Woodside Energy Group Ltd (WDS) 2020 Q2 法說會逐字稿

Thank you for standing by, and welcome to the Woodside Petroleum Limited Half Year 2020 results. (Operator Instructions) And there will be a presentation followed by a question-and-answer session.

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

Good morning, everyone. Thanks for joining us for our 2020 half year results. As you would have seen this morning, we released our half year report and the results briefing pack to the ASX. Joining me on the call is our Chief Financial Officer, Sherry Duhe. As we've done in previous years, we'll make some introductory remarks before opening up the call to a question-and-answer session.

There's the 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.

If I can move to Slide 3. Really, in an extraordinary first half of 2020, we proved our resilience to an onslaught of challenges and ended the period as we began with a strong balance sheet and well positioned to take advantage of the right growth opportunities when they emerge. We've confronted the challenges of the first half head-on, maintaining our disciplined approach to financial management. We acted decisively to reduce our investment in exploration and operating expenditure and deferred final investment decisions on our major growth projects.

Throughout the half, we've ensured the well-being of our people and maintained safe and secure gas supplies to our customers in Western Australia and overseas. Now I'm tremendously proud of how all our teams have responded, again, demonstrating their commitment to sustained operational excellence. Their efforts delivered record first half production of 50.1 million barrels of oil equivalent, up 28% on the corresponding period in 2019. That's an outstanding achievement given the back-to-back impacts of Tropical Cyclone Damien and the COVID-19 pandemic.

We've maintained our strong operated LNG reliability and lower gas unit production cost of $3.80 per barrel of oil equivalent. Our financial results were impacted by the noncash post-tax impairment losses and onerous contract provision announced in July. As a result, we recorded a net loss of just over $4 billion, but our underlying net profit after-tax was solid $303 million. We've continued the dividend reinvestment plan and declared an interim dividend for the first half USD 0.26 per share.

Now let me talk a little bit more about the external environment on Slide 4. The first half of 2020 is being characterized by unprecedented disruptions to Woodside's operations in markets in Australia and around the world. The impact of the pandemic on global travel and the industrial activity were immediate and severe. The economic contraction was compounded by geopolitical tensions and the supply side actions of OPEC+1, resulting in oil prices falling nearly 80% during the second quarter, and LNG spot price is hitting record lows. But we've tackled price volatility and other risks by managing our existing long-term sales contracts and proactively optimizing our LNG portfolio. As the half ended, we were seeing the signs of recovery, with dated Brent rebounding above $40 per barrel and the LNG spot price climbing towards $3 per MMBTu.

Turning to Slide 5. As I mentioned earlier, we've delivered sustained operational excellence, reporting record production whilst ensuring outstanding safety outcomes throughout the half. You can see on the chart here the increased contributions of Pluto LNG and the Ngujima-Yin FPSO, producing for the first half since coming back online last year. We faced some tough decisions, but we're doing what is right with a sector-leading response. As you're aware, in March, we announced a 60% reduction in 2020 investment expenditure, and we deferred the key target investment milestones for both Scarborough and Browse. Woodside entered this year with a strong balance sheet and our ongoing commitment to disciplined capital management has ensured that despite the difficult external conditions, our balance sheet remains strong with high liquidity and strong cash flow. Sherry will talk through our financial position in more detail shortly.

Moving on to Slide 6. An inevitable consequence of the lower oil and gas prices was a review of the carrying value of our assets, resulting in our announcement in July of impairment losses and an onerous contract provision with a combined post-tax noncash impact of $4.37 billion. The reduction in carrying value of oil and gas properties was principally driven by lower oil prices assumptions out to 2025. Now despite these adjustments, we're still executing committed activities.

So let's turn to Slide 7. For the Sangomar field development in Senegal, we achieved a final investment decision in January this year and moved straight into project execution to support our targeted first oil in 2023. A number of activities have progressed, although we've also been closely managing the risk of COVID-19 on the supply chain and project schedule. The oil tanker which will be converted to the FPSO was purchased by our contractor in February and will undergo tank inspection and cleaning this year with modifications targeted to commence in Q4. Technical work is steaming ahead with detailed design engineering for the FPSO and the commencement of major topsides equipment fabrication. Our contracting and procurement team has also been busy, with purchase orders for long lead items being awarded and readiness for drilling operations targeted to commence in mid-2021.

