Good morning and welcome to the presentation of Santos’ 2025. I’m speaking today from the traditional lands of the Kaurna people.

I pay respect to Elders past and present. I also acknowledge the traditional owners and Indigenous people everywhere Santos operates.

Before we start, I draw your attention to the usual disclaimer on slide 2. Santos delivered a strong result despite lower commodity prices, with the base business continuing to demonstrate the resilience operating model.

I’ll begin with an overview of our results before handing over to our Chief Financial Officer, Lachlan Harris, to present. Chief Operating Officer Brett Darley will then discuss the operational performance of our base business.

Following Brett’s presentation, I’ll take you through our outlook and strategic priorities for 2026 and open the call up to questions. In 2025, personal and process safety performance were outstanding, top quartile of our sector globally for personal safety and outperforming the global benchmark.

Our lost time injury rate and total recordable injury rate were Santos’s best on record. Process safety performance, measured by the loss of containment incident rate, was the best on record.

While we are proud of these outcomes, we remain focused on continuous improvement, and I want to thank all of our employees across our global operations for their hard work and commitment to continuous improvement. Slide 5 summarises our 2025.

The business generated strong revenues and delivered free cash flow from operations of $1.8 billion, $2.4 billion, and underlying profit after tax of almost $900 million. 26.9% including leases, and 21.5% excluding leases, notwithstanding a capital-intensive period.

This performance disciplined focus on costs, reliability, and margin. Accordingly, we will deliver a dividend of 10.3 US cents per share, 48% of free cash flow from operations in the second half.

Operating model, the base business continues to improve reliability. Total production for the year was 87.7 million barrels of oil equivalent, an increase on 2024, and unit production cost was the lowest in a decade at 78 cents.

Pleasingly, we received more than 900,000 acres for Moomba CCS Phase 1. BNG LNG plant was at capacity throughout 2025.

We saw plant reliability of more than 99.5%, and our marketing and trading team purchase agreements in the year, compounding growth in shareholder returns, extraction from the underlying portfolio, and a disciplined application of our capital allocation framework. The 10.3 cents per share will be returned to shareholders in the final dividend, equivalent to 48% of free cash flow from operations and in line with our commitment under the capital allocation framework.

The total amount returned to shareholders for the year is 23.7 cents per share, which is 43% of free cash flow. The board’s decision to increase returns to shareholders reflects that Barossa is now producing, and gearing has passed its peak at a lower level than previously anticipated.

Over the last seven years, compound annual dividend growth of more than 13% has been achieved despite a period of major capital global inflation. Santos delivered Barossa, a tier one long life asset within around six months of the original planned start date, and without drawing on additional budget contingency.

For a project of significant achievement, it demonstrates outstanding project self-execution and discipline through the challenges of COVID, global supply chain disruption, uncertain regulatory approvals, and underperformance. Just as importantly, it demonstrates our capability to execute major development projects while continuing to run the base business efficiently.

We’ve taken a very considered approach to the final stages of commissioning to ensure offshore operations achieve as quickly as possible once full production is achieved. The project is a highly technical complex improve operational efficiency and emissions, and we’re currently producing at just under half rates while we go through a sequence of compressor dry gas seal change out, to full production rates in the next few weeks.

This one was achieved in January, with ramp up to plateau production rates expected around the middle of the year. Commissioning is underway at the seawater treatment plant, Nanushuk drill site B, and the Nanushuk processing facility.

Another key milestone towards first oil. Drilling performance remains strong.

26 well and continue to push technical limits. Two combination wells have been completed, including a record 10,000 foot horizontal section with a single well.

Combination wells deliver savings on cost as well as rig time, accelerating the drilling schedule and getting more reservoir. 20 development wells have been flowed back, including expected startup flow rates of approximately 7,000 barrels per day per well, in line with pre-drill expectations.

Productivity to date, with expectations of flow rates of approximately 8,000 barrels per day. Once complete, Phase 1 together are expected to lift Santos’s production by around 25% to 2025 levels.

In 2026, integrated into the base business and we right-size the business, we expect a reduction in headcount of around 10% across the business. Moving to slide 10.

Santos holds a unique and diversified resource base, reserves life and a 10-year 1P life, support billion barrels of oil equivalent in reserves and contingent resources, and depth of our inventory underpins our strategy to continue to backfill existing infrastructure and grow production. Significant resource additions following the appraisal campaigns in the Beetaloo in 18 months or so.

Across support opportunities embedded in the base business, these have the potential to leverage existing infrastructure to lift production and deliver strong returns. Our ambition to maintain production between 100 and 120 million barrels in the near term, with clear pathways to sustained growth beyond that.

