Woodside Energy Group Ltd (PNK:WOPEF) Q2 2024 Earnings Call Transcript

Woodside Energy Group Ltd (PNK:WOPEF) Q2 2024 Earnings Call Transcript August 27, 2024

Operator: Thank you for standing by, and welcome to the Woodside Energy Group Limited Half-Year 2024 Results. All participants are in a listen-only mode. There will be a presentation followed by a question-and-answer session. [Operator Instructions] I would now like to hand the conference over to Ms. Meg O’Neill, Chief Executive Officer and Managing Director. Please go ahead.

Meg O’Neill: Well, good morning, everyone, and welcome to Woodside’s 2024 Half Year Results Presentation. We are presenting from Sydney, and I would like to begin by acknowledging the traditional custodians of this land, the Gadigal people of the Eora Nation and pay my respects to their elders past and present. Today, I’m joined on the call by our Chief Financial Officer, Graham Tiver. Together, we will provide an overview of our half-year 2024 performance before opening up to Q&A. Please take the time to read the disclaimers, assumptions and other important information. I’d like to remind you that all dollar figures in today’s presentation are in U.S. dollars, unless otherwise indicated. I am very pleased to present a strong set of half-year results today.

They are a testament not just to our operating performance in the past six months, but also demonstrate how we are delivering on our strategy to thrive through the energy transition. This strategy is underpinned by three goals: providing energy, creating and returning value to our shareholders and conducting our business sustainably. During the first-half of 2024, we have delivered on all three. Our project execution capabilities have been demonstrated again with the safe startup and strong ramp-up performance at Sangomar and excellent progress at our Scarborough Energy project. Our reliable and cost-competitive base business has translated into strong financial performance and returns to shareholders with a fully franked interim dividend of $0.69 per share once again at the top end of our payout ratio range.

With our disciplined approach to cost management, we have reduced our unit production costs by 6% in an inflationary environment. And we will continue progressing actions to ensure that we can fund growth, while supporting strong shareholder distributions. Looking across Woodside’s global business, I’ve never been more confident in our ability to deliver reliable, affordable and lower carbon energy to a world that needs it today and into the future. Our key operational and financial metrics in the half-year results demonstrate how well our base business is performing. World-class LNG reliability of 98% and production of more than 89 million barrels of oil equivalent put us on track to deliver our full-year production guidance. We’re pleased to have delivered net profit after tax of $1.9 billion, translating into strong earnings per share and a healthy interim dividend for our shareholders.

Ensuring everyone who works at Woodside goes home safely remains our highest priority. Our commitment to continuous improvement means taking action to strengthen our safety culture, simplify our processes, and improve our systems. The full impact of these actions will take some time and our overall safety performance is not yet meeting our expectations. However, we are seeing some positive results. For example, the safe delivery of our Sangomar project included 30 million hours worked on the FPSO without a serious injury, a remarkable result and sets the standard for what I expect to see across the business. Let me now speak to the global market environment and our firm conviction that LNG will play an important role in the energy transitions.

Starting with energy demand, the fundamentals are strong. As the world’s population continues to grow and economies develop, the demand for energy is increasing. According to recent updates on progress towards the UN sustainable development goals, the number of people lacking access to electricity around the world remain significant. In 2022, this reached 685 million people the highest in over a decade. So while the precise pathway of the global energy transition remains uncertain, there is one thing we can bank on. demand for reliable, affordable and increasingly lower carbon energy will continue to grow. At the same time, we firmly believe that LNG will remain an important global energy source as countries seek to lower their emissions. When used to generate electricity, gas typically provides — sorry, gas typically produces half the life cycle emissions of coal.

Gas can also provide support for electricity grids powered by renewables and batteries. Therefore, for many economies, switching from coal to gas is often the most material and affordable way to reduce emissions, while maintaining a reliable source of energy to underpin modern living standards. For example, in the U.S. from 2022 to 2023, coal to gas switching accounted for two-thirds of the emissions reduction in electricity generation. While coal use in markets like Europe has already peaked, the Asia Pacific region currently accounts for more than 80% of global coal use and global coal consumption is approximately 8 times higher than global LNG. So we see a clear and sustained opportunity for coal to gas switching in key markets as they navigate the energy transition.

These fundamental drivers for long-term demand also give us confidence that the so-called LNG glut forecast for later this decade is unlikely to have a sustained impact on demand or pricing. Recent history has shown that due to customers’ energy security and decarbonization drivers, increased supply is continuously absorbed by the market with price remaining resilient. For example, international energy agency concerns expressed in both 2009 and 2016, of a sustained “LNG glut” with far-reaching impacts on gas prices did not eventuate. Looking forward, we believe demand will continue to keep pace as new supply comes online. Underpinned by these strong market fundamentals, our high-quality portfolio is well positioned to provide energy and create value now and into the future.

Core to this is Woodside’s continued world-class operational performance, which combines consistently high reliability with reduced operating costs. We are also making targeted investments to extend the production life of our key operated assets to ensure we continue to extract value from our base business. We achieved a major milestone in June with the start-up of our Sangomar project. This demonstrates clear delivery against our growth strategy, creating shareholder value, as well as significant economic benefits to Senegal. I’m pleased to report strong well and subsurface performance. Nameplate capacity of 100,000 barrels per day has been achieved, and all 24 wells have been drilled and completed. This achievement has relied on the creation of strong local relationships, including with our joint venture partner, Petrosen.