Moving to Slide 8. Let's take a look at our next wave of growth. Since March, we've made and implemented hard, but necessary, decisions to protect our balance sheet and value for shareholders. We're now in a strong position to pursue value-creating options, both through our existing growth strategy and by inorganic opportunities when the time is right. Scarborough is a capital-efficient development, and the joint venture is aligned on a target final investment decision in the second half of 2021. We've progressed commercial agreements and regulatory approvals, submitting production license applications in February. With our joint venture partner, BHP, we agreed to extend the validity of the tolling price for processing gas from the Scarborough field of Pluto LNG until the end of 2020.

Now before I pass to Sherry, I want to talk to you about what we're doing around sustainability, which is summarized on Slide 9. You may have also seen our recent creation of a new executive role, Senior Vice President of Climate, reporting to me, to consolidate our carbon strategy and climate disclosures and to help us meet our aspiration of -- to be net 0 for direct emissions by 2050. It's been a busy period for the climate and new energy teams in the first half. We achieved a 6.2% improvement in energy-efficient performance against the 2016 baseline, positioning us well to meet our overall target of 5% by 2021. Our partnership with Greening Australia saw the first phase of native tree planting commenced in May this year, and this supports our target to offset our global equity reservoir carbon emissions from 2021.

I'm pleased with the progress in new energy opportunities and the development of markets and supply chains for future products, particularly hydrogen and ammonia. We signed an agreement with Japanese companies, JERA, Marubeni and IHI Corporation to undertake a joint study examining the large-scale export of hydrogen and ammonia to decarbonize coal-fired power generation in Japan. The consortium received approval from Japan's New Energy and Industrial Technology Development Organization for a feasibility study covering the entire hydrogen and ammonia value chain. Now as a part of this study, we're investigating the transition from blue to green hydrogen for export. And we're also involved in 2 potential hydrogen projects, H2TAS and Badgingarra renewable hydrogen project, seeking funding from the Australian Renewable Energy Agency.

So we're seeing activity on a number of fronts. Pleasingly, we've also been recognized for our ESG disclosure and performance. So with that as an introduction, Sherry will take us through the financial update, and I'll come back and provide an overview we move to Q&A.

Thank you, Peter, and good morning, everyone. Peter has already discussed the array of challenges being faced not only by our industry but across the globe. And in Slide 11, I will touch on some of the factors that have affected Woodside's financial results most directly. The collapse of oil and LNG spot prices through March and April were sudden and severe, and the dated Brent oil price fell by 80% from the start of the year. Although we were dealing with an evolving situation in real time and the extent of the impact was unclear, it became apparent that the commodity price fall would impact the revenue for our base business and our ability to sanction the growth projects we have been preparing for. Lower commodity prices translated directly to lower realized prices for our prospects and, hence, lower revenue.

Revenue was further impacted in the second quarter by several of our customers exercising contractual flexibilities, which increased our exposure to a very soft LNG spot market. We took a number of decisive measures early on to protect the balance sheet and preserve our ability to capitalize on future opportunities, including significant reductions in total and investment expenditure and hedging a portion of our oil production to protect against further oil price falls. As you'll see, these measures have proved effective.

The waterfall chart on Slide 12 shows the impact of various factors on our half year reported net profit after-tax. The shape of the waterfall is clearly not something we're used to seeing and is driven by the impairment losses announced last month. Moving from left to right, it's clear that lower commodity prices had a significant impact on revenue in the half, down $663 million from the first half in 2019. This drop was partially offset by the increased sales volume, thanks to the record first half production results delivered by our people.

We captured additional benefit from lower production costs as we had no major turnarounds and deferred other nonessential maintenance. We recognized additional depreciation and amortization expenses, which were primarily due to the Ngujima-Yin FPSO being back online following completion of the Greater Enfield project last year. One of the cost-saving measures announced in March was a reduction in exploration activity, and this has yielded a $70 million reduction compared to the expenditure in the corresponding period of 2019. And this is a good example of how we've been able to flex the organization in a disciplined way to preserve cash through a challenging period.

Now looking at trading costs. Our strong production performance in the first half meant that we didn't have to buy any third-party cargoes to fill contract positions. And other optimization opportunities were, of course, limited, so our base trading costs were lower. However, this gain was more than offset by the onerous contract provision recognized for the Corpus Christi LNG sale and purchase agreement with the net effect of increasing our trading and other hydrocarbon costs by $284 million compared to the first half of 2019.

The impairment losses announced last month are the biggest contributor to our reported NPAT this half. $3.71 billion of the pretax losses are attributable to oil and gas properties, and that's largely a consequence of assumed lower oil and gas prices to 2025. The remaining $1.56 billion is attributable to exploration and evaluation assets and due to increased uncertainty in future market conditions and development timing.

