Woodside Energy Group Ltd (WDS) 2020 Q4 法說會逐字稿

Thank you for standing by, and welcome to the Woodside Petroleum Limited Full Year 2020 Results Conference Call. (Operator Instructions) I must advise you that, today, this call is being recorded, Thursday, 18th of February.

I would now like to hand the conference over to Mr. Peter Coleman, CEO and Managing Director. Please go ahead.

Good morning, everyone, and thanks for joining us for our 2020 full year results. As you would have seen this morning, we released our full year report and the results briefing pack to the ASX.

Joining me on the call is our Chief Financial Officer, Sherry Duhe. And as we've done in previous years, we'll make some introductory remarks before I open up the call to a question-and-answer session.

There's a standard disclaimer on Slide 2 and just a reminder that this presentation does include some forward-looking statements and that our reported numbers are all in U.S. dollars.

Well, I don't need to tell you that 2020 was a challenging year for

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confluence of events, including a severe tropical cyclone and rapid development of the COVID-19 global pandemic. Despite this, we've still achieved significant performance outcomes and maintained a strong financial position.

So let's start with an overall summary of our performance on Slide 3. Back in 2017, when we set out to achieve production of 100 million barrels of oil equivalent, and -- back in 2017, we set out to achieve production of 100 million barrels of oil equivalent. And to deliver this in a year like 2020 is really a credit to the efforts of our team. This outcome was underpinned by the successful project execution in recent years at Greater Enfield, Greater Western Flank Phase 2 and Wheatstone along with strong production performance across our facilities. Our annual production of 100.3 million barrels of oil equivalent set a new record for Woodside, and we achieved another record for our annual sales volume, up 10% to 106.8 million barrels.

Also, we achieved a low unit production cost of $4.80 per barrel of oil equivalent and a strong cash margin of 78%.

The reported loss of just over $4 billion was largely a result of the asset value impairments and onerous contract provisions

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Of course, these were a consequence of the unique conditions experienced last year, which impacted oil and gas pricing assumptions out to 2025.

The underlying profit of $447 million is a sound result given the adverse conditions. A strong balance sheet and prudent approach to capital management ensured we were able to continue delivery of committed activities.

If we move on to Slide 4. We did exceptionally well on the things that we control. Our operational performance was outstanding. Again, another record, we achieved our best-ever safety performance with a total recordable injury rate of 0.88 million work hours -- per million work hours. And of course, this is an excellent result, which is even more notable in the context of COVID-19. We were able to continue our supply without interruptions, without -- and without any without any cases on (sic) [at] Woodside facilities. Throughout the year, our operated LNG reliability remained strong and improved from the previous year with an average of 97.6%.

So let's move now to the progress made on our growth plans on Slide 5. For Scarborough, we are positioned to take FID, which is targeted in the second half of this year subject to satisfactory market conditions and in finalizing some environmental approvals. We used 2020 to further improve the value of the development, increasing offshore capacity by about 20% to 8 million tonnes per annum of LNG. And of course, we're seeing strong interest from customers, and indeed, we've already contracted half of our expected equity offtake gas.

We've made significant progress throughout the year. We've secured the majority of environmental approvals and were awarded production licenses. We're also nearing completion of commercial agreements.

I've said it before: Scarborough's a world-class resource. It's a globally competitive project, and it's a game changer for Woodside.

Onto Slide 6 in the Sangomar field development in Senegal. After we took the final investment decision back in January 2020, we launched into project execution and managed the COVID-19 disruption throughout the year. You can see the range of activities on the slide here. It's a long list that includes the preparation of the oil tanker for FPO (sic) [FPSO] conversion as well as preparation for the development drilling. As we announced near the end of last year, we've completed the acquisition of Cairn's interest in the joint venture.

We successfully implemented mitigation measures to address COVID-19 impacts, and these included supply chain disruptions, which we've addressed by implementing creative solutions to logistics challenges, and leveraging experienced, qualified service -- local service providers where we were unable to travel. You'll see the schedule has come under some pressure due to COVID-19, but we're working to pull this back. In any event, we're still targeting first oil in 2023.

In 2020, we laid the foundations to transform the North West Shelf Project into a third-party tolling facility with 2 agreements executed for Pluto and Waitsia gas. Construction

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the pipeline linking our 2 facilities, Karratha Gas Plant and Pluto LNG, which you can see on Slide 7. At the state level, we've also executed a domestic gas agreement with the WA government for Pluto.

Now moving on to Slide 8. Our development drilling and completions performance has been outstanding. We've realized significant cost savings across both Julimar-Brunello Phase 2 and Pyxis Hub with no lost time due to COVID 19. Pyxis Hub is Woodside's deepest water development at a similar depth to the proposed Scarborough development wells, and we achieved best-in-basins performance for these wells. This is an excellent precursor to the planned drilling program we take -- once we take FID on Scarborough.

You can see on Slide 9 that we've updated our emissions reductions targets to set clear near- and medium-term objectives on our pathway to net zero by 2050 or sooner. We've actively managed our carbon emissions for many years, having offset or avoided over 2.2 million tonnes of equity CO2 equivalents since 2008.

Moving on to Slide 10. We have a multifaceted approach to reducing our carbon footprint. We've been building a cost-effective carbon offsets portfolio since 2008 and last year completed Phase 1 of the native reforestation project, which involved planting around 3.6 million trees in Western Australia. We're targeting a low portfolio carbon cost of less than $15 per tonne.