We will operate this asset in the same way we do in all jurisdictions, maintaining full compliance with local requirements and positive relationships with regulators, while ensuring we protect shareholder value. Moving to Australia. We have made impressive progress with our Scarborough Energy project. Scarborough was 67% complete at the end of the period and is on track for first LNG cargo in 2026. Scarborough was also set to deliver domestic gas at a time the local Western Australian market needs it. The image on this slide shows the floating production unit, which reached a major milestone during the half, achieving structural completion of the top sides. Other key onshore and offshore activities are progressing well, and I look forward to taking some of our investors to see firsthand our progress at Scarborough during a site visit planned for later this year.

We were very pleased to welcome LNG Japan to the Scarborough joint venture and look forward to completing the sell-down to JERA. This demonstrates our ability to attract high-quality partners at a competitive price to a Woodside operated project. Moving to Trion. We remain on track for first oil in 2028. Front-end engineering design on the FSO was completed in the period. We have also progressed engineering procurement and contracting activities, including the award of the Subsea marine installation contracts. While progressing our growth projects, we continue to look for opportunities to grow our portfolio into the 2030s and beyond to deliver long-term value for our shareholders. In July and August, we entered into agreements to acquire two significant energy projects on the U.S. Gulf Coast, which I will now turn to.

Our proposed acquisition of Tellurian and its Driftwood LNG development positions Woodside as a leading independent LNG player with exposure to both the Pacific and Atlantic Basin. It has potential for significant future cash generation and reduction of the average Scope 1 and 2 emissions intensity of our LNG portfolio. As we engage with investors following the announcement, there was a desire for more clarity on Woodside’s value drivers and expected returns from the Driftwood LNG opportunity. Driftwood is a pre-FID project, and we are confident it can achieve the returns of our capital allocation framework. Looking at the chart on the slide, the first two gray bars compare the return profile of a typical project finance development with the returns already achieved by some U.S. LNG players.

Some are improving returns by increasing plant capacity selling some volumes at international pricing and extending the life of the project. We see even more potential for Woodside. Driftwood plays to our established strengths in project execution, operations and marketing. Our track record on reliability and train debottlenecking gives us the credentials to extract more value from assets, compared to other players. Another competitive advantage of Woodside is our global LNG marketing portfolio. This provides us with flexibility to serve our customers and enables global price indexation. Our long shipping position is another strength we bring to the opportunity. We’ve seen traditional U.S. LNG players building out shipping fleets to allow dead sales.

This is, of course, strength of Woodside today. Driftwood is truly advantaged. It is the only fully permitted pre-FID opportunity in U.S. LNG and has Bechtel as the EPC contractor. We have a very compelling opportunity for sell-downs. Multiple inbounds have been received, and we are in conversations with interested parties. Importantly, however, we will be focused and find the right strategic partners for this opportunity as we did for Scarborough. Now to our proposed acquisition of OCI’s Clean Ammonia Project. This is another investment that positions us to thrive through the energy transition. The project is under development with expansion potential. Construction is already 70% complete with ammonia production targeted for 2025 and lower carbon ammonia for 2026.

Global ammonia demand is forecast to double by 2050 with lower carbon ammonia make nearly two-thirds of demand total. Market forecasts show that growing demand for lower carbon ammonia will be supported by policies in key energy markets, stimulating use of ammonia beyond traditional applications, to include power generation, marine bunkering and as a hydrogen carrier. Over the past two decades, we have seen the EU leading the charge in tackling climate change through incentives like the emissions trading scheme. Last year, it strengthened its lower carbon framework through the implementation of the carbon border adjustment mechanism. This policy combines a carbon intensity measurement with a mandatory carbon price further incentivizing use of lower carbon energy sources.

Lower carbon ammonia is also being used in Japan and Korea to decarbonize power generation by co-firing ammonia with coal. I’ll now hand over to Graham to take you through our financial performance.

Graham Tiver: Thanks, Meg, and hello, everyone. Our financial performance and balance sheet have remained resilient because of our strong underlying business and our consistent approach to capital management. I would like to highlight here that our capital management framework remains unchanged. This framework provides the flexibility of funding value-accretive growth, while continuing to deliver strong shareholder returns. Underpinning our capital management framework is discipline. We run our business with consistent cost focus and have managed our unit production costs down despite inflationary pressures. We will further tighten our belts and continue to rationalize discretionary spend. We are disciplined with our investment decisions.

The acquisitions of Tellurian and OCI’s clean ammonia project are both aligned with Woodside’s corporate strategy and our capital allocation framework. As the operator of these opportunities, we control the spend, allowing us to face the development, bring in partners at our determination and use the contractors we want. The sell-down of equity in the Scarborough joint venture bring quality partners into the project and back into the business. The sale proceeds of $910 million received from LNG Japan and an estimated total consideration of $1.4 billion coming from JERA. And we are disciplined in how we position the balance sheet to achieve our goals. We know the importance of dividends to our shareholders. And when we evaluate the financial scenarios, we assume a dividend payout ratio at the top end of our range, even a stress case pricing.

We target a gearing range of 10% to 20% through the investment cycle. With the recent acquisitions, we expect to access debt markets in the near-term. Our gearing will likely go above the top of our range for a period of time. This is expected to reduce back to within our target gearing range by utilizing the various levers at our disposal. Moving to our financial performance in the period. Despite lower average realized prices, our base business continues to perform very well. Costs are down and we’re demonstrating excellent operational discipline and resilience across our financial metrics. This is translating into a healthy dividend payment representing a half-year annualized yield of 7.3% at June 30. Cash flow generation through the first-half of 2024 was strong, delivering a cash margin above 80%, which has been sustained over the past five years.

Importantly, we have achieved positive free cash flow of $740 million in a heavy capital investment year and with significant tax payments. This is in line with the previously provided outlook for free cash flow. We expect to update our outlook to include acquisitions and sell-downs once we complete the transactions. Our balance sheet is well positioned with our gearing at the lower end of our target range and a strong cash-generative portfolio of assets. This is how we have created and returned value to shareholders in the first-half. I’ll now hand back to Meg.

