WOODSIDE ENERGY GROUP LTD — Call Transcript 2020

Aug 13, 2020

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Company: Woodside Petroleum Ltd Title: Half-Year 2020 Results Briefing Date: 13 August 2020 Time: 9:30AM AEST

Start of Transcript

Operator: Thank you for standing by and welcome to the Woodside Petroleum Ltd half-year 2020 results. All participants are in a listen only mode. There will be a presentation followed by a question and answer session. If you wish to ask a question, you will need to press the star key followed by the number one on your telephone keypad. I would now like to hand the conference over to Mr Peter Coleman, CEO and Managing Director. Please go ahead.

Peter Coleman: Good morning everyone and thanks for joining us for our 2020 half-year results.

As you would have seen this morning, we released our half year report and 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 US dollars.

If I can move to slide 3, really in an extraordinary first half of 2020, we’ve proved our resilience to an onslaught of challenges and end 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 wellbeing 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 low gas unit production costs at $3.80 per barrel of oil equivalent. Our financial results were impacted by the non-cash 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 at $303 million. We’ve continued the dividend reinvestment plan and declared an interim dividend for the first half of US$0.26 per share.

Now, let me talk a little bit more about the external environment on slide 4. The first half of 2020 has been characterised by unprecedented disruptions to Woodside’s operations and markets in Australia and around the world. The impact of the pandemic on global travel and 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 prices hitting record lows. We’ve tackled price volatility and other risks by managing our existing long-term sales contracts and proactively optimising 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.

DISCLAIMER: This transcript has been prepared by a third party for Orient Capital Pty Ltd. It may not be accurate or complete and should be verified directly with the issuer. Orient Capital Pty Ltd is not responsible for any consequences of the use you make of the information contained in this transcript, including any loss or damage you or a third party might suffer as a result of that use.

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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 to 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 to our financial position in more detail shortly.

Moving on to slide 6, an inevitable consequence of the low 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, non-cash impact of $4.37 billion. The reduction in carrying value of oil and gas properties was principally driven by lower oil price 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 risks 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 in 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 licence 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 at Pluto LNG until the end of 2020.

Before I pass to Sherry, I want to talk to you about what we’re doing around sustainability which is summarised on slide 9. You may have also seen our recent creation of a new executive role of Senior Vice President Climate, reporting to me, to consolidate our carbon strategy and climate disclosures and to help us meet our aspiration to be net zero 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 efficiency 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 commence 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 projects, 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 as ammonia to decarbonise coal fired power generation in Japan. The consortium received approval from Japan’s New Energy and Industrial Technology Development Organisation for a feasibility study covering the entire hydrogen-as-ammonia value chain. Now as a part of this study, we’re investigating the transition from blue to green hydrogen for export. We’re also involved in two potential hydrogen projects, H2Tas and Badgingarra Renewable Hydrogen Project, seeking funding from the Australian Renewable Energy Agency.

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So we’re seeing activity on a number of fronts. Pleasingly we’ve also been recognised 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 before we move to Q&A.

Sherry Duhe: Thank you Peter and good morning everyone.

Peter’s already discussed the array of challenges being faced not only by our industry, but across the globe and on 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 impacts 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 had been preparing for.

Lower commodity prices translated directly to lower realised prices for our products 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 capitalise 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 cost as we had no major turnarounds and deferred other nonessential maintenance. We recognised additional depreciation and amortisation 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 costsaving 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. This is a good example of how we’ve been able to flex the organisation in a disciplined way to preserve cash through a challenging period.

Now looking at trading cost, our strong production performance in the first half meant that we didn’t have to buy any third-party cargoes to fill contract position and other optimisation opportunities were of course limited, so our base trading costs were lower. However, this gain was more than offset by the onerous contract provision recognised 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 pre-tax 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 recognised 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.

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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 cargos 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 incentivised to exercise some of their limited contract volume flexibility options which further increased our exposure to the spot market. To put this in context for 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 want 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 $4.5 per barrel of oil equivalent is an improvement on the half one of 2019, even when correcting for the cost of 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 break-even 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 one capital expenditure of the Sangomar field development, which took FID in January, as well as three large subsea tieback projects in Pyxis Hub, Julimar-Brunello Phase 2 and Greater Western Flank Phase 3. Without these developments, the break-even oil price would be significantly lower.