In addition to our carbon business, we're delivering energy efficiency improvements in operations and assessing carbon capture and storage opportunities, including for Browse. We've laid the foundation for a hydrogen business that can grow as the market matures, building capability in Australia and in our export markets.

Now before I pass to Sherry, I want to talk about Woodside as a values-led organization. This is something I'm very proud of and is critical to Woodside's ongoing success. Slide 11 summarizes some of our sustainability performance metrics. It's pleasing to see our sustainability practices recognized in the industry with leading scores under various rating criteria. We completed our 5-year Elevate level Reconciliation Action Plan, and we'll be releasing the 2021 to 2025 RAP next quarter. As an Elevate RAP partner, we work closely with traditional owners and custodians in the Pilbara region. And of course, culture recognition and awareness are core to Woodside's identity and values. We always appreciate being recognized for our environmental stewardship.

So with that introduction, Sherry will take you through the financial update, and then I'll come back and provide an overview before we move to Q&A.

Thanks, Peter, and good morning to everyone on the call. The headline financial metrics here in Slide 13 speaks to our disciplined response and ability to pivot as the effects of the COVID pandemic unfolded throughout the year. Our revenue fell by around $1.3 billion compared to 2019 as a result of lower prices. The average oil price in 2020 was about 35% lower than in 2019. We implemented comprehensive measures to control our expenditure across all parts of the business, and as a result, we've been able to maintain a high cash margin.

We have entered 2020 primed for growth with a balance sheet that has been strengthened to provide a buffer against potential market volatility. Whilst our growth plans were deferred in Australia, we have protected our financial capacity to sanction major capital projects, and our liquidity is almost the same position as 12 months ago.

Our gearing is still comfortably between -- within our target range of 15% to 35%. It increased by about 10% from our position at the end of 2019. The asset value impairments and onerous contract provision announced last July account for almost half this increase with our acquisition of the Cairn's stake in the Sangomar project another key contributor.

As you would have seen this morning, the Board declared a dividend of USD 0.12 per share, which represents approximately 80% of our underlying profit. The net profit reconciliation slide on Slide 14 is dominated by the asset value impairments and onerous contract provision announced in July.

But first, I'd like to point out the substantial impact on our revenue due to the sudden and significant fall in oil and gas prices. Over the year, this would have negatively impacted us by about $1.9 billion, but this impact was lessened by increased sales volumes, a positive consequence of our record annual production.

The noncash impairments and Corpus Christi onerous contract provision were largely driven by

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Okay, team. Hopefully, we've gotten you back. We dropped off for a moment. So I'm going to start again on Slide 15 and continue from there.

So onto Slide 15, Peter has already discussed our outstanding operational performance across our facilities, realizing record production and safety outcomes. The chart shows that we achieved this while keeping costs well under control. Total production costs in 2020 were lower primarily due to reduced turnaround activity, including the scheduling of our North West Shelf turnaround into 2021. This was done safely and in compliance with our management of change process. Production costs for the Ngujima-Yin FPSO increased due to a full year of production. We also incurred COVID-related costs which, across our business, were approximately $44 million, of which $28 million impacted production costs. These costs included the extra expense incurred in managing the travel, testing and quarantine requirements for our operational workforce.

Our full year unit production cost for all products came in at a low $4.80 per barrel of oil equivalent, our strongest result in recent years. This reducing trend was helped by record production in 2020.

Looking at our LNG cargo mix on Slide 16. We experienced high volatile market conditions, particularly in the first half of the year, which resulted in some extraordinary outcomes. In Q1, at the same time our customers were finalizing their LNG commitments for the coming year, the twin effects of an oil price war and a COVID-driven global economic slowdown resulted in a sudden crash in demand and significant increase in market uncertainty. These conditions incentivized customers to exercise limited contractual rights to reduce their purchasing commitments. The result was an increase in the number of cargoes available for us to sell in the spot market, which you can see was most pronounced in Q2. This was, of course, exacerbated by our strong production performance in the period.

The low spot prices experienced in the middle of 2020 were the sign of a functioning and efficient market. We utilized our trading capability to sell every cargo we produce without having to turn down or shut in production.

To Slide 17. The flip side of the spot market is that higher prices are realized when the market tightens, and we've seen all-time record highs in recent months. We generally aim to retain around 15% to 20% of our LNG production uncontracted each year. This provides us flexibility to deal with operational issues or to manage and optimize market conditions as they arise.

Earlier this year, the market experienced a significant supply crunch due to strong demand caused by a cold Northern Hemisphere winter combined with some supply outages. This created an environment where spot LNG prices spiked to record levels. We were able to take advantage of this set of circumstances to lock in value by, firstly, selling available cargoes into the highly priced spot market in the first quarter of 2021. And secondly, we were able to benefit from the difference between spot and contract pricing to secure higher pricing for some cargoes through the remainder of 2021. We've skewed our uncommitted production to match the summer and winter pricing seasonality typical in the LNG spot market.

As a result of utilizing some of our flexibility to capture this market opportunity, we now expect around 10% to 15% of our produced LNG to be sold in the spot market over the course of 2021.

I should point out that a general target of 15% to 20% uncontracted production means that we generally have 80% to 85% of our LNG committed to mid- and long-term contracts. This helps underpin our long-term revenue and provide certainty for the targeted final investment decision of major projects. Our long-term customers are high-quality, low-risk counterparties with whom we have established relationships over many years and, in some cases, decades.