Meg O’Neill: Thanks, Graham. As I outlined earlier, conducting our business sustainably is one of the goals underpinning our strategy to thrive through the energy transition. While we were disappointed at the shareholder vote received on our climate transition action plan at our AGM. We respect the results, and we will continue seeking feedback from investors. During the half, we progressed the implementation of our asset decarbonization plans and remain on track to achieve our Scope 1 and 2 emissions reduction targets. We also announced a new complementary abatement target to take FID on new energy opportunities by 2030, with total abatement capacity of 5 million tonnes per annum of CO2 equivalents, as well as generating attractive investment returns, the acquisition of OCI’s Clean Ammonia Project is a material step towards delivering on our Scope 3 investments and abatement targets.

And beyond our own initiatives and investments. Woodside is also championing lower carbon initiatives across the sector. In January, we became the first Australian company to join the oil and gas methane partnership 2.0, a flagship international program aimed at improving the accuracy and transparency of methane emissions reporting. Conducting our business sustainably also extends to supporting community development wherever we operate. Woodside continues to be among Australia’s top tax contributors, our total tax and royalty payments during the half to Australian governments was AUD2.7 billion. This demonstrates an ongoing and significant contribution to the economic prosperity of Australia. As described in our Northwest Community development report, we spent more than AUD2.4 billion with local businesses in Western Australia through the Northwest Shelf and Scarborough projects during 2023.

In Senegal, our Sangomar project is providing significant local content opportunities creating jobs for more than 4,400 Senegalese people. I’d like to close by recapping on our strategic priorities for 2024 and demonstrating the strong investment case for our shareholders. We have a high-quality, cash-generative portfolio, and we are well positioned to supply growing LNG demands. We deliver strong and consistent returns to our shareholders and are on track to deliver our emissions reduction targets. And above all, we are committed to continuously improving safety. Our achievements in the first-half of 2024 demonstrate delivery of our strategic goals and give us great confidence that Woodside will thrive through the energy transition. Last month, we celebrated 70-years as an Australian company and reflected on our proud history and proven experience.

Looking to the future, we have the strategy, the people and the portfolio to enable us to deliver shareholder value for decades to come. Thank you. I’ll now open the call to your questions. Please limit your questions to two each. So everybody has an opportunity to ask their questions.

Q&A Session

Operator: Thank you. [Operator Instructions] Your first question comes from Mark Wiseman with Macquarie. Please go ahead.

Mark Wiseman: Good morning, Meg, Graham and team, congratulations on a strong result and a strong dividend. I just had a question on the cash flows, the operating cash flows. You paid more than we expected in tax. Are you able to give any breakdown of the $1.7 billion tax, how much of that’s PRRT versus income tax?

Graham Tiver: Hi, Mark, thank you, Graham here. So yes, so effectively, of that $1.7 billion paid in tax in the cash flow statement, $1.5 billion was related to income tax and the remainder being PRRT. What I’d point to Mark is if you have a look at the end of December as a part of our full-year results in the balance sheet, we had a tax payable liability of $1.1 billion. So effectively, that has been paid along with tax payments for the 2024 year. So hopefully, that provides some clarity. Importantly, we are one of the largest taxpayers in Australia. And as Meg touched on in her presentation, all up across all taxes and royalties in Australia, we paid AUD2.7 billion in the first-half.

Mark Wiseman: Okay. Thanks, Graham. And just for my second question, just on hedging, with the two M&A deals that you’re working on, the Driftwood FID coming up and maintaining the 80% dividend payout for now at least. What’s your posture with hedging in ’25 and ’26? Thanks.

Meg O’Neill: Yes. Mark, it’s probably worth reminding you and the investors why we hedge. So we have been hedging plus or minus 30 million barrels of oil for the last couple of years in this period of higher capital spend. We also hedge our Corpus Christi contracts. So those are Henry Hub and TTF hedges, and that’s really to manage the trading risk in that particular contract. So the hedging that — I think you’re asking about is the oil-linked hedging, and we do expect to continue hedging in 2025, and we will take a look in due course at 2026 as we firm up plans forward for Driftwood as we get better line of sight as to what exactly our capital spend is going to look like, that will inform our decisions as to whether or not we hedge in ’26.

Mark Wiseman: Okay. So would it be reasonable to assume all else equal, more CapEx commitment and more gearing on the balance sheet would point you towards more hedged volume?

Meg O’Neill: Yes. But again, well, look, I’d say not necessarily more. We’ve been targeting the 30 million barrels because we feel that’s an appropriate level of hedging to protect our ability to cover our base costs as well as continue the investments that we’ve sanctioned. And so I wouldn’t expect it to go above the 30 million barrels, but it really will be a question for 2026 of how much hedging is appropriate — as we — you’ll recall, 2026 is when we expect to start LNG production from Scarborough. So spend ramps down, revenue starts to come in, but that will be kind of the critical year as we think about the cash balance going forward.

Mark Wiseman: Okay, thank you. That’s clear and congrats on the result again. Cheers.

Graham Tiver: Thanks, Mark.

Operator: Thank you. Your next question comes from Saul Kavonic with MST. Please go ahead.

Saul Kavonic: Good morning. A couple of questions. Perhaps the first one is for Graham. Just in the context where you talk about gearing to go above the top end of the 20% gearing range for a period. Should we think about this providing time to enable targeted sell-downs of Driftwood perhaps another way of phrasing that once the — if you — once the 50% sell-down of Driftwood occurs, do you think you would then be — may be below the 20% gearing range at kind of current $70, $80 oil prices?