An impact of the impairment losses is that we recognized income tax and PRRT benefits in the half. The impairment losses are responsible for a $1.35 billion movement. And to be absolutely clear, $140 million of that is a PRRT benefit, and the remaining $1.21 billion is income tax. The combination of these factors resulted in a reported net loss after-tax of $4.067 billion. However, the adjusted or underlying NPAT is calculated by adding back in the post-tax impairment losses and the onerous contract provision, and that resulted in an underlying profit of a positive $303 million.

Moving to Slide 13. We were faced with a perfect storm in the second quarter, which increased our spot exposure above our planned level of approximately 20%. We had strong production due to high reliability and the deferral of nonessential maintenance, which meant we produced additional cargoes that were sold to the spot market. On the buyer side, our customers were dealing with weak demand, high levels of uncertainty and a large spread between the contract and spot prices, so they were incentivized to exercise some of their limited contract volume flexibility options, which further increased our exposure to the spot market. To put this in context of the half, contractual flexibility only represents about 9% out of a total of 31% of our spot sales for the half. We don't expect further exercise of contractual flexibility through the rest of the year, and we expect spot sales to make up about 25% to 30% of our full year LNG sales accordingly.

I wanted to talk to a couple of slides on the performance of our low-cost operations, with the first being Slide 14. Our team has delivered an outstanding half of production despite the unique challenges presented by physical distancing requirements in an operational environment. Our portfolio unit production cost of only $4.50 per barrel of oil equivalent is an improvement on the half 1 of 2019, even when correcting for the cost and production impact of last year's Pluto LNG turnaround. Total production costs remained almost flat, a good achievement considering the restart of the Ngujima-Yin FPSO. Another way to look at our operational performance is the cash cost of sales, which represents the delivered cost of product to our customers. You can see that we've driven our cash costs down significantly to $7.20 per boe, and that speaks to our credentials as a competitive, low-cost supplier of energy in our region.

Next on Slide 15 is the breakeven oil price analysis, which has remained a low $32 per barrel of oil equivalent. And it's really important to note that this includes the half 1 capital expenditure of the Sangomar field development, which took FID at January as well as 3 large subsea tieback projects in Pyxis Hub, hub, Julimar-Brunello Phase 2 and Greater Western Flank Phase 3. Without these developments, the breakeven oil price would be significantly lower.

On to Slide 16. We enter 2020 in a strong position, having prepared the balance sheet for a period of major capital expenditure. The cash preservation decisions we made as the pandemic struck have protected our ability to pursue growth options. Our gearing of 19.4%, which increased slightly following the asset value is still at the lower end of our target of 15% to 35%, and we have liquidity of approximately $7.5 billion. Our treasury team has been active in the debt market, refinancing our debt maturity profile and taking advantage of lower rates. We will continue to actively manage our debt portfolio through the second half of the year.

You'll recall that on the 27th of March, we announced our response to market conditions, including a 50% reduction of targeted total spend and a 60% reduction of investment expenditure. We're in a position now to update these figures for the remainder of 2020 on Slide 17. I'm really pleased to say that our production guidance remains unchanged at 97 million to 103 million barrels of oil equivalent, which again reflects the achievement of the organization in response to the unprecedented circumstances of this year-to-date. We've said for a few years that 2020 would be higher in production due to the execution of our near-term growth projects, and it's great to see this being realized. Our total expenditure of approximately $2.4 billion is unchanged from the guidance we published in March, and our investment expenditure of $1.5 to $1.7 billion has come down slightly as we found additional ways to tighten our belts over the past few months.

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

Thank you, Sherry. Look, to recap on Slide 19, you'll see that we're optimistic that the worst of the external demand and supply shocks are behind us. We've always said Q3 will be important to see a rebalancing of supply and demand, and we're seeing that. Economic activity is clearly increasing, and we expect prices to firm in the second half of this year and into 2021. There are likely also to be emerging external opportunities as other resource owners revisit their own strategies and as demand for new energy evolves, underpinned by the global push for reductions in emissions intensity. Woodside has clear advantages in tapping into these opportunities. We have a resilient base business, strong free cash flow and liquidity, and our current capital commitments are fully funded. We have attractive equity positions in our existing globally competitive projects and the capability to capitalize on organic and inorganic opportunities.