Turning now to Slide 18, to our preparedness for growth. Woodside has maintained a consistent investment-grade credit rating for many years through several commodity cycles. A strong investment-grade credit rating is important to us and for enabling our continued access to competitive debt, and it's also a sign of our long track record of disciplined approach to capital management. We are well placed in our peer group.

Slide 19 demonstrates that we've been successful in maintaining a strong balance sheet through a challenging year. We maintained high liquidity of $6.7 billion despite increasing our equity interest in the Sangomar project. Our treasury team continues to actively manage our debt portfolio, taking advantage of current low rates to reduce the portfolio cost of debt from 3.6% to a low 2.9%. Just last week, we repaid a $700 million bond that was due to mature later this year.

Our high liquidity position and low cost of debt helps derisk the Scarborough FID targeted for the second half of the year. Our liquidity coverage of 12 to 18 months provides a buffer against market volatility, which will be important as we enter a phase of increased capital expenditure.

You can see on Slide 20 that we have multiple capital levers at our disposal to help manage our expenditure requirements in the coming years. Woodside has a long history of utilizing these capital management levers to support our credit rating and provide funding certainty for growth. And as we look at our funding requirements for Sangomar, Scarborough and Pluto Train 2 in the coming years, we'll continue to exercise these levers prudently, factoring in the long-term price environment.

An important lever is the level of participating interest in our projects, and one of our priorities is to reduce our interest in Sangomar to a target of around 40% to 50%. Recent announcements highlight the continuing market interest in this project, which is targeting first oil in 2023. We've seen an improving oil price environment since we preempted Cairn's interest last year, which increases the value of the project. A reduction in our equity in Sangomar will have an immediate and material impact on our funding requirements.

Another priority is reducing our interest in Pluto Train 2 to around 50%. Building an LNG train is capital-intensive, and we can reduce our capital expenditure requirements by around $3 billion during project execution by selling down our equity. We're in the process of finalizing preparation for formal engagement with potential buyers, and ideally, we'd like to complete this sell-down at or before FID.

We're also kicking off some soft market testing for a dilution of our interest in the upstream Scarborough resource. As you know, Scarborough is a world-class valuable asset, and market conditions have improved significantly in recent months, making a potential sell-down more attractive.

There are, of course, other capital management levers to consider. Second on the list is our own spend. We have an acute cost focus across all areas of the business, and we kicked off our operations transformation program, which is aiming to improve cost efficiency by 30% over the next 3 years.

Next, we have dividend. The dividend reinvestment plan remains active, and we're finding this a very efficient contributor to the funding of our capital requirement while providing the opportunity for eligible shareholders to reinvest their dividend at a discount. We continue to review the payout ratio to ensure we're delivering value to shareholders consistent with prudent capital management and our funding requirements in coming years.

And finally, our debt portfolio continues to be refined. As already discussed, we've been successful in reducing our cost of debt in the current environment.

On Slide 21, I'll reiterate our production guidance provided in our Q4 report last month. We're targeting full year production in 2021 of 90 million to 95 million barrels of oil equivalent. We also provided details of the major turnaround activities planned in North West Shelf this year.

And finally, on Slide 22, our investment expenditure guidance for 2021 is $2.9 billion to $3.2 billion, noting, of course, that this would come down significantly with successful sell-downs of our participating interest in Sangomar and Pluto Train 2.

And I'll now pass back to Peter for his summary.

Okay. Look, thanks, Sherry. Before we move to questions, I want to discuss our 2021 priorities.

For Scarborough, on Slide 24, we're preparing for our targeted final investment decision in the second half of this year. We're in a strong position but need the market to continue to demonstrate that it has stabilized before we move forward with the project. We've also completed a large number of activities across the technical, commercial, construction, marketing and regulatory work streams. And in the lead-up to FID, our key priorities are to execute the remaining commercial agreements, sell down our equity in Pluto Train 2 and secure remaining environmental approvals and agreements with government.

Finally, on Slide 25, our priorities for 2021 are very clear. As Sherry discussed, we've maintained a strong financial position, and we will continue our prudent balance sheet management as we look to sell down equity in Pluto Train 2 and Sangoma. As part of this, we'll review the dividend payout ratio to ensure it supports the major capital programs we have underway and plan to commit to later this year. Our credit rating is important to us, and we will take appropriate measures to ensure it stays robust.

Next, we remain focused on creating and protecting value for our shareholders. Despite the challenges of 2020, we've protected and increased the value of Scarborough as a world-class resource. As I mentioned earlier, Scarborough is a game changer for Woodside. We continue the safe execution and delivery of Sangomar to achieve first oil in 2023.

Under disciplined expenditure, a key priority is our operations transformation program to improve efficiency and reduce costs, including an immediate target of a 15% reduction in North West Shelf cash operating costs in 2021. Now this program will ensure that Woodside continues to demonstrate its operational leadership well into the future.

Last, but certainly not least, we're focused on building a sustainable future, respected for not only what we do but how we do it, and critical to this is growing our carbon business.

2020 was an extraordinary year, and we were able to respond with confidence to all the challenges. We're now looking to capture opportunities as we work towards FID on Scarborough later this year.

With those opening remarks, I welcome your questions.

(Operator Instructions) Your first question comes from Tom Allen with UBS.

Can you share some color on the Board decision to continue to pay out 80% of underlying NPAT and distributions as you're approaching a major FID on Scarborough? So at the Investor Day at the end of last year, Woodside played down expectations of a cap raise to support the Scarborough FID. So just doesn't today -- the payout today plus increasing pressure on your credit ratings suggest that cap raise is inevitable?