Graham Tiver: So it’s very early days. We are still working through one project completion of the actual acquisition, we’re still reassessing the capital, the phasing of the capital, et cetera, and then the sell-down process. But to answer your question at a very high level, based on what we see today, it is highly likely that we will still pop up above 20% for gearing for a period of time in a 50% sell-down scenario. But having said that, and I caveat, there’s still a lot of work to do between now and then.

Meg O’Neill: And Saul, maybe it’s worth elaborating on Graham’s answer. We said our target gearing range is 10% to 20%, but it’s not hard guardrails, it’s a target range, and we may be above or below at periods in time. And you’d be well aware that we were below it last year when market conditions were in our favor. We again, with the investment in Driftwood may go above it for a period of a couple of years. But again, they’re not hard and fast rules. It’s more target range.

Saul Kavonic: Okay. So I guess a follow-up to that is, in the absence of a Driftwood sell-down, are you still comfortable you can maintain this modeled 80% payout policy within the various scenarios you look at? Or is the pressure really on to have a sell-down to maintain that recent payout ratio?

Meg O’Neill: Yes. So what we said about Driftwood is we really want to put together the Dream team. We’ve had more inbounds than we can shake a stick at. So we’ve got the luxury of being able to really pick the partners we want to work with. And our intention, as we progress towards an investment decision there is we want to have line of sight to the partnership that we want. We may not have everything signed, sealed and delivered, but we do want to have line of sight to the partnership. If we didn’t have anybody interested, I don’t — it would not be our intention to go forward at 100% with nobody queued up.

Saul Kavonic: All right. Thanks. I also just have a question on Driftwood. It could be for you. I don’t know if Mark’s on the call maybe he’s better to address it. But just looking at the steps you provided here to show how this can go from an infrastructure return to the 12%-plus rate of return. And you highlight debottlenecking and longer life, et cetera. But I just wanted to kind of [holding on two] (ph) elements. You talked about Woodside achieving greater than 95% reliability. Could you provide some, I guess, guidance on what the average U.S. LNG plan achieves that is what you think Woodside can achieve?

Meg O’Neill: Yes. Thanks for the question, Saul. We actually tried to get that hard and fast data. And unfortunately, it’s a bit all over the map. There are some very high-quality operators in the U.S., who operate in that 95%-ish range reliability. There are other operators that struggle to keep their plants online. What we can speak to is our track record and part of why we highlight our LNG reliability every half-year and full-year is just to kind of confirm with the market the capability that we have in our organization to get the maximum value through the facilities that we have.

Saul Kavonic: Thanks. And just a second point to touch on the — I guess, the upside from the marketing position. Do you expect, for example, if you would have signed an FOB contract from Driftwood that you’ll achieve a premium toll value versus kind of the more recent tolls that have been signed and our push, is it this like a $0.05 in MMBtu premium or $0.50 MMBtu premium?

Meg O’Neill: So Saul, one of the things that we’re working on as we put together our dream team is making some of those decisions around how much equity LNG we want to maintain, how much equity in the plant we want to maintain and how much equity LNG we want to maintain. If – look, it’d be premature for us to speculate on how we would structure any contracts. There may be circumstances where we would sign FOB contracts. But in some ways, that really is linked to the infrastructure kind of model where you get that high confidence in the new stream, where we think we can really add value is actually by taking more of that into our portfolio. So our starting point is whatever equity position we take, we’re going to take it into our portfolio because we think we can access better pricing by being able to sell it at either oil indexation, CTS indexation or JKM.

Saul Kavonic: Sorry, just one more. My understanding is the approval…

Meg O’Neill: Saul, we’ve got a few others in the queue if we can — if I can ask you to hop back in. Thanks, Saul.

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

Gordon Ramsay: First of all, big congratulations on getting Sangomar up to 100,000 barrels a day. I think that’s a terrific achievement considering the complexities of the project and particularly some of the subsurface infrastructure involved. Just on Sangomar, Meg, if you 100,000 barrels a day, obviously, that’s the cap that you’re working with on the project. Do you think that can push out the plateau volumes further than maybe than what you originally thought based on initial well performance?

Meg O’Neill: Yes. Thanks for the question, Gordon. And I appreciate your commentary. I know you’ve studied that quite closely, and you appreciate the complexities of the asset that we have there. We’re really pleased with the well performance that we’ve seen to-date. What we haven’t done yet is gotten water injection or gas injection up and running. And as you would well appreciate, we need those secondary recovery mechanisms to maintain the flow rates from the wells. So it’s going to take us a bit of time to really understand how the field is plumbed together and how effective those secondary recovery mechanisms are going to be. So I’d say we’re still in the — too early to say stage. But very pleased with the well performance to date.

Gordon Ramsay: Okay. And just one other operational question just on the unit production cost, bringing that down by 6% to $8.30 and a lower production compared to first-half 2023. What were the drivers to that? And could that be sustained going forward?

Meg O’Neill: It’s a lot of hard work on a lot of different fronts as I’m sure you’d appreciate, to manage unit production costs, a lot of focus in base cost management through the business. just taking a look at everything we do and how we do our work. It’s looking at things like how efficiently we’re managing our turnarounds how efficiently we’re executing maintenance, looking for synergies and things like helicopters and boats making sure we’re efficient in our above field support. So there’s no silver bullets. It’s a lot of hard work on a lot of different fronts.

Gordon Ramsay: Okay, thank you.

Meg O’Neill: Thanks, Gordon.

Operator: Thank you. Your next question comes from Tom Allen with UBS. Please go ahead.

