess I was operating on the presumption that BHP wanted a higher IRR upstream. So the toll will be set quite low, and that might dissuade some [import] buyers. Is that not the case?

Look, we've not talked about the quantum of the toll, but we feel like the toll is a good reflection of the balance of risk and value between the different parts of the business, the upstream and the midstream.

Okay. Maybe moving on to just on production guidance being cut 2 million barrels at the top end. Can you maybe just elaborate a little bit on what's been driving that primarily?

Yes. A couple of things, Daniel. So as we reported in the half year, we have seen some operational challenges, particularly in the FPSO. So there's been weather-related downtime as well as some operational issues. So that's driven us to reduce the top end of the range.

Okay. So nothing to do with North West Shelf water in the well issue?

No.

Okay. A final question for me, if I can. Just back to the merger, I mean, you may have alluded to it a little bit before. I'm just sort of wondering what your analysis on the churn and a number of offshore holders that will be churning out the stock when they get it from BHP. Can you maybe just share with us a few thoughts around about what you can advise there from your bankers?

Look, it's a great question, Daniel. Obviously, with BHP's announcement of their unification, that adds a degree of complexity to it. And now that, that is transparent, we'll be able to do this with all of the information available at hand. But our first assessment is that about half the BHP register is index and retail investors, and we would expect to see rebalancing in the portfolio. Retail shareholders have always been a strong portion of the Woodside register, and we look forward to engaging with those mom and dad shareholders to help them understand the value of staying with Woodside. But the balance of the assessment would suggest that whilst there will be folks who leave the register, that will be more than offset by demand.

And that demand is from local index funds with double the weighting in the ASX? Is that mainly the case? Or...

Look, there'll be some of that. But one of the things that we're looking at is the option to pick up some additional listings. So one of the things we are quite mindful of is that BHP does have an investor base that's international, that we've probably not historically been able to access. So we are looking at listings both in London and New York to be able to attract some new investors to Woodside now that we're a bigger player in the global energy market.

Your next question comes from Nik Burns with Jarden Australia.

Just my follow-up on one of Dan's questions, just in relation to Pluto Train 2 toll. You're in the process of bringing in a buyer there, assuming there's an announcement between now and FID around that. How are we going to be able to judge the value of that if we don't know what the toll is? Potentially, you could attract more parties then by having a higher toll there. But if you don't announce that, we don't necessarily know. So is there plans to provide additional disclosure around this at the time that you announce any sales?

Yes. Nik, that's confidential information, and I don't envision scenarios where we would talk about the quantum of the toll. What I can tell you is that the data room is open, and we do have very strong interests from a number of very credible infrastructure investors. There's the sorts of players that you've seen active in the market both here and overseas over the last couple of years, picking up more interest in this type of asset. So we feel really good about the interest and the opportunity. And we feel like, as I said, the toll is set in a way that balances risk and reward between the upstream and the midstream and should be attractive to investors in both spaces.

Got it. Have you set an effective date for that transaction? Could you be able to claw back some of the CapEx you've set aside this year for Train 2?

I'll let Sherry speak to that.

Yes. No, Nik, thanks for that. And I would just say that the way that we have structured the data room setup, it is very transparent to bidders what that toll will be, just to kind of follow on to Meg's previous answer. But also, the effective date will be something that balances out the CapEx burden that we have going forward but also compensates us on a pro rata basis for the investment we've made to date in both of those projects, depending on what you're looking at, Scarborough or Pluto Train 2.

Great. That's very clear. Just quickly on the merger, have you estimated the costs to implement the merger?

We haven't disclosed that, Nik.

Okay. And then maybe just a final one. Any key regulatory or JV approvals required associated with the merger process?

Nik, there's actually a very long list of regulatory approvals, as you might expect for a transaction of this complexity, spanning multiple international jurisdictions. So we've got a very clear understanding of all of the regulatory approvals required, and that's something that we'll be working through over the coming months. Yes, I think the question was asked yesterday about what drives the time line between today and potential completion. The regulatory approvals is a very important step in that process.

Right. Are there any of those that are more key than others?

Well, they're all important. I wouldn't want any regulator to feel like I was implying they were unimportant. They're all important. Yes, we've got a number in Australia. We've got a number in the U.S. We've got some in other international jurisdictions. So we just have to work through all of that.

Thank you. Your next question comes from Tom Allen with UBS.

Quick question for Sherry. Just on your segment revenue and expenses, there's a big step-up this half in other costs to $151 million. Looks like $81 million of that is unallocated. Can you share some detail on what makes up the unallocated step-up in costs?