I think that's a really bold, out-there statement, Tom. I think it's ridiculous actually for you to say that. I'm not sure how you do that. The actual payout that we had for the dividend is about $115 million, so it's quite reasonable when you think about it. And the difference between changing payout ratio is de minimis in the overall scheme of the capital that we're spending. I think we made it pretty clear on the call this morning, I think we mentioned at least 3 times, that we're reviewing our dividend policy. So I'm not sure where you're going with the question and what your point is.

Okay. Then is the payout range then, Peter -- should we consider it likely to change over the course of the year? Or would that be contingent upon plans to sell down equity in Sangoma?

I think the key for it, Tom, is there's some triggers for us. And so as we form a view -- firstly, it's price. So the price that we are working to is lower than the price -- prevailing prices today. So I mean, if prices today stay where they are for the remainder of the year, of course, we've got a lot more room to move.

But we also got some decisions in front of us. So one of the precursors for Scarborough development is, of course, the sell-down of Train 2 at Pluto. We've made that very clear. Sherry just mentioned that we'll also go and test the market with respect to upstream equity as well. We've tested that previously. Conditions weren't right. We think conditions are improving for us. So we'll test that again. And then, of course, on Sangomar, we've got to look at what happens with the FAR transaction and Lukoil and then form a view. So there's a number of things.

But I mean, I've been pretty clear that the dividend policy -- the dividend is under review. The payout ratio is under review. The policy is not. So what I want to be clear is the policy is a minimum of a 50% payout ratio. What we'd been targeting since 2013, 2014 was an 80% payout ratio, and that was just based on the cash that we had available. But clearly, as we come into these major capital decisions, the Board is reviewing whether that's an appropriate target for us.

So I want to differentiate between policy and target: Policy will stay the same. The target may change as we get closer to FID.

Your next question comes from Adam Martin with Morgan Stanley.

Just on cost for Scarborough. You previously talked about a 6.80 MTA level with the 10% return. I think you did say that perhaps if the offshore goes up to 8 MTA, then that has the potential to reduce that breakeven. Do you expect any sort of momentum on costs prior to FID in the second half, please?

Yes. Great question, Adam. We are in the course of finalizing updated pricing with all of our major contracts both for Scarborough and for Pluto. Certainly, we're not seeing upside pressure on cost, and we're hoping that we are able to come back to you with an update that even reduces those costs further as we get closer to FID. So that 6.8 MTA is a good number, and we're hoping to come south end of that in the coming months.

Yes. Adam, I would add to that. I think you saw the drilling performance on Pyxis. That hasn't been baked into the cost yet. So that's important for us. So that will reset some things for us. As Sherry said, we've seen no cost escalation in the market, so that's been good news as well.

And we've increased the capacity. We haven't provided guidance on that previously. But I can tell you, it's in the order of $200 million to $300 million depending on whether we believe we need to drill a well early. Now that's not an incremental cost. That's just pre-FID -- sorry, pre-start-up costs would be that well. So we're not drilling an extra well in the total program. It's just whether we need an extra well to get to the 8 million tonnes of capacity at RFSU. So you can -- the number is quite minimal when you think about the additional capacity we've been able to achieve.

Okay, that's good to hear.

And so that's -- just for clarity, that $200 million to $300 million is on a 100% basis.

Yes. Yes. Okay. That's good to hear, so lots of momentum. And just on Senegal, can you just update where you are on that sell-down? Like, do you have data rooms open, initial offers, et cetera? Or is it more early stage? And I suppose with this FAR, Lukoil news overnight, does that have an impact on time line for selling? Just any thoughts there, please.

Yes. Look, we had some bilateral discussions underway, Adam. We haven't opened a data room. We kind of piggybacked onto the data room activities that Cairn and FAR had previously, and so we knew who the potential buyers in the market were. So we've been having bilateral discussions.

Obviously, we've been able to see some price points with ONGC coming in. We thought that was opportunistic, which is why we preempted. And of course, we still -- that preempt is still in place with FAR. So whilst they've delayed their shareholder meeting from today, that preemption is still in place, and the long stop date is still there, which is in July (sic) [June]. So well, I think if we kind of deal with what we know, the things that we've put in place, we've preempted, and the long stop dates are still sitting there.

With respect to the Lukoil transaction, I really can't comment on that. I think FAR will need to -- the only thing I would say is, and I've seen -- read some of the discussions around it, Lukoil are bound by the same joint operating agreement conditions as everybody else is. So coming in as a minority partner gives them no additional rights to anybody else, and it certainly doesn't allow them to block Woodside being able to pursue the normal course of activities that we would within the joint venture.

Your next question comes from Mark Samter with MST.

I guess extending what you just said, Peter, just to be clear, if we hypothesize that Lukoil are successful, presumably you're not trying to say that they wouldn't have the right to preempt any sell-down you carry out. And I guess, if we did take it to that extent, do you think it is possible to sell down given obviously the previous concerns about U.S. sanctions. And I don't want to offend any Russian oligarchs on this call, but there's obviously the sanction issues that existed, and they existed at the time you preempted Cairn. If they do, though, take over FAR, they would have preemptive rights, would they not, if you sell down subsequently?

Yes, they will, Mark. So as you know, the takeover for FAR is at a corporate level. So what that does is it takes away Woodside. If that goes ahead, of course, Woodside can't preempt at an asset level. With respect to the sanctions, the sanctions kick in at 33% equity. So I think that's important for people to remember, is that there basically are no sanctions or no sanction constraints until you get above 33%. And so that still provides plenty of headroom even in a situation where, if Woodside decided to sell down, we look at our target range and Lukoil decided to preempt the -- it's up to us actually to keep them below that sanction level if they chose to preempt. So we're not concerned by that at all. And of course, Woodside -- Lukoil's already indicated a willingness to acquire more equity in the project.