Tom Allen: Good morning, Meg, Graham and the broader team. Are you comfortable that following the two big deals recently announced with Tellurian an OCI ammonia that Woodside’s now added sufficient growth to the outlook? Or given that these deals haven’t added upstream production, should we expect more? Woodside said that it wants to add growth in LNG, new energy and deepwater oil you’ve hit the first two parts of that plan with recent deals. So is adding further scale investment in deepwater oil still a near-term key growth ambition?

Meg O’Neill: Well, Tom, I’d say we already are taking steps to add growth in deepwater LNG with Sangomar and Trion. So we’ve got a project that’s now in the operational phase, and then the Trion project 10% completes. So we actually have taken steps to increase our — sorry, our deepwater oil portfolio. If you’re trying to fish more generally as are we looking at other M&A opportunities. Look, nothing at this point in time. We’re very pleased with the quality of the Driftwood and OCI Clean Ammonia Project Acquisitions, and we’ll be very focused on finding a pathway to make the Driftwood FID decision in a way that delivers value for our shareholders.

Tom Allen: Thanks, Meg. Just following an earlier question on Sangomar. The initial well performance outcomes read well. And so based on those initial outcomes and to guide how we think about cash flows over the next six to 12-months, can you please comment on — when should we expect peak plateau production? And are the initial flows that you’re seeing, recognizing it’s early days, but are these supportive of around that 75,000 barrel a day plateau production level? Or is risk to the upside or downside from those levels based on what you’re seeing so far?

Meg O’Neill: Look, Tom, as I said, really pleased with how the wells are performing. It’s a new facility. And every time you start up the new facility, you always have to work through a few, we’ll call it upsets and the team has been doing actually a fantastic job of as we bring new equipment on as we learn things, responding to those learnings. But it really is too early to draw any conclusions around the long-term reservoir performance Again, the key kind of challenge or question with Sangomar is the connectivity within the reservoir, and we need to get the water injection wells up and running and the gas injection wells up and running to understand our ability to sweep oil through the reservoir.

Tom Allen: Okay, thanks Meg.

Meg O’Neill: Thanks Tom.

Operator: Thank you. Your next question comes from Nik Burns with Jordan Australia. Please go ahead.

Nik Burns: Hi, thanks Meg and Graham. Look, I’m going to risk trying to ask another M&A question, but talk about risk management instead. Assuming you do complete both the Tellurian and ammonia plant acquisitions to move ahead with the Driftwood LNG project, by the time Driftwood comes online, you’ll have considerable exposure to Henry Hub gas prices and input costs. Just wondering whether you’re comfortable with that long-term exposure to Henry Hub? Or should we expect you might look to try and remove or mitigate that risk via the acquisition of more U.S. gas production assets such as shale gas?

Meg O’Neill: Yes. Thanks, Nick. Look, I appreciate a lot of interest in this topic. As we think about putting together our dream team, one of the capabilities we’re going to be looking at our partners as you can bring connection into that upstream gas world because, as you know, it will be incredibly important for us to understand the U.S. onshore gas market and to have ability to ensure we get the gas feeding into the plant that we need at a price that remains affordable. But at this point in time, we have no intentions of going into the upstream. We would be very cautious if we were to do so, again, recognizing the skills and capabilities for onshore U.S. shale gas is quite different from the skills and capabilities we have. So in due course, we will continue to look at ways we can manage that upstream risk, but it is not a priority for us to get into upstream U.S. at this point in time.

Nik Burns: Okay, that’s clear. Thank you. And then just a question on Scarborough. You recently increased the cost there by $500 million, and that was primarily associated with Train 1 mods. Just wondering if you can talk through your confidence in the current cost estimates now? And did the $500 million increase allow you to replenish your contingency budget? And just sort of looking ahead, how should we think about what are the residual key risks into the project? I understand it’s quite complex. But if you can talk to that and maybe the further risk to cost and schedule from here?

Meg O’Neill: Sure. We’ve worked very hard before we put out that cost update to really understand the vulnerabilities of the Scarborough project to understand where we’ve spent the money to date and where we’re tight and where we needed a bit of support I have a very high level of confidence that we will deliver the project within that $12.5 billion. I guess just for the market’s understanding, I am personally keeping a couple of hundred million of that in my pocket. So the project team doesn’t have that. So they’ve been challenged to deliver it for $12.3 billion as we think about ongoing risks, so very pleased with particularly how the onshore work is going with Pluto Train 2, pleased with how the offshore pipeline installation is going.

The FTA always has been a critical path, and that remains on critical path. As you saw in the deck, the top side is structurally complete, but there’s still many hours to go to get everything ready to go before we made it with the hole. So we watch from a project execution perspective, that’s a key item to watch. The second thing that we are watching very closely and working very closely with the regulator on is the Scarborough operations environment plan. We have already passed the completeness check with a NOPSEMA, so we are continuing to work through their questions. But given the evolving rules around consultation, we wanted to make sure we got that into NOPSEMA well in advance of needing it to make sure that we are robust and have the approvals we need by the time we bring the FTU into Australian waters.

Nik Burns: That’s great. Thanks, Meg.

Meg O’Neill: Thanks, Nik.

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

James Byrne: Good morning. I wanted to ask about the outlook for cash flows and whether the performance of the business has deteriorated at all relative to the prior expectations? And just bear with me like I’m just going to state a few things here. So the IBD last year 2024 free cash flow at $70 oil was sort of being indicated at around $600 million? If we take that up to $84 oil using your own sensitivity, we can kind of get to a number of about $1.5 billion for 2024, assuming second-half oil price is the same as first. CapEx, $5.5 billion, so that kind of gets us to operating cash flow is $7 billion for 2024. We have to adjust then for the asset sales LNG Japan, so probably more like $6 billion, right? First-half achieved less than $2.4 billion of operating cash flow.

