WOODSIDE ENERGY GROUP LTD — Call Transcript 2023

Nov 10, 2023

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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 LSE: WDS

Announcement

Friday, 10 November 2023

INVESTOR BRIEFING DAY 2023 TRANSCRIPT

Date: 8 November 2023 Time: 09:30 AEDT / 06:30 AWST (16.30 CST on Tuesday, 7 November 2023)

Start of Transcript

[Video playing]

Matthew Turnbull: Good morning everybody, it’s a pleasure to welcome you to Woodside’s 2023 Investor Briefing Day here in Sydney. I’d also like to welcome those joining on the webcast, it’s great to have you involved. Today we’re meeting on the land of the Gadigal people of the Eora Nation. We acknowledge their continued connection to these impressive land and waters, and we pay our respects to Gadigal Elders past and present and honour their enduring traditions and culture.

It's been a year since our last investor briefing day and it’s been a very busy and exciting period for us, as we have progressed the execution of our strategy to thrive through the energy transition. Now before we get started, I need to address a few important points. First, please take the time to read the disclaimer, assumptions and other important information on slides 3 and 4 of the slide deck. All dollar figures in the presentation are in US dollars, unless noted otherwise.

Second, in the event of an emergency, please follow the instructions of the hotel staff. So, we’ll exit through the doors behind you and assembly points are either north of Crown at Barangaroo Reserve, or south of Crown on the Wharf Promenade. And there’s no need to bring anything, please leave all items behind. Third, we’d also appreciate it, if you could please make sure your mobiles are switched to silent for the duration of the presentation.

Now today you’ll hear from our Chief Executive Officer, Meg O’Neill, who’ll discuss Woodside’s role in providing energy the world needs, today and into the future. You’ll also hear from other members of the executive leadership team, on what they are doing in each of their respective areas, to deliver enduring value. We’ll cover a lot of ground today and provide information on the activities and strategy of the company in the coming years, and as usual we’ll be providing specific 2024 guidance in January.

Now after the presentation in the first session, we’ll have a quick break before Meg returns for a question and answer session. So please hold your questions to ask during the Q&A session. Meg and the leadership team are looking forward to discussing Woodside’s activities with you, so please take the opportunity over

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lunch to ask any additional questions you might have. I’d now like to welcome Meg to the stage, to begin today’s investor briefing day.

Meg O’Neill: Alright, well thank you Matthew. Welcome to everyone in the room and online. We’re very pleased that you can join us for the 2023 Woodside Energy Investor Briefing Day. The leadership team and I will provide an overview of our strategy and priorities, and we look forward to addressing your questions. As the world responds to climate change, by transitioning towards a lower carbon economy, we must prepare for and contribute to, a managed and equitable transition, by continuing to supply reliable and affordable energy.

I believe our strategy to thrive through the energy transition remains the right approach. We intend to optimise value and shareholder returns, through developing a low cost, lower carbon, profitable, resilient and diversified portfolio. It is also important to note that our Company strategy is a climate strategy, we don’t have two separate strategies. Climate considerations are incorporated in our decision-making processes, as we consider how to invest in the business.

But what does it mean, to thrive through the energy transition? There are three goals which drive our strategic direction. First, we must provide the energy required for future demand. We will play to our strengths in this area, providing oil and gas and advancing alternatives in the new energy space, as demand is increasingly shaped by decarbonisation goals. Second, it is essential that we create and return value. Value creation will not only drive opportunity growth, but also allow us to continue our demonstrated track record of returning value to shareholders.

Third, we must conduct our business sustainably. We have been in business for almost 70 years and we plan to be operating for many years to come. To do this, we must manage our impact on people, communities and the environment, which includes a strong focus on emissions, and we must take a longterm perspective. To thrive through the energy transition, means achieving all three goals. I’ll now spend some time, discussing how we see the global energy landscape and what that means for oil and gas demand. Many people don’t appreciate how deeply our standards of living depend on reliable access to energy.

If we turn the lights on, we’re using energy, charging our phones uses energy, as it gets hotter here in Australia, or cooler in the northern hemisphere, we use air-conditioning and heaters, both of which require energy. It’s embedded in everything we do and we need more of it. There is sustained demand for energy, driven by expected rises in population and GDP, as countries outside the OECD strive to grow their economies and improve their standards of living. That demand is coupled with a need to provide affordable, reliable and lower carbon energy supply. Woodside is an important part of this equation. With our long track record of returning value and our focus on emissions reduction, we are well placed to continue to supply energy the world needs.

Slide 10 demonstrates the resilience of our key products and energy demand around the world. Asia Pacific primary energy demand remains key. We are strategically located close to these demand centres. Oil and gas demand remain strong out to 2050 and importantly, no single energy source can meet the world’s demand for energy. Forecasts similar to those shown on the slide, help inform Woodside’s underlying view of long term, energy market demand. And our understanding of energy markets drives our investment strategy and allows us to make informed choices to create value.

An enormous amount of investment is required in all forms of energy in the coming decades, to meet forecast demand. Natural gas, particularly LNG plays a key role in energy security. We are very positive on the continued role for gas. The charts on this slide make it clear, that under current forecasts, supply from gas and oil projects that are operational today and under development, will not meet future demand. And additional investment in gas and oil is required.

Slide 12 provides a view on the potential growth of hydrogen demand across different sectors. Now the hydrogen market and government policy is still maturing but momentum is building for it to play a key role in

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our customer’s decarbonisation efforts. It’s also important to note the scale of hydrogen demand growth. It will take decades and trillions of dollars of investment in hydrogen, to develop the scale needed to meaningfully replace other fuels. Hydrogen leverages our core capabilities in LNG, including developing and operating large scale industrial facilities and collaborating with customers and partners across the value chain.

This slide also provides a view on the potential CCS capacity outlook across different locations, into the future. We believe CCS will have a dual role to play in delivering global decarbonisation targets, as well as meeting Woodside’s aspiration for net zero by 2050, which you’ll hear more about today. I’ll now discuss what Woodside is doing to create value now and for the future. It all starts with our core business of oil and gas. In our core business we drive for safe, reliable, cost efficient and lower carbon operations.

Our safety performance this year has been disappointing, and we will talk more about that today. Let me assure you, the full leadership team is stepping in to address this challenge.

When it comes to costs, our expected cash flow break-even oil price in 2024 is approximately $32 per barrel excluding major projects. This gives us confidence in our ability to create value through the cycle. For the last five years we have maintained a cash margin of approximately 80%, including through a lower price environment, which demonstrates the resilience of our business. We are working to achieve our decarbonisation targets, to reduce net equity scope 1 and 2 emissions by 15% by 2025, and by 30% by 2030 with an aspiration of net zero by 2050.

As our existing portfolio matures and our resources decline, we are investing in opportunities to deliver profitable production that will provide value for shareholders well into the 2030s. We have a suite of infill and near field development opportunities, that leverage the benefit of existing infrastructure. This year we started producing from Mad Dog Phase 2 and Shenzi North. We have also taken a final investment decision on Julimar Phase 3 and are assessing other value accretive infill opportunities, both in Australia and the US Gulf of Mexico.

Additionally, we have three world class projects in execution. Sangomar, Scarborough Pluto Train 2 and Trion. Matthew Ridolfi, EVP Projects will talk more to these projects. Further, Woodside has investment opportunities that could contribute to production beyond 2028. We have a healthy pipeline of these opportunities across different geographies and different commodities, including oil, gas and new energy. The new energy and integrated carbon opportunities, diversify our portfolio and support our customer’s decarbonisation goals. Future investments could take the form of organic or inorganic opportunities.

The key benefit of the breadth of these investment opportunities, is we have development optionality. We can be increasingly selective and only progress the opportunities which best fit our overall strategy. Having just described portfolio optionality, I would like to reiterate Woodside’s capital allocation framework which informs how we think about future investments. This framework is unchanged from what you have seen previously. As an energy company we intend to continue developing oil and gas opportunities and in parallel, bring forward opportunities to invest in new energy.

We will be disciplined in our investment decisions with clear targets for financial returns and payback periods expected from each opportunity. Our history of strong shareholder returns is something we at Woodside are proud of. The strong operational performance of our low-cost producing assets and the resilience of the business, has allowed us to maintain strong returns through the commodity price cycle. Our dividends are fully franked, which we know is important for our Australian shareholders. Our disciplined approach to capital management provides the framework to ensure we continue to return value to our shareholders through the cycle.

Projects in execution today will support cash generation in the future and position us well to deliver both growth and returns. Graham Tiver, our CFO, will provide more insights on this point. I know many of you are interested in how we intend to achieve our aspiration of net zero by 2050. We remain focused on our hierarchy of design out, operate out and offset. Through to 2050 we have identified and are progressing, a

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total of 28 million tonnes of cumulative design out and operate out emissions reductions. Offsets will remain important to our indicative abatement profile.

They’re important because they are available for us in the short and medium term for emissions that cannot otherwise be avoided or eliminated. Design out, operate out and offsets are shown on the indicative scope 1 and 2 greenhouse gas emission profile chart on the right. We are also progressing opportunities for large scale abatement, and you’ll note how much of an impact those could have between 2030 and 2050. It’s important that we work on these opportunities now, as many of the ideas in this category require technical and or commercial maturation.

We know and understand our largest sources of operational emissions. On a typical LNG train, the majority of emissions are from mechanical drives and power generation. We also understand where the abatement opportunities are. They could be in post-combustion capture, electrification, or hydrogen fuelling, to name a few. But we must decarbonise in a cost-effective manner. There are some activities currently underway, which are under our US$80 a tonne long term cost of carbon. These include biosequestration, acquisition of carbon credits and other activities identified in our asset decarbonisation plans. These are delivering net emission reductions today.

Liz Westcott, EVP Australian Operations and Shiva McMahon, EVP International Operations, will talk about actions being taken on our facilities. Shaun Gregory, EVP New Energy, will talk later to what we’re doing in our carbon portfolio and with CCS. There are decarbonisation technologies which are significantly more expensive today but have potential to greatly impact our emissions profile. We are progressing work on these today and collaborating with other in industry, in order to reduce the implementation cost.

Daniel Kalms, EVP Technical Services, will talk more to how we are positioning ourselves to take advantage of these technologies, in support of the longer-term decarbonisation of our operations. The quality of Woodside’s business and our competitive positioning, presents a compelling investment case. There are three attributes that differentiate Woodside from other companies in our sector. First, a high-quality portfolio, underpinned by high performing, cash generating operating assets, with future value coming from major projects under development.

Second, a disciplined framework for capital management, delivering a strong balance sheet and the ability to both provide strong shareholder returns and invest in quality opportunities and third, our strong positioning for the energy transition, leveraging our traditional energy capabilities. You’ll hear now from my leadership team, as they discuss how they are contributing to the achievement of these objectives. With that, I’d like to welcome Graham Tiver to the stage.