Now the reason we preempted on Cairn, the Cairn equity was above the sanction limit. So that's just how that works. It's a binary outcome. Once you're above the sanctions limit, then we had to protect our shareholders' equity in the project. Now, again, at 33%, Lukoil do not get any voting rights more than what they have at 13%. So I think the key there is to also understand the joint operating agreement and the fact that they would not be able to control the venture.

Okay. Okay. And then just another quick question, if I can. Just on the -- there's a huge step-up in SG&A from $80 million to $190 million. Can we get a bit more breakdown of what caused and how much of that we think persists through 2021 and beyond?

Yes. Thanks for that, Mark. So having the team to just look at the detail around that, I think there's one component that was adjusted back for underlying. It's a one-off adjustment for joint venture costs and allocations that go into that. So you back that out. And in terms of cost guidance going forward, I think I can just reiterate what we've talked about in terms of our operational transformation activities that do run across the organization, including into our functional and overhead costs. So we haven't provided numeric guidance around that, but we're very committed and progressing well on all of those activities to keep that competitive on a total and on a unit cost basis.

I guess I'm going to -- I might sneak one really quick question again, if I can. BHP reiterated their guidance for Scarborough upstream CapEx which, I guess, at the bottom end of their range, was in line with your initial target but, at the top end, is 35% above yours. It might be a question for them. But do we -- do you have a feel for where the differences lie in your view on costs?

Look, we do, Mark. We saw that. I mean we were heartened by the fact that they're also targeting FID in the same range that we are. And it's really a question you need to ask Mike as he does the rounds this week but -- or next week. But the -- our understanding is that the bottom of the range is very much in line with us. That's up to RFSU. And then the rest of the range is full life CapEx for the field plus some escalation that they've put in there.

So it's just a slightly different basis. But my understanding is the range is not what they expect pre-RFSU. So I wouldn't read it as that they're expecting costs substantially or materially different to what we're carrying as operator. It's more the way that they portrayed their full life cost for it.

Your next question comes from James Byrne with Citi.

Just a few quick ones for me. Just thinking around the credit rating at BBB+, are you still looking to defend that? Or would you consider relaxing to BBB at all? Just noting that a few weeks ago now, your rating agency had put you on negative credit watch. So just trying to understand how to think about that.

Yes. Great question. I think I can just reiterate that we are strongly committed to our credit rating. Like others in our peer group, we've been having ongoing transparent conversations with S&P around our plans, which have not changed. And as Peter has mentioned, the 2 big things, and there are other things that support around that, that I've gone through in the call are really the oil price assumption and the LNG price assumptions that go along with that, which continue to improve materially but also these sell-down activities that we're after for Sangomar and Pluto Train 2.

And of course, the discussion right now with S&P is really all around Sangomar because it would be speculative to start talking about what we will or will not do for Scarborough and Pluto given the water that's between us in that part of the year. So we're really focused on those discussions right now around Sangomar with S&P.

Yes. So ordinarily, if you go into like a negative credit watch, then a decision is fairly imminent. But it sounds like, for Woodside, because there's so much going on, so many moving pieces that, that kind of decision on your credit rating might still be some time away. Is that accurate? Is that the right way to think about it?

I think the right way to think about it is that, when S&P looked at things, and I think it's an appropriate approach, you have to look at the things we've committed to now. So discussions around what we will or will not do as we get to Scarborough and Pluto FID are still some months away, and we've got these big levers that need to move. So they can opine on that on what commitments are we taking on at that time and how have we balanced the balance sheet. The current decision obviously is very focused, at least from our perspective, around our continued intent to get Sangomar to 40% to 50% equity versus where we were when we preempted Cairn last year.

Yes. Got it. That makes sense. And then just picking up on the remarks around testing the market again for a farm-down of Scarborough, where you've said conditions are more attractive. Like, I can understand why conditions are more attractive for Woodside. But what do you think has changed relative to last year when that process was not able to result in a sale? Is it just because there's more confidence in the market or that an FID looks increasingly likely? Why do you think that buyers would be more likely to acquire an equity stake in Scarborough?

Well, look, I think you have to take into context that, last year, before we moved the date from 2020 into 2021, we all were experiencing the same dual crises of COVID and the pandemic. And so we had, as you recall, a data room open formally at that time, and we had very interested buyers in that. But I think it became mutual that we all needed to take a pause at that moment, and it's really hard to have discussions around selling down a resource that has oil price exposure when oil prices in some parts of the world going negative on a spot basis. And so it was really just that realization at that point that trying to do significant M&A transactions at a very low oil price is not necessarily going to maximize your chances of getting the best price for what we think the asset is actually worth.

So roll forward to now, we're now sitting in a much more attractive pricing environment. And of course, as Peter has underlined, we've significantly improved the value of the project through upsizing the offshore and onshore capacity up to 8 million tonnes per annum. So that's why we just want to go back and have a look. We never -- we completely stopped talking to counterparties, but we want to kind of ramp that up and do some soft testing of the market to see where their appetite is really starting now and in the lead-up to when we formalize our process in Q2. And obviously, we know very much what we think the project is worth. So if we sense appetite at that level, we'll proceed. If not, the soft testing will have done what it needs to do.