And to leave you with Slide 20. During the half, Woodside maintained a strike record of outstanding operational performance, and the decisive action we took earlier in the year has preserved our robust cash flow and balance sheet. And we're prudently executing our committed capital projects appropriately, progressing our pipeline of developments and advancing our work in new energy and carbon. We're primed to pursue value creating opportunities both inside and outside our existing portfolio as and when they arise.

Everyone at Woodside should be proud of the resilience we have shown and the opportunities that lie ahead of us. And with those opening remarks, I'll now open to your questions.

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

A couple of quick questions. The first one, on the $2.4 billion expenditure guidance being unchanged but the investment expenditures decreased $200 million, where is the offsetting, I guess, increase in $200 million? What's driving that? And what could we allocate it to?

Indeed, Saul, the biggest impact that we're seeing on the operational expense side is just simply the FX and the Australian dollar moving higher as we go through the year from what we assumed in our last set of projections. There are some modest impacts of COVID-19 operating model cost but really, the big driver is the FX impact for the year.

Great. One more also on the LNG spot exposure. Can you just confirm if that includes the Corpus Christi volumes or not?

No, it does not. Those are from our produced [cargoes].

Got it. And just lastly, on the -- just I'm trying to reconcile the tax. Are you able to give us color on what you expect the underlying income tax would be excluding the one-off impairments?

So I've tried to give you how you can calculate that, so I'll just repeat. I put a sentence in my notes, but it might have gone quite quickly. So the impairment losses are responsible for a $1.35 billion total tax movement. And of that, $140 million is PRRT, and $1.21 billion is income tax. So that should give you exactly what you need to just take that out of the line for PRRT and income tax and get the underlying for the period. It's a very small net movement. You should come out to, I think, about $18 billion net movement between PRRT and income tax when you take that out.

Your next question comes from James Byrne from Citi.

Peter, I just wanted to ask you firstly about the debottlenecking opportunity you flagged at Scarborough. Hoping you'd be able to maybe help quantify or just give us a sense of the magnitude there of the debottlenecking and if you'd entertain us perhaps on the extent to which that would also lower the breakeven LNG price. I guess what I'm looking for here is the market's probably not yet willing to pay for some of the growth projects here for Scarborough, but if we can be convinced that it's going to become a globally competitive project through the means of things like Scarborough debottlenecking, I think that the market would appreciate that kind of disclosure.

Thanks, James. The debottlenecking we're looking at is increasing the capacity of the offshore part of the system for Scarborough. And we can do that for a modest amount of anywhere between $100 million to $200 million extra capital. It's mainly around increasing the pipeline size, and so telescoping the pipeline. Some parts of the pipeline are limited because -- in diameter because of the water depth they're in. But as we get into the shallower waters, we've identified an opportunity to increase the diameter, therefore, decreasing the back pressure on the platform. That has the potential to take us from an offshore LNG equivalent of 6.5 million tonnes up to 8 million tonnes, plus our domestic gas commitment. So anytime I quote you a number, always add the domestic gas commitment on top of that, which is the 15-plus percent. So when I'm saying 6.5 million, it's 6.5 million plus roughly 1 million of domestic gas. And if I say 8 million, I'm saying 8 million plus 1 million of domestic gas for that. So that's how it's working.

Minor modifications to the onshore plant [for it]. The assumption is that we've got 2 options that we're still optimizing. One is a closed-loop option within the Pluto site itself where we would potentially back out Pluto Train 1 volumes. The other option there on that side is increasing the capacity of Train 2. And as you're aware, this type of design of train has a history of being able to produce above nameplate capacity. So we're looking to see if we can bring that opportunity forward. And then, of course, the second main option is to sidestream it across to Northwest Shelf and that extra capacity across the North West Shelf. But we're currently optimizing that. We'll have more information about that at the Investor Briefing Day later this year.

Yes. Does that decision on putting it into Pluto Train 1 or increasing the capacity to Pluto Train 2 depend at all upon whether Tokyo Gas and Kansai Electric exercise their option to extend the foundation contracts?

The option is actually ours, James, not the other way around. And we've already chosen not to extend one of those, and we're in negotiations on the second one.

Okay. Great. So the next question I had was just around thinking about the balance sheet ahead of incurring CapEx for your Burrup Hub strategy. Can you just -- before I ask the question, can you confirm for me whether your oil price outlook that you used for impairment testing, that you kindly disclosed last month, is the same oil deck that you used for budgeting purposes?