It’s the disciplined low-cost operating model in action. With a relatively stable, we have still managed to reduce unit production costs during this period, despite falling commodity prices, resulting in our ability to increase shareholder returns over this.

We have delivered two major developments, Moomba CCS and Barossa, and are closing in on the startup of Pikka Phase 1. All of this has been achieved by improving our personal and process safety performance and lowering our emissions.

Santos has already achieved its target, supported by the world-class Moomba CCS. The role lower-carbon gas can play in delivering energy security while reducing emissions.

Our strategy remains clear: generate strong cash flow, reward shareholders, reinvest to backfill new capacity and grow production, and continue to operate efficiently. I’ll now hand over to Lachlan to provide an overview of our financial results.

Thanks. I’ll step through the financial performance for 2025, which reflects a resilient base business and disciplined execution.

In terms of our 2025 financial highlights, free cash flow breakeven $43 per barrel, demonstrating the ongoing cost discipline from our base business. All-in free cash flow breakeven was $58 per barrel.

Going forward, we will target an all-in free cash flow breakeven of $45 to $50 per barrel to invest in projects that add high-quality production volumes, reserves and resources and continue fit opportunities. Unit production cost was $6.78 per barrel, the best result in a decade, achieved with FX tailwinds, total 2025 dividends of $770 million includes a $35 million.

Pleasingly, gearing finished the year at 26.9% including leases, which is a real positive, noting we are at the conclusion of our peak capital investment phase, Barossa is in production, and Pikka Phase 1 nearing completion. We are committed to a resilient balance sheet and maintaining an investment-grade credit rating following the delivery of Barossa and Pikka Phase 1.

This financial growth deliver shareholder returns and actively manage gearing. Our continued investment-grade credit ratings from Fitch, Moody's and S&P reflects Santos's disciplined capital management and lease since 2016.

Our long-dated debt maturity profile supports financial stability with an average weighted term to maturity of 2025. We accelerated the final repayment of the PNG LNG project, repaying the debt.

The early repayment reduces interest costs and removes restricted cash requirements, which helps strengthen our liquidity position, with approximately 4.3 billion dollars of liquidity across cash and undrawn facilities. There are no scheduled debt maturities in 2027.

During 2025, we also issued a senior unsecured 10-year bond offering in the U.S. 144A Reg S market.

This capital further strengthens our funding base and supports disciplined growth from our high-quality diversified portfolio. Consistent with our capital management framework, we continue to protect and strengthen the balance position through hedging strategies for both commodity and FX exposure.

Hedging has been undertaken at rates well below the long-term Australian dollar FX average, providing strong protection for the balance sheet. This is what has funded the development projects, whilst providing strong returns to shareholders.

Our underlying earnings strong at over 4.9 billion dollars, generating EBITDAX of 3.4 billion dollars and underlying profit of 898 million dollars. Underlying profit is lower than the prior year reflecting lower commodity prices and a higher...

Our 2025 free cash flow from operations highlights the strength of Santos's diversified portfolio, long LNG contracts, inflation-linked domestic gas contracts and continued cost discipline to maintain high gross profit margins across the portfolio, with a gross profit margin of 33.7%, delivered savings of around 50 million dollars and continue to target an annual savings run rate of 150 million. Previously advised, once Barossa and Pikka Phase 1 are online, we expect our free cash flow sensitivity to increase for every $10 movement in Brent oil, up to $550 movement.

As outlined earlier, production costs of $6.78 per barrel in 2025, supported by FX tailwinds, and our track record shows we continue to outperform our peers in this space. In addition, we remain focused on our target of less than $7.

Santos is Australia's low-cost operator, and that is not a slogan. It is a competitive advantage.

With the production from Barossa and Pikka Phase 1, we are well-positioned to fully fund the base business and growth capital requirements, including exploration and appraisal, decommissioning, corporate and funding costs, and investment in growth at an all-in five to fifty dollars per barrel. Our portfolio will keep producing barrels of oil equivalent over the next few years, but the 45 to 50 dollar framework allows us to pre-invest, including exploration and appraisal projects such as Papua LNG, Beetaloo and the Bedout Basin.

Cash flow in excess of break-even will be returned to shareholders at a minimum of 60%, degearing the balance sheet or increase shareholder returns. With a strong balance sheet, Santos has the ability to take advantages of opportunities.

Thank you, and I'll now hand over to our Chief Operating Officer, Brett Darley.

Thanks, Lachlan. We turn now to the operational performance.