Perfect. That makes a lot of sense. And then just lastly, I just wanted to clarify around that guidance for spot in calendar '21 at 10% to 15%. And so it sounds like you'll overachieve on that in the first quarter and capture the recent JKM spike. And then for the rest of the calendar year, have you basically signed mid-term contracts at slopes that you think are going to outperform where the JKM forwards are?

You've got it right. So the way we've done is we've actually seasonalized our spot. So don't think of spot as just being -- the spot exposure as just being a flat number throughout the year. What we've done is we've seasonalized it so that we have more spot available to us in Q4 and Q1 and -- which, of course, is when price is the strongest.

Yes. And just to add to that, we've started to grab on a handful of cargoes as well, some of that higher pricing into the months in between as well. So we've still got some open. We're already starting to lock that in, and it's been great to take advantage of those record spot prices that we've seen at the start of the year.

Yes, absolutely. But on those midterm cargoes, so the pricing is actually like becoming reasonably favorable. Can you maybe give us a bit of an idea on where market pricing is for midterm contracts?

I think I'll probably stop at sharing more detail around the specific contracts other than to say, as you see, there's a lag effect that comes into some of those that will continue to help us out as we go through Q1 and beyond. And certainly, when we look forward for the totality of 2021, we're expecting a much better average price across the year than we've been seeing in 2020. There's still a lot of seasonality to come into that as well as it normally does in each year.

Your next question comes from Saul Kanovic (sic) [Saul Kavonic] with Credit Suisse.

Sorry, I think I was on mute. Three quick questions. Sticking with the LNG pricing dynamic, the enlarged Uniper deal, is it possible to get some indication of -- is the pricing for that likely to be similar to the original Uniper deal? Or are we expecting materially lower pricing for the enlarged Uniper deal in the wake of the market kind of deteriorating last year?

Thanks, Saul. This is Meg O’Neill, EVP, Development and Marketing. Look, we've not publicly commented on the pricing, but I think it's fair to say that it's in the same ballpark as the original deal.

Great. If I could also ask, in the Q4 results, you included a price review impact in there which, if I scale it all back, look very small, kind of a less than 0.5% change equivalent to a Pluto slope. I just wanted to have a sense that the -- is that indicative of the way you think this is going, that it's going to be a very, very small adjustment? Or is it too early to say something like that based just on the Q4 percentage result?

Saul, I'll take a crack at that. This is Sherry. So I think the first thing is we've adjusted back and made a provision for a negotiation that's still ongoing, and of course, there's accounting conservatism that comes into that. So as you say, this goes back to 2019 and also 2020 and -- but there's still negotiations ongoing. So we're feeling pretty good about getting to the right point that works for both us and the buyers at some point in 2021. And for that reason, you shouldn't expect to see a big impact coming into the current year. We've already provided for that.

And Saul, it's worth noting that the fourth quarter adjustment was for Pluto price review and some unconcluded North West Shelf price reviews. So it's not just Pluto that you're looking at.

Got it. Would it be fair to say, though, then that the Pluto impact could be proportionally more or like a greater drop if it's being offset by the price reviews in North West Shelf?

No, I wouldn't go that far. I would say that you've got an aggregate in there. Pluto was a significant component of that, but I wouldn't say that there's offset.

Great. My last question is just on the Scarborough timing. With the technical work being announced completed today and the target for the final commercial negotiations to conclude by the end of the quarter, what is, I guess then, the critical path then between the end of this quarter and second half of the year to take FID?

Well, I think it's -- from a -- first of all, from a transaction perspective, it's really kicking off our formal process for the sell-down activities. The rest of it will be just the final technical maturation and technical readiness for FID and getting final regulatory approvals as we go into that and then, of course, just a line-up of corporate Board approvals, et cetera, for ourselves and for BHP.

Yes. So we don't expect final lump sum costs to come in from the contractors until May -- April, May. So by the time we look at them, it's going to take us until midyear to see the conditions of all of those and get comfortable and then run through the Board processes.

I will say there's -- there are 2 environmental approvals out there that I mentioned. One is an approval we already have that has been from the WA EPA. It's a minor administrative approval, but it's been challenged in the Supreme Court by the Conservation Council of WA. And of course, we don't have a hearing date for that yet. We believe the EPA is on very strong ground with respect to the process. But nonetheless, we'll flag that.

Second one is, of course, the submerged heritage with respect to the pipeline -- the initial pipeline crossing for Scarborough coming into the Pluto plant. The study work on that is being completed, and the technical expert reports are being finalized at the moment. We don't -- again, we don't believe that will have a material impact on the project at all, but I just flagged that because there are unresolved issues at this point.

Great. Just one last one, and I think it's following on one of your earlier comments, Sherry. Is the sell-down of Train 2 a precondition, in your view, to taking FID? Or will you consider taking FID and defer even if we have to wait beyond FID for a sell-down of Train 2?

Look, I think I chose my words quite carefully to be as clear as I could be in my speaker comments that we'd really like to be concluded with the transaction by FID. But at a minimum, what we'd like to see is a binding commitment that could execute at a point near to that. But it is a precondition for us to make sure we've got a partner coming in at around 50% to fund capital going forward. And of course, we'd also deal with that with the effective date of the transaction, if need be.

Your next question comes from James Redfern with Bank of America.

Peter and Sherry, most of my questions have been asked, but maybe just want to clarify the discussion around the sell-down in Pluto Train 2 and Scarborough. So just -- my impression was that you're definitely seeking to sell down in Pluto Train 2, but I also heard some discussion around testing the market for selling down Scarborough as well. Can I just confirm that, like just -- if we could see a sell-down on both assets?

