Exhibit 99.1

 

Announcement   Wednesday, 20 August 2025		Woodside Energy Group Ltd. ACN 004 898 962 Mia Yellagonga 11 Mount Street Perth WA 6000 Australia T +61 8 9348 4000 www.woodside.com   ASX: WDS NYSE: WDS

HALF-YEAR 2025 RESULTS TELECONFERENCE TRANSCRIPT

Date: 19 August 2025

Time: 08:00 AWST/10:00 AEST (19:00 CDT on Monday, 18 August 2025)

Start of Transcript

Operator: Thank you for standing by, and welcome to the Woodside Energy Group Limited Half Year Results 2025 conference call.

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 keypads.

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

Meg O’Neill: Good morning and welcome to Woodside’s 2025 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 am joined on the call by our Chief Financial Officer, Graham Tiver. Together, we will provide an overview of our half-year 2025 performance before opening up to Q&A.

Please take the time to read the disclaimers, assumptions and other important information on slides 2 and 3.

I’d like to remind you that all dollar figures in today’s presentation are in US dollars unless otherwise indicated.

Moving to slide 4. I am very pleased to present a strong set of half-year results today. They demonstrate outstanding performance across our portfolio of world-class assets, efficient execution of our major growth projects, and continued strong returns for our shareholders.

During the first half, we have remained focused on delivering against all aspects of our strategy and investment case: providing energy, creating and returning value and conducting our business sustainably.

 

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We combined strong, safe and reliable operations over the half with reduced unit production costs, maximising value from our core assets.

We continued to demonstrate excellence in project delivery across multiple major projects including Scarborough and Trion.

In April, we approved a final investment decision on Louisiana LNG, positioning Woodside as a global LNG powerhouse. Louisiana LNG builds on our proven strengths in project execution, operational excellence and LNG marketing to meet growing global demand and create long-term shareholder value.

Our strong financial performance and disciplined capital management enables us to invest in future profitable growth while rewarding shareholders today, with a fully franked interim dividend of 53 US cents per share, once again at the top end of our payout range.

And we continue to conduct our business sustainably. We recorded no high consequence injuries or significant environmental impacts during the half and remain on track to achieve our net equity Scope 1 and 2 greenhouse gas emissions reduction targets.

Our key operational and financial outcomes on slide 5 highlight the strong performance of our base business.

Exceptional performance at Sangomar contributed to an outstanding half-year production of 548 thousand barrels oil equivalent per day and total production of 99.2 million barrels of oil equivalent.

Increased production was matched by increased efficiency across our operating business, as we reduced unit production costs by a further seven percent.

We are generating value from our marketing and trading business. At half-year, marketing and trading activities delivered a strong contribution of $144 million, representing approximately eight percent of total EBIT.

We reported a net profit after tax of more than $1.3 billion. Our balance sheet remains well positioned through this period of higher capital investment, and we continue to maintain a strong liquidity position with gearing within our targeted range. As a result, we remain well positioned to progress our growth projects while continuing to deliver strong shareholder distributions.

Keeping our people safe remains at the forefront of everything we do at Woodside.

As the graph on slide 6 outlines, it’s very pleasing that during a time of heightened activity levels, we did not record any high consequence injuries.

We also marked significant safety milestones across our global portfolio. We achieved 100,000 hours worked across two major turnarounds at our North West Shelf Project in Western Australia with no lost-time injuries. Safety was also front and centre of our exceptional performance at Sangomar, with no recordable injuries during the project’s first year of operations.

These examples demonstrate our continuous commitment to safety and establish the required standards for Woodside.

We continue to be proactive and focused on continuous improvement. This has included the deployment of AI-driven analytics to improve our investigations and learning efficiency.

To slide 8. The first half of the year has once again showcased Woodside’s world-class operational capabilities, with consistent high reliability and disciplined cost control across our global portfolio.

 

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Outstanding half-year production has allowed us to narrow our full-year guidance to the upper end of the range, even with the impact of the divestment of the Greater Angostura assets.

As highlighted on the graph, high reliability of our operated assets combined with an unrelenting focus on cost control has seen unit production costs further reduced to $7.70 per barrel of oil equivalent.

Our teams continue to keep a sharp focus on costs across the business, including new ways of using technology including AI to deliver safety, cost and efficiency improvements, such as speeding up root cause analysis during plant trips. We are also finding new avenues to reduce our corporate costs, such as our planned establishment of a Digital Solutions Centre in India.

Since the Minister announced his proposed approval of the North West Shelf Extension in May, we have been working with the Government to secure a final approval that supports continued and long-term operations and is consistent with the Government’s Future Gas Strategy.

The WA government’s approval, which was under rigorous assessment for more than six years, includes conditions that are based on the best available science and are also technically feasible. We are seeking the same objectives in our consultation with the Federal government.

It’s frustrating that we still don’t have the final Federal approval. Approval timeframes are certainly something that needs to be considered when we are thinking about how to lift productivity in Australia.

We know that the Federal Government understands how important the North West Shelf Extension is for our communities, customers, and our workforce and therefore the nation.

We look forward to a positive final outcome in the very near future.

A real highlight during the period was the ongoing exceptional performance of Sangomar.

As highlighted on slide 9, in the first half alone, Sangomar has generated revenue of almost $1 billion.

Fourteen months after achieving first oil, the project has maintained gross production at nameplate capacity of 100,000 barrels per day with almost 99 percent reliability.

Future development decisions will be informed by the first 12 to 24 months of production data, and the performance of Sangomar’s subsurface and wells continues to be very encouraging.

A potential Sangomar Phase 2 development could leverage the existing FPSO infrastructure, ensuring a more efficient, lower-cost brownfield expansion.