So there’s a big delta there to get up to what you’d loosely guided to at the IBD next year. And yes, Sangomar is ramping up, but nonetheless, it’s a very big delta. Secondly, at the Beaumont acquisition call, it was stated that gearing would go to the low-20s to mid-20s in a subdued oil price environment. And today, it sounds like it will go to the low to mid-20s in at Woodside’s internal assumption of oil as opposed to necessarily a subdued stress test or price environment? And lastly, Sangomar is ramping up really well and yet the production guidance is unchanged. So if I triangulate those things, it kind of feels like there are parts of the business that might have deteriorated versus prior expectations. And I just wanted you to explicitly be able to say that, that was not the case.

Graham Tiver: Thanks, James. I’m very happy to answer the cash flow question. As you’ve quite rightly pointed out, there are swings and roundabouts. We can go into all the different line items. But if we stand back, I’m very comfortable in saying that our half one free cash flow is on track as per our IBD ‘23, November ‘23 cash flow guidance. And when we extrapolate that forward for the full-year position, also very comfortable that we are tracking above that as you hit on, the prices are generally higher than what we’ve received to the mid case of 70 that we put forward in the IBD. So yes, we can go into the detail and happy to take that offline. But in terms of — yes, there are swings around about in regards to prices, timing of CapEx, tax payments, et cetera.

But when you stand back and look at it, the business is performing extremely strongly. And that’s evidenced in our cash flow generation and the ability to pay strong dividends. We are in line with what we put forward at the November IBD and will likely exceed it.

Meg O’Neill: And from a production perspective, so the guidance we put out, I think at that point in time, we would have said Sangomar start-up was expected in “mid-24”, which is what we’ve delivered. So yes, very pleased with how it’s ramping up. But again, in any business, there’s a number of different assets, and we still feel pretty — well, we still believe and stand by the guidance we’ve put out for total production.

James Byrne: Okay. Second question, just back around the gearing. To have the gearing go to sort of that low mid-20s percent. I’m actually getting — this is very anecdotal, I’m getting credit investors that right to me with our concerns, along with equity investments that are similarly concerned. And my fear is that if the bondholders are pitted against the shareholders, then equity that’s likely going to lose out. Now if I pick up, Graham, on what you mentioned in your opening remarks, you mentioned you have various levers that you can pull, and you sound quite intent on maintaining that strong dividend payout ratio, what levers would you describe as being able to pull in that instance that a normal oil price environment is still getting to that mid gearing mid-20s gearing range, a little low day bear market for oil.

I’m just very interested in what levers you think you have to pull because it appears to me that and many in the market, by the way, that the path of least resistance is in fact the dividends.

Graham Tiver: Yes. Thanks, James, and always good questions. And I think if we can go back to the work at OCI where we spoke around about the strength of the balance sheet and our gearing. I think it was sort of as I touched on with Saul’s question, in our mid-price scenario, we will be above 20% and at the stress price. I’m not sure if that’s what you mean by subdued. It was more around the mid-20s. What I would say, when we look at the levers, the first and foremost is just continued strong operational performance. We must continue for the underlying business to perform well and generate strong cash flows to support the balance sheet. We’ve always got opportunities around phasing of capital spend. We’ve got opportunities around cost reductions, tightening up on the OpEx and CapEx, discretionary spend, et cetera.

We’ve already touched on the hedging program. We’ve touched on earlier on around our willingness or our plan to sell down a portion of Driftwood and that’s a core part of it. So look, there’s many levers, and we will assess them on their merits. And it’s all a part of the work that has to take place over the next six months or so.

Meg O’Neill: But James, at a high level, it’s probably worth reinforcing that over the period, you would have seen that Woodside has a track record of taking care of both our debt holders and our equity holders. You would have seen we’ve been in and out of the debt market for probably the last 20 or 30 years. And we pay our debts as and when they’re due. And for the last decade, we’ve continued to provide very healthy returns to our shareholders. So we’ve certainly got the ability to do both.

James Byrne: So could I perhaps ask it a different way, though. So some of those levers sound very much business as usual, right, like operational performance, filling down Driftwood — they’re things that I think both equity and credit would expect management to undertake. But Graham, in your conversations with debt investors and rating agencies, would you say that they are comfortable with the trajectory of the balance sheet given the extension of the CapEx cycle?

Graham Tiver: Yes.

James Byrne: Okay.

Meg O’Neill: Thanks, James.

James Byrne: That’s all from me.

Operator: Thank you. Your next question comes from Adam Martin with E&P. Please go ahead.

Adam Martin: Yes. Good morning, Meg, Graham. Obviously, pretty strong market reaction post your two recent deals. Just perhaps just sort of summarize investor feedback, any differences in anything that surprised you? And I suppose, what the market might be missing here?

Meg O’Neill: Sure. Well, look, what I think we’ve had a couple of thematic questions, which we tried to address in this presentation. With Driftwood, there’s been a lot of desire to understand what’s different about how Woodside would do a U.S., LNG projects from how other U.S., LNG players have done their projects. And so that’s why we put that slide in showing the sorts of activities that we believe we bring to the opportunity to create additional value and why we think it’s compelling. And with OCI, look, I think there was an element of surprise. We’ve been saying for three years that we would spend — that our intention was to profitably invest $5 billion in new energy products and services. I think the market just wasn’t expecting us to do $2.3 billion this year.

I think a lot of folks had probably built into their model that we would back-end weight that — and look to be fair, we had probably signaled that as we had been focused on pursuing organic growth opportunities, which would have had a slower ramp-up of spend. So those are probably the key themes that we’ve been hearing, Adam.