James, I'll take that one. So that is the base case that we use for impairment testing. I think we've consistently talked to you about the fact that for budgeting purposes, as it relates to investment decision making and also as it relates to balance sheet management, we actually run an array of prices because we recognize, of course, particularly in this environment, that you don't know what the price is going to be. So we have to look at an array of different prices. We look at a base final investment decision price. We look at a low case for the project. And then we then look at a low stress test case for the overall balance sheet to make sure that we're clear on what could happen with extreme volatility, particularly when we're in peak periods of spend. So it's not as simple as just using that one price. It's an array of them. And then we look at all of the different levers we have to best decide how we're going to fund those projects.

James, I think it's fair to say we use the transition from existing prices to what we think long-term prices are. That's typically the forward curve. So if you look at the forward curve, we'll transition that depending on which scenario we're running over either a 3-year or a 5-year forward curve. But we run a multitude of cases. So as you know, to date, the forward curve is looking fairly robust. And obviously, I've been clear in previous discussions around decisions on investment timing that we would need to see multiple quarters of improving prices so that we could get comfortable that the price trajectory that we're on is consistent with what our long-term view is.

That makes sense. So the forward curve is well above your free cash flow breakeven. And so effectively, by delaying your growth CapEx, you kind of build up the capacity on your balance sheet to be able to execute on spending CapEx. Now in the past, pre-COVID, we might have argued you needed a $60, $65 sort of oil price world to be able to spend that CapEx, and that includes the benefit of farming down. Do you think that with the delays, and the fact that you're still free cash flow positive, that you can actually -- your balance sheet can afford the CapEx that's ahead of you for Pluto Train 2 and Scarborough in an oil price environment that's lower than that $60? Because the reason I ask is part of the questions that I get, the conversations I have with investors is, does the equity only work if the oil price is going to be $60 or higher?

Yes. Yes. So look, it's a good question. Look, I would say in an unconstrained world, you're correct in that as we look at that, our ability to actually fund and move forward is more than adequate. The challenge we'll have is -- the fine balance there would be with the ratings agencies and being able to match up there forward curve expectations with when we make that investment decision. Because as you know, once we make those investment decisions, then the ratings agencies will review our rating. And they'll do it based on their price, not on whether we have the adequate cash flow in the business. So we've just got to balance that, James, and get that right. But that doesn't say we'll be waiting for the ratings agencies, no. And the ratings agencies have demonstrated a willingness to kind of see through some of these short-term perturbations as long as they're seeing management demonstrate appropriate capital discipline. So there'll be a number of factors that we'd be discussing with ratings agencies at that time.

Okay. Just third and final question, really quick one. Just, Sherry, I wanted to clarify what you'd said earlier about DQT. The guidance for this year is spot of 25% to 30% via LNG book. You did about 31% so far. So are you saying that you expect no more DQT above the current levels? Or like, are we maintaining the same sort of DQT we saw in second quarter? Because I can't quite reconcile the 25% to 30% guidance.

Yes. So James, that's exactly correct. When you look at the timing of the ADP nominations, really the down flex, the modest down flex that our customers have has been fully exhausted. So we don't expect that to come through in the second half. So we were quite low in Q1, extraordinarily high in Q2, and then it comes back down for the rest of the year. So it's really just the averaging of effect of that across the year that gets us to our full year guidance of between 25% and 30% on produced volumes.

Got it. Okay. So the second half is lower. All right.

Yes.

Your next question comes from Mark Samter from MST.

Three quick questions, if I can. Just the first one, you've been pretty vocal over the last month or 2 that you think there's opportunities that are going to crop up. And I guess when you look globally, particularly European companies don't want to be oil companies, in particular, anymore. Is there a preference, a desire, to diversify the portfolio through these opportunities and add some more oil to the portfolio?

Look, Mark, I'm not sure that we've got necessarily a strategy that says, look, we need to push into more product in one way or another. We've kind of looked at that previously and found it's a very difficult thing to do. Now having said that, we're clearly scanning the landscape very closely, looking for opportunities. And we've got a large array of competencies within the company that if something comes up, we think we may have a look -- well, we'll definitely have a strong look at it. Our preference is obviously things closer to the home. If we can build things around existing assets, then, of course, we'll do that. But equally, we recognize that we're very concentrated geographically in our footprint, and diversification of that would assist us. So I'd say there are some parts of the world that are just clearly off the list, simply due to the complexity, the geopolitical complexities and so forth. We don't think we need to make the business any more complex than what it is. But definitely, if assets, particularly mature assets or assets that are flowing, become available to us, then that will be of significant interest.