Our base business has safety remains a leading indicator of operating capability, and we achieved our lowest lost time injury. We are getting more from our infrastructure, with reliability above 98% across PNG gas, PNG stream facilities.

The GLNG plant at Curtis Island achieved 99.5% reliability. An advantage for Santos is our ability to self-execute projects.

In 2025, 296 wells were drilled globally, in the Cooper by two and a half days per well, drilled a record 8,200-meter horizontal well in Alaska, lateral CSG well in Queensland. In 2025, PNG LNG sustained an annualized 16 million tonnes per annum, supported by plant reliability of more than 98% and the first full year production from Angore.

We effectively ran full for the year, with upstream capacity. We intentionally choke back some of our operated wells, a strong position that highlights the depth and flexibility of our resource base.

Our stand-alone PNG LNG gas supply, with upstream operated gas reliability of 98%, pleased with a safe and accelerated startup in the first quarter. In the fourth quarter, averaging around 60 TJs a day, further adding volume and resilience to our supply base.

Alongside strong operational cost performance, upstream PNG production costs decreased 34 cents per BOE, and overall we delivered a 5% reduction in unit production costs with initiatives, including the re-org of our supply chain and logistics services, delivering around 1.3 million in sustainable annual savings programs, contributing more than $5 million in savings in 2025. Put simply, PNG LNG is performing, costs are improving and we've got a deep runway ahead of us.

It's a high-quality, long-life asset in a very strong position. PNG and our Queensland CSG operations delivered another year of strong performance.

GLNG produced 6 million tonnes of LNG, shipping 199.5% plant reliability. We also planned on schedule.

GLNG continued to support the East Coast domestic gas market, supplying 11 petajoules and working with our joint venture partners to exercise contractual flexibility, we can continue supporting the domestic gas market in 26. Upstream supply remains stable with record production rates from Roma of 223 terajoules per day and record average production from Scotia of 105 terajoules per day, underpinned and we continue to focus on disciplined cost performance.

In 2025, we completed seven... enabling the shutdown of a legacy facility.

These initiatives delivered cost savings and unlocked an additional 15 terajoules a day of incremental production. At the well level, we continue to push technical boundaries.

Pump life has improved through solids handling initiatives and the roll-out, which reduces failure rates and improves uptime. We also extended our well to a lateral CSG well in achieving our longest in-seam lateral length at 3.

Reservoir access and improving recovery. In Western Australia, our focus on reliability, infrastructure-led value continues to deliver strong results.

Varanus Island in 2025. Production costs improved by around $66 million compared to 24, with unit production costs down 15 cents per BOE, benefiting from strong contribution from the Halyard 2 well and FX tailwinds.

The Halyard 2 infill well is a strong example of our self-execute capability. It came online in the first quarter and has exceeded pre-drill deliverability expectations, reinforcing the value of developing reserves close to existing infrastructure.

The same tie-back model underpins approval of the John Brookes 7 infill well as the next Varanus Island compression project phase 2 has developed around 24 million barrels of 2P reserves. The Cooper Basin was impacted by a record-breaking flood event on a scale not since, affecting more than 200 wells and several upstream compressor facilities.

Our focus throughout has been the safe recovery of these facilities, which have now returned to pre-flood levels. We have safely reinstalled facilities and restored more than 2,500 kilometers of road access.

Importantly, drilling activity continues drills and 80 wells connected during the year, as a reconnection in early 26, once residual floodwaters recede and full access to flowline routes is restored. Beyond recovery, we continue to advance the long-term potential of the Cooper Basin.

Whilst the Cooper has its challenges, opportunities including the Granite Wash and the Patchawarra tight gas plays. Our future investments will focus on these areas that provide higher margins and contain the majority of our future reserves.

We have also progressed in the planning of a new way of operating these areas with the development of the Moomba Central optimization, Transform the cost structure in the central area of the basin, and we have plans in place to change the way we are thinking about the Cooper Basin more broadly. In 2025, we also implemented our integrated remote drilling ops center, safety and cost by taking people out of the field and reducing evaluation costs, and is expected to deliver annual recurring savings.

It will also improve our stimulation and completion activities. I'll now hand back to Kevin.

Thanks, Brett, and thanks, Lachlan. As we step back and look at the global energy system, energy demand continues to rise.

The transition, it's adding new supply to meet structural growth. Gas plays the only scalable, dispatchable fuel capable of supporting stability.

That makes it a foundation fuel for economies. Asia remains at the center of LNG demand growth, with consumption forecast to expand strongly through to 2050.

Santos is well positioned with advantaged tier one customers and a track record of reliability. In a world of geopolitical uncertainty and shifting trade dynamics, that means customers are prioritizing dependable partners.