Adam Martin: Okay. Thank you. And just second question around decommissioning, sort of any updates around what you’re thinking for North West Shelf? And then also just on the Bass Strait, I think Exxon have recently pulled the EP around 13 platforms that I think is issue around sort of leaving everything below 55 meters in the water. Just talk through what’s going on in the Bass Strait, but also Northwest Shelf, please?

Meg O’Neill: Sure. Well, let me speak more broadly about decommissioning. We have a very significant decommissioning campaign underway this year. And this builds on activities we started last year with the build plug and abandonment campaign. We’ve got a large plug-and-abandonment campaign for Stybarrow this year. And we’re taking steps to remove subsea flow lines, riser dirt mooring systems from a number of legacy assets, things like Griffin as well as Stybarrow. As we go to Bass Strait, the operator and joint venture has been working for many years on decommissioning their initial focus on plug and abandonments. So basically dealing with the wells so that the platforms can subsequently be removed safely. We have been working with the operator on a plan forward for removing a number of the steel pile jackets that are in place.

And the work that we’ve done thus far would support that a better safety and environmental outcome would be to leave the parts of the steel pile jackets that are in deeper water in place. Now Australian law today requires full removal, and that’s why the joint venture has pulled that EP with the intention of continuing to do the scientific work to document the positive environmental impacts associated with live in place. North West Shelf, I assume you’re asking about train retirement dates. So we continue to monitor production from North West Shelf. The offshore is doing quite well. We’re processing a fair amount of Pluto gas at the Karratha Gas Plant today and do expect to see ramp-up from Waitsia in due course. So we are continuing with our planning to take on LNG train offline either late this year or in the first-half of next year.

Adam Martin: Okay, thanks for the detailed response Meg.

Meg O’Neill: Thanks, Adam.

Operator: Thank you. Your next question comes from Dale Koenders with Barrenjoey. Please go ahead.

Dale Koenders: Morning. Meg, Graham and team. Just wondering about Sangomar now that you started up. There’s been obviously a lot of cost inflation in the industry. There’s a little bit of uncertainty around depreciation rates. Do you think that we need to get guidance as a market on those numbers going forward? Or are you comfortable with how the consensus is forecasting those costs?

Meg O’Neill: I’ll let Graham deal that.

Graham Tiver: Yes. So Dale, we don’t normally provide that level of detail, asset by operational level. hear your question. I think the key point is to — as Meg touched on is around the ramp-up and we get a feel for the ramp up, how the connectivity is across the wells and then we can look to consensus and see how we’re traveling.

Dale Koenders: Okay, thank you very much for that. I’ll leave it there.

Meg O’Neill: Thanks Dale.

Operator: Thank you. Your next question comes from Henry Meyer with Goldman Sachs. Please go ahead.

Henry Meyer: Good morning. Just a question on the inclusion of asset sale proceeds and underlying earnings and dividends. Can you share how you determine the amount of sale proceeds that are included in underlying, I think that what we could assume going forward, for example, the $1.4 billion from Scarborough this half?

Graham Tiver: Yes. So Henry, just for clarity, on the $1.4 billion is the cash proceeds that will go into the cash flow statement once received, and that’s estimated at this point in time. What we’re talking about in the net profit after tax calculation is the profit or loss on the sale, which for both LNG Japan and for JERA sell-down, it will be a profit. And for LNG Japan, I think it was $110 million — $120 million apologies. So it’s not — I want to be very clear, it’s not the full cash amount that’s going into the underlying dividend calculation. It’s the profit on the sale.

Henry Meyer: Yes, absolutely. And so that $120 million for LNG Japan, is that proportional to what would you expect from the JERA sale as well?

Graham Tiver: Roundabouts.

Henry Meyer: Great. Okay, thanks. And last one for me at Sangomar, we’re continuing to see headlines in the press from the Senegalese government looking to renegotiate contracts? I understand, of course, that it will be confidential, but could you share Woodside’s perspective on any of these contents, any potential risks, changes timeline for any resolution that you see from here?

Meg O’Neill: Yes. At this point, Henry, we’re very pleased with the relationship we’ve built with Petrosen and the relationship we’ve built with the government of Senegal. You would have seen in the past that photo, myself and the President of Senegal out on the FPSO, celebrating first oil. Look, we know every governments all around the world has the rights to determine the framework that governs resource development in their nations. In Senegal, we have a contract. We have a production sharing contract. We have a host government agreement. These were fairly negotiated with the government of that nation. And look, we’re happy to have a conversation with the government, but we need to make sure that we’re protecting the thesis, the investment thesis on which we entered the project.

So at this point in time, we’ll continue to have open discussions. I would note that the Presidents around the time of his appointments or his election. He made some very positive comments welcoming private investment to the nation of Senegal and Sangomar development is one of the nation’s largest private investments. So I’ll leave it there.

Meg O’Neill: Okay. Thanks Meg.

Henry Meyer: Thanks Henry.

Operator: Thank you. Your next question comes from Sarah Kerr with Morgan Stanley. Please go ahead.

Sarah Kerr: Thanks so much and congratulations on the result. I was just wondering if there was any update for the timing on Perdaman contract? And if there’s any impact to Woodside from the changes with the WA domestic gas policy?

Meg O’Neill: Look, you’re probably better off asking Perdaman for the timeline. We need to be ready to supply them in 2026, and we will be. As to the pace of their ramp-up, that’s really for Perdaman to communicate to the market. And in terms of the WA domestic gas inquiry. Look, we recognize this is an important matter for the state. We recognize that the domestic gas largely from the Northwest Shelf has underpinned a tremendous amount of economic prosperity in Western Australia. We intend to continue to work with the government on how to continue to get those positive benefits. It’s probably worth Sarah noting that I know Browse has also received quite a bit of recent media attention. As we think about the State’s gas needs in the 2030s, Browse is going to be an important part of solving what appears to be a growing supply-demand gap.