Yes. So I think I went through a number of the details on that when I went through the summary. But the biggest single item that you see in there is basically the movement in the financial hedges. We've also got the Kitimat exit costs that are sitting in there. Those are the 2 single biggest components in that 1 line item.

Sure. Sure. All right. I'll move on. Do you still expect your exposure to spot LNG cargoes to be in the 10% to 15% range for the remainder of this year and then into 2022?

That's correct for this year. I did state that we're still looking at 10% to 15% for the full calendar year. We haven't put out a number yet for next year. But as you'll know from past years, it goes anywhere from 10% to 20%, depending on what's happening in the marketplace in that particular year and the different ADP nominations that are made by our customers in the end of the first quarter of each year.

Right. And just following up some questions earlier just on the trading business. Over the half, the trading business made a loss. We're seeing higher third-party LNG purchases coming through. Can you just break out the drivers there and how you're confident with those trading volumes lifting up and down half-on-half that you're going to secure that margin that you're targeting?

Yes. And just to be clear, when you look at our overall trading activity for the period, we did not experience any losses. There is a little bit of a nuance in the sense that we have an onerous contract provision that we booked last year for Corpus Christi. And so changes in that position actually go to a different line item on the financials, and you can see that broken out in the segment P&L for that line item.

But overall, we saw a positive impact for our trading activities for the period. And some of that goes through those spot activities that I highlighted earlier. And other of that is just the trading contribution to the equity volumes that we sell from our produced portfolio.

Your next question comes from Baden Moore with Goldman Sachs.

Meg and Sherry, just a follow-on on the spot exposure for the business. In the context of the merger, you'll be a much larger player in the global market. And I was wondering how you think about whether you'll be looking to take a greater spot exposure in the future. And then in that context, as we look at the Scarborough development, you previously talked about a 50% commission precedent on contracted levels for Scarborough. So I was just wondering if that's still the case.

Look, Baden, it's a great question and is probably one we need to put on our list of things to work through. Obviously, we've taken a bit of a different approach from BHP Petroleum in terms of marketing strategy, particularly for growth projects like Scarborough. We do need to get our thoughts together, and we've talked about it in the past actually that we're seeing an LNG market that is changing in many fundamental ways. It's becoming far more liquid. We're seeing different price markers. So I think the guidance that Sherry gave is sound for the next few years. But as we move forward in time and as we think about what our marketing strategy is going to be in the context of the merger, we'll be looking to refine our approach to spot.

It's probably worth highlighting that we have a very strong marketing team. As Sherry highlighted, we've been doing a good bit more trading this year, managed under a very tight risk management framework. But we are getting great experience in the market. We know the customers well. We understand what the market is doing. And so that gives us a few more levers to pull, particularly as the merger comes together.

And on the Scarborough volumes, will they be 50% contracted?

Look, Baden, that's where we are today actually with our current working interest in Scarborough, between LNG term sales as well as our domestic gas sales to Perdaman. One of the complexities, of course, is we're going through a sell-down process. So we'll be kind of seeing how those bids come in. And we'll be working with other prospective joint venture partners on whether or not they'd be interested in some of the Perdaman volumes. But the number, I don't want to be too definitive on the number, recognizing that our equity is likely to be a little bit different than what it is today.

Okay. And on the revised $12 billion capital number, in the 2018 capital-raising documents, the business flagged a 25% contingency allowance in the capital program. I was wondering, did that change through the revision of the CapEx estimates for FID at this point? Or can you shed any light on what's there for contingency in the latest CapEx update?

Yes. Look, Baden, we wouldn't normally disclose contingency levels or allowances or any of that sort of information. I think it's worth highlighting, though, that the technical work and the execution planning for Scarborough and Train 2 is extremely well advanced. It's -- with the delay in FID from 2020 to 2021, the technical teams have had a chance to really firm up our understanding of what the facilities will look like to mature the engineering and the detailed design work. We've actually purchased some long leads. So our confidence in the cost estimate is very high.

And worth pointing out as well that our contracting strategy with a heavy bias towards lump sum and fixed rates puts us in a position where we've got very high certainty that when we take that final investment decision that, that's the cost that we will pay for those assets.

If I could just ask one more. On the capital -- on the cost program that you flagged, the 30% cost reduction, just how do I think about that? Is that a -- is there a capital program that's linked to that OpEx reduction that you could talk to?

No. So I mean, a lot of it's, Baden, just to be, I guess, elaborate on the no, is around how we do our work. So while we are investing in technology, that's all done on OpEx. So we are spending a bit of OpEx, but we do expect to get significant OpEx savings from that spend.