Right. And I mean I guess one imminent decision on an oil asset you have to -- like, there was -- there's no mention in the release about [prevention] in Sangomar. I presume that's a standard 30-day term. I think that was kind of announced during the [fall] processes. Should we just interpret that you are still considering your options and that decision's being reached?

Yes, I would do that. It is a 30-day term. So I can confirm that. And that the 30 days has about 1.5 weeks to run. So we're still considering what we do.

Got you. Then just the last question. I'm not sure if you saw -- [phase or flow] into one. I think it was last week. Chevron, in their 10-Q said that they are expecting to downgrade 10% of 1P reserves at the end of the year with the majority of that in the Permian and Australia. You're obviously bedfellows with them in 2 of their 3 projects down here. I know, in some ways, it's a question for Chevron, but I guess is there anything that they're seeing that you think should make us think anything is at risk on your reserve base on North West Shelf and Wheatstone where you are in JV with them?

Yes. Look, let me deal with Wheatstone first. You probably recall, it's a different accumulation. So you might recall that Julimar-Brunello is a joint venture between ourselves and KUFPEC. And so anything that Chevron does on their side of that development would just really ring-fence to them. It's got nothing to do with us. And we're not seeing any pressure on reserves there. We currently have a drilling campaign underway on Julimar, and that's going quite well. With respect to North West Shelf, no, again, nothing that we're seeing on North West Shelf that would indicate that. So no, not in our business at all, Mark. I would suggest that's probably more focused on other areas of the world.

Okay. Sorry, I got to sneak one really quick one. And this is back to the impairment that have stood out to me the other day. With the Pluto impairment PRRT bit, you said you changed your price assumption and consequent reduction in recognized general expenditure. Does that in any way mean you changed the expectation of the end of Pluto's life?

No, not at all. No, there's no change to the life cycle of Pluto for that.

Perfect. It's just cost rather than duration cost. Okay. Perfect.

Yes. Look, Mark, if you might recall, a lot of that is because we made the decision early on to ring-fence Pluto within Pluto. If it was treated like our other assets, then we would have been able to offset some of that PRRT asset against other production, but we're unable to do it. So it's kind of locked up within the Pluto asset. So the best way for us to unlock it is to have further developments going through Pluto.

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

Yes. Just two questions, please. Wondering -- in relation to Lukoil's proposed transaction of Cairn Energy's stake in Senegal, just wondering if you can comment as to whether you think the price they're offering is a fair price or a low price. And then the second question is if you can make any comments around the LNG contracting market, which is obviously very weak. The slope's about 10%, 10.5%. Just wondering if you could provide a bit more color on what you're seeing out there in the LNG contracting market in relation to, I guess, Scarborough negotiations, which are probably likely to be postponed until next year?

Well, on the first one, James, no, I'm really not going to comment on whether I think it's a fair price or not. I think you can see there are those who make it their business to do this, to publish what they think about the pricing and so forth. So it's not up to me, and it's up to Cairn's shareholders to determine whether they think that's a fair price for the asset. So I'll just let that one go through, if you don't mind.

With respect to LNG contracting, it's really difficult to contract at the moment. We're focusing our efforts on MOUs or HOAs that we already had in place and making sure that we get them finalized. And we've announced 2 or 3 of those for Scarborough. So we're just working at the moment. Those counterparties are engaging with us. And so we're seeing no impact at the moment with respect to pressure on what we had previously agreed the pricing formula would be, we're seeing no geopolitical impact at all in that regard. And things have just slowed down simply because what would normally be face-to-face discussions are now having to be done using video conferencing and so forth. And for some of those customers, they have not actually been able to get into their offices during the COVID period in first half. So that's all ramping up again.

Clearly, the slopes at the moment in that -- I don't know anybody who's doing 10.5 deals at the moment or at least on major volumes. I think what you're seeing, to be quite honest with you, in the spot pricing is you're starting to see a disconnect between LNG pricing and crude oil pricing. And we don't know to the extent that, that disconnect will on into the future.

Okay. Hopefully, that's where [they lift] loophole considerations, it's just very low, low offer.

Yes. Yes. Well, we're just -- we'll know in a couple of weeks.

Your next question comes from Mark Wiseman from Macquarie.

I just wanted to touch on the Pluto deferred tax asset issue again. You made some brief comments. But I just want to clarify, you've debooked the deferred tax asset. Does that mean basically at $65 oil long-term, producing out the 2P reserves at Pluto with no further tieback, basically that you would never pay PRRT? Is that essentially what we should read from that?