On to slide 16, we entered 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 review, 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 [Clarification: refining] 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 will recall that on 27 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 to 103 million barrels of oil equivalent, which again reflects the achievement of the organisation and 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 realised. Our total expenditure of approximately $2.4 billion is unchanged from the guidance we published in March and our investment expenditure of $1.5 billion 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.

Peter Coleman: 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 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.

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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 capitalise on organic and inorganic opportunities. To leave you with slide 20, during the half Woodside maintained its track 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’ve shown and the opportunities that lie ahead of us and with those opening remarks, I’ll now open to your questions.

Operator: Thank you. If you wish to ask a question, please press star-one on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star-two. If you are on a speakerphone, please pick up the handset to ask your question. Your first question comes from Saul Kavonic from Credit Suisse. Please go ahead.

Saul Kavonic: (Credit Suisse, Analyst) Hi Peter. Hi Sherry. Thanks for the update. A couple of quick questions. The first one’s on the $2.4 billion expenditure guidance being unchanged, but the investment expenditure has decreased $200 million. Where’s the offsetting, I guess, increasing $200 million, what’s driving that and what could we allocate it to?

Sherry Duhe: So 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 costs but really the big driver is the FX impacts for the year.

Saul Kavonic: (Credit Suisse, Analyst) Great, thanks. One more also on the LNG spot exposure. Could you just confirm if that includes the Corpus Christi volumes or not?

Sherry Duhe: No, it does not. Those are from our produced cargoes.

Saul Kavonic: (Credit Suisse, Analyst) Got it. Just lastly on the - just I'm trying to reconcile the tax. Are you able to give us colour on what you expect the underlying income tax would be excluding the one-off impairments?

Sherry Duhe: So, I tried to give you how you can calculate that Saul. I'll just repeat it. I put a sentence in my notes, but it might have gone quite quickly. 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. 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 up to I think about $18 million net movement between PRRT and income tax when you take that out.

Saul Kavonic: (Credit Suisse, Analyst) Great, thank you, that's all from me.

Operator: Thank you. Your next question comes from James Byrne from Citi. Please go ahead.

James Byrne: (Citi, Analyst) Good morning Peter and Sherry, thanks for taking my question. Peter, I just wanted to ask you firstly about the debottlenecking opportunity you flagged at Scarborough. I was hoping you would be able to maybe help quantify or just give us a sense of the magnitude there with the debottlenecking. If you'd entertain us perhaps on the extent to which that would also lower the break-even LNG price. I guess what I'm looking for here is, you know, the market is probably not yet willing to pay for some of the growth projects here for Scarborough but if we can be

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convinced that it is 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.

Peter Coleman: Thanks James. The debottlenecking we are 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 in diameter because of the water depth they are in, but as we get into the shallower waters, we have identified an opportunity to increase the diameter therefore decreasing the backpressure on the platform.

That has a potential to take us from an offshore LNG equivalent of 6.5 million tonnes up to 8 million tonnes, plus our domestic gas commitments. Any time I quote you a number always add the domestic gas commitment on top of that which is the 15-plus percent. So, if I am saying 6.5, it's 6.5 plus roughly a million of domestic gas and if I say eight, I'm saying eight plus one 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 two options that we are still optimising. 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 are 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.

Then of course the second main option is to side stream it across to North West Shelf and that extra capacity across to North West Shelf, but we're currently optimising that. We will have more information about that at the Investor Briefing Day later this year.

James Byrne: (Citi, Analyst) 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 contract?

Peter Coleman: The option is actually ours James, not the other way around. And we have already chosen not to extend one of those and we are in negotiations on the second one.

James Byrne: (Citi, Analyst) Okay, great. The next question I had was just around I think 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've used for impairment testing that you kindly disclosed last month, is the same oil deck that you use for budgeting purposes?