At the same time, oil demand remains resilient, competitive, low break-even supply that strengthens our portfolio. That structural demand growth is not theoretical for Santos; it's already in performance of our LNG portfolio.

Our LNG portfolio value through disciplined end-use customer focused contracting. 83% contracted over the next five years, with portfolio pricing realized slope to Brent in 2025.

Our average contract price remains above peers, cash margins. Our proximity to Asian demand centers provides a structural advantage with lower shipping costs, faster responsiveness compared to more distant suppliers.

That adds flexibility. With multiple LNG sources, we can direct volumes into highest value markets and respond to short-term needs.

Our LNG portfolio is also weighted toward higher heating value gas, pre-Barossa, which together account for over 75% of our equity LNG volumes. Customers place, and is reflected directly in our realized prices relative to our peers.

That demand and portfolio, for execution, which brings me to our 2026 strategic priorities. There are eight priorities that will guide our focus in 2026 and form a single operating framework: cost discipline and long-term value creation.

I'll step through each of them. The first priority is delivering Barossa, establishing it as a reliable tier one, long-life, cash-generative asset.

Barossa is expected to achieve full rates in just a few weeks' time, and throughout the next few months we'll work to overcome the usual early issues on any new project to achieve the sort of reliability we see across the rest of our operating assets. The second plateau production rate, with a focus on a safe, controlled ramp-up to steady performance.

We expect to achieve in quarter, and then that focus will turn to achieving the expected levels of reliability of any other. The third priority is delivering on PNG LNG, as a core asset in our long-term portfolio, supported by a prolific resource base.

Our focus is on sustaining capital opportunities, including an oil infill drilling program. These are practical, very high return projects designed to extend asset life and preserve cash generation.

The fourth priority is progressing Papua LNG to final investment decision. Papua represents the next phase of development and is underpinned by a net 2C resource of 1.6 TCF.

Just the other day, I was pleased to hear the CEO clarifying the improved cost position, that we are aiming to get an FID decision around the middle of the year. The second appraisal activities.

Beetaloo is a transformational opportunity for Australia and Santos. The scale of the resource is globally significant and has the potential to reshape our future.

This is not a marginal resource addition. It is a new basin with the potential to supply both domestic and LNG markets.

Subject to... Our 2026 program is focused on proving commercial flow at scale and demonstrating the basin's development potential.

Importantly, Beetaloo sets that has established a clear pathway for responsible development. Alongside being the Bedout Basin appraisal program, this work expands future supply options.

We've already discovered five fields in the basin, with contingent resource of 230 million barrels of oil equivalent. Gas and liquid concept is about building scalable value from that emerging position.

We're planning to drill up to three gas wells to further define that potential and optimize the development concept. A future gas development could be brought back to Devil Creek gas plant to access the domestic gas market, or LNG processing infrastructure to provide access to the export markets.

It's early stage, but the ingredients for a material high rate of return future are there. Now that we are nearing the end of the current capital intensive investment phase, we're keen to get back to focusing on moving this opportunity forward.

Moomba CCS for large-scale carbon storage. The seventh priority is extending that capability through development of a Northern Australia CCS hub.

Northern Australia is well positioned to become a CCS center, supported by capacity and proximity to regional emitters, underpinning a development for Bayu-Undan, which has the potential to be one of the world's largest... With existing wells and facilities already in place, Bayu-Undan could provide low-cost, large-scale commercial storage for regional CO2 volumes.

In parallel, we are progressing feasibility work on additional storage options in the Bonaparte Basin, including G11. That upcoming work program is focused on expanding Australian storage capacity framework.

The eighth priority is to conduct a strategic review of our Australian integrated... including the Cooper Basin, Western Australia and Narrabri.

This review is underway and we will share further details at our investor day. In closing, the momentum we built in 2025, driven by strong base business performance for Barossa, carries directly into 2026, with first LNG from Barossa and our execution agenda focused on disciplined delivery and continued value creation for shareholders.

Thank you.

Good morning, thank you very much, and congrats on a Santos team. My first question just relates to Barossa entry on the CO2 that's coming out of the field in the early days.

Looking at your climate strategy document, you're kind of looking like Bayu-Undan CCS FID readiness in about... could outline some of the critical path towards that, if that's correct.

Thank you.

I'm not quite sure of the first question. I'll try and answer that as I understand it, but I think you mean during the commissioning phase for CO2 emissions as you do some flaring as you're commissioning activities, but obviously once we go into full production, it'll be in line with our environmental permits.