No, you shouldn't read it from that. First, just to clarify, we've adjusted the quantum of the deferred tax asset. We haven't debooked it completely, but it has been adjusted as a normal part of the impairment process where you look at both the PRRT benefit that's sitting within the asset and also broader across the portfolio. And as Peter said, this one is ring-fenced and quarantined. I think the question around will we ever pay PRRT tax on Pluto is one we can't answer because, as you'll be aware, there's a number of complex factors that go into that. The oil price and gas prices themselves, they're impacting it, the long-term bond rates, the overall PRRT augmentation rules around that. So it's impossible for us at any point in time to determine when and how much we might pay on that particular asset.

Okay. Okay. And can I just ask another one, just on M&A. Obviously, We've seen a sharp uptick in deals being announced and, in some cases, binding in the last few weeks, seemingly favoring buyers with more contingent payments and price discounts. How do you think about your organic growth projects where you've outlined 12% or so IRRs versus the M&A opportunities that you're looking at? I'm just interested in how you sort of weigh up the 2.

Look, it's a good question. As the industry goes through price cycles, of course, the pendulum moves from one quadrant to another. And we would say, at this point in time, inorganic opportunities start to come into the frame more than they would when prices are high. Now we just need to always be careful about inorganic opportunities because it always looks better than what you know, and so we have to be careful that we don't look at something through rose-colored glasses and then find it's got lots of issues with it. So those are some of the learnings that we've had over time in the M&A area. But clearly, M&A comes into the frame now. Now what sort of opportunities would we be looking at? We're not looking at opportunities that kind of look like our current growth portfolio. So that's a given. So anything that is -- has a heavy capital requirement is not going to be added to the portfolio because simply we've already got some of that.

So we don't need a lot more of that, unless it buys us control. And so control is really, really important when prices are low or recovering because -- and as you will have seen in Senegal, you've got a situation where your joint venture partners, and the lowest common denominator can often drive the timing of your decisions. And we don't -- we just don't think that's the right thing for Woodside shareholders to be continually at the behest of others who've got different priorities. So if we can get control then obviously, that opens up a broader set of assets for us and gives us more interest there. But if they are new assets, then we'd be looking at something that is flowing or very close to flowing, something with a much lower capital commitment than our current portfolio. I think just simply adding to our current portfolio and an asset that you don't control, an asset that is long-dated in CapEx just doesn't make sense, to be quite frank, as cheap as they might be in the market at the moment. We've already got world-class assets that we need to develop and have waited for long enough, so we need to focus on those.

Okay. Just one more question for me, if I can. Just on the other resource owners and thinking about backfilling the North West Shelf. As the Chevron process, so them exiting that JV is sort of ongoing, is it possible to still continue that planning process? And would it be possible to sign a third-party gas deal whilst this process is still underway?

Look, the short answer to that is, yes, it is. Clearly, a third-party coming in will want to see what that deal looks like and, at some point, Chevron would have to seek partner approval to put that into their data room. But you can't value the asset. Now the difficult part about it is how do you pay for something that you don't have. So it's interesting to put an incomplete negotiation into a data room. But at the end of the day, it's still incomplete. And so I think any party looking at that asset will have to look at it through that particular lens. Now Chevron's process has commenced. The flyers are out. So we've got some insight now as to both the timing of their process and the nature of what their process will be.

Our next question comes from Gordon Ramsay from RBC Capital Markets.

Just following up on the Lukoil related questions. Lukoil specifically mentioned with respect to the U.S.-SSA oil project sanction against Russia, I just wanted to know if this has any impact on the project, particularly in terms of your position and for the contractors that have been chosen to work on the project at Senegal.

Gordon, that's a really good question. And at the moment, I'm just simply not able to comment on it.

(Operator Instructions) Your next question comes from Joseph Wong from UBS.

Just 2 quick questions from me. So the first one is just on the CapEx guidance. I just wanted to understand the reduction. Is that largely related to deferrals versus, I guess, absolute reductions on different projects that you've got underway?

Yes, Joseph, that's a great question. And if you were to look at it on an asset-specific basis, it's just very small adjustments, plus or minus, depending on which project or activity you're talking about. The single biggest change is just to the Scarborough project itself, and that is simply phasing at this point in time in terms of the pre-FID readiness activities and the phasing of that between now and 2021. The rest of it truly are rats and mice here and there, small adjustments up and down for projects.