Your next question comes from Jennifer Hewett with AFR.

This is a more general question, Meg, and congratulations on your appointment. But in terms of future growth options, I'm just wondering how you see the future of blue hydrogen relative to that of green hydrogen.

Thanks, Jennifer. That's a very timely question. I know there's been a lot of press recently around the merits of the 2. It's probably -- we're stepping back a bit in talking about the transition to new forms of energy, and one of the things we've been doing as we've been building out our capability in ammonia and hydrogen is really working closely with our customers to understand what they need. And we fully recognize that any material investment in new energy is one that has to be customer-led. We could build facilities today to make hydrogen, but if nobody is there to take it and pay for it, it's not a good use of our shareholders' money. So as we work with our customers, one of the things we recognize is they're going to have to make investments on their side to take products.

So blue hydrogen, we see as a very natural kind of bridge between LNG, which is something we make today and something that's very affordable for our customers, and green hydrogen, which is not something that is widely produced today and that likely will end up being more expensive for customers. So in many ways, we see blue hydrogen as a stepping stone to get to the ideal world, which is a green hydrogen world, where there's no emissions at all. But we do recognize that we need to really understand the actual emissions profile of any investment in this space. And so this is something we'll continue to work very closely with our customers as we mature those opportunities.

Your next question comes from Sarah Kerr with AustralianSuper.

I just had a question on your growth projects. Is the Browse field development concept still to come through KGP? And when do you think that asset will be realized?

Great question, Sarah. So our base plan for Browse is still to bring that through the North West Shelf and the Karratha Gas Plant. Obviously, Browse has gone through a few iterations over the course of its life. One of the things we fully recognize now is we need to make sure we've got all the regulatory approvals and commercial agreements in place before we ramp up technical activity, and that's been the key focus of the Browse team over the last year.

And just on the strategy for carbon emissions associated with the reservoir of the Browse complex, are you looking at CCS or just using offsets?

So we absolutely are looking at CCS. And Sarah, that's one of the things that's probably changed from a technical perspective in Browse since we lasted work on it a couple of years ago, is the recognition that we absolutely need to have a better carbon solution for Browse. And we need to take a really hard look at CCS to make sure that we manage those reservoir emissions.

And do you have any kind of, I guess, years or time frame when you think Browse will start to go to feed?

No. I think it's probably premature to answer that, Sarah. As I said, there's some fundamental work -- we have fundamental work. We need the environmental approvals. We need the production licenses. We need commercial approvals. We need to mature our CCS work.

Okay. Great. And just one final question. And if there's any progress on the Sunrise field and negotiations with the Timor-Leste government?

Yes. It's a great question, Sarah. So Sunrise, obviously, is an asset that we've held for a while. We're very pleased that the Australian and Timor East governments have settled the maritime disputes. We are involved in those PSC discussions, and they're continuing.

Okay. So no movement on it yet?

As you might appreciate, any time you're negotiating a commercial agreement with 2 governments, it takes a bit of time.

Your next question is a follow-up question from Saul Kavonic with Credit Suisse.

I just also just wanted to ask if you could just tidy up a few other things regarding the Scarborough auction FID. Meg, can you just clarify for us, the FID payment that was due BHP, is that now folded into the mergedco? Or is that going to be an additional payment for kind of BHP corporate outside of BHP Petroleum?

And a related question is the 15th December date for the option. What's driving such a specific arbitrary date? And when does the Train 2 contracted Bechtel costs expire? Sorry, there's about 3 in there.

Yes. That was a long follow-up question, Saul. Look, we haven't commented on the Scarborough FID payments. Yes, the option date is quite specific. Pragmatically, the last 2 weeks of December, you don't get a whole lot done with the holidays. And so this is -- it's essentially a end-of-year date but a pragmatic one. And what was your third question?

Bechtel costs.

Bechtel costs.

When does the Bechtel costs expire? Yes.

We haven't disclosed that date either. So I think it's worth emphasizing, Saul, that all of our contracts are lined up with our anticipated final investment decision in the second half of this year.

That does conclude our question session. I'll now hand back to Ms. O’Neill for closing remarks.

All right. Thank you all for your questions. I understand we have given you a lot of information in the last 24 hours, and we are very excited about the direction we're headed in. I'm looking forward to meeting with many of you virtually over the coming weeks. We will certainly keep you updated as we deliver on our key priorities for the remainder of the year, particularly safely executing Sangomar, progressing towards Scarborough FID and finalizing the transaction documents for the merger with BHP's petroleum business. Thank you.

That does conclude our conference for today. Thank you for participating. You may now disconnect.