As you probably are aware under the safeguard mechanism rules, Barossa emissions from day one. That will be our plan until we are able to develop a CCS solution for those emissions from day one.

In terms of the second part on Bayu-Undan, yeah, we'reFID completed the FEED work. We have a little bit of work to do before we take FID.

I'd say we're FEED complete, and there's a little bit required to do basically to finalize costs and cost estimates, but the engineering design work is funded. That would be an excellent project.

We're in discussions with the regulators about moving forward and trying to progress. It's really those activities that are required before we can go to the next step and take FID, and that would take, yeah, I think 2027 second half is probably realistic in terms of as quick, but really it depends on how we get on with the two governments, the two national governments, cross-border approvals for the transport of CO2 and in Timor-Leste.

Great. Thank you.

That's super helpful. My second question's on the, and just wondering, you've given us guidance for this year, just wondering if you can maybe give us a steer on the longer-term outlook.

Then also, I guess during 2025, I think you came in a little bit under budget, except for the cyclone impacts. I'm just wondering if you can share any kind of learnings for future efficiency of decommissioning?

Look, first of all, I'd like to say the majority of our decommissioning activities are in Western Australia under Jason Young, have performed fantastically over the last two years, expediting decommissioning in an extremely cost-efficient, industry-leading way, and they've come through with lots of innovations. It's a cost; every dollar you spend on decommissioning comes with no return on it, yeah?

I can't think of it as spend, but it's not investment spend. The guys have done a fantastic job over the last couple of years, 600 to 700 million U.S.

dollars of liability off the balance sheet. As much as the liabilities have only come, we build new projects like Barossa and Pikka, they go back on our books, but of course they're 20-plus years out.

We're liquidating a lot of that near-term stuff, and we'll continue, I think, anywhere from the sort of 200 to 300 million dollars per year is probably a good way to think about the level of activity over the next few years. You point to some of the cost under-spend and some of the team have been able to deliver under budget.

The WA job you're referring to is about 22 million overall last year. There are lots of learnings, and we're continually recycling some of that stuff back through the organization.

Costs required to decommissioning our activities down, but operations teams, commercial teams, we're getting good commercial solutions. For example, we were able to sell a vessel for someone else to use it last year, and that was a bit of a win for us, and you can see FPSO.

The time it took from shutting the field down to that vessel exiting the country was best in class, pushing every boundary, and we're really proud of the effort they've turned in there to go. Over the next few years, we'll continue to drive those costs down, continue to learn.

As in decomm, building that capability in-house is something we've put a lot of effort into over the last few years to minimize that risk and minimize that cost.

Great. Thank you so much.

Morning, Kevin. On Santos's free cash flow sensitivity to changes in oil, when Barossa and Pikka phase one are at full run rate, 50 percent stronger free cash flow sensitivity per $10 barrel change in volumes and lower head count is clearly a key driver, but what else?

Are there changes to baseline capex are implied there too, or broader cost reduction initiatives?

Tom, all of those things matter, right? Variables go into that.

One of the biggest contributors is, of course, the fact that 60 percent of our production is LNG, 10 percent and 20 percent from our Australian integrated oil and gas assets. Those higher costs and coming in from Alaska are driving that free cash flow sensitivity in the right direction.

To think Santos is now a company that, if you go back a decade, we had a 13.5 percent investment in a tier one asset for that because we had balance sheet challenges at the time as an organization. If you look at us, certainly from 27, we'll have three tier one assets.

We'll be 50 percent equity in Barossa. We're 39.5 percent equity in PNG.

That is giving us a much higher percentage of that cash flow sensitivity.

Thanks, Kevin. Just on your broader options to accelerate deleveraging.

We've seen a couple of capital recycling initiatives last quarter, and up in the Bonaparte Basin. Can you comment on broader initiatives and perhaps tidy up the portfolio further?

I think on the call, strategic priority in regard to the strategic review, you might have mentioned at the Cooper Basin, Narrabri in WA.

Oh, I admire your effort to get me tell you what the answer is. I'll give you credit for that.

Look, we've talked about the strategic review, but I go back to the fact that really what's driving Pikka come on line, Santos's portfolio changes, because as much as 60 coming from our LNG assets and 20 percent from the oil project, it's from our Australian integrated oil and gas assets. Those three tier one high-value growth opportunities around those as well.

What changes now is, of course, we've put in place the 45 to 50 dollar forward for the organization, and within that we still want to grow the business, right? Margin and the highest value opportunities will win.

That's where we will invest. It changes the way we think about what and where we invest.

The review, and the opportunities around those assets, fit into our future growth and organization. I'm not going to comment on what will likely come out of that review, but we'll share that with you when we get to our investor day.