Sherry Duhe: James, I'll take that one. So that is the base case that we use for impairment testing. I think we have 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 recognise 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 look at a low stress test case for the overall balance sheet to make sure that we are clear on what could happen with extreme volatility, particularly when we are in peak periods of spend. 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 are going to fund those projects.

Peter Coleman: James and I think it's fair to say we used a transition from existing prices to what we think long term prices are. That's typically a forward curve so if you look at the forward curve and we will transition that depending on which scenario we are running over either a three-year or a five-year forward curve, but we run a multitude of cases. So as you know today, the forward curve is looking fairly robust.

James Byrne: (Citi, Analyst) Yes.

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Peter Coleman: 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 can get comfortable that the price trajectory that we are on is consistent with what our long-term view is.

James Byrne: (Citi, Analyst) That makes sense. The forward curve is well above your free cash flow break even 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 to $65 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 - I guess the conversations I have with investors is does the equity only work if the oil price is going to be $60 or higher?

Peter Coleman: Yes, yes. Look, it's a good question. Look, I would say in an unconstrained world you are correct in that as we look at that our ability to actually fund and move forward is more than adequate. The challenge we will have is, the fine balance there, will be with the ratings agencies and being able to match up their forward curve expectations with when we make that investment decision, because as you know once we make that investment decision then the ratings agencies will review our rating and they will do it based on their price, not on whether we have the adequate cash flow in the business. So, we have just got to balance that James and get that right.

James Byrne: (Citi, Analyst) Sure, okay.

Peter Coleman: That doesn't say we will be waiting for the ratings agencies and the ratings agencies have demonstrated a willingness to see through some of these short-term perturbations as long as they're seeing management demonstrate appropriate capital discipline. There'll be a number of factors that we would be discussing with ratings agencies at that time.

James Byrne: (Citi, Analyst) Okay. Just a third and final question, a 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% for your LNG book. You did about 31% so far, so are you saying that you expect no more DQT above the current levels or are we maintaining the same sort of DQT we saw in second quarter, because I can't quite reconcile the 25% to 30% guidance.

Sherry Duhe: 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. 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 effect of that across the year that gets us to our full year guidance of between 25% and 30% on produced volumes.

James Byrne: (Citi, Analyst) Got it, okay, so the second half is lower. All right.

Sherry Duhe: Yes.

James Byrne: (Citi, Analyst) Thanks. That's all from me. Thank you very much.

Operator: Thank you. Your next question comes from Mark Samter from MST. Please go ahead.

Mark Samter: (MST, Analyst) Yes, morning guys. Three quick questions if I can. Just the first one, you've been pretty vocal over the last month or two that you think there’s opportunities that are going to crop up and I guess globally,

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particularly European companies, don't want to be oil companies in particular anymore. Is there a preference, a desire, to divest the portfolio through these opportunities and add some more oil to the portfolio?

Peter Coleman: 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 looked at that previously and found it's a very difficult thing to do. Now, having said that, we are 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, you know, we may have a look, well we'll definitely have a strong look at it. Our preference is obviously things closer to home. If we can build things around existing assets then of course we will do that, but equally we recognise that we are very concentrated geographically in our footprint and diversification of that would assist us.

I would 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 they will be of significant interest.

Mark Samter: (MST, Analyst) All right, thanks for that. I mean I guess one imminent decision in an oil asset you have to make there is - there's no mention in the release about pre-emption in Sangomar. I presume that's the standard 30-day term. I think that was announced during the FAR processes. Should we just interpret that you're still considering your options and no decision has been reached?

Peter Coleman: Yes, I would do that. It is a 30-day term so I can confirm that and that the 30 days has about a week and a half to run so we're still considering what we do.

Mark Samter: (MST, Analyst) Thanks. Just a last question. I'm not sure if you saw - days all blur into one, I think it was last week - Chevron in their 10-Q said 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 two of their three 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?

Peter Coleman: Yes, 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. So, anything that Chevron does on their side of that development is really ring-fenced to them. It's got nothing to do with us. 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. No, not in our business at all, Mark. I would suggest that that's probably more focused on other areas of the world.