So we’ll continue to work with the government, both state and commonwealth on Browse to ensure that the state doesn’t end up in a similar situation as these East Coast states.

Sarah Kerr: Great. Thank you. And just staying on Browse. You have the Sunrise development concept to in the fourth quarter of this year. So I was just wondering how Woodside is thinking about and what takes priority over Browse versus Sunrise for possibly the next organic development in Australia?

Meg O’Neill: Look, I’d say that both of those developments have their challenges. So Browse, as you know, we’ve been working on environmental approvals for six years and continue to seek them. We’re not going to make any significant capital investments until we have confidence in those approvals. Sunrise has a lot of complexity, straddling the border of both Australia and Timor-Leste trying to get all of the governing documents negotiated has complexities and then getting to the point where we’ve got an investable project. We’ve got a bit of work to do. So no priority. There are two horses that want to get into the race, but they’re both in the training track right now.

Sarah Kerr: Great thank you so much and congratulations again.

Meg O’Neill: Thanks Sarah.

Operator: Thank you. Your next question comes from Matt Chalmers with Bank of America. Please go ahead.

Matt Chalmers: Thanks and good morning. Mig, just a quick question on Trion. Just with regards to Pemex and some of the world documented challenges that they’re facing. Just keen to get your thoughts in terms of how you’re thinking about how that may impact the overall development time line at Trion given the fact that they’re your major partner in the project?

Meg O’Neill: Sure. So we’ve, over the past few years, established a very constructive working relationship with Pemex. They have quite a bit of deep expertise having been the sole proponent of the Mexican oil and gas sector for many years. They do have financial challenges, and that’s part of why the Trion contract was structured with a carry. So we continue to carry Pemex for their share of investments through this calendar year. We’ve worked very closely with both Pemex and the government to ensure there’s clarity around Pemex’s needs to pay their fairway starting in 2025. And at this point in time, we’ve received all assurances from the government and Pemex that they will do so.

Matt Chalmers: Got it. Okay. And just one last question for my end. Just with regards to the lower production unit costs during the year I noted from relatively speaking compared to H1 ’23, those costs were elevated and understand that royalties were lower and duties have like given the lower LNG prices in this half. just can understand if there’s any further cost out that you managed to take out of those Australian operations that can speak to that cost discipline during the course of this year?

Graham Tiver: Yes. Thanks, Matt. A couple of things. The unit costs are really just focused on the production cost. So we’re not necessarily. We don’t include royalties, et cetera, but you’re right, royalties are lower. This is the raw production costs of producing our products. When you normalize across the two years — the 2.5 years, whether turnaround for interconnector, it doesn’t matter how you look at it, our costs for the first-half of ‘24 below those of FY ’23 for the first-half. And as Meg touched on, is there one particular point that stands out where we press the button and it all unfolded. No, it is hard work. It’s constant process and energy plugging away at the underlying cost base and just really strong alignment across our businesses and focus on cost scrutiny in the business.

Matt Chalmers: Got it. So there is actual costs out there. It’s not just because it’s coming off a higher base in H1 ’23, right?

Graham Tiver: Absolutely. The underlying costs have decreased across Woodside, obviously, ups and downs between operations. It depends what’s going on. But across the business, a very broad theme of strong cost improvement.

Matt Chalmers: Thanks Graham, appreciate it.

Operator: Thank you. Your next question comes from Rob Koh with Morgan Stanley. Please go ahead.

Rob Koh: Good morning. Morgan Stanley’s way of getting more than two questions in at a time, I guess. Just a question about your climate transition action plan, which you acknowledged you continue and reflect. Can you give us a sense of where the feedback came from? Were people looking for more ambition or less ambition or was the technical issues around offsets? And then as a subsidiary question, does the future made in Australia program helped with H2Perth?

Meg O’Neill: All right. Well, thanks, Rob. So look, this seems on the climate transition action plan, we’re probably thematically oriented towards wanting more rather than wanting less really a broad range of areas of interest from various investors though. Some wanted to see more detail and clarity on Scope 1 some expressed concerns around offsets, some themes around demand resilience for LNG and part of why we included the chart in this presentation showing coal demand is to make that point around the role for LNG and helping the world decarbonize. Some more questions around our ambition on new energy, which the OCI Clean Ammonia Acquisition, I think, addresses pretty elegantly. There are really a wide range of feedbacks. In terms of the future made in Australia, look, probably less of a connection to H2Perth.

But what I would say, Rob, is if we’re thinking about a future made in Australia, just as if we think about it today made in Australia, we need gas. If you look at how the manufacturing sector in Australia has grown over the decades, it’s been underpinned by access to reliable and affordable gas. So not just a future made in Australia, but it today made in Australia need natural gas.

Rob Koh: Okay. Great, thank you. And then maybe just a small flyer question. Any update on your thinking on exploration in Namibia?

Meg O’Neill: Nothing’s changed. So we still have our option to come as operator on one block there. We continue to look at the opportunity space there. Obviously, a lot of kind of interest across our industry with some of the other discoveries, but we’re going to be patient and disciplined as we are with all of our exploration opportunities.

Rob Koh: All right, you sounds good. Thank you so much.

Meg O’Neill: Thanks, Rob.

Operator: Thank you. There are no further questions at this time. I’ll now hand back to Ms. O’Neill for closing remarks.

Meg O’Neill: All right. Well, thanks everyone, for joining the call. I really appreciate your interest in Woodside and appreciate your support of the business. We look forward to engaging with you in future days to further discuss and share with you our strategy of how we’re delivering on our goal to thrive through the energy transition. Thank you.

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