Of course, we'll continue, where it makes sense, to clean up the portfolio to do that. We're not going to there for asset sell-downs or anything like that because we know how precarious, right?

We'll continue, if those opportunities come up to clean up the portfolio, we'll continue to look at that and execute it where it makes sense.

Your capital framework, you still need to support growth, and you've got quite a broad set of growth options. Can you clarify how you're prioritizing?

Will projects simply compete for capital, or are there other drivers? Perhaps you've commented now on your strategic drivers that will bring some projects ahead of others.

We're going to run the business for value. We'll be looking at those rate of returns.

The best that will win every time. Production position, or high heating value LNG has a force, because not only does that allow us to get better prices for LNG, it allows a lot of portfolio optimization, always seasonal to create more value.

We've done a bit of that over the last few years as well. Really, I think the best way to describe what I, Tom, is that we'll be running it for value, and so it's really the best value outcomes and the best value...

That's clear. Thanks, Kevin.

Cheers, Tom.

Morning, Kevin, Lachlan, Brett and team. I suppose first question, Kevin, just on the gas, any implications for the business going forward, just on the federal gas market review there, please.

Look, thanks, Mark. I'm sorry, that's a very good question, and a good opportunity to communicate a few things that we've done.

Look, I think the challenge with this is that we see no material value impact to reducing into GLNG. There's a couple of fields we'll continue to take gas from that were developed specifically for GLNG.

From 2020 gas will come predominantly from equity gas plus those developed for GLNG. We're working with our partners and we've already made agreements with partners for certain mitigations in terms of contract, any liability-type impacts.

The bottom line is that it doesn't make sense in the domestic market to sell into the LNG markets. The free market is working and value barrels.

GLNG is actually a better asset without doing that. As I say, we're going to continue drilling and developing our indigenous resource over the next few years.

You'll see 2029, 2030, and the third-party contracts that still exist as they come up for renewal in a couple of years. What does that mean?

That will mean that it will drop back a bit. The production will not be impacted at all.

In fact, our production will increase over the next few years. LNG sales will come back, but in terms of margin, or materially impacting at all, because, as I say, gas really is zero-margin barrels, or very low-margin barrels.

What does that mean for the domestic gas? We won't be contracting, can be turned back into the domestic market.

The domestic market, in my view, should alleviate any shortage 2027.

Thank you. We're also seeing some encouraging well performance, well cost data.

What are you looking to do differently this time around? I think your well costs are pretty high.

It was a few low, but any changes around well design that you need to do? I think it's the second half of the year, please.

Look, I think when we drilled in the basin, and I have to say, it looked like a well that I drilled. We've got better drillers there now.

We've got a very experienced team with a lot of shale experience in the team. We've also performance of other people as that experience has been built over the last five.

We're in the process of contracting rigs and getting everything set up. If I give an indication, or how you see the 2026, 2027,

and

what the appraisal plan is.

Thanks, Kevin. There's been a lot of drilling up there.

There's been 12 wells drilled since we've drilled. We want to make sure we learn from that.

Tamboran's a partner in that block with us, and they obviously have been getting everything we can from the other operators, including Tamboran, and we are making sure we're learning from what's happening in the... all the learnings we can.

We've got a team focused on delivering this. It's a very focused plan.

Our plan is to drill these, emulate them as though they're production wells, and produce them for 12 months. That ultimately will allow us to make an FID decision out of this program.

A very, very targeted, and we've got people from the U.S. involved, whether they work directly for us or through our contractors to make what's happened in the Beetaloo Basin over the last couple of years.

Based on the work that we've done, we're actually very optimistic. cost of supply target that we need to achieve here opportunity, and we're targeting the total booking and this appraisal campaign of just under 5 TCF of 2C resource.

It's a very significant and important appraisal program, which hopefully 2C resource.

Great. Looks like—

Thanks, Adam.

Morning, Kevin, Lachlan, and Brett. Just firstly on the cost out, the 10% reduction in headcount, is this savings targeted?

Is it net of inflation and other inflationary around those numbers?

Look, we see that as quite a natural trend. A big part of it, Dale, as you transition from the projects we've had ongoing, it's pretty natural that your headcount goes up as you build these projects, and as they come off, you move more into the operations phase.

Some of it's more from technology improvements allowing us to see some headcount or FTE reductions. I'd see most of that occurring over this year.

It's pretty short to medium-term number. It's not in addition to.

That's important to clarify. We see it this year, and it's mainly a combination and some efficiency gains and improvements just through technology and different ways of working.