Mark Samter: (MST, Analyst) Okay, thanks. I have another one, a really quick one, which is back to the impairment, but it stood out really the other day. With the Pluto impairment PRRT bit you said you'd changed the price assumption and consequent reduction in recognised general expenditure. Did that in any way mean you changed the expectation of the end of Pluto's life?

Sherry Duhe: No.

Mark Samter: (MST, Analyst) No? Okay.

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

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Mark Samter: (MST, Analyst) Okay, it's just actually just cost rather than duration of cost. Okay, perfect. Thank you, Sherry.

Peter Coleman: Yes, look Mark, 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. It's locked up within the Pluto asset. The best way for us to unlock it is to have further developments going through Pluto.

Mark Samter: (MST, Analyst) Perfect, thank you.

Operator: Thank you. Your next question comes from James Redfern from Bank of America. Please go ahead.

James Redfern: (Bank of America, Analyst) Yes, hi Peter and Sherry, good morning. Two questions, please. One in relation to Lukoil's proposed transaction of Cairn Energy’s stake in Senegal. I'm just wondering if you can comment as to whether you think the price that they're offering is a fair price or a low price?

Then the second question is just can you make any comments around the LNG contracting market, which is obviously very weak with slopes around 10%, 10.5%. Just wondering if you can provide a bit more colour on what you're seeing out there in the energy contracting market in relation to Scarborough negotiations, which are probably likely to be postponed until next year. Thank you.

Peter Coleman: On the first one, James, no I'm really not going to comment on whether I think it's fair price or not. I think you can see there are those who make it their business to do this and publish what they think about that pricing and so forth. 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. 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 finalised. We have announced two or three 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. 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. For some of those customers, they've not actually been able to get into their offices during the COVID period in first half. That's all ramping up again.

Clearly the slopes at the moment, I don't know anybody who's doing 10.5% deals at the moment, 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. We don't know to the extent that that disconnect will continue into the future.

James Redfern: (Bank of America, Analyst) Okay, thanks a lot, Peter. For what it's worth, I think with the Lukoil consideration would be that it's a very low offer. Yes, I'll leave it there. Thank you.

Peter Coleman: Yes, well we'll just - we'll know in a couple of weeks.

James Redfern: (Bank of America, Analyst) Thanks, Peter.

Operator: Thank you. Your next question comes from Mark Wiseman, from Macquarie. Please go ahead.

Mark Wiseman: (Macquarie, Analyst) Yes, good morning Peter and Sherry. Thanks for the update. 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 de-

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booked the deferred tax asset. Does that mean basically it's $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?

Sherry Duhe: No, you shouldn't read it from that. First just to clarify, we've adjusted the quantum of deferred tax asset. We haven't de-booked it completely, but it has been adjusted as a normal part of the impairment process, where you look at both the PRRT benefits that are sitting within the asset, and also broader across the portfolio. 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 as 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.

Mark Wiseman: (Macquarie, Analyst) Okay, thanks. Can I just ask another one, just on M&A? Obviously, we're seeing a sharp uptick in deals being announced, and in some cases finding, in the last few weeks, seemingly favouring 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 weigh up the two.

Peter Coleman: Look, it's a good question. As the industry goes through price cycles, of course the pendulum moves from one quadrant to another. 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. We have to be careful that we don't look at something through rosecoloured glasses, and then find it's got lots of issues with it. They're 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 look like our current growth portfolio, that's a given. Anything that 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. Control is really, really important when prices are low or recovering, because - and as you are seeing 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.

We just don't think that's a right thing for Woodside shareholders to be continually at the behest of others who have got different priorities. 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 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 worldclass assets that we need to develop, and they've laid fallow for long enough, so we need to focus on those.

Mark Wiseman: (Macquarie, Analyst) Okay, thanks for the insight there. Just one more question from me, if I can. Just on the other resource owners and thinking about backfilling the North West Shelf. As the Chevron process, for them exiting that JV, is ongoing, is it possible to still continue that planning process? Would it be possible to sign a third-party gas deal whilst this process is still underway?