Yes. Yes. And then just the other quick one, just on the cost reduction that you achieved. I guess is that largely related to efficiencies that you expect to, I guess, continue to realize? Or is that really deferral that you put on [central] maintenance work that you've outlined in the presentation?

So Joseph, I would say that it's both. We're really trying to take advantage of the crisis, for lack of a better word, to really hunker down even further in terms of our systematic cost structure across the base business, in particular. We're going through our annual integrated planning process right now, and we're really looking on a bottoms-up basis to make sure we're being as efficient as we can on a sustainable basis in our assets but also in our corporate cost as well in support of those assets. So it's something that we want to hang on to and keep structurally as we go forward. There is a deferral of maintenance and turnaround piece to it, but we do have a major turnaround coming up very soon in North West Shelf in September. And then 2021, we'll have a higher than previously expected turnaround set of activities due to pushing some of those scheduled turnarounds into 2021 on the back end of the COVID impacts.

Your next question comes from Baden Moore from Goldman Sachs.

I was wondering if you could just give us some thoughts around your capital management. With still very high payout ratio on your underlying earnings and you're now trading below NAV, whether that might impact how you think about returns to shareholders going forward. Or is it more about a franking credit issue that you're balancing there?

Baden, I think it's fair to say we look at all ways that we can get value back to shareholders. Clearly, the franking credit is a latent value that's locked up if we're not giving dividends out. So we look at ability to pay. Our dividend policy is a robust one because it's based on NPAT. You've seen a lot of others move away or change their dividend policy. Some have become quite complex, linking them to future oil prices, cash flow, buybacks and so forth. We've looked at those in the past, and we've decided for -- or chosen that for Woodside's business, we just kind of keep it simple, and it's really on ability to pay, so what's your cash flow position and what's your liquidity position and then really what's your underlying NPAT.

And that -- so you can see the outflow for the dividend payment is down quite significantly so simply because it's on the back of NPAT. And we've kept the DRP on nonunderwritten. And there's advantages for that. Some shareholders like to participate in that. The uptake of that was good last half. We're not sure what the appetite will be this half. So that's our cash preservation, but it's about releasing those franking credits back to investors. And as you know, we've got quite a lot of investors who value those dividends highly.

Now our view arguably is that returns to investors, particularly in the form of cash, will be highly priced during this period of uncertainty. And so maintaining a good, solid dividend flow, in our view, is very, very important, in the absence of near-term growth projects. And as you know, Woodside has mostly longer-term growth projects. So if -- that's kind of a balance for us. And we'll continue to review that, as we've said, as we get closer to major FID decisions, but it's not something that's on our mind today simply because our major projects, Scarborough, is being pushed out into next year.

There are no further questions at this time. I'll now hand back to Mr. Coleman for closing remarks.

Look, thanks, everybody, for joining us this morning. We've enjoyed your questions. So thanks for helping us to look forward. We want to put the past behind us. It's been a very difficult half, but we also need to recognize the performance of the business. Let's not forget it's been a record production half for us. And if we look at it over a 12-month period, we've actually produced more than 100 million barrels. So we're within our target in the last 12 months. Our cash flow and balance sheet have remained strong during the period. We're continuing to move forward, albeit at a lower pace -- or a slower pace on our major capital projects. We're starting to make good progress in new energy and carbon. And as we've discussed a lot this morning on the call, we're actively looking at inorganic opportunities, should and if they arise.

All of that's because we've been able to maintain the discipline around our commitments and where we are in the cycle. And as this perfect storm hit us during the first half, particularly the second quarter, which we've come out of it. We've kind of dusted ourselves off. And now we're looking forward to what the next 18 months or so brings to us. So I think there'll be many opportunities that we can't see today. Some of those are starting to show green shoots already. Oil price, commodities prices, oil prices and gas prices starting to firm as we had expected and hoped. So we're seeing some light here at the end of the tunnel, and we're very well positioned to take advantage of anything that comes up.

So again, thank you very much. I just also want to make sure everybody is aware, we look at our business through a particular lens, that's the quality of the work we do. And that's our safety, our commitment to safety. We've had our best half of safety performance on record. And that's in the context of a very significant amount of uncertainty in our business, people being dislocated from their families for extended periods of time, people moving out of the office and into different locations, us repatriating people from around the globe, we've all done that and maintained our focus on the things that are vitally important to the business. So I want to thank the Woodside team and our contractors for that. So again, thanks again this morning, and we look forward to talking to you over the next few days.

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