5 to $50 per barrel break-even number and the $7 per barrel opex, is it incremental to them?

No, no, it's already included in those numbers.

Review, the concept of, I guess, exiting the mature high-cost margins to leave a higher quality LNG core. The idea has been around for a while.

Are there any considerations you're thinking of that you can provide a bit more colour and a bit more meat around the bones of the strategic review?

We're not saying is that we're selling anything or buying anything. I think that's very important to clarify up front.

Those come from the strategic review. We're looking differently at those assets, how they compete in the portfolio going forward.

If they're not going to get capital, what does that mean? If they're not going to compete against Alaska expansion and growth opportunities, or they're not going to compete at near drilling in PNG, how are they going to...

what are we going to do with them? What is put on the table in that review?

I look forward to sharing the details with DME. Our target is to complete the work.

We're well advanced in that work. We've been doing it for a little while.

We'll complete that work, and then we'll share it with our investors, the investors DME.

Thank you.

Cheers, Dale. Thanks.

Morning, team. Thanks for the update.

Development now largely de-risked and now having line of sight to first execution to date has been a standout. Could you please refresh us specifically on what milestones or operating performances you might look to addressing a brownfield expansion, and just how we should think about the potential timing, noting that you talk about running the business, growth opportunities that are also competing with this particular opportunity?

Thank you.

Thank you, Tom. There are challenges, right?

On the execution front, it's been excellent. The drilling's been superb.

Costs could have been better, right? We've got to be frank about that.

We're not pleased. The team are not pleased themselves.Spent more than we intended to spend along the way, and inflation and the high activity levels in the region have driven inflation there above what we were expecting.

That's not been a great outcome on the cost side. The projects, they're very high quality.

I always get nervous talking about it like we actually won the game, and so I'm not going to get carried away. We've got that last 5% or so to close out with commissioning, and we're getting close to that.

We have projects. We've had a few bumps after we started up in Barossa, which is not unusual.

I think something like 20 PSOs that have come to Australia have departed pretty soon afterwards to go back. Unfortunately, touch wood, we've not seen anything like that.

It's been pretty good, but we've had a few bumps, and no doubt there'll be a few little things. The team's very focused.

We're running a very strong commissioning quality assurance process. We want a strong ramp-up, and really starting up and getting the water injection plant up and running so that we have a pressure support.

If we can start up early, that's easy. If we're producing too fast without the water injection support, we'll end up leaving the water injection plant up and running, get the pressure support in place, and then ramp up to full production to plateau rates.

What I'm very pleased about is the subsurface indications are in line when, of course, when you're developing anything in a new basin for the first time, that's one of the key deliverables. You can fix little things on the plant, what you can't fix is if you get a bad...

That's looking very, very promising, and as I said in my notes, just tested, was significantly higher in terms of its productivity, than the average for the wells to date. That's very encouraging.

Back for first oil, late Q1, but really it's not about the first oil date. It's really about the ramp-up from that, because that ramp-up is determined the injection system up and running and the pressure support for the reservoir.

The plan is to two, reaching plateau at the end of Q2. Of course, if we can get the injection up and running, there's the opportunity that that could be quicker.

Yeah. Thanks, Tom.

Yes, thanks. My questions.

First one is a clarification on your 45 to 50 dollar all-in free cash flow prescriptive. Does that set a hard upper limit on investment every year, or is it an average over, say, three years?

In 26, it looks like you're going to come in below that number. Whether that provides to maybe lift it above that range.

Thanks.

I think one for Lachlan to handle.

Thanks, Kevin. Thanks, Nick.

Look, we'll guide each year to where we think that will hit on an annual basis in well-defined parameters, but we'll guide each year to the 45 to 50. Obviously, it aligns with Five, and as we said, we do have a lot of investments that we can look to.

45 to 50, I think, will be where we'll be targeting across the range.

That's what our sort of forecast at this point in time would be. The point there, 15 to 25 percent is our target gearing range.

At the lower end of that, our interest payments are significantly. to reinvest in the business within that framework as well.

De-gearing is actually an important part of the strategy.

Thinking that over the next two or three years, you could be well below that number as you lower gearing ahead of a pick-up in investment towards the end of this decade.

It could be either/or, right? It depends.

We talked about some of the development opportunities that we're progressing. There's no major development spend on the balance sheet in the next couple of years, but depending on the results of those, we might, right?

There's nothing scheduled there right now, but whether that, who knows? We'll wait and see what the results of those programs are, and we'll make those decisions as we go, but.

Got it. My second question is just on Papua, at the improved cost estimates coming through from the operator.

There's been some speculation. I think the JV was targeting a reduction in costs from around the 18 billion to 14 billion.

Are you able to sort of quantify whether those costs are coming out around that level?

Patrick, it's Total, and he was talking in the 14 to 15 range. I think that was public.

He did actually say that, and progressing, the project financing progressing. Everything's heading, things we still have to get ironed out, but ultimately ourselves, Exxon, Total, are working to, and we'd like that to be around the middle of the year.

We're hoping that's around the middle of the year. In that 45 to 50 guidance we've given you, we've assumed that Papua's in.

That's very important.

That's very clear. Thanks, Kevin.

Thanks, Nick.

Thank you very much. Kevin, I just picked up on this, and maybe it's nothing, data that the combined production intake is going to be 25 to 30 percent by 2027.

You're now saying 25 percent. Is that just being conservative?

There's no change there? Is there any kind of risk that you're taking into account that you might not have seen?

I still say it's in that range, Gordon. I'm being a bit conservative with the number because you guys always pick me up, and you just have done.

Look, I'd say we've been a wee bit. It's in that range, right?

25 to 30 percent. I'm being conservative, yes, a little, but it's also about phasing and timing and when things come on.

I always say we still don't know how Alaska will perform until it comes on. We were assuming 80 percent rate.

I'm sure we'll get there. The team are confident we'll get there based on the well tests.

Bank it, yeah.

Just a second question. Congratulations on good IPs and the dual completions that you do wells.

Can you comment on what annual decline from the Pikka wells? I know we're starting up really well, but do you have a feel for what, six out or two years out on some of these wells?

Look, I actually can't give you that number, Gordon, but what I can tell you is that we're looking at a five to six-year plateau. I see two to three years of sustaining drilling, keeping that performing at those levels before it starts, years on plateau, and you're probably looking at nine wells a year or whatever during that period.

Excellent. Thank you very much.

Thanks, Gordon.

Morning, team. Jumping back to Barossa, could you share any detail on the challenges that were observed doing that?

What the current state of the FPSO performance is as you ramp over the next few weeks?

The very first thing I would say is that the process, from a processing integrity point of view, which is often one of the biggest issues you have with a new gas plant or oil facility, were very, very encouraging. My hat goes off.

I take my hat off to BW Offshore for the quality of the process. In terms of the issues we've had, once I think I communicated last year that we had a heat sensor that caused us two or three weeks to reset the settings on each one of those 300-busser facilities, and that was more of a software issue and risks you take with all the high-tech stuff we have in our facilities.

Our GRE and safety utility water system, some connection failures that we looked at systemically, and we had to go through a program of connections across the facility because design error or not, but we figured it was a systemic issue that we wanted to address for the longer term and not take any risks on that. That cost us two or three weeks.

Following that, everything's been working well. We've had the usual little kind of tuning type issues you get in any new facility, but the issue with seals, our main equipment issued to BWO, and we've taken the decision to run at half rates just now while we take compressed softline and change those seals now rather than take the risk of any failures occurring further down the line, a product upgrade type alert that you ground the planes and fix them, right?

What we're kind of doing is we're taking half rates while we replace them, and we've got them coming on over the next two weeks, and then two or three weeks from now I fully expect we'll have the potential to be pretty close to ethanol at full rates. And

covering a lot of ground with all the assets, maybe jumping into...

Henry, just to close on that, obviously we've had a couple of cargoes already shipped, and another one the next few weeks, still getting cargoes out, just at a slower rate until we get the...

Sounds good. Thanks, Kevin.

Cooper Basin, just any details around the capex you're expecting there and improvements to costs and production going forward?

That's a really exciting project for the Cooper Basin because that is a project that certainly makes one part of the Cooper Basin become very competitive in our portfolio. I just want to give a sort of one-minute summary of the scope and why the costs will be coming down so much with that investment.

Thanks, Kevin.

Look, we've been working years along with our joint venture beach, and it's really about the Cooper Basin. Part of that is getting a resource, the resource is in the future, and we've made some great progress with formations pretty much around our central facilities.

We've got a basin that's got hundreds and hundreds in an area the size of Wales, and what we've been trying to do is get focus on the areas that are going to provide and actually do it at a lower cost. Spending a lot of time there, and we've been proving up the economics of those rocks.

Then ultimately, that area, which is closer to Moomba, that area holds most of our future production. It is also our oldest facilities, our least reliable, the ones that require the most manning.

The step with Moomba Central optimization will be to completely modernize the Cooper in that area and improve reliability, reducing costs incredibly significantly, and flow from those areas, which we're currently constrained on producing