Peter Coleman: 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? It's interesting to put an incomplete negotiation into a data room, but at the end of the day it's still incomplete. I think any party looking at that asset will have to look at it through that particular lens.

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Now, Chevron's process has commenced. The fliers are out, so we've got some insight now as to both the timing of their process and the nature of what that process will be.

Mark Wiseman: (Macquarie, Analyst) Okay, great. Thanks very much.

Operator: Thank you. Your next question comes from Gordon Ramsay from RBC Capital Markets. Please go ahead.

Gordon Ramsay: (RBC Capital Markets, Analyst) Thank you very much. Just following up on the Lukoil-related questions. Lukoil is specifically mentioned with respect to the US SSI oil project sanctions against Russia. I just wanted to know if that 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 with Senegal.

Peter Coleman: Gordon, that's a really good question. At the moment, I'm just simply not able to comment on it.

Gordon Ramsay: (RBC Capital Markets, Analyst) Okay, that's all from me. Thank you.

Operator: Thank you. Once again, if you wish to ask a question please press star-one on your telephone and wait for your name to be announced. Your next question comes from Joseph Wong from UBS. Please go ahead.

Joseph Wong: (UBS, Analyst) Hi guys, just two quick questions from me. My first is just on the capex guidance. I just wanted to understand the reduction. Is that largely related to deferrals versus absolute reductions on different projects that you've got underway?

Sherry Duhe: Joseph, 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.

Joseph Wong: (UBS, Analyst) Yes. Yes, and then just the other quick one, just on the cost reductions that you achieved. Is that largely related to efficiency that you expect to continue to realise, or is that really deferral of non-essential maintenance works that you outlined in the presentation?

Sherry Duhe: 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 costs as well in support of those assets. It's something that we want to hang onto 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 will 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 impact.

Joseph Wong: (UBS, Analyst) Okay, got it. Those were the quick ones for me.

Operator: Thank you. Your next question comes from Baden Moore from Goldman Sachs. Please, go ahead.

Baden Moore: (Goldman Sachs, Analyst) Morning, Peter. I was wondering if you could just give us some thoughts around your capital management with still a very high payout ratio on your underlying earnings and you’re now trading

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below NAV, whether that might impact how you think about returns to shareholders going forward? Or is it a bit more of a franking credit issue that you’re balancing there?

Peter Coleman: Look, Baden, I think it’s fair to say that 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 or chosen that for Woodside’s business, we just keep it simple and it’s really on ability to pay. So, what’s your cash flow position and what’s your liquidity position? Then really, what’s your underlying NPAT?

So you can see that the outflow for the dividend payment is down quite significantly simply because it’s on the back of NPAT and we kept the DRP on, non-underwritten. 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.

Our view, arguably, is that returns to investors, particularly in the form of cash, will be highly prized during this period of uncertainty and so maintaining a good solid dividend flow in our view, is very, very important in the absence of nearterm growth projects and, as you know, Woodside has mostly longer term growth projects so that’s kind of a balance for us.

We will 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 project, Scarborough, has been pushed out into next year.

Baden Moore: (Goldman Sachs, Analyst) Thank you.

Operator: Thank you. There are no further questions at this time. I will now hand back to Mr Coleman for closing remarks.

Peter Coleman: 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 recognise the performance of the business.

Let’s not forget that 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 are continuing to move forward, albeit at a lower pace or slower pace on our major capital projects. We are starting to make good progress in new energy and carbon and, as we’ve discussed a lot this morning on the call, we are actively looking at inorganic opportunities should and if they arise.

All of that is because we have been able to maintain the discipline around our commitments and where we are in the cycle. As this perfect storm hit us during the first half, particularly the second quarter, which we have come out of it. We have kind of dusted ourselves off and now we’re looking forward to what the next 18 months or so brings to us.

I think there will be many opportunities that we can’t see today. Some of those are starting to show green shoots already. Oil price, commodity prices - oil prices and gas prices starting to firm as we had expected and hoped. So, we

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are 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. It’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 plus repatriating people from around the globe. We have 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.

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

End of Transcript

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