James, I'm glad you asked the question. You're exactly right. So a precursor to FID is a sell-down in Train 2. Scarborough is just simply being opportunistic in the market at this point. So it's not a precursor at all to FID.

(Operator Instructions) Your next question comes from Gordon Ramsay with RBC Capital Markets.

Just a very quick one on Sangomar. You said the delay is anticipated to be less than 3 months. Where is that coming from? I understand it's COVID-related.

Yes, Gordon, this is Meg again. So over the course of last year, we saw a number of impacts, particularly in starting the FPSO construction. So we had anticipated that the VLCC that will form the base of the FPSO would arrive in the yard in China in November/December. That's been delayed. The vessel has just arrived. And that's a critical foundation for executing the construction work. We're seeing other pressures at various points in the supply chain. The team has done a great job of managing most of those. But we do see pressure in the FPSO, which is a critical path to first oil.

Okay. And just if I can jump across to Scarborough, have you guys actually formally stated for Pluto Train 2 what contracts are against that? Because I understand a lot of your contracts are equity gas from your LNG facilities. But I'm just trying to understand what the breakdown of contracts are that support Pluto Train 2.

Gordon, that's a good question, and I'll let Meg answer it a bit more. But you're right. We don't state contracts against assets anymore. I mean that's the old way of thinking. Or if you have to project finance, you have to state the asset. Or historically, as you're very well aware, contracts with buyers used to be against an asset because they wanted to be owners in the asset. It's not necessary for us to have buyers to be owners in Train 2. In fact, we may have some, we may not have buyers in Train 2. So no, there won't be volumes specifically assigned to the asset onshore. It will be -- but there are CPs in some of the contracts with respect to Scarborough going to FID, not all of them but some of them.

Yes, Gordon, I think it's worth highlighting that the Uniper deal, in particular, has a Scarborough FID condition precedent for particularly the large volumes that kick in, in that contract. Our domestic gas agreement with Perdaman also has a Scarborough FID condition precedent. And then the other contract that we've talked about is the Pertamina contract where we have a seller's option to execute, and that's one that we've got flexibility until 2022 to be able to pull the trigger on that. But when we calculate the 50%, we allocate the Pertamina contract against Scarborough volumes.

But as Peter said, the reality is we sell on a portfolio basis, not point-to-point, and we see that giving us great flexibility in our sales process. We've got the ability to optimize significantly across the portfolio, and that generates additional value for our shareholders.

That's very helpful. And just last one from me just on where buyers went to minimum contract quantities last year. Can you confirm that that's pretty -- all removed now, that they've all pretty much gone to full contract volumes?

So they have an annual process that, each year around March, they're able to look at down-flex and up-flex. And I think it is safe to say that the extreme conditions that we saw last year have actually reversed and gone in the other direction where you're very tight in the spot markets, and people are, in many cases, struggling to get access to cargo. So the pressure is actually going in the other direction as evidenced by the record spot prices we're seeing in Q1 of this year.

Yes. But the process is still underway, Gordon. We work on the Japanese reporting calendar, which is April 1 to March 31. So we're in the process of finalizing the ADPs with those foundation buyers. But as Sherry noted, we haven't seen the desire for the down-flex that we saw last year.

Having said that, Gordon, at this time last year, we were sailing along pretty happily, and COVID-19 was just an issue limited to Wuhan province. So I'd be careful. The world -- as we've learned, the world changes very, very quickly. And as Meg said, we're exposed on that out through March. So I don't -- no promises here. It's just we're seeing indications, of course, that buyers have learned from last year and want to be contracted because they got caught on the other end of it come November, December. So -- but no promise here. This changes very quickly.

Your next question comes from Daniel Butcher with CLSA.

Just a couple of very quick short ones from me. Just curious on the commercial agreements with BHP and so forth for Scarborough, you said sort of early 2021. I guess that's been pushed back a number of times. Can you maybe just tell us what you're seeing or hearing from them differently that gives you confidence about that date?

And my second question would just be with the sort of further news on progress in Qatar with the amount of construction going on there and the award of EPCs. Are you seeing any impact on your marketing program at all for LNG?

Why don't you take the first one?

Okay. I'll take the first one. So in regards to BHP, I think that we remain very aligned in terms of the timing of the project. We know that they put out their results as well, also targeting FID in the second half of this year. And at the working level here, we've got very aligned teams in terms of closing out the commercial agreements in the course of this quarter and then working forward on just the final input from contracting cost, Board approvals, et cetera, as we move forward. And of course, last year, it was a joint decision in terms of looking at market conditions and thinking about movement on that.

Right. Daniel, I would color it and say we'd actually completed the commercial agreements for a 6.5 MTA concept. And of course, when we increase the capacity to 8 MTA, that has impacts on Pluto Train 1 and on some of the sharing. And so all we're simply doing now is just revising those agreements that were already there in place. So it sounds like we've just kind of kept going on forever, but no, we actually closed on them. And then we looked at enhancing the concept by increasing the capacity. BHP reviewed that. They liked that concept. And so we're just now going back through those commercial agreements to make sure that the revenue sharing is fair.

On the question of Qatar expansion, so this isn't a surprise, Qatar has been talking for many years now about working towards an FID decision this year. It is -- those volumes are built into all of our forward outlooks for a competitive supply. And when we look at the demand, we do see that LNG demand will continue to be growing at a rate that we estimate at about 4% per year out through 2040. So we do still see emerging demand in the market. We know that Qataris are out there placing large volumes, but the buyer appetite is growing. The buyer universe is growing. So we do continue to have some very productive conversations with a number of interested parties to enter mid- and long-term deals with Woodside.