To slide 10. In Australia, our agreement announced in July with ExxonMobil to assume operatorship of the Bass Strait assets strengthens our Australian operations and unlocks the potential development of additional gas resources. This transaction is expected to complete next year.

This strategic move combines Woodside’s existing global operational capabilities with Exxon’s highly experienced Bass Strait workforce, further strengthening our overall operating expertise.

By taking operatorship of a larger group of assets in Australia, we will create economies of scale that are expected to drive cost efficiencies and synergies across our operations.

The agreement also creates flexibility for future development opportunities through existing infrastructure. With four potential development wells that could deliver up to 200 petajoules of sales gas to the domestic market,

 

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it also demonstrates our long-standing commitment to supplying reliable and affordable energy to Australian customers.

Let’s now take a moment to review the global energy landscape, and the pivotal role LNG will play in meeting this future demand.

As the world’s population grows and living standards improve, energy use is also increasing. As the graph on slide 11 shows, since 2020, primary energy consumption per capita has grown 14 percent in non-OECD Asia Pacific countries.

At the same time, even with this growth, a major demand gap exists between these nations and OECD APAC and the USA, indicating significant additional demand growth is likely as nations seek economic growth and improved quality of life.

The challenges for these countries remains to secure reliable and affordable supply, while at the same time reducing emissions and improving air quality.

Natural gas and LNG are flexible energy sources, supporting baseload power, industrial use and grid reliability. LNG contributes towards our customer countries’ energy security through diversification and as a versatile, tradable energy source.

With Scarborough and Louisiana LNG in the pipeline, Woodside is well positioned to meet growing LNG demand, which is expected to rise by approximately 60 percent by 2040 – delivering competitive, reliable energy into key markets.

On to slide 12. Underpinned by this robust, long-term demand for our products, we are positioning Woodside to maximise value through our global marketing and trading business.

We are capturing value from our diverse portfolio of high-quality assets, established marketing and trading capabilities, and strong shipping position.

Our portfolio provides volume and contractual flexibility, allowing us to adapt to our customers’ requirements and changing market conditions.

Our gas hub exposure on produced LNG was 24.2%, which realised a premium of approximately 3% per MMBtu [Clarification: $3 per MMBtu] compared to oil-linked sales, demonstrating the value of price diversity in volatile markets.

Sale and purchase agreements signed during the half with Uniper and China Resources will see Woodside’s LNG delivered to customers in Europe and Asia into the 2040s, demonstrating the robust long-term demand for LNG.

Moving to our major projects, we have made excellent progress with our Scarborough Energy Project, which is 86 percent complete and targeting first LNG cargo in the second half of 2026.

The image on slide 13 showcases a significant milestone reached in May, as we successfully connected the floating production unit hull and topsides. Integration activities are underway as we prepare for sailaway from China to Australia.

In readiness for the arrival of the FPU and subsequent hook up, subsea installation, testing and pre-commissioning works were completed subsequent to the period.

 

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Our development drilling campaign is also proceeding to schedule, with four of the eight wells now having drilled the reservoir section, confirming excellent reservoir properties. Three of these wells have already been completed.

Moving to Trion on slide 14, we are on track for targeted first oil in 2028.

During the half we advanced the construction of the floating production unit, completing key activities including equipment fabrication and the construction of three modules and living quarters.

Preparations are progressing for the construction of the floating storage and offloading vessel scheduled for the second half of 2025, and we are ready for major subsea work scopes to commence next year.

As I mentioned earlier, Louisiana LNG is a game-changer for Woodside, set to transform our company into a global LNG powerhouse and deliver enduring shareholder value for decades to come.

On Slide 15, you will see that since the completion.

Operator: Ladies and gentlemen, it seems that we may have a technical issue with the main speaker line. Please stay on the line while we try to reconnect. Thank you.

Everyone, we are reconnecting the speaker line. Please, proceed.

Meg O’Neill: All right. I’m not sure what happened there, but I’ll start with Louisiana LNG because it’s not entirely clear where we cut out.

As I mentioned earlier, Louisiana LNG is a game-changer for Woodside, set to transform our company into a global LNG powerhouse and deliver enduring value to shareholders for decades to come.

On slide 15, you will see that since the completion of the acquisition in October last year, we have secured highly competitive EPC pricing for all three trains, selected a high-quality infrastructure partner to share the capital expenditure, secured long-term offtake agreements with Uniper, and signed a long-term gas supply agreement for feedgas.

Following FID in April, we have maintained strong momentum on the project as we target first LNG in 2029. As outlined on slide 15, construction of Train 1 is 22 percent complete and we are targeting first structural steel on site by the end of this year.

In June, we completed a 40 percent sell-down in Louisiana LNG Infrastructure to Stonepeak. This will see Stonepeak contribute $5.7 billion towards the expected capital expenditure including contributing 75% of capital expenditure over both 2025 and 2026. This strengthens our balance sheet and our ability to fund our growth projects and provide shareholder returns.

We continue to receive strong interest from high-quality potential partners as we explore further sell-downs.

To slide 16. There are several strengths to the traditional US LNG model, including abundant low-cost feedgas and access to Asian and European markets.

Louisiana LNG builds on these strengths. The project itself is extremely competitive, with a fully permitted site and an LNG project cost of around $960 per tonne, and the sell-down to Stonepeak reduces our capital exposure.

 

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Woodside’s strong balance sheet and investment grade credit rating means we don’t require project financing. This allows us to take full advantage of the international market prices for LNG and not be reliant on low-margin 20-year offtake agreements. We will continue to secure LNG sales agreements over the coming years as we advance towards first LNG.

In addition, Louisiana LNG volumes will also be added into Woodside’s global LNG marketing portfolio, which further enhances value through shipping, trading and broader portfolio optimisation.

As we evaluate the strong market interest in Louisiana LNG HoldCo equity, our priority is to secure long-term strategic alignment and bring in partners who can contribute complementary capabilities to enhance the value of the project.

A good analogy is our sell-down of equity interests in Scarborough to JERA and LNG Japan. This helped to share the investment with partners, secured offtake, and opened up further opportunities such as exploring lower-carbon solutions. We are not driven by timing or short-term considerations and are undertaking a deliberate and disciplined approach in the selection of partners.

Moving to Beaumont New Ammonia on slide 17. At the end of the first half Train 1 was 95 percent complete, with first ammonia production targeted for late 2025.

Over the period, we successfully completed key activities and have commenced pre-commissioning activities in preparation for start-up.

We also focused our marketing efforts to support offtake. We plan to market our early ammonia production in the US and Europe, with existing spot markets providing us with flexibility to place our initial production volumes.

Aligned with market forecasts, we expect opportunities beyond 2026 to place lower-carbon ammonia into Europe as customer demand increases, following the introduction of policies in key energy markets such as the carbon border adjustment mechanism.

To slide 18. During the first half we continued to execute multiple, complex decommissioning campaigns, including successfully completing a multi-year decommissioning program at Enfield. This is an asset that Woodside has taken from exploration, through development and operations, to decommissioning.

Removal of equipment at the legacy Griffin, Minerva and Stybarrow assets has been impacted by unexpected challenges resulting in cost impacts over 2025 and the next few years.

We are focused on reducing risk across our decommissioning operations and continue to integrate learnings and improvements while remaining focused on safety, the environment and efficiency.

With the decommissioning works safely ongoing at the Gippsland Basin Joint Venture, including the permanent plugging and abandonment of more than 200 wells, we do not expect to encounter similar challenges with future decommissioning of the Bass Strait assets.

I’ll now hand over to Graham to provide an overview of our financial strategy and performance.

Graham Tiver: Thanks Meg and hello everyone.

I’m pleased to present a strong set of financial results on. [Clarification – due to technical difficulties the following audio was not heard by teleconference participants: “slide 20 that demonstrate the resilience of our

 

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business, the value of our high-quality portfolio, the health of the balance sheet and the disciplined execution of our strategy. Our base business continues to perform, with operating cash flow for the half increasing by 40 percent year-on-year. This growth highlights the strength of our world-class core assets and ongoing focus on cost discipline.”]

It’s worth calling out Sangomar’s cash contribution of approximately $800 million.

Our EBITDA margin of 70 percent remains peer-leading, an outstanding result given lower realised prices and ongoing inflationary pressures.

This reliable and cost-competitive performance has translated into half-year earnings of 69 US cents per share. Coupled with our consistent approach to capital management, this provides our balance sheet the resilience and flexibility to continue delivering strong returns for shareholders while funding value accretive growth.

Moving to slide 21. We continue to deliver our business in line with our capital management framework, which remains unchanged.

We operate with discipline and focus. We continue to exercise strong cost control across our business, once again achieving a measurable reduction in unit production costs.

The same discipline is applied when making investment decisions, adhering strictly to our capital allocation framework and ensuring alignment to our strategic goals. And we are disciplined in how we position the balance sheet to achieve these goals.

Levers such as the sell-down of a 40 percent interest in Louisiana LNG Infrastructure to Stonepeak assists in strengthening our balance sheet metrics, while also bringing a quality partner into the project.

Operator: Everyone, once again we seem to be having technical difficulty with the main speaker line. One moment while we try to reconnect the line.

Thank you for standing by everyone. We have reconnected the speaker line. You may proceed.

Graham Tiver: Hi, it’s Graham Tiver joining again. I do apologise for the technical difficulties. What I’ll do is I’ll start from slide 21, the capital management framework slide.

We continue to deliver our business in line with our capital management framework, which remains unchanged.

We operate with discipline and focus. We continue to exercise strong cost control across our business, once again achieving a measurable reduction in unit production costs.

The same discipline is applied when making investment decisions, adhering strictly to our capital allocation framework and ensuring alignment to our strategic goals. And we are disciplined in how we position the balance sheet to achieve these goals.

Levers such as the sell-down of a 40 percent interest in Louisiana LNG Infrastructure to Stonepeak assists in strengthening our balance sheet metrics, while also bringing a quality partner into the project.

As Meg mentioned, Stonepeak will provide $5.7 billion towards the expected capital expenditure of Louisiana LNG, and importantly on an accelerated basis, will contribute 75% of expected project capital expenditure in both 2025 and 2026. This innovative approach has improved our liquidity and keeps our gearing within the target range.

 

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The capital management framework underpins a healthy balance sheet, allowing us to invest in our future while providing strong returns to our shareholders.

When referring to returns, our dividend policy is to pay a minimum of 50 percent of underlying NPAT. We target paying between 50 and 80 percent, and for more than a decade we have consistently paid at the top end of this range.

As highlighted on slide 22, we have achieved this once again with a healthy interim dividend of 53 US cents per share fully franked, representing a half-year annualised yield of 6.9 per cent.

We have taken important steps to maintain the balance sheet strength and pay a dividend at the top of the range. This starts with strong underlying performance of our assets, supported by Sangomar coming on line, exceeding our expectations. Secondly, strong financial discipline and investment grade credit rating. And finally, portfolio optimisation from the Stonepeak transaction and Greater Angostura divestment, as well as a focus on opex and capex including minimising discretionary spend.

Our balance sheet remains well positioned, with a portfolio of high-quality producing assets and transformative growth projects.

We are actively managing our debt portfolio, we have minimal debt maturities over the next 12 months, and as you can see on slide 23, our liquidity remains strong. The strong cash generating capacity of our assets combined with the issuance of $3.5 billion in senior unsecured bonds in the US market, which attracted significant oversubscription, has led to a liquidity position of $8.4 billion.

We remain committed to maintaining an investment grade credit rating. It enables efficient access to global debt markets on competitive terms and represents an independent assessment of the financial strength of our business.

Strong operating cash flow and disciplined capital allocation results in a strong balance sheet. At the half-year, our gearing remains within our range of 10 to 20 percent, and we have $8.4 billion in liquidity.

I’ll now hand back to Meg.

Meg O’Neill: Thanks Graham.

Conducting our business sustainably is one of the goals underpinning our strategy to thrive through the energy transition.

As shown on slide 25, our company-wide sustainability strategy sets clear objectives and focus areas to track our performance across four material areas: health, safety and wellbeing; climate; First Nations cultural heritage and engagement; and environment and biodiversity.

Beyond our safety performance which I outlined earlier; we have made positive progress across all these areas.

We progressed the implementation of our asset decarbonisation plans and remain on track to achieve our net equity Scope 1 and 2 greenhouse gas emissions reduction targets.

Engagement with Traditional Owner representatives remains central to our Australian activities. This included the completion of a planned annual cultural heritage audit of the North West Shelf Project leases in collaboration with Traditional Owners.

 

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And we continue to invest in major environmental scientific research partnerships, including a five-year extension to our long-standing marine research collaboration with the University of Western Australia [Clarification: WA Museum and Foundation for the WA Museum] announced earlier this month.

Moving to slide 26. Woodside continues to make significant economic and social contributions to the communities where we operate.

We remain one of Australia’s top tax contributors. Our total taxes, royalties and levies paid during the half to Australian governments was $1.3 billion Australian dollars, demonstrating an ongoing and significant contribution to the nation’s economic prosperity.

We continue to make major investments that drive local content and capability. Our Scarborough Energy Project is estimated to spend more than $5.4 billion Australian dollars across Western Australia through its development phase, while our Louisiana LNG Project is expected to generate approximately 40,000 nationwide jobs during construction.

On to slide 28. I’d like to close by re-capping on our achievements to date for 2025 and the compelling investment case before our shareholders.

Above all, the first half of 2025 for Woodside has been about delivery.

Delivering strong and consistent returns to our shareholders.

Delivering outstanding production from our world-class assets, matched by increased efficiency and cost control.

Delivering our major growth projects, including a final investment decision on Louisiana LNG that positions Woodside to meet growing global demand and unlock long-term shareholder value.

We remain on track to deliver our net equity Scope 1 and 2 greenhouse gas emissions reduction targets. And above all we are committed to safety.

Our achievements in the first half demonstrate delivery of our strategic goals and give us great confidence that Woodside will thrive through the energy transition, as we continue to play a critical role in delivering reliable, affordable and lower-carbon energy the world needs today and into the future.

Thank you.

I’ll now open the call to questions. I know we’ve had some technical issues, so I’d like you to please limit your questions to two each to ensure everybody has an opportunity to ask their questions.

Operator: Thank you. If you wish to ask a question, please press star and one on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star and two. If you are on a speakerphone, we do ask that you please pick up the handset to ask your question. Your first question comes from Gordon Ramsay from RBC Capital Markets. Please go ahead with your question.

Gordon Ramsay (RBC, Analyst): Congratulations, Meg and team, on a great result, really encouraged with what we’re seeing. I just want to pick up on Sangomar. Obviously, you’ve delivered exceptional operating performance with that field and reservoirs performed very, very well. The phase 1 production is based largely on the S500 sand development. You made a comment today that phase 2 could leverage off existing infrastructure. Are you able to provide an update on the performance of the injector-producer pairs in the S400

 

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sand units and when Woodside might possibly be in a position to advance what appears to be encouraging initial results from those wells?

Meg O’Neill: Yes, thanks Gordon and we appreciate your ongoing interest in Sangomar. As you would have seen in the announcements, we made a reserve add based on the S400 performance early in the period. That was about 7.1 million barrels to proved and 16 million barrels to P plus P [Clarification: 16.1 million barrels to proved plus probable (2P) reserves, Woodside share], so some initial positive signs in the S400s. The second reserve add that we made subsequent to the period that’s noted in the report of 18.4 million barrels is associated with the S500. So that main portion of the development continues to perform very well.

We continue to gather data. So we believe that we’ll need, call it 12 to 24 months of production data to inform decisions around phase 2, but conceptually, as I mentioned in the call, the intention would be to leverage the existing FPSO and to continue to tie back subsea wells to the infrastructure. As you can well appreciate, that’s a very capital-efficient way of continuing to develop the asset. So yes, we’ll keep you posted as we start moving those opportunities through the gate process.

Gordon Ramsay (RBC, Analyst): Thank you. Just one other question from me, just on unit production costs, you brought that guidance down to $8 to $8.50 a barrel oil equivalent. Again, can you just run through how you’ve been able to do that? Obviously Sangomar has performed very well, but also are there other aspects to the cost reduction that we should be aware of?

Meg O’Neill: Sure. So Sangomar has been really a star with really strong production and if you look at the unit production cost for Sangomar itself, it’s very competitive and has helped bring down our average. We also have been working across the business to bring costs down. In the first half there were some one-off cost reductions in the US and then there’s an activity set that will take our full year UPC into that guidance range of 8.00 to 8.50 above where we are for the first half, which is the 7.70.

Gordon Ramsay (RBC, Analyst): Thank you.

Operator: And your next question comes from Tom Allen from UBS. Please go ahead with your question.

Tom Allen (UBS, Analyst): Good morning, Meg, Graham and the broader team. Maybe just over starting with Louisiana LNG. So just noting that we’ve been through a few updates where negotiations on equity sell down have been ongoing. Wondering, Meg, if you could please provide some colour on what or if anything has changed relative to Woodside’s expectations on sell downs that we discussed at the Feb result? Is Woodside and prospective partners seeing stronger than anticipated competition from competing projects, or is it the subtle differences in the EPC arrangements across projects? Woodside obviously have a fully wrapped EPC with Bechtel, or is it the political environment adding complexity and timing risk to the negotiations for project equity?

Meg O’Neill: Well, thanks for the question, Tom. So with Louisiana LNG, as we said in the call and have said all along, we think this is an advantaged project and you just look at the numbers, you look at our construction costs, the UPC—sorry, the dollars per tonne construction cost. Very competitive, and you would have seen numbers released from others in this space that would suggest that there’s inflationary pressures affecting costs that are getting locked in subsequent to the Louisiana LNG project.

We’re being disciplined. The key focus for us is getting the right partner in and getting a fair value for Woodside shareholders. So it’s really similar to what we did with Scarborough and Pluto Train 2, where we brought in an

 

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infrastructure investor early into the part of the project where the investment and the returns met their expectations and we’re being now very disciplined in who we want to bring into the HoldCo. As I think I said—I probably would have said in a previous call, once we took FID, that really opened the door to companies to come back into the process.

So we’d been running a very fast process and some companies said, we’re interested but we can’t meet your timeline. Now that we’re post-FID and we’re proceeding into the execute phase, that’s allowed some players who need a little bit more time to come to the table. So again, we’re being disciplined and we’ll bring quality partners in at value that’s attractive to our shareholders.

Tom Allen (UBS, Analyst): Okay, thanks Meg. Second question, just over at Beaumont Ammonia please. There’s just a little slip in the schedule for first production out of Beaumont to later in the year. Are you able to share just some colour on what happened there? I think Woodside previously guided plans to sell down the project and enter into offtake. That’s obviously still ahead. Can we assume that that’s well advanced with partners and offtake and that will promptly come through over the quarter ahead of first production?

Meg O’Neill: Yeah, so I don’t recall us guiding to sell down. We have no process underway to sell down Beaumont. Our focus very much is on getting – working with OCI to complete construction and just to remind you and the other callers, the obligation to complete construction and to deliver an operational plant to very clear performance standards is OCIs. So the delay in schedule is due to some delays in construction, but again, that’s not a scope that Woodside is managing and there is no cost impact to us other than the delay of the second payment, the completion payment.

As we signalled, I think in the second quarter, that completion payment is going to likely be made in 2026 and not this year. So that was communicated in the 2Q. So we are working on the marketing. That’s a really critical focus area for us is ensuring that we’ve got buyers ready to purchase the ammonia when we start up later in the year. The second phase, of course, is starting up the low carbon ammonia production, which will be in the second half of 2026, and that’s when we’ll be able to market the products. We are marketing the product already to try to attract those premium pricing associated with the lower carbon intensity of the blue ammonia that we’ll be producing then.

Tom Allen (UBS, Analyst): Thank you, Meg.

Meg O’Neill: Thanks Tom.

Operator: And your next question comes from Adam Martin from E&P. Please go ahead.

Adam Martin (E&P, Analyst): Yeah. Morning, Meg, Graham and team, I suppose firstly just on the Bass Strait, could you walk through those potential four development opportunities? What needs to happen to get those into FID please?

Meg O’Neill: Yeah, thanks Adam and really appreciate the interest in the Bass Strait operatorship transition. We were very excited to be able to conclude that negotiation with ExxonMobil, particularly with the ability for us to solely develop some of these opportunities. These are gas discoveries that were made many, many years ago. They’ve been in the contingent resource for a period. Our teams have been doing scoping work for, well a number of months to understand what the potential is. So we need to work through our normal technical due diligence, but we do have the ability to take a final investment decision. That would not happen until the operatorship transition has completed.

 

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Adam Martin (E&P, Analyst): Okay, thank you. Just a second question. Obviously you’ve got the 443 million restoration movements. I think that relates to CapEx going up a little bit from previous expectations. Can you just talk through timing of that future spend and I suppose why that’s not a risk for other programs like the Bass Strait moving forward, please?

Meg O’Neill: Yep. So one of the challenges we have faced with the decommissioning work this year has been the condition of some of the closed sites. So these are fields like Stybarrow, Minerva, and Griffin that have not produced oil and gas for many years and the condition of the equipment as we found it when we got into the field was not as it was documented. So that’s resulted in a number of challenges in recovery. I am very pleased to say that we have plugged all of the wells. So when you think about environmental risk, that is where it is highest. So I’m very pleased that we have completed that scope of work.

We’ve had to take a bit of a step back, recognising some of the challenges we’ve encountered. We’re back to doing some more engineering work to understand how do we manage the safety and environmental risks that we’ve found. The additional spend will happen over the coming years. When we have more information, we can put further information out there to the market, but we’re going to take our time. As you would have seen, NOPSEMA’s revised the general directions associated with these legacy assets, giving us more time to ensure we have good engineering work plans and we are managing the construction and the safety and environmental risk appropriately.

When it comes to Bass Strait, so one of the advantages we’ve seen and we’ve seen at Enfield is probably another good example, when you do the decommissioning work, shortly after completing production, you’re able to execute it much more efficiently. Bass Strait, as we noted in the report, have plugged and abandoned more than 200 wells and the platform removal campaign is deep in the engineering phase. We’ve been going through all of the normal engineering and project gating processes to ensure that we have our arms around the cost. That’s the scope, and I think we’ve indicated this before, the bulk of the scope will happen in 2027. So we’re working very closely with ExxonMobil, but as we’ve been advancing that project, everything is remaining on track from a cost perspective.

Adam Martin (E&P, Analyst): Okay. No, that’s great. That’s it. Thank you.

Operator: And your next question comes from Saul Kavonic from MST. Please go ahead.

Saul Kavonic (MST Financial, Analyst): Hi Meg. Possible to just get the latest update on the MOU with Aramco. Are those discussions still proceeding in line with your expectations and could you elaborate just a bit of elaboration on what it means by collaboration on ammonia and how that might relate to Beaumont?

Meg O’Neill: Sure. So not a lot to update on Saul. We were very pleased to be invited by Aramco to participate in the US-Saudi Investment Forum back in May and very pleased to execute the MOU with them, looking at US investment opportunities in both LNG and low carbon ammonia. Look, we continue to build a very strong and constructive relationship with Aramco and when we have something announceable, we will announce.

Saul Kavonic (MST Financial, Analyst): Thank you. That’s all for me.

Meg O’Neill: Thanks Saul.

Operator: And your next question comes from Nik Burns from Jarden Australia. Please go ahead with your question.

 

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Nik Burns (Jarden Australia, Analyst): Thanks Meg and team, just first question, maybe just on the dividend paying out again at the top end of your payout range. The gearing at 30 June is at the top end of the gearing target range as well, and the dividend probably could push you over the top end of that. Maybe, can you talk about the factors that led you to be comfortable with retaining an 80% payout ratio for the interim result and whether being at the upper end places any risk of having to pay out below the upper end over the next few periods? Thank you.

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

Graham Tiver: Thanks Nik. Yeah, as you know through our capital management framework, we’re not just looking at a point in time. We’re looking through into the future as well. We are really comfortable and happy where the business is today. It’s performing well and the balance sheet is in a strong position. I guess I’d call out that the strong underlying performance of the business continues to shine through, generating very strong operational cash flows. The strong financial discipline around our cost and CapEx control.

We’ve got the investment grade credit rating and I guess we’ve been able to optimise our portfolio during the period as well. So with Stonepeak coming in, as I said in my speech, quite an innovative approach with the funding in that 75% upfront in the 2025 and ‘26 and then the Angostura sell down as well. So you bring all that together and the business is in good shape and we are confident with our forward view on being able to continue to generate strong cashflow, invest in our growth projects, our immediate future, and also provide strong returns to our shareholders.

Nik Burns (Jarden Australia, Analyst): Got it. Thanks for that, Graham. Just a question on marketing. Meg, you called out the strong returns being driven by the marketing team, circa 8% of Group EBIT in the first half. I was interested in the fact that you retained your gas hub exposure guidance of 28% to 35% for the full year. I think on my numbers, you averaged around 24% in the first half. Can you talk a bit about the current state of the global spot LNG market, and looking ahead, what’s going to drive a material increase in your sales into the spot market in the second half of the year? Thank you.

Meg O’Neill: Thanks Nik. It’s a great question and I think the results really validate our strategy to preserve a certain amount of our LNG to sell at gas hub exposure. So when we look at the difference in pricing between oil indexed LNG sales versus gas hub indexed LNG sales, it’s a $3 premium. So a very significant uplift associated with the way we have our pricing exposure managed. As you’ll note, and as you’ve caught on, our guidance for the full year is higher than what we’ve delivered in the first half. So obviously our performance in the second half will be above where we are today.

When you look at what’s happening in the market with softening in Brents, but continued strength in the LNG pricing, that bodes well and that continues to reinforce the value of our strategy. Now when we look further down the road, I think we’ve been pretty clear that our target in the next couple of years is to retain that exposure of, call it circa 30% gas hub indexation and as we start up Louisiana LNG, we’ll continue to be refining our intentions around price indexation and the exposures.

One of the things that’s very clear, the fundamentals for the 2030s are very robust when you look at things like Asian demands, underpinned by economic growth, declining domestic supply in many Asian nations that have historically been strong gas producers. So if you reference Wood Mac for example, they’re expecting more than 100 million tonnes of new pre–FID LNG supply will be required by 2040. So we’re very bullish in the long term, but we’ll continue to be refining our price index exposure over time. We’ve got a fair amount of opportunity

 

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and flexibility with the Louisiana LNG offtake and we’ll be looking to balance that in a way that best works for our shareholders.

Nik Burns (Jarden Australia, Analyst): That’s great. Thanks Meg.

Operator: And your next question comes from Dale Koenders from Barrenjoey. Please go ahead with your question.

Dale Koenders (Barrenjoey, Analyst): Good morning, Meg and Graham. This question might be more for Graham. In the second quarter report you reported CapEx and exploration of $2.5 billion year to date, including net contributions from Louisiana, which benefit from the 1.8 Stonepeak contribution. Gets us to $4.3 billion. On your cashflow statement, you reported $4.9 billion spend on CapEx and exploration. I’m just wondering what the $600 million difference is.

Graham Tiver: Sorry, I’m just looking at – yeah, so what you’ve got here is the cashflow view and that number will also include borrowing. You capitalise borrowing costs as well. Whereas what we report to the market is just a pure view of CapEx expenditure and that’s the major component or the major differentiating factor between what we were reporting to the market and the actual underlying cashflow version or view. [Clarification: Capitalised borrowing costs are not a driver of the variance. Refer to page 18 for a reconciliation.]

Dale Koenders (Barrenjoey, Analyst): So the $330 million line item that was then called out on your cashflow statement, what is that? Is that borrowing costs as well, or…

Graham Tiver: The 300 – sorry.

Dale Koenders (Barrenjoey, Analyst): Sorry, go.

Graham Tiver: What I suggest is maybe the team can take it offline and have a conversation with you, but that’s the major difference.

Dale Koenders (Barrenjoey, Analyst): Okay. Then just secondly, in terms of cash tax payments, they’re a little bit higher than expensed. I’m just wondering on a go forward basis how you think that delta will play out?

Graham Tiver: Yeah, so as you know, cash tax payments, there’s many different factors that play into the cash tax. Obviously this year we have had lower prices across the Australian business. That’s also flowing in. You’ve got the PRRT. I guess all we can do is continue to provide as much guidance as possible on that but it’s very difficult to sit here and say exactly what that tax number will be because there’s many factors that play into it, Dale.

Dale Koenders (Barrenjoey, Analyst): Okay, thanks Graham.

Operator: And your next question comes from Henry Meyer from Goldman Sachs. Please go ahead.

Henry Meyer (Goldman Sachs, Analyst): Morning team. Just on the LNG carrier position, could you give any update on plans to lease or own carriers to support the Louisiana delivered cargoes? And in light of gearing and the balance sheet, just what lease liabilities do you expect to carry when they’re delivered, perhaps related to the Scarborough carriers on order?

Meg O’Neill: Sure. So philosophically, Henry, we think there are other companies that are well equipped and well suited to own LNG carriers. When we started up North West Shelf, there were some project owned vessels, but we’ve moved away from that and that’s probably the industry standard to use leased vessels. The

 

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number of vessels, the balance sheet exposure is something that we’re working through as we speak, so too early to advise, but as we progress that work and progress those contracts, we will certainly keep the market updated.

Henry Meyer (Goldman Sachs, Analyst): Okay, thanks Meg. Following up on the decommissioning costs for Griffin, Minerva and Stybarrow, I just wanted to double check one of the comments before. Have some of those challenges encountered been reflected in estimates for other fields, or is there work underway to revise those costs as well?

Meg O’Neill: So we always, as we update our decommissioning estimates, which is typically an annual process, we incorporate things that we’ve learned as we’ve gone through the process. One of the positives that I would say we’ve taken from dealing with these closed sites is we’re feeding that back into our decommissioning planning for sites that are still operational today. So for example, in our Australia business, some of the FPSOs will be coming offline in the 2030s. We’re feeding the lessons learned from these closed sites into those so that we can be more proactive and avoid the sorts of challenges that we’ve encountered here.

Perhaps the point of success is Enfield. So Enfield is a field that Woodside operated. It stopped operations in 2018. We’ve had none of those issues when we decommissioned the Enfield subsea equipment that we’ve seen with Griffin and Minerva and Stybarrow.

Henry Meyer (Goldman Sachs, Analyst): Okay. Thank you Meg.

Meg O’Neill: Thanks Henry.

Operator: And your next question comes from Mark Wiseman from Macquarie. Please go ahead with your question.

Mark Wiseman (Macquarie, Analyst): G’day Meg, Graham. Thanks for the update today. I wanted to ask, firstly, on the Bass Strait operatorship decision. Could we talk about what the alternative would have been to this? It sounds like ESSO was waiting for policy stability from the government and perhaps has come to the conclusion that they wouldn’t invest in those four development opportunities, the 200 PJs, and so the alternative would have been to remain non operator and not see any of that contingent resource come to fruition. Is that right? I wonder, you made a comment there, Meg, around the workforce. It sounded like you see some benefit in bringing those ESSO experienced staff into your team. Could you perhaps elaborate on that as well, please?

Meg O’Neill: Yes, certainly the alternative, Mark, would have been for ExxonMobil to continue operating. As I said, those four fields [Clarification: Four potential development wells] that we’ve identified and have the rights to exclusively develop are discoveries that have been on the books and the joint venture has known about for a very long time period. So, I suspect, although I can’t guarantee, that those likely would not have matured had we stayed with the existing operation.

On the people side, yes, we’re super excited. There’s a lot of talent and capability within the ExxonMobil workforce in Australia. Our head of operations in Australia came out of that workforce. We know the people, and I’ve been really pleased with the positive response we’ve seen from the ExxonMobil folks who I think see potentially a little bit longer horizon to be able to live and work in Australia with Woodside as operator,

 

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recognising we’ve got a little bit bigger footprint and recognising our desire to continue to be a significant player in the East Coast gas market.

Mark Wiseman (Macquarie, Analyst): Thank you. Finally from me, just on Santos. Obviously, Woodside and Santos had been in discussions a while back. Those discussions came to a conclusion. Since then, there’s obviously been a non-binding offer for Santos. Did that offer from XRG Carlyle cause you to review the merits of a merger with Santos? Could you perhaps just comment on what was the appeal back then and would you still see those sorts of benefits from re-engaging with Santos? Thank you.

Meg O’Neill: Short answer, Mark, is absolutely not. The thing that we—the reason that we had been exploring opportunities with Santos was the LNG portfolio, and we’ve moved on. We’ve acquired Tellurian, we’ve got the Louisiana LNG investment going. When you look at the upside opportunity that’s created by having a material Atlantic Basin position coupled with our material Pacific Basin position, that’s actually a better portfolio than combining the two Pacific-oriented businesses. So, we wish them well, but we’re focused on delivering our commitments.

Mark Wiseman (Macquarie, Analyst): That’s super clear. Thank you.

Operator: Your next question comes from Rob Koh from MS. Please go ahead with your question.

Rob Koh (Morgan Stanley, Analyst): Good morning. My first question is on balance sheet management. You’ve got sell-down possibilities for Louisiana HoldCo, you’ve got your Chevron asset swap coming and lots of other things in train, I’m sure. Could you comment on the possibility to do any further executory contract-type deals, like the Stonepeak deal, on any of the other assets? Is that something we could contemplate?

Meg O’Neill: Look, Rob, that kind of model was something that we’ve looked at a few times. We looked at it actually before we took FID on Pluto Train 2 and Scarborough, because it is one way to unlock capital. But given the joint venture structures of some of our existing assets, it’s more complicated, so we’re very much focused on the HoldCo sell-down at Louisiana LNG, and again, it’s about getting the right partner at the right price, and then executing the transactions that we’ve announced. So, the Chevron asset swap, as well as the operatorship transition in Bass Strait.

Rob Koh (Morgan Stanley, Analyst): Okay, thank you. My second question relates to the restoration rehabilitation provisions. Part A of the question is, can you give us a steer on any kind of contingency should the pipelines need to be taken out? Because I think the provision is made on a pipeline in situ basis. Then, secondly, I saw that Chevron has a very old legacy deal for Barrow Island where decommissioning is offset against royalty refunds. I’m just wondering, does Woodside have anything similar like that on the books and within the provision?

Meg O’Neill: When it comes to the provisions, we take a risked approach to certain pieces of equipment that we think there’s a good environmental reason to arguably leave in situ, so things like jacket structures and pipelines. Within the restoration provision, there’s a risking that reflects a certain percentage chance that those items may have to be removed.

We are doing quite a bit of science, both in the Bass Strait with ExxonMobil as well as in our operations, to really understand the marine habitat that has formed around these assets over the decades they’ve been in situ. So, we are doing work to really understand what’s the best environmental outcome, but we have a risked provision in the—sorry, a risked cost in the provisions. When it comes to royalty refunds, no, we don’t have

 

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that same access or that same structure that Chevron has in Bass Strait [Clarification: Chevron has on Barrow Island].

It probably is worth noting that abandonment expense is creditable on PRRT and income tax, of course. Again, those are expenses for the oil field developments, so that’s the structure that we have access to.

Rob Koh (Morgan Stanley, Analyst): Okay, great. Thank you so much.

Meg O’Neill: Thanks, Rob.

Operator: Your next question comes from Nicholas Morgan from JP Morgan. Please go ahead with your question.

Nicholas Morgan (JP Morgan, Analyst); Good morning, Meg and team, and thanks for your time this morning. Two questions from me. Firstly, on Louisiana LNG, could you give some further detail on what the targeted split is for Woodside’s equity share of LNG, on a contracted vs spot basis?

Meg O’Neill: We want to take about 8 million tonnes into our portfolio. The FID we’ve taken for the first three trains is 16.5 million tonnes. We want to keep about 8 million tonnes of that in our portfolio, but we will on-sell a good portion of that. How much we on-sell and the contracting structure, actually we have quite a bit of flexibility. As you would have seen from our announcements in the half, we’ve done LNG offtake agreements with China Resources, with Uniper. One of the Uniper agreements was direct from Louisiana LNG. I would call that in the 8 million tonnes that’s not for our accounts. So, we do have quite a bit of flexibility in our LNG marketing, really to work closely with customers to understand what do they need and to negotiate outcomes that work for both players. But 8 million tonnes is what we intend to take into our portfolio.

Nicholas Morgan (JP Morgan, Analyst): Perfect, thanks. The second one from me is have you seen any inflationary pressures on steel costs for the Louisiana LNG pipeline in the US, and just how those costs are tracking towards expectations taken at FID?

Meg O’Neill: The pipeline costs are still tracking within what was announced at FID.

Nicholas Morgan (JP Morgan, Analyst): Perfect. Thank you, Meg.

Meg O’Neill: Thanks, Nick.

Operator: There are no further phone questions at this time. I will now turn the call back over to Ms O’Neill for closing remarks.

Meg O’Neill: Thank you all for listening in and participating today. I look forward to speaking to many more of you in the coming days but would also like to highlight that we have a capital markets day planned for5 November, and we look forward to talking more about the Woodside business at that occasion. Thank you all.

Operator: That does conclude our conference for today. We thank you for participating. You may now disconnect your lines.

[END OF TRANSCRIPT]

 

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Reconciliation: Payments for capital and exploration expenditure to capital expenditure

The below reconciliation has been prepared in response to the question from Dale Koenders (Barrenjoey) on page 14 of the transcript.

Capital expenditure is $2,558 million (see page 3 of the Half-Year 2025 Report). Net cash outflow for capital and exploration expenditure of $2,775 million is set out in the table below. The variance between capital expenditure and net cash outflow for capital and exploration expenditure of $217 million is primarily due to timing of payments.

 

Cash outflow for capital and exploration expenditure		2025 (US$m)
Payments for capital and exploration expenditure1			(4,881	)
Reimbursements received from external parties for capital expenditure1			236
Contributions from/(distributions to) non-controlling interests2			1,870
Net cash outflow for capital and exploration expenditure			(2,775	)

 

1	Refer to page 24 of the Half-Year 2025 Report.

2	Refer to footnote 1 on page 24 of the Half-Year 2025 Report.

 

 

INVESTORS Vanessa Martin M: +61 477 397 961 E: investor@woodside.com		MEDIA Christine Abbott M: +61 484 112 469 E: christine.abbott@woodside.com

This announcement was approved and authorised for release by Woodside’s Disclosure Committee.

 

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