Graham Tiver: Thank you Meg and good morning everyone. My role as the CFO is to ensure that the balance sheet enables the execution of the Woodside strategy. We achieve this through a disciplined approach to capital allocation and prudent management of the balance sheet, to ensure we can fund our base business requirements, meet our capital commitments and provide returns to our shareholders. Today, I’ll take you through how we are achieving this. Woodside is well positioned to deliver value into the future.

We are investing in future production by progressing our major projects Sangomar, Scarborough, Trion and we have the balance sheet strength to support these investments. Our business is highly cash generative and resilient through the price cycle. Our capital management framework provides the principles on how we utilise the cash we are generating, to optimise value for our shareholders. There are three parameters which we must work within. The first, we’re committed to maintaining an investment grade credit rating.

Second, we must meet our investment expenditure commitments and third, our dividend policy is to pay a minimum of 50% of our underlying profit, where we target a range of 50% to 80%. Over the last decade, we have consistently paid at the top end of the range. Maintaining our investment grade credit ratings, is important to us. It enables access to debt at a competitive rate and is an independent assessment of the financial strength of our business. Gearing is another metric we use to measure the strength of our balance

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sheet. We have a target gearing range of 10% to 20% through the cycle, it may at times temporarily sit outside of this range.

At the end of October, our gearing was approximately 11% and that includes the distribution of the recently paid dividend. Once we meet our capital commitments, target credit metrics and dividend obligations and consider the external factors that may impact our future cashflows, such as the pricing environment, we can then consider what to do with any excess cash we have. Options include additional returns to our shareholders through special dividends and share buybacks.

The chart on the screen shows an indicative view of forecast capital expenditure through to 2028. Capital expenditure peaks in 2023 and is expected to be in the range of US$5.7 billion to US$6 billion. As we progress through the next five years and we complete execution of our major projects, our forecast capital expenditure is expected to taper off. This provides capacity for investment in future growth opportunities, both organic and inorganic.

It also provides the balance sheet capacity to support Woodside’s target to invest US$5 billion in new energy services and lower carbon services, which is anticipated to ramp up towards the back end of the decade. Future investment decisions will be assessed against our target metrics and will be considered alongside options for additional returns to shareholders.

Our balance sheet is well positioned to support our current investment program. Our liquidity remains strong, providing ample capacity to meet our expenditure requirements and at the end of October, our liquidity was US$8.1 billion, of which undrawn debt facilities were approximately $6 billion. We executed additional facilities in October, recognising near-term market volatility and our debt maturity profile is well managed. Subject to completion, we expect to receive the proceeds from the sale of a 10% interest in Scarborough in Q1 2024, totalling approximately US$880 million. This will provide further balance sheet flexibility.

Our investment grade credit rating is important and is currently BBB+ and Baa1 as assessed by S&P and Moody’s respectively. Our strong balance sheet is well placed to fund the major investment program that is underway, as well as navigate market volatility and continue strong returns to our shareholders. Our highly cash generative business differentiates Woodside as an investment. The chart on the screen provides a fiveyear indicative production profile and free cash flow projections at an oil price of $50, $70 and $90. At $70, we expect to remain free cash flow positive through the current period of high capital and at $50 we expect to be free cash flow positive from 2025.

There is upside to these two pricing scenarios, as shown at a $90 oil price and it’s important to note that today the Brent forward curve is in the range of $80 over the next two years. The chart demonstrates the resilience and flexibility of Woodside’s cash flow, the strength of our existing production portfolio and the value to be delivered by the major projects which are currently in execution.

Expanding on the previous slide, the indicative charts on the screen show how cash generated from our operations at both the $50 and $70 oil price could be utilised in the coming five-year period. In both pricing scenarios, the investing cash outflow is relatively flat. What flexes, is the potential dividend payment and the remaining cashflow available for investment or additional shareholder returns. However, in reality, we would respond to significant unexpected oil price movements by rationalising uncommitted operating and capital expenditure.

As an investment proposition, Woodside offers exposure to a highly cash generative business, with capacity to continue to produce significant cash flows through to the end of the decade and beyond. This further demonstrates that Woodside’s balance sheet is well positioned to deliver future value for our shareholders, even in a lower price environment.

Before I wrap up, I would like to reflect on Woodside’s contribution to the Australian economy. Woodside is among Australia’s largest taxpayers and since 2011, has paid more than AU$18 billion in Australian taxes and royalties. In the first half of 2023 alone, we paid a record AU$3.7 billion in Australian tax and royalties,

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reflecting our strong business performance in 2022 and 2023. The all-in effective tax rate at the 30 June Half-Year results was 42% when we exclude the one offs.

To provide further context, we paid more than AU$1 billion in petroleum resource rent tax or PRRT and that’s up to the last 12 months to 30 June 2023. Our contribution demonstrates that when Woodside performs well, Western Australia, Australia and the other countries where we operate enjoy significant benefits through our taxes and royalty payments.

To summarise, Woodside’s balance sheet is well placed to enable the execution of our strategy. We remain disciplined in our approach to capital management and are actively managing our balance sheet to ensure that we can continue to create value and reward our shareholders through the cycle.

I’ll now pass over to Mark Abbotsford, Executive Vice President Marketing and Trading, to talk through the marketing strategy and activities. Thank you.

Mark Abbotsford: Well thank you very much, Graham and good morning everyone. It’s an absolute pleasure to be here again this year in Sydney. My name is Mark Abbotsford and I’m Woodside’s EVP of Marketing and Trading. Following the geopolitical events of 2022 and their subsequent impact on global energy markets, we saw renewed focus on the importance of both reliable and affordable energy. This year, as nations prioritise energy security, we’ve seen an increased appreciation that the energy transition will be more challenging. As Meg has already noted, this reinforces the critical role of gas in ensuring affordable, reliable and low-carbon energy is available across both the developing and developed economies.

In the medium term, the global LNG market remains structurally short supply in both the Asia Pacific and Atlantic basins. As we look more near term, storage levels in Europe are currently at multi-year highs as we head into the northern hemisphere winter. While LNG prices have come down from the extreme peaks that we saw during 2022, spot prices are well above long-term averages and volatility remains high. This highlights a continued risk premium in the market and increased vulnerability of markets to demand and/or supply shocks.

In the second half of this decade, we will see new supply enter the market as projects sanctioned during 2021 and 2022 come online. Further investment is required to ensure markets remain in balance into the next decade, however rising financing and construction costs are challenging new investment in supply globally. With most new supply coming from non-Asia-Pacific sources, Asia-Pacific markets are likely to continue to be the premium global market and a source for strong demand for Woodside’s Australian assets.

With uncertainty facing the world around the pace and shape of the energy transition, coupled with volatile energy markets, Woodside needs to remain flexible and adaptable to continue to meet its customers’ requirements. Woodside’s portfolio is positioned to capture value and manage risk and is underpinned by three key principles. Firstly, Woodside has a diverse and flexible marketing portfolio of supply and delivery points across both the Asia Pacific and Atlantic basins. We are actively looking for opportunities to grow our global supply portfolio and to build scale through cost competitive equity and third-party LNG.

Secondly, our portfolio is adaptable, resilient and responsive. We have taken the approach of layering contracts throughout market cycles to ensure that we balance upside exposure with revenue certainty. Our sales strategy is underpinned by ex-ship sales and strong, logistical capability. Woodside is advantaged through our long shipping position, which enables Woodside to create upside value through short-term trading and portfolio optimisation activities.

Thirdly, Woodside is a reliable and experienced energy supplier, with strong global relationships, who is able to meet our customers’ evolving requirements. We have seen a renewed focus for long-term security of LNG supply from key buyers in Asia who are also looking to complement it with their new energy initiatives. With uncommitted volumes in our LNG portfolio and the progress being made by Shaun on our new energy opportunities, we are well positioned to meet our customers’ needs.

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The proximity of Woodside’s LNG operations to Asia is a competitive advantage for our business. LNG will play a critical role in the energy transition for many countries in Asia, especially those with limited domestic natural gas supplies. With reliance on coal still strong, countries that have committed to net zero by the middle of the century are looking for reliable, affordable, lower carbon energy sources to support their decarbonisation goals. LNG meets these requirements.

We have four large LNG customer markets on our doorstep. Japan and South Korea are still nearly 30% reliant on coal for their energy needs today. China and India’s reliance on coal is significantly higher at 63% and 55% respectively. Proximity of Woodside’s operation to Asia, our strong relationships with customers and track record as a reliable and experienced supplier of energy positions us well to understand and meet customer requirements as they evolve.

An important consideration when managing our customer contracts is the overall exposure to different pricing indices across our portfolio. Woodside’s revenue is predominantly exposed to the oil price, with the remainder being fixed price or other low-volatility constructs, all linked to gas hub prices such as JKM or TTF. Woodside’s near-term gas hub exposure for produced LNG is expected to increase to 25% to 30% in the near term and this is an increase from the 20% to 25% that we indicated at last year’s investor briefing day.

Better than expected performance at the North West Shelf, high reliability at Pluto and contract portfolio choices increase our hub exposure in the near term when we see the market as being supply constrained. Following the startup of Scarborough, we expect gas hub exposure for produced LNG to be in the range of 30% to 35%. Our long-term traded LNG from Corpus Christi in the United States, will provide additional gas hub exposure, noting significant volumes remain unhedged.

This portfolio mix is complemented by our low volatility portfolio of predominantly pipeline gas sales here in Australia, in Trinidad and Tobago and oil sales in the United States, which provide revenue certainty. This provides portfolio flexibility to layer in new long-term contracts and meet customer requirements for new term supply, while also allowing us to adapt to rapidly changing external market conditions. This enables Woodside to capture the current robust pricing environment and manage risk.

Coming to Australia, Woodside is a significant contributor to Australia’s domestic gas market. We estimate that during 2024 Woodside’s share of domestic gas projects will supply approximately 22% of the West Australian domestic market and 17% of the East Coast market. All of our East Coast production is delivered into the domestic market and not for export. In Western Australia, Woodside supplies gas to industrial and wholesale users to meet residential gas demand and also power supply. Our gas powers industry and keeps the Western Australian economy going.

On the East Coast of Australia, the market remains finely balanced with continued strong demand for gas from also the residential and power sectors. New supply sources are key to meeting this demand. Woodside is exceptionally proud to continue to supply reliable gas into Australia’s domestic markets.

With that, I thank you for your time and I’d like to hand over to Matthew Ridolfi, our EVP of Projects.

Matthew Ridolfi: Thank you, Mark. Good morning, my name is Matthew Ridolfi and I’m very pleased to be here today to talk to you about our projects business which I lead for Woodside Energy. We’ve made great progress with our projects over the last 12 months as we continue to invest in our business future. Our portfolio now has over $15 billion, Woodside share, of projects in execution, including Scarborough, Sangomar and Trion. We’ve also been executing additional brownfield opportunities like Shenzi North in the Gulf of Mexico, which came online recently on budget and ahead of schedule.

Delivering value through our projects comes down to doing it safely, at low cost, with lower carbon solutions. Scarborough is a really good example of this. As Mark mentioned, Scarborough is one of the lowest carbon intensity projects for LNG delivered in North Asia and it also has a very competitive cost of supply. With our increased scale of projects in execution, we’re also able to build deeper relationships with our contractors

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and be well informed of any changes going on in industry. And while thorough project execution planning is critical to what we do, our view of risk is not static and our team actively manages the emerging risks and adapts plans to protect and deliver value.

Another core part of our business is safe execution and setting up for safe, low cost, lower carbon operations. Upfront design is key to enable this. The decisions we make early in the lifecycle of projects facilitates safer operations and reduced emissions and whilst we’re always looking for ways to improve our safety performance during execution, I’m pleased to say we’ve not had any high consequence injuries in our projects this year.

Sangomar, Scarborough and Trion are all material projects in their own right that will deliver production in 2024, 2026 and 2028 respectively. We’ve included some details of the key project metrics on this slide for your reference and I’ll now provide you with an update on the status of each of these projects. Sangomar is the most advanced of the three projects and is targeting first oil from mid-2024, 14 of the 23 wells have already been completed and the drilling results are in line with expectations. The subsea work is approximately 96% complete and this includes about 125 kilometres of flowlines and rises that have been successfully installed and installed safely. The FPSO topsides integration and pre-commissioning work is continuing in Singapore and we’re well advanced on our preparations for handover to operations and Shiva will talk about this in her section today.

Turning now to Scarborough, which is now approaching 50% complete, firstly the technical and fabrication aspects of the project are progressing really well. The fabrication of the Pluto Train 2 modules in Batam in Indonesia is well advanced with 44 of the 51 modules currently under construction. Pluto site construction in Karratha also continues in readiness for delivery of equipment and modules, with about 450 workers currently onsite. We recently awarded the EPCM contract for the Pluto Train 1 modifications that will enable us to process Scarborough gas through Pluto Train 1.

The Scarborough floating production unit, or FPU, is progressing well with fabrication of the hull and topsides in China and the FPU progress continues to support the first LNG cargo delivery target of the project of 2026 and I’ll now show you a short video of the progress of the FPU.

[Video playing]

Matthew Ridolfi: So on Scarborough, we have also commenced the pipelay activities in state waters, where we will be installing the first 32 kilometres of the trunkline. The total employment associated with the Scarborough construction vessels that we’ll have offshore, is expected to peak at over 2,000 people, of which approximately 80% are Australian jobs. Secondary regulatory approvals are a key focus area for us on Scarborough, as well as our other project activities in Australia, including decommissioning.

I’ll now provide an update on this. Woodside currently has six environmental plans under consideration by NOPSEMA including EPs for Scarborough Drilling, Scarborough Seismic and other offshore construction activities. In developing our EPs, we’ve engaged extensively with our stakeholders, including the associated First Nations groups. For the Scarborough Seismic EP alone, we’ve consulted with more than 80 stakeholders including 10 First Nations groups, spanning out hundreds of kilometres from the operational area itself.

For other Scarborough project EPs, we’ve consulted stakeholders along 3,500 kilometres of the coastline as shown on this chart. We’ve worked collaboratively with the regulator to understand and address the consultation requirements for these environmental plans and we respond to any items raised by the associated stakeholders and as such, we believe we have met the requirements of the current regulations. We’re confident that we will ultimately get these approvals. In the meantime, we are working with our contractors and continuing to review the activities and manage and mitigate impacts of any delays in the approvals process.

Moving on now to Trion. I’ll start by showing a short video of the Trion development.

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[Video playing]

Matthew Ridolfi: Since taking FID on the Trion project earlier this year, we’ve continued to work well with our joint venture partner, PEMEX and the regulator in Mexico, CNH and we are very pleased to see that the field development plan was approved in 62 days, well ahead of the 120-day allowance. This further demonstrated the support of the regulator and the key stakeholders for the project in Mexico. The Trion facilities FEED was completed following 30 months of engineering, to inform tenders and make sure that we reduce the risks of any changes during execution.

At FID approximately 70% of our forecast capital was underpinned by firm tenders that were lump sum based or based on fixed rates and the team has been progressively locking in all of these contracts since FID. We’ve also commenced detailed engineering for major scopes of work including the Trion FPU, scheduled to commence fabrication in Korea next year.

Moving to the other end of the lifecycle, when our assets finish their production phase, we are ready to safely and responsibly decommission them. The recent successful removal of the decommissioned Nganhurra riser turret mooring in Western Australia was a significant milestone for Woodside. This video helps show the scale of that operation. Just by way of context, the RTM weighs about 2,500 tonnes and is over 80 metres in length.

[Video playing]

Matthew Ridolfi: And you may have picked up in that slide, that 95% of the RTM will be recycled or reused and that’s going to support local employment and also enable local contracting opportunities. The charts on the right-hand side of the slide show our planned decommissioning activities through to the end of 2025 and provides an indicative decommissioning spend over that same time frame.

Across both our operated and non-operated activities, we plan to remove more than 350 kilometres of flowlines, umbilicals and risers, permanently plug and abandon more than 160 wells and remove more than 35,000 tonnes of infrastructure. This is a complex area which presents opportunities for us to listen, learn and collaborate across the industry and with regulators, to ensure that we execute our decommissioning responsibilities safely, whilst ensuring that our costs remain competitive.

In closing, we have three major projects in execution, and we continue to invest in the future of the business. These are world class assets that will provide value to Woodside shareholders well into the 2030s.

I’d now like to invite Shiva McMahon, EVP International Operations, to the stage.

Shiva McMahon: Thank you Matthew and good morning everyone. I’m Shiva McMahon, EVP for International Operations and today I’m pleased to speak to you about our International Operations business, where we have high quality assets, with high margins and we’re focused on sustainably delivering value.

This slide shows our focus areas, as an operations team. Safety is paramount to everything that we do. Liz will elaborate further on our corporate-wide safety performance shortly. It is critical that we get safety right and this continues to be underpinned by our field leadership program, that I discussed at our investor briefing day last year. A key aspect of this, is about planning the work. This year, we had several complex scopes of work completed at Shenzi, including tying in the Shenzi North wells, as well as a maintenance turnaround that included the use of a helicopter to replace our flare tip. A very complex and high-risk operation.

Thorough planning set the teams up for success and I’m really pleased that we executed these scopes incident and injury free, as well as on schedule and under budget.

Our teams have a culture to maximise value and to control costs and in a transitioning world, it is important that the barrels that we produce are also lower carbon. All through field life, our focus on cost and reliability,

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maximises the value of the assets. We have a concerted effort across all cost fronts and make adjustments as our operations evolve. We have a zero-based approach to cost management, which enables a healthy challenge of our spend, to ensure that the spend is appropriate for the phase of operations.

Our field leadership teams have full visibility of the spend and they apply an owner’s mindset to make sure that we are efficient with every dollar that we spend, without compromising on our core values of process and personal safety. This year, we’ve also achieved very high reliability at Shenzi. We have a proactive approach for risk management and defect elimination and this has continued to evolve with digitisation, allowing us to get the most out of our historical performance data, for deeper insights to help inform and prioritise our maintenance programs.

Now we’ve had operations in the Gulf of Mexico since Mad Dog started up back in 2006. These are large, long-life fields, with attractive returns and we’ve produced almost half a billion barrels net from our assets and today, we still have almost half a billion barrels of 2P reserves remaining. Our teams are identifying and screening the next set of opportunities, to maximise the value of our assets and to manage and offset the underlying base decline.

For example, I spoke to you last year about the startup of the subsea multiphase pump which was among the first installed in the deepwater Gulf of Mexico. That project paid out in less than one year from startup, with an uplift in production of about 10,000 barrels a day, during smooth operations.

As you heard from Matthew, Shenzi North has had a strong execution, with delivery on budget and ahead of schedule. While it’s early days, we’re watching reservoir connectivity and we expect a peak rate could be around 10,000 barrels a day.

In April, we also brought online Mad Dog Phase 2, or Argos, which has been ramping up and has a capacity of 140,000 barrels a day. Following the appraisal well in the south west of the field, we are already in the process of finalising plans for a multi-well subsea tieback.

Exploration is another important part of our aspiration in the Gulf of Mexico. We have a portfolio of exploration opportunities, and we believe that managing the risks and the cost exposure are key to value-adding exploration.

Now moving to Trinidad and Tobago, where we’ve had an operating presence since 2005. Our existing shallow water fields are later in life and we’re planning for end of field life by the end of this decade. The mindset of the teams is super important though. Everything we do is through a lens of personal and process safety and facility integrity first. At the same time, we remain focused on maximising the value of the assets and the remaining reserves. This year we’ve been able to increase the daily production by approximately 10% through screening and execution of ideas from our teams.

This was unlocked in several ways. By converting gas injectors into producers to produce the gas cap before the end of field life. We also added perforations to capture gas from unswept reservoir zones. We also reduced back pressure on wells, by operating the facilities differently than we did, when the production rates were higher.

Now looking into the future, we see Trinidad and Tobago as an advantaged region, with existing infrastructure and favourable demand outlook. So we’re continuing to progress Calypso in the deep water. We have selected an infield host as the preferred development concept and are making really good progress on commercial and marketing fronts as well.

Slide 47 highlights our efforts to decarbonise in a transitioning world. The Gulf of Mexico is one of the lowest emissions intensity sources of oil and Shenzi has approximately half the emissions intensity of the global oil average. But even with that, we’re focused on opportunities to reduce our Scope 1 and Scope 2 emissions further.

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Meg spoke to the typical operational emission sources for LNG projects and Daniel will expand on it a little bit more. The emission sources for oil projects are a little different though. Fuel gas makes up about 85% of the emissions and flaring is about 10%. While options like electrifying the facilities to reduce fuel gas are cost prohibitive in an offshore deep-water environment, there are incremental emission reductions that we can and we do chase.

Since the merger, we’ve developed asset decarbonisation plans for our fuels and we are in the process of implementing these. The change of the Shenzi flare tip that I mentioned earlier was to a more efficient flare tip that has reduced our flare gas emissions by circa 10%. These contribute to our corporate emissions reductions targets and also allow more gas to go to sales and hence create incremental value.

Now moving to our five-year production profile, safety, reliability and sustainability remain the cornerstone of our operations. We continue to get the most out of our existing assets and we’re preparing to bring online new regions with Sangomar and ultimately Trion. At Sangomar we’re already preparing for operations handover from projects. In fact we’ve had key operation team members with the projects for the last 18 months. The combined Woodside and the FPSO operations contractor team have significant international experience on similar projects and our priority is to deliver safe and efficient start-up operations. We’re expecting successive ramp-up of the wells, which will enable peak production to be achieved within about six months of start-up.

So in closing, our international operations are a material business with high-quality assets, high margins and lower emissions and we’re actively maximising the value and the returns of these assets and we will apply the same mantra to maximise the value of Sangomar when we bring that online by middle of next year [Clarification: Sangomar targeting first oil mid-2024]. With that, I thank you for your attention. I now would like to invite Liz Westcott, our EVP of Australian operations, to the stage. Thank you.

Liz Westcott: Thank you, Shiva and thank you all for joining us. It’s a pleasure to be speaking to you today. For those I’ve not met, my name is Liz Westcott and I look after the Australian Operations team. I joined Woodside in June, following 30 years in the energy industry, working for ExxonMobil and Energy Australia and I’m really pleased to be working for an Australian company that makes an important contribution to the world’s energy needs. Today I will talk about how we’re setting up our Australian operations to continue to deliver energy to our customers and value to our shareholders.

First though, I want to talk to you about our number one priority, safety. Our safety performance needs to improve. I want to take a moment to acknowledge the death of Michael Jurman, while working as a contractor at the North Rankin offshore platform on June the 2[nd] . A loss of life at work is a tragedy and this was devastating for Michael’s family, his workmates and caused deep reflection across the entire company. Safety comes first. We say this so often, that perhaps it now sounds cliched, but I want to reiterate there is nothing more important to us than everyone going home safely after working at a Woodside site.

Personal and process safety are affected by many factors. From engineering design and maintenance, to work management practices and the work environment itself. How we manage these factors is our system of safety. To ensure it remains effective, we are both stepping in and stepping back. We’re stepping in and looking at our internal processes, ensuring that safety fundamentals are embedded in every aspect of our work and elevating field leadership to drive a renewed frontline focus on safety. And we’re also stepping back. We’re conducting an external assessment of our global operational system of safety and working with industry through our partnerships.

Good safety performance is essential as a responsible operator and also, though, it enables reliable and efficient operations. Our focus is on maximising value from our high-quality assets while ensuring that our operations remain safe, low cost and lower carbon, including through implementing asset decarbonisation plans. When combined with our track record of high reliability, all of these imperatives contribute to ensuring we remain competitive.

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Let me now explain in more detail. We need to be smart about costs to stay competitive globally and continue to deliver high margins. Technology can give us an edge, but we are also driving efficiencies in our operating model, our infrastructure planning. The photo, showing a drone inspection of a flare tower, is one example of how using technology to monitor hazardous areas is cost effective, avoids exposing people to certain risks and minimises impact on production. Fitted with high-definition cameras, the drone conducts an inspection much faster and with much lower risk than if humans do it.

We have adopted an operating model that removes duplication and enables decision making and are rolling out a streamlined operational management system that will deliver efficiencies. For our later-life assets, we are scaling facilities to match production, supporting a reduction in cost and emissions. At the North West Shelf, this means planning for progressive LNG train retirement commencing in 2024 and in Bass Strait, asset modifications are supporting the transition to a cost-efficient and streamlined gas-focused business as oil production declines.

At a time when customers are telling us that reliability matters, our record speaks for itself. Excluding the impact of the planned maintenance turnaround, LNG reliability for Pluto for the nine months to the end of September was 99.9%, and 98% for Karratha Gas Plant. We are looking at ways to optimise production from our facilities, including through improved maintenance effectiveness, delivering reduced turnaround frequency and duration.

Our efforts to harness value from existing assets are paying off. The start-up last year of the Pluto to Karratha Gas Plant Interconnector facilitated third-party processing at the North West Shelf. This allowed accelerated production of 17 million barrels of oil equivalent from Pluto since first quarter 2022 and its sale into a high-priced market, creating significant upside value.

We are also developing infill and nearfield opportunities, such as Xena 3 to Pluto and Lambert West to the North West Shelf, and have made a final investment decision to Julimar Phase 3 to Wheatstone. Our production from Australian assets is set to increase when Scarborough comes online as you can see in the indicative chart on the right.

I would like to share with you a big step we took recently to enable safer and more efficient operations. The Pluto remote operations centre, pictured here, allows the plant to be operated from Perth. Locating our control room with our engineering, technology and marketing expertise supports better decision making and collaboration. This approach is reflected in the name of the centre, Moorditj Danjoo, which in the local Noongar language means stronger together. Building on this experience, we are preparing for Scarborough and Pluto Train 2 to also be remotely operated from Perth.

Across our operations, we have challenged our teams to implement practical changes that can reduce the carbon footprint from established assets.

We spoke last year about the development of asset decarbonisation plans and we are now implementing them. Efficient power generation is a great example. As an earlier slide showed, gas turbine generators are the second largest source of emissions on our LNG facilities, accounting for about 25% of total operational emissions. By upgrading hardware, optimising sparing and control systems and improving the electrical distribution, we are reducing emissions intensity of power generation at both the Karratha Gas Plant and Pluto LNG Plant.

Another example is upgrading seal oil systems on our main refrigerant compressors at KGP to reduce fugitive methane emissions. A further reduction in fugitive methane emissions, through an upgrade to the seal systems on the boil off gas compressors, is targeted for a final investment decision next year.

At Pluto, modifications were substantially completed this year in readiness for import of solar power from the proposed Woodside solar project. The solar facility, which will be based in Karratha, has now received approval from the state of Western Australia, one of the key approvals that supports the project's targeted FID readiness of 2023.

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Decarbonisation requires action across multiple fronts. While plant efficiencies and flaring optimisation are key focus areas for existing facilities, we have the chance to install more efficient equipment at our new facilities. Emissions reduction was a key consideration in designing our combined Pluto, Scarborough facilities and making them fit for the future.

As you can see, we are setting Australian Operations up to continue to deliver energy to our customers and deliver value to our shareholders. We have high-quality assets, we remain a high-margin business and are building on our reputation for delivering reliable energy supply. I'll now pass over to Daniel Kalms, EVP Technical Services.

Daniel Kalms: Thank you, Liz. My name is Daniel Kalms. I lead Woodside's Technical Services organisation. This includes our technology and digital groups and it's the focus of this presentation on those two areas. I've had a quite long career in Woodside. It's included some pretty significant time in operations and in projects and I think that gives me a good perspective on where and when technology can deliver results for our business.

Our business by design is technologically advanced, so when we invest in new and additional technology, it's in areas where we need to continuously improve, the four areas that you see on the slide. We have had an active technology plan for a number of years. Our people are innovating every day to deliver results from technology.

In the next couple of slides, I'll highlight some specific areas where we're delivering on safety and on cost. We'll also discuss how our culture supports innovation and we believe we can capitalise on the work we've done on digital with the opportunity of AI. The same culture and capability that we believe will allow us to make a step change in the cost of the technology for large-scale abatement of carbon emissions.

Let me start with drones and robotics, which we've spent some years working on. The main reason, the primary benefit, of investing time and effort in this is to improve safety and we do need to improve safety. We can reduce the exposure of our people to hazardous tasks and hazardous areas by using this technology. There are three use cases that are shown on the slide there, all of which generate additional benefits beyond safety, they also can improve the time for tasks and the costs for the tasks that we do.

Whilst the energy industry is technologically advanced, there are definitely things that we can adopt from other industries and I’ll highlight 3D printing. 3D printing is an area where we see that we can reduce the cost of our supply chain. We see big potential in this area. We have older assets that we are maintaining at a high level of performance. In order to maintain that performance, we must maintain them and supply them with parts. 3D printing provides an opportunity to print parts at lower cost, lower time and with lower supply chain risk.

We show an example on the left-hand side there, it’s a subsea control module. On the left-hand side is the original, it’s an obsolete part, you can’t source it anymore. We need a number of these. If we had to upgrade to the new model, it was a significant cost. We were able to 3D print a replica of that part that you see on the right-hand side. This is saving us $12 million. There are numerous examples through our business where this will happen.

In the middle and the right-hand side panel, you’ll see where we’re using sensors. In the middle, we’re installing sensors on our insulated pipework to measure humidity under the insulation. That’s an indicator of a corrosive environment. In the past, we would strip off the insulation to inspect it. That’s time consuming, that’s costly. On the right-hand side is an IoT sensor. We can get vibration monitoring on our fin fans at a much lower cost than a commercially available standard process control sensor. These things are driving down lower cost in our business.

It leads naturally into digitalisation. We leaned heavily into digital, probably ahead of most oil and gas peers.

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We pushed it because we could see the benefit in our performance: lifting production, improving energy efficiency, optimising our maintenance and it’s borne out through the results. We continue to lift the production of Pluto [Clarification: production lift in the future]. Our LNG reliability is world class. We now have in place the foundations for a digital transformation, sensors delivering data to a data lake, high performance computing allowing us to run simulation models of digital twins.

We’re paused now, able to automate and unlock the potential of AI. In future, we foresee an AI co-pilot working with our operations staff in our remote operations centre, providing insight and advice on how to lift the performance of the asset. Lifting the performance will drive more value and this is something that shouldn’t just be for our existing assets, we’re bringing on Scarborough and Pluto Train 2. Our ability to ramp up and achieve maximum production as early as possible can add significant value to our assets.

I want to touch on a picture next that Meg showed in the previous section. We are delivering and executing asset decarbonisation plans in operations. We are investing in bio sequestration. Both of these areas are delivering reduction in carbon at less than $80 per tonne.

We are working with a range of partners on less mature technologies that are at higher cost. Our objective is to work with our partners on a range of options and drive a step change in those costs to bring them down, to be cost competitive, to make them viable options, even alongside things like bio sequestration. Technology we can deploy in our assets.

If we go to the next section, we showed earlier that the majority of our emissions are actually related to LNG production, now and increasing in future, the proportion of our emissions. In the middle you see the stack of the specific sources of emissions. We’ve added on the right-hand side of this slide the options that we are pursuing against each type of emission. You see some of these technologies are relatively mature. We believe and know that we could implement them prior to 2030. There are some that are less mature, that we need to do more work on and we see them being able to be implemented post 2030, but still well in advance of our 2050 net zero aspiration. This is the work that we have to do to drive a step change in costs.

A common feature in many of those solutions is the requirement for carbon sequestration. Carbon sequestration is something that we’ve been working on for a period of time, in Shaun’s New Energy business, so I’ll hand over to Shaun to give a rundown on the New Energy portfolio.

Shaun Gregory: Thanks Daniel. My name is Shaun Gregory and I lead Woodside’s New Energy team. I’d like to update you on the progress of the New Energy portfolio.

Our new energy and lower carbon services strategy remains unchanged. Customers and relationships are at the heart of everything we do. Customers ultimately drive the demand and timing for new energy products. We need to collaborate with them and other stakeholders to ensure the entire value chain, from production to end use, is available on a coordinated and appropriate timeline. We are leveraging Woodside’s core capabilities and experience as a safe and reliable energy producer, targeting hydrogen and ammonia and emerging fuels.

And our integrated carbon solution business is integral to Woodside’s emissions reduction targets and in providing solutions for our customers. I also want to emphasise that while we are targeting large-scale investments in order to make a material difference, these are all underpinned by the discipline provided by the capital allocation framework that Meg spoke to.

As Mark outlined earlier, Woodside has been building relationships for decades with our traditional LNG buyers and we continue to extend that to new and emerging customers in new energy. Some examples include a heads of agreement with Keppel Data Centres, to evaluate the potential supply of liquid hydrogen to Singapore and a collaboration with Kansai Electric Power Company, to enable studies of a potential carbon capture and storage value chain between Japan and Australia. These are just two examples of the way in which Woodside is well placed to serve these growing markets, through existing relationships, collaborations and our core capability in delivering energy.

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Let’s now talk through the end use sectors we are targeting with our hydrogen and ammonia solutions. First, heavy duty transport, where we’re focused on hydrogen as a substitute for diesel. We are continuing to progress H2OK and our hydrogen refueller at H2Perth, both targeting this sector. Second, we’re targeting investments in hydrogen and ammonia for power generation. And ammonia also has the potential to decarbonise the shipping industry. In aviation, both hydrogen and CO2 are potential feedstocks for sustainable aviation fuel and finally, we are targeting hard-to-abate sectors where there is increasing opportunity for lower carbon hydrogen as an industrial feedstock.

I’d like to take a moment to provide you an update on H2OK. H2OK is centrally located along a strategic transport and supply chain corridor. This enables proximity to customers looking to adopt hydrogen as a fuel in the heavy transport sector. It is our most advanced hydrogen project, having secured the land, finalised power and water terms and awarded key contracts for long lead items, in addition to completing feed late last year. That said, we made a strategic decision to adjust timing of FID to align with policy developments and customer requirements behind the emerging hydrogen economy. Like many of our peers, we are awaiting further guidance on the US Inflation Reduction Act’s production tax credit.

Here you can see a portfolio of new energy opportunities. We are a global player and are continuing to build a diverse portfolio of opportunities in attractive locations, scalable with customer demand. We focus on locations that are advantaged to enable a lower cost of supply. If it is an electrolysis project, we need access to scalable, affordable power, which means a strong, renewable capacity factor. For reforming, we need access to a CCS solution nearby. And for all projects, access to existing infrastructure and a clear regulatory environment are also key.

Now turning to our integrated carbon solutions business. Managing carbon is not new to Woodside. We established the carbon business in 2018 and have been building these capabilities ever since. First, we are enabling our base business by managing the price risk associated with the regulations in Australia under the Safeguard Mechanism and assisting the operating assets in their decarbonisation plans. And our growing capabilities in the carbon business, which now include a portfolio of CCS opportunities are providing solutions to support future growth. Looking to the future, there is the potential to expand these services to provide solutions and offerings to our JV partners, customers and third parties.

I’d like to update you on the progress we’ve made across our three pillars. First, carbon credits, where our portfolio has grown to more than 20 million credits. These are important because they are available for us now and can be used in the short and medium term for emissions that cannot otherwise be avoided or reduced.

Our second pillar is carbon capture and storage. We are targeting high-quality storage reservoirs that enable large-scale sequestration. CCS benefits from scale. Where the fixed infrastructure costs may be recovered faster through high throughput rates. We are seeing more interest in CCS this past year and it is encouraging to see governments, including the Australian Government, lean into its potential to assist in decarbonising the world.

Our third focused area is carbon utilisation. Woodside is investing in technologies to convert carbon into useful products. This is an emerging area and we have been collaborating with several companies to drive the development of these technologies forward.

We have continued to build a diverse portfolio of carbon credits to support Woodside’s net emissions reduction targets. We use a mix of avoidance, reduction and removal type carbon credits and our portfolio is geographically diverse, which helps us to mitigate country and weather risks.

We are increasingly focused on originating our own carbon credits to manage cost and quality and targeting 50% nature-based solution credits through bio sequestration, which includes reforestation and natural growth.

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I’d like to show you a short video to see one such example project, three years on now in Western Australia.

[Video playing]

Now turning to the development of our carbon capture and storage portfolio. We are working to reduce emissions at our based operations first, with proposed storage capacity at the planned South East Australia and Angel CCS facilities. Together with Bonaparte, these three CCS opportunities could store over three million tonnes per annum of CO2 by 2030. And longer term, our future growth projects have potential to store our customers’ and third-party emissions. Our capabilities are well suited to this space as we have the technical know-how, subsurface expertise and experience with large-scale project development to deliver these projects safely.

As you can see, we have made a great progress developing our new energy and integrated carbon services in the last year. We are working to develop the products and services to help reduce emissions in our own business and that of our customers. And we’re targeting the parts of the value chain that not only play to our strengths but aim to deliver the best return on investment.

We have also developed a robust pipeline of opportunities, which if all progressed at current equity, would meet our previously stated $5 billion target. We want to create a sustainable, lower-carbon future for decades to come.

I will now hand back to Meg to close.

Meg O’Neill: Well thank you, Shaun, thank you all. We’ve covered a lot of territory today and I really appreciate your time. As I said at the start, Woodside’s strategy is to thrive through the energy transition. That starts with understanding energy markets and demand in a world that is growing economically and responding to climate change.

It is founded on Woodside’s long track record of growing value and returning value to shareholders through the cycle. A track record that the company is committed to going forward. It includes our approach to ensuring our business is sustainable in the long term and taking action to reduce our net equity Scope 1 and 2 emissions whilst offering our customers lower carbon energy products and delivering value to shareholders.

When we look across the sector, Woodside’s performance is clearly differentiated. Woodside’s defining features for many years have been consistent delivery of strong margins from our operations, returning cash to shareholders and gas developments which we believe will be increasingly attractive as part of the energy transition.

I’ll close with a slide that we’ve shown before that reiterates why Woodside. We have a high quality, global portfolio with low cost and high margin operating assets. We are developing other world-class opportunities that will sustain strong performance years into the future. We have a strong balance sheet, a clear framework for capital allocation to ensure that we are balancing shareholder returns with reinvestment in the business. And we are well positioned for the uncertainty of the energy transition, with optionality across the portfolio in oil, gas and new energy.

We’re very excited for the future and the opportunities that it brings. We look forward to delivering value and providing energy that the world needs.

We will now take a five-minute break and I’m looking forward to answering your questions when we return. Thank you.

Matthew Turnbull: All right, let’s, if everyone can come back into the room we’ll kick off the second half of the presentation this morning. So we’ve got about 40 minute, 45 minutes for Q&A which Meg will take. Logistics for this session, there’s a couple of roving mics, so we’ve got Shamila and Sarah. And so, if you’d

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like to ask a question, raise your hand. Please limit your turn to two questions, so we can get through everybody, and please direct your questions to Meg. We've got a couple of hands up already, which is great. We might just start with James then. No, James is giving the floor to Dale. We'll hand over to Dale and Meg will take it from here. Thank you.

Meg O’Neill: Thank you. Thank you, Matt, am I on? There we go. All right.

Dale Koenders: (Barrenjoey, Analyst) Thank you. Quite rare to be gifted the microphone. I just want to ask a question about the free cash flow outlook and really, Meg, your comments around us judging your strategy on thriving and creating value through the transition. When we look at the free cash flow profile on slide 25 relative to what was presented 12 months ago, 12 months ago you were forecasting US$4 billion of free cash flow in 2024, and it now looks more like break even and when we look at that terminal free cash flow level, now at around US$5 billion per annum out in 2027-28 versus more like US$7 billion 12 months ago, it looks like that free cash flow profile has stepped down materially. On my numbers, it's around $7 billion lower free cash flow over the next four years. I'm just wondering what’s changed in your view between those two profiles?

Meg O’Neill: Well, look, let me invite Graham up to talk you through the details of the two charts.

Graham Tiver: Good? Thank you. A good question, Dale. I think the two key points to call out is that what we positioned this year was a flat $70 from, as at today, through the - I think it was five years we put up. Last year's curve, last year's pricing was the curve at the time and I think it was $85, $87 per barrel [Clarification: 2024: $82/bbl, 2025: $77/bbl] which was brought into the early parts of the year but that is the main difference between the two. Obviously, there are nuances. Last year we assumed Sangomar would be up and operating by the start of 2024, there's a six-month delay, but in terms of key operating costs, key capex and the other assumptions in general, there's no real material change outside of the pricing side of things.

Dale Koenders: (Barrenjoey, Analyst) It looks like, from the slide last year, you’re using $82 a barrel in 2024 and you've given that price sensitivity of $1 a barrel, $58 million, so that's only $0.5 billion.

Graham Tiver: What are you saying the…

Dale Koenders: (Barrenjoey, Analyst) Have you really lost $4 billion or $3.5 billion?

Graham Tiver: No, we haven't. Maybe we can go through the detail of that outside of this, but there's not really a lot that's changed on top of that.

Dale Koenders: (Barrenjoey, Analyst) Then maybe just throwing a question for my second one back to Meg. We've seen some really large changes in the regulatory landscape over the last few months, particularly around Barossa, a project you're not involved in, but there's obviously ramifications for Scarborough. Could you provide any more detail on where that process is up to in terms of getting drilling approvals? Where the critical path is on your schedule? And where you start to get into problems about losing contractors? And then continuing that thematic, I noticed Browse is not in the pack at all, how does this increase in delays and cost overruns from the environmental activists actually impact your strategy? And how is the Board thinking about capital allocation?

Meg O’Neill: That sounded like about three questions, but I'll see if I can get through all of them. Look, the environmental approval and regulatory landscape is one that is changing very rapidly. Following the Barossa court decision last December, Woodside, the industry at large, have been working very closely with NOPSEMA, our regulator, to understand how to interpret the court's decision as it comes to the consultation requirements that are required for environmental plans.

And I think we've seen some really encouraging signs from NOPSEMA in the last, probably, three months. So they have approved a couple of EPs. One, of course, was the Scarborough seismic which had some conditions which the court has ruled NOPSEMA could not have issued an EP with those sorts of conditions

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so that we've updated the environment plan. But subsequent to that, NOPSEMA has approved without conditions an EP for some work with another operator. So we do believe that we as an industry, and we as Woodside, have greater clarity on what's required in terms of both executing the consultation and documenting it for NOPSEMA. And as Matthew noted, we have four EPs back with the regulator [Clarification: four EPs for Scarborough back with the regulator].

Now, from an overall Scarborough perspective critical path is construction of the floating production unit. We showed you the video there, just to give you a bit of sense for how that construction is progressing. It is progressing extremely well, but we do have flex in the schedule on other elements of the project. I appreciate that the market would like to have greater detail, but the reality is our project teams are very good at adapting to things that change. If we get to a point where we have something that we need to notify the market of when it comes to cost or schedule impact, we will do so but we're not at that point yet. We are still on track for the 2026 first LNG.

Second question you had was around Browse, so you’re correct Browse wasn't mentioned in the pack. The conditions we've been talking about for Browse are unchanged. So we've said we need three things for Browse - we need a carbon solution; we need kind of clarity on our ability to obtain environmental approvals; and we need commercial agreement to process Browse gas through the North West Shelf. We've made really good progress on a carbon solution and Shaun talked about CCS opportunities - Browse is one of those. Angel also is available to help manage the CO2 emissions from the plant. So, we feel like we've got good progress on the technical front related to CCS. We continue to work with the Commonwealth and State governments on environmental approvals and those applications have been with the regulators for several years now and we continue to try to move them forward but it is a bit of a challenging environment.

And thirdly, we are in active discussions between the Browse Joint Venture and North West Shelf Joint Venture on a potential tolling agreement. So, we continue to work on the things that are critical path. From the perspective of being sensible with our deployment of shareholder funds, we are being very measured in our approach to Browse to make sure we don't ramp up engineering ahead of resolving these critical matters. So, that's our focus for Browse.

Bigger picture, Browse of course is a fantastic resource. It's 15 plus Tcf of gas. We hear very regularly from the Government of Japan, customers in Japan and our joint venture partners that they're keen to see the development progress. So the appetite is there and, as we illustrated in some of the slides that talk about market demand, the demand for LNG from Browse is there, so we will continue to work with the Commonwealth regulator and the State to try to progress Browse.

Meg O’Neill: James?

James Byrne: (Citi, Analyst) Thank you, Meg. Good morning. The commodity price at the moment this year, call it $80 a barrel, so fairly high commodity price environment and yet on our estimates, the business is only going to earn an 8% return on its invested capital. I was quite perplexed by that. These comments - I certainly don't mean to drag you over the coals for any prior misallocation of capital, but you add up the numbers. Over the last 15 years, exploration expenses and impairments have been over for close to $5 billion; M&A impairments $3.5 billion; cost overruns on major projects about $3 billion, just shy of.

So if we think about this business today, notwithstanding all the dividends that you've paid, I kind of think that Woodside struggles a bit with actually creating value through growing the business. And yet today, the exploration footprint has expanded at global again. I don't think there are many people in the room that aren't worried about the execution on Scarborough, Trion’s been FID’d in a really difficult environment for procurement and on M&A you haven't been shy about telling us in the sell side about aspirations to look at acquiring assets in North America. So with all that preamble my question’s actually pretty simple which is, why is Woodside today more capable or more sophisticated on executing projects and allocating capital versus Woodside of the past?

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Meg O’Neill: Look, probably a key way to answer that, James, is following the merger with BHPs petroleum business, we have global reach; we have greater scale; and we have an incredibly strong focus on capital discipline. Now, if you think about the industry that we're in, we make money from producing from resources that are always declining, so after the first day you start production you've got a declining resource. So to continue to have a viable business, we do have to invest in future opportunities. But the position that we're in following the merger is one where we actually have the health, the scale, the size, the materiality to be more disciplined.

I think it's worth noting that, in our industry, scale matters. As the smaller businesses struggle and they end up being opportunity driven, we are strategy driven. So we will pursue opportunities that are aligned with our strategy. We will not be chasing opportunities because it is the only thing that we have available to us. And again, the past of the company is a very long one. There were, perhaps, points in time where we felt like exploration was the best way to grow the business.

I'll note that the exploration footprint we have now does continue to be very disciplined. The focus of the exploration team is to ensure that we're pursuing opportunities that have a rapid pathway to commercialisation. So, we're in places like the Gulf of Mexico, one of the world's most mature basins. We're in places like Egypt, again, a very seasoned, mature basin for oil and gas development. Namibia is an area which has the most significant discoveries in the past couple of years.

But the other element that we're putting to our exploration strategy, James, is making sure that we're really disciplined in the equity position that we take. If a deepwater exploration well costs $100 million, well, we don't want to be participating at a high working interest in just a couple of those - that's not setting us up for success. So we're being very disciplined in our partnering approach, very disciplined in risk management. M&A and organic growth are all opportunities but, as we said in the presentation, we do have portfolio choice now and that allows us to be much more disciplined about what we bring into the business.

James Byrne: (Citi, Analyst) Thank you, ok my second question, I want to pick up on the conversation you had with Dale earlier around the free cash flow outlook. If we normalise for some of the changes, like around Trion, adjust oil price according to the sensitivity you've provided around free cash for each dollar change in oil price, that 2025 to 2027 period we actually sort of get a, call it $3 billion downgrade in free cash flow. I also note that your guidance for operating cash flow and dividends both fall significantly short of the consensus estimates. So, I guess, I'd like to perhaps have a conversation in a bit more detail around some of those moving pieces.

For me, one of the bugbears I've had this year is I think that the market overestimates the outlook for Pluto production in the middle of the decade. I do think that it comes off a bit sharp. So can we, perhaps, talk in more detail around the outlook for the business in the middle of the decade?

Meg O’Neill : Sure. So, at a high level, not a tonne has changed year-on-year. As Graham noted, we've taken a different approach to the free cash flow chart this year to normalise for price. So last year the price would have been varying across the period, and that's why we've provided the three lines is to give a bit more clarity around in a static price setting - what does the cash flow generation look like?

Look, Pluto, really, fundamentally nothing has changed from last year, probably even the year before. We always, and I think we've been clear since we took FID on Scarborough, that when Scarborough comes online, we will be ramping back Pluto production because Scarborough and Pluto will share Train One. That does push Pluto end of field life out a few years, but I think we've been pretty transparent with that.

Perhaps this is something, James and Dale, that we can take offline and make sure we've got clarity on the models and how the models are working and address your questions in that setting.

James: (Citi, Analyst) Thank you.

Meg O’Neill: Let's go Tom and then Mark.

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Tom Allen: (UBS, Analyst) Good morning. Tom Allen from UBS. We've seen the number of 15 to 27-year LNG offtake agreements over the last six months that have come out of the Middle East, out of the US. Asia obviously offers a huge source of LNG demand growth, and Scarborough offers one of few new sources of LNG supply in that middle of the decade. Yet approximately only 25% of Scarborough reserve is contracted. The non-binding HOA with LNG Japan for 0.9 million tonnes was a good first step. The question is, can you provide a refresh on the LNG marketing strategy for Scarborough? Are you requiring equity in the upstream project with offtake and why haven't we seen more LNG offtake?

Meg O’Neill: Well look, let me start by saying that we have adjusted our strategy to LNG marketing over the last, probably, five years to move away from project specific contracting to portfolio contracting. So we do continue to market LNG from our overall portfolio but, again, as the market has grown and evolved and become more sophisticated we’re no longer source specific and the customers are often no longer destination specific as well.

Our marketing team is very busy out in the market right now, talking to a number of high-quality end customers in particular, to try to continue to place more volumes. And Mark talked a bit about our strategy of layering in LNG sales over the time period. Perhaps I'll invite Mark up to just share a little bit more of the flavour of what the team is doing and how we think about these opportunities.

Mark Abbotsford: Is the camera there? All good. So Tom, I think one of the things I would also note is, those deals that you're talking about from the Middle East into a number of European IOCs, and also to Far East NOCs, are 27-year deal starting from 2026, so it gets back to the conversation around the energy transition and the critical role of gas. So I think we've seen quite a significant change in terms of contracting strategies, obviously, with the particular projects that also aligns with some of the PSC terms. So that is actually quite a fundamental shift, particularly for those European counterparties that previously were not prepared to contract for as long beyond the 2042 period, so that's a pretty significant signpost.

To Meg's comment in terms of the activity, we've obviously indicated where our current gas hub exposure is. That doesn't necessarily relate to how much volume we have uncommitted, but it's a reasonable proxy. And then if you look at how it's tracking, and as I mentioned in my slides, to 30% to 35% in 2027, plus, when Scarborough starts, would indicate, obviously, we have a number of other arrangements in place. We are seeing, at the moment, the activity levels have spiked quite significantly. In 2022 we saw buyers very focused on the short term and managing a crisis. Now, we're starting to see a far more strategic lens to procurement activities. And as Meg said, actually our activity levels in this space are at very high levels at this point in time. Obviously, if and when we get to a point of disclosing something to the market, we will.

Meg O’Neill: Thanks, Mark.

Tom Allen: (UBS, Analyst) Thanks, Mark. Noting your comment, Meg, about moving to portfolio sales, I think a couple of the contracts, the Uniper, the RWE contracts that have been notionally attributed to Scarborough as European buyers and, naturally, you won't actually see Scarborough cargoes travel all the way to Europe, so it does mean that Scarborough, as a resource, is still very significantly undersold. The points that Mark made…

Meg O’Neill: Let me actually correct a point there. So both of those utilities are building LNG trading positions in the Pacific. So those are Pacific sourced contracts. Now, we did do one Atlantic sourced contract with Uniper last year, but the ones that have been attributed to Scarborough are Pacific sourced.

Tom Allen: (UBS, Analyst) Sure. In the comments that Mark made then around the contracting market generally being really favourable at the moment, but the question still stands. Why haven't we seen more out of this particular project? Is there any specifics related to the project that you can share?

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Meg O’Neill: Again, as I said, we don't sell project specific LNG anymore. We are selling everything on a portfolio basis. And as Mark said, we're deep in many discussions and when we have something to announce, we will.

Tom Allen: (UBS, Analyst) Okay, sure, sure. My question relating to Shaun’s section. I was wondering if you could provide an update on the indicative cost of the four different CCS concepts that you’re looking at and, on your offset portfolio, just the proportion that are Australian carbon credit units versus the international CERs and perhaps the indicative cost of that offset portfolio over the near term?

Meg O’Neill: Sure, let me invite Shaun back to speak to some of those questions.

Tom Allen: (UBS, Analyst) Thanks Meg.

Meg O’Neill: I think the split of Australia versus international was actually on one of those charts.

Tom Allen: (UBS, Analyst) Sure, I might have missed that.

Meg O’Neill: But Shaun can speak to what we’re doing on CCS and look, as you noted at a high level, one of the things that is critical with CCS is quantities, particularly when you’re doing offshore, you’ve got a high fixed cost, so we need to be working towards large volumes, but I’ll let Shaun talk to where we are on cost.

Shaun Gregory: On the CCS project yes, Meg’s right. We’re designing the facility at 5 million tonnes per annum for Phase 1 and looking to go to another 5 million tonnes per annum for Phase 2 and that fundamentally will impact - I think what you’re trying to find out is, what is the dollars per tonne of CO2 abatement cost and, of course, we’re trying to drive that well below 100.

Right now, we’re just past concept select gate for that, so all the engineering for the concept now is complete, but in terms of the detailed costing and, more importantly, how much of that 5 million tonnes gets taken up by customers, ourselves being one of those customers, will impact that final cost, so we probably wouldn’t look to disclose that until this time next year. And, you’re right. The graph in the - I can talk to you later after the graph in the chart provided shows about half of the carbon credits are in ACCUs.

Tom Allen: (UBS, Analyst) And the cost of the portfolio?

Shaun Gregory: I think we disclosed across the entire portfolio is less than $20.

Meg O’Neill: That’s US, correct Shaun?

Shaun Gregory: Yes.

Mark Wiseman: (Macquarie, Analyst) Mark Wiseman from Macquarie. Thanks for the update today. Just a question on Slide 32 with the gas hub exposure of 25% to 30%. There’s a huge amount of LNG capacity coming onstream really from late 2024 onwards. I’m a little surprised that you’re not trying to reduce that gas hub exposure through those first couple of years of the new wave. Could you maybe just talk about why that’s the right level and what your outlook is for spot prices?

Meg O’Neill: We’re pretty happy with the gas hub exposure, particularly in ’24 an ’25. As we reflect on what’s happened in the world the last couple of years and the tremendous volatility we’ve seen in gas, we want to make sure that we preserve enough of our gas production to be able to take advantage on future volatility.

And look, I appreciate past performance is not indicative of future, but one of the things that we believe is that structurally the LNG market has diverged from the oil market and in the oil market we’re seeing steps from OPEC, steps from consumer nations, that we think are driving towards an oil price that is range bound, whereas in the gas markets, we see far more volatility and it’s often driven by factors like weather again, if

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it’s cold in Japan or cold in Europe, those nations are going to buy because they have to. They literally have to keep homes warm. So we do want to preserve exposure to gas hub pricing in ’24 and ’25.

Where we're actually having more discussion as a leadership team is in that longer dated period and we’ll be watching very closely as the market evolves in the next couple of years. As Mark noted, we have more gas hub exposure today in that longer period, but there is more supply coming to market at that point in time as well. So that’s the area where we’re having more discussion as a leadership team, but again, if you philosophically believe that the LNG market is structurally diverging from oil, you’d say, actually, I want to preserve my ability to access those price peaks as and when they present themselves.

Mark Wiseman: (Macquarie, Analyst) And just on the Pluto project, you mentioned the Xena 3 addition. Could you maybe just talk through the ability to keep Pluto full up until the time that Scarborough comes onstream. Are there more investments beyond Xena 3 in that period?

Meg O’Neill: With both North West Shelf and Pluto, we are approaching – so both are very large, significant assets. We have been developing those assets over many years and we’re getting to the point where there are fewer undeveloped opportunities, so we have Xena 3, we have Lambert West in the North West Shelf. Obviously, it is a key priority for us to keep plants full as long as we possibly can, but we are coming towards the end of those points in time.

The Interconnector has been fabulous and Liz spoke about it in her presentation, so we were able to accelerate a tremendous amount of Pluto reserves through the Interconnector to be processed at North West Shelf into both domgas and LNG at a point in time where the world desperately needed more LNG. The flipside of that coin is that means we’ve accelerated Pluto reserves. We continue to look at the Pluto plant. We believe we’ll keep it full until Scarborough is online, but we continue to look at that very closely every year.

As I noted when Scarborough does start up, we will curtail Pluto to ensure that the two fields can share the Train 1 facilities.

Meg O’Neill: Hello Mark.

Mark Samter: (Millennium Management, Analyst) Thank you. Old habits die hard. Sorry Meg. Just a quick question if I can on slide 26, the sources and uses of cash. We can squabble about over the shading, but to make the maths easy, let’s say that underlying dividend at 80% payout ratio there’s about, it looks like, US$6.5 billion over that five-year period. That equals US$1.3 billion a year. That’s a 3% dividend yield. I guess when we compare that to the slide you put on page 76 looking back at the prospective 12-month dividend, you’re up near the top, but 73% is down near the bottom. As a Board, do you think that at $70 oil paying a 3% dividend is competitive enough, or is that something you need to think about on an ongoing basis?

Meg O’Neill: We’ve taken a hard look at our dividend policy many times over the years and there’s been a lot of question in the market about is NPAT the right basis, or should we be looking at something like free cash flow. One of the key reasons why we’ve kept to NPAT is in the period of higher capital spend, if we - our free cash flow gets substantially squeezed and this year is a good example of that, so we do want to make sure that we’re able to rateably pay a dividend over the period. We have a good track record of paying at a high yield. Perhaps I can invite Graham to speak to the specifics of the chart.

Graham Tiver: Mark, you will also see the lighter shade of blue at the top and that’s the flexibility that we have. I’m not sure where Mark is, sorry, but the cash generation - there we are, with the cash generation flexibility and I guess the underlying dividend policy will give us the amount that you spoke about, but obviously that additional lighter blue, which is the flex or the significant cash generation the business will yield from the three major projects coming on, that is the capacity we have to weigh up in terms of additional returns on top of the 80% dividend versus reinvesting that back into the business where see higher returns.

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So we’ve got the flexibility there, we just wanted to show just to highlight the capacity of the cash that the business can generate beyond the decade, or through to and beyond the decade.

Mark Samter: (Millennium Management, Analyst) Thanks. Maybe just slightly following up on James’ and Dale’s question about consensus, but I think consensus has about $11 billion of dividends over the same period at an 80% payout ratio on kind of mid-$70 oil. I don’t know if you guys have looked at consensus to get - and I presume the definition by definition that means consensus impact forecasts are too high off a fixed oil price. Do we know - is it something around PRRT payment? Is there anything you’ve looked at in consensus that maybe explains some of that?

Graham Tiver: Not - well, we do look at consensus, but I don’t have enough to give you the answer right now, Mark, but what I can say is that PRRT with the proposed changes, is not a significant driver in any of these conversations. It’s more of a timing issue.

Mark Samter: (Millennium Management, Analyst) Perfect, thank you. Thank you for indulging my brief cameo.

Henry Meyer (Goldman Sachs, Analyst) Okay, thanks Meg. I just want to follow up and go into a little bit more detail on the Scarborough risk please. In the event that the EP approvals are delays, I just want to touch on the flexibility you have in managing the drilling rig and pipelay vessel availability. There’s a lot of decommissioning work you have planned. Is there scope you could utilise the current rig to do some decommissioning work at other scope to reduce standby rate risk?

Then on the pipelay vessel availability, in the event that the EP approval is delayed and you might miss the slots, how are you seeing the pipelay market out there to potentially recontract a slot and the earliest availability you might be able to do that for the Scarborough trunkline please?

Meg O’Neill: Sure. So, the rig that’s scheduled to drill the Scarborough wells actually is doing decommissioning work for us today. It’s doing part of the Enfield decommissioning scope that Matthew spoke to.

Look we have that rig under contract and we’ve got - yes, that’s our rig. If there are delays it would be unfortunate to have to pay standby but, as I said, if we get to a point where we’ve got a material cost or schedule impact, we will notify the market.

The vessel that’s coming for pipelay is actually going to be arriving probably before year end. As Matthew noted, we have approvals to do pipeline installation in State waters, so the vessel will start work on that. Again, this is one where we would hate to be having to pay standby, but if it gets to a point where that’s a material impact, we will let the market know. I think we were pretty clear at the time that we took FID that there’s not a lot of vessels in the world that have this capability and unfortunately that’s the challenge with all of these projects, is that some of these vessels are quite bespoke but again, I’ll go back to the point.

NOPSEMA has now approved EPs without conditions that shows a pathway to being able to get approvals through. We have used that as a guide and confirmed that our consultation meets those requirements, so all of those applications are back with NOPSEMA.

Henry Meyer (Goldman Sachs, Analyst) Okay, thanks Meg. And my second question just on managing the North West Shelf decline. Conscious that the production profile going forward now is quite dependent on offsetting that decline and this could be quite a comprehensive question, but are you able to touch on the key points in the field management plan going forwards for the North West Shelf. Maybe touching on the current constraints on the main producing fields, how or when they’re expected to fail, whether it’s water drive or water break though or pressure constraints and then what opportunities you still have within, I think, the 1 Tcf contingent net resources to try and mitigate some of that decline. If we’re seeing just a straight drop or a bit of a staggered fall over time.

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Meg O’Neill: North West Shelf has been an absolutely fantastic asset for Woodside. We’ve been producing domestic gas for almost 40 years. It will be 40 years next year and LNG for approaching 35. It is a gift that has continued to give over the years. We’ve developed not just the big anchor fields, so Rankin and Goodwyn, but a number of satellite fields around the basin. We’re at a point - the reservoirs have different drive mechanisms and there’s always a bit of uncertainty. We model all of the reservoirs individually to make sure we understand the range of possible outcomes.

The history of North West Shelf, until the last couple of years we were plant constrained and so our focus was very much on LNG plant reliability. I’m really proud of how the team has pivoted to understand when you’re not LNG plant constrained how to operate the business. We’ve got projects underway to reduce back pressure, so that’s one of the key levers. If you’re trying to get more gas out of the ground and it’s as simple as releasing gas from a balloon, it’s the same mechanism. If you’ve got less pressure to fight against, you can get more gas out, so we’ve got projects underway to try to reduce the back pressure, try to squeeze a bit more gas out of the fields. All of those efforts are underway.

I mentioned Lambert West as an infill opportunity, so that’s assets that’s been on our radar for a long time and we continue to develop the subsurface understanding of that field.

The challenge of course is North West Shelf, the Karratha Gas Plant is a very big plant and it consumes a lot of gas every year, so once we shut down a train and Liz, I think, made this comment, even in a world where we bring Browse gas in, we don’t anticipate needing five trains to process the Browse resource. So we will be stepping trains down over time. The profile of that will depend a bit on reservoir performance, but the first train next year.

It's probably worth elaborating so from a – you asked, what else can we do with this fantastic resource, we are processing the Pluto gas through the Interconnector, Waitsia gas, we’re technically processing Waitsia gas now in sort of a commissioning phase and then we’ll start processing that at large scale when that field comes online and you’ll have to ask other companies about that. And we continue to talk to other gas resource holders in the basin about potentially processing through the Karratha Gas Plant, so we are looking for other gas that we can flow through the facility.

Henry Meyer (Goldman Sachs, Analyst) Thanks Meg. I might jump back in the queue.

Sarah Peyman (Operator): Thanks Henry.

Meg O’Neill : I think front row.

Sarah Peyman (Operator): Yes. Here you go, Nik.

Nik Burns: (Jarden, Analyst) Thanks Meg. Its Nik Burns here. Just a question maybe following up on North West Shelf first of all. You’ve flagged today that there will be train closing next year and if we look at one of your JV partners, BP’s recent presentation, they show over the next two years around a 40% decline in North West Shelf output. That will probably support the case for a further closure pretty soon after next year. Just thinking about - you talked about you will be looking at that, but at what point do you mothball rather than permanently close and who pays for the upkeep of those mothballed trains given ultimately, they’re being held in lieu for Browse for further down the track?

Meg O’Neill: As I said, the first train is a closure scenario. I’ve got experience operating late life LNG plants and the first train shutdown becomes the parts train and I expect that will happen here as well, particularly with some of the older equipment that we have.

Decisions subsequent to that will have to be made on the day. The cost difference between shutting down and mothballing isn’t tremendous, so we’ll leave it to the North West Shelf Joint Venture to sort that out. In some ways, the North West Shelf Joint Venture if it wants to market capacity for gas processing, it needs to

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maintain that capacity for gas processing, so a starting point would be North West Shelf would be making sure that it’s got capacity available to market to others.

Nik Burns: (Jarden, Analyst) Thanks. Just on your five-year capex outlook, it falls off pretty quickly and I think most of us probably look at it and model this growing free cash flow potential. That’s certainly how you’re showing it today. I guess history tells us that companies generally find ways to reinvest that. If we are here and say we roll the clock forward a year, you’re up there, you’re talking about the next major growth opportunity or opportunities on your books, which projects in particular are you really focused on that are closest to development? When will we probably see a reasonable chunk of capex allocated to it in the near term? Thanks.

Meg O’Neill: Yes, we talked about two in the presentation today, so H2OK is from a technical perspective quite mature, waiting on clarity from the US government around how those IRA incentives are going to be applied and that’s information that we need to have to be able to conclude offtake discussions with customers. Again, it’s a bit sequential on that front, but that is the most mature project in the hopper.

Shiva also spoke to Calypso, so Calypso continues to make good progress. We’ve got many of the attributes that are constructive, so it is a good quality gas resource. It’s not particularly big. It’s in a jurisdiction though that is very supportive of development, so Trinidad and Tobago, their whole economy is founded on oil and gas. They’ve got LNG, they have petrochemical, so the Government is very supportive of progressing Calypso. Our partner is supportive, so that one is a field that’s got a big of momentum.

As we talked about Browse, we’re working through critical issues. Discussions are underway on Sunrise but again it’s minimal investment at this point in time given the complexities of the two-government solution. We’ve got infill opportunities but again those would be captured in kind of the base capex there. So those are probably the leading.

But that said, there’s a fair amount of work in Shaun’s space as well and he spoke to some of the interest from customers. The Keppel Data Centres is perhaps a good example, so Singapore has been very clear with the data centre companies that they need to be bringing green power, so they have a very strong business imperative to tackle the question of how do they get low carbon power to continue their business expansion. So something like an H2Perth would be able to capitalise on those opportunities.

And it is worth noting that graph is only inclusive of committed capex, so Oklahoma, Calypso, those sorts of things are not included. If you looked at last year’s pack, we had a little bit of a dotted line that showed what that spend might be. Again, given the dynamic landscape this year, we chose not to put that on, so it’s just committed capex.

Gordon Ramsay: (RBC, Analyst) Hi Meg. I’m an explorationist at heart and last year, I think you had one slide on exploration. Maybe I missed it, I didn’t see one this year. You’re talking about projects to deliver growth and decarbonisation and moving to new energy. Can you maybe highlight what Woodside is doing on the exploration side and whether that’s now just very much an afterthought and hydrogen is the new exploration for the company?

Meg O’Neill: I think there was a bullet on exploration in Shiva’s section which she spoke to. Exploration is an area that - maybe let me step back. As we think about tools to grow the business, there are probably three key levers. One is exploration, one is developing assets that we have in house today and the third would be in organic approaches through M&A. We want to make sure we've got activity in all three of those pillars, because again the suite of opportunities that we have today, some of them look appealing but some have challenges, and you can again never really tell until you start moving things forward about how it's going to pan out. So, we do want to keep the door open on the exploration front and the M&A front.

In exploration, the mandate to the team has been really clear. We do have an exploration budget and I think we've provided guidance for this year and we'll be spending within that guidance range. We want to be

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focused on places where we've got a rapid pathway to commercialisation, and the industry unfortunately is littered with examples of things that were technical successes but commercially challenged.

So, we're very much focused on Gulf of Mexico, again it's a very mature basin, a long track record of development capability, it aligns with our capability as a deep water company. We are in non-operated positions in places like Egypt, again a country that has a very strong commitment to oil and gas development. And there's some great examples there of fields being discovered and commercialised very rapidly.

So, we want to make sure that our focus is in places where we have that line of sight to rapid development. Calypso's probably a great example of something that came to us in the merger, again a discovery in a country that strongly supports the industry, where again you've got the right fiscal framework, you've got the right commercial framework, you've got the right industrial setting. So, that's going to be our focus.

Gordon Ramsay: (RBC, Analyst) Okay, and just second question on Calypso, how important is getting access to Atlantic LNG for the commercial development of Calypso? Is the government facilitating that at the moment?

Meg O'Neill: The government's been doing quite a bit of work actually to harmonise the fiscal terms for Atlantic LNG and to commercially restructure that venture. The reality for us though is we're interested in both LNG and we've got the option for sales into some of the petchem facilities. If you reflect on Shaun's discussion, one of the key forms of hydrogen that's going to be attractive is ammonia, and there are facilities in Trinidad and Tobago that produce ammonia.

So, we want to make sure that we keep the door open, that we create a bit of commercial tension amongst all the potential processors of gas and consider options for us to offtake our product as well. So, that's very much a live conversation right now. But we believe we'd be able to access Atlantic LNG if that was our preferred development concept.

Gordon Ramsay: (RBC, Analyst) Thank you.

Rob Koh: (Morgan Stanley, Analyst) Thank you, and good morning, Ms O'Neill. First question is again on the offshore approvals with NOPSEMA on environmental plans. With the Federal Court ruling on the Scarborough seismic, there were two elements to that decision, one was in relation to the condition of consultation, which you mentioned, and your team is doing an extraordinary amount of consultation in the region, I want to acknowledge that.

The second element to the case was around the determination of the relevant person in that case. Just wondering if you can talk to the strategy there and the thinking there and how that fits in with the wider social licence that you're thinking about on the project?

Meg O'Neill: Sure, so in the court case, the Judge ruled on the conditionality of the approval, the Judge did not even consider then the question of relevance and whether or not that individual was a relevant person. So, that actually is in some ways at the heart of the process that we've been evolving with NOPSEMA, is the process around determining who is relevant.

Matthew showed a picture of the coastline to illustrate the breadth over which we've been consulting through our view of groups that may have relevance to these decisions. There is a question around whether or not an individual can self-declare themselves a relevant person. If you look at some of our documentations you'll see that we try to cast a wide net in that space to ensure that we are consulting adequately.

You may have also noted some comments from the Judge that if a person wants to be relevant, they have to participate in consultation. So look, I fully expected the question of the substantive consultation and relevance, I would expect that that matter will get heard again in due course. But as I've said a few times, the

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critical path for Scarborough is floating production unit, we do have, we believe, flexibility in the other activities to be able to maintain that first LNG target.

Again, if we get to a point where that's not the case or we see a more significant cost schedule impact, we will notify the market accordingly.

Rob Koh: (Morgan Stanley, Analyst) Thank you so much. All right, second question, just relates to H2OK and we'll be trying to model and assess that one on the capital framework that's nice and clear, we appreciate that. Just wondering if for modelling purposes we should be thinking about non-recourse finance or green purpose finance for that, if there's anything else that helps with that, I guess it's as 10% equity IRR, thanks.

Meg O'Neill: Yes, it's a great question and actually if you look around the new energy space you would see there's probably more money that wants to invest in this space than there are viable opportunities to be invested in. The strategy we've taken with H2OK, and we're taking with all of our projects, is we want to get the project to a level of maturity where we can then go out to the market and solicit either a partner or a financing opportunity.

Maybe the best example for you is what we did with Pluto Train 2, so we had a project that was well advanced, we were of course talking to GIP for a fairly long time period ahead of that, but we didn't want to bring them in too early and risk slowing down the project. So, we completed the bulk of the commercial negotiations between the upstream and the downstream, and then were able to bring that partner in, in that case it was right before FID.

For H2OK, the capital load is one that we believe we can readily carry within our own balance sheet's capacity, so we're not set to bring a partner in pre-FID, but I do expect when we hit that milestone that there'll be plenty of companies that are interested in coming into the project with us. So, that's certainly something that we're considering, but with the Oklahoma project we want to get it over the line. We want to get it over the line.

Rob Koh: (Morgan Stanley, Analyst) Sounds like a good order of preference there, thank you.

Meg O'Neill: Thanks. Look I think we're approaching time, we've got - sorry it's bright, who is that? Yes, we’ll do one more.

Henry Meyer (Goldman Sachs, Analyst) Excellent, thanks Meg, Henry Meyer from Goldman Sachs. Just a final question if I can on Sangomar? I think I asked this last year, but you've now drilled another, or 16 wells out of total. How have the static properties of the reservoirs you've drilled through, particularly in the shallower S400s compared to expectations? Have you got data now that would give you more confidence in delivering phases 2 to 5? Or is it still too early to say?

Meg O'Neill: Short answer is it's still too early to say. So, we focused our drilling campaign initially on the deeper reservoir section, which is the heart of the Sangomar Phase 1 development. We have now been drilling some of the shallower horizons. Geologically we're seeing reasonable conformance with what we're expecting, but as we've said all along, the key question for us in the shallower horizons is connectivity and how they perform in a dynamic setting, and whether or not the water from the injectors can sweep through to the producers.

So, we really won't know that until after we start-up. So, it's something that we're watching very closely and the team is updating our subsurface models as we go. We're really pleased with how the drilling campaign has gone, but that still is going to be an open question for us. It's probably going to take us call it 12 months after start-up to have a sense of are these wells connected as we expect or not?

Henry Meyer (Goldman Sachs, Analyst) Great, thanks Meg.

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Meg O'Neill: All right, well look let me once again thank everyone for attending the 2023 Woodside Energy Investor Briefing Day. We really value this opportunity to connect with the markets, to our shareholders, the analyst community, the media, the banks and everybody who's interested in the business. We find this a valuable setting to talk to you about our strategy and what our priorities are. I hope that you have found the day valuable as well.

So again, thank you for your attendance and we look forward to seeing you again in 2024.

End of Transcript

Contacts: INVESTORS

MEDIA

Matthew Turnbull (Group) Christine Forster M: +61 410 471 079 M: +61 484 112 469 E: christine.forster@woodside.com Sarah Peyman (Australia) M: +61 457 513 249

Rohan Goudge (US) M: +1 (713) 679-1550 E: investor@woodside.com

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

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