Sure. And I don't want sort of revise old ground here, but just with the sell-down of Pluto 2, can you maybe give us latest thoughts, changes about whether the buyer would be appearing in such a fund or whether those funded in the mix to buy some equity?

That's a great question. I think that the buyer appetite for infrastructure assets just continues to grow. And so we do believe that there'll be strong interest for that asset, particularly given just the nature of the Bechtel contract that is quite easy for them to understand in terms of being mostly lump sum. And therefore, they can really understand the construction risk around that.

That being said, we'll have a look. As we look at Scarborough as well, if there's someone out there who's really interested in integrated interest, you could see a combination of someone coming in with an integrated share and then an infrastructure buyer as well. So we'll really look wide and not eliminate any possibilities, but of course, there is very strong interest that we're seeing continuing to escalate on the infrastructure player side.

Okay. Great. And just one final a quick one. It's been a busy day today, but just sort of struggling with your cash result, which was well below what we had. Maybe some others have the same issue. Can you give us -- is there any sort of one-offs or any sort of working capital items in your operating cash flow that you can flag that would explain how you got the operating cash flows you reported today?

I don't think that there's anything big that we've not fully outlined in detail across the financials around cash flow. We've also fully highlighted all of the things that are just impacting how we pay the dividend that are one-off items. But we'll have the team have a talk with you off-line and make sure we can point you to all that detail.

Your next question is a follow-up question from Mark Samter with MST.

Just a quick one on Scarborough costs, if I can. I think if we go back a couple of years ago, which was really the last time you gave us some numerical cost guidance on Scarborough -- maybe it wasn't called guidance but guidance in effect. The message from Woodside at the time was now is the time to be brave and get ahead of the rest of the cycle because costs will only go up if you don't jump the queue. Scarborough's obviously shifted to the right. We had Qatar sanctioned. We have Mozambique who has since been sanctioned. We had LNG Canada, et cetera, et cetera. Barossa would probably get ahead of the -- in the queue as well.

I guess I'm just trying to reconcile that with the message that costs actually won't go up. If anything, maybe you're even trying to steer us to say that it could be a little bit lower. Can you help me reconcile how being much further towards the back of the queue hasn't led to cost increases?

Yes. I think we gave you an update in Q4 of 2019, Mark. So they're the numbers that we've been running with. And of course, we were very, very close to FID when we got hit with the impacts of COVID last year. The contractor market is actually under even more pressure than it was when we showed you those numbers. And then if you recall, last year, there were really no significant FIDs. There was one small one, Costa Azul in Mexico, and that was it. Shell Canada actually -- LNG Canada required FID before COVID. And the Qataris are always in the mix, but the 2 contractors there are not the contractors that we're dealing with. It's Technip and Chiyoda who were the original contractors for the Qatari trains.

So no, we're not seeing any impact. If you think about it, some other projects have rolled off during that period of time. The U.S. projects have rolled off. Yes, one of the projects of Mozambique is moving forward, albeit at a much slower pace. The second project, that's indeterminate. And I would push to having a look at the balance sheet capacity of many of these project proponents globally. It's been severely impacted by the events of 2020.

Some of the super majors are starting to -- some are doubling down on LNG. Some are taking it now out of their strategic priorities. Exxon, in particular, has taken LNG out of its 5 strategic priorities. So that's of significant interest given that they may be a participant in the Qatari trains. So we kind of look at all of that balance and say -- we still say we're better off going to Scarborough in the short term rather than waiting out to 2023-'24.

We actually believe in that '23-'24 time frame, particularly in offshore drilling. There is an increased likelihood of price increases in the double digits going out into that time frame as we see drilling rigs continuing to be cold stacked and scrapped. So that is one area for us but not -- certainly not in the onshore plants at this point but definitely in the offshore drilling but in the '23-'24 time frame.

Now there's a few other things, of course, coming in there. There's ForEx impacts. You're seeing things happening up in the Pilbara with other projects and so forth outside of the oil and gas industry. We're working that very closely also to ensure that some of those impacts don't come across into the Pluto Train 2 execution.

Look, we're out of time. Thanks very much for your questions this morning, everybody. I do understand that you're extremely busy with 3 oil and gas companies reporting today. So apologies for that. We'll see a number of shareholders and sell-side next week. I want to thank you for your time today and thank you for your questions.

As I've mentioned, I think, for the things that Woodside could control, last year, our team did an outstanding job. Clearly, though, it had -- the existential events had a significant impact on our finances both on our balance sheet but also on our revenues. We've come out of that. I would say we took a couple of hits along the way, but we've come out and still in pretty good shape. And we're getting ourselves ready again for this next round of investment as it comes through.

So the thing I would leave you with, with all of everything that was happening last year, LNG demand on a world basis still grew, and it grew, particularly in the region -- the North Asia region, where Woodside targets its sales, and particularly in the growth markets of China. So notwithstanding all of the other bad news around, if you want to pick a gold nugget out of it, customers are still saying that they have a significant demand for our products. And even in the face of increasing climate change pressure, LNG or gas -- natural gas, LNG, in particular, is more and more being recognized, particularly in developing nations as part of that particular solution, which again has been very consistent with the narrative that we've been running for some period of time.

So again, thanks very much for your support, and we look forward to meeting with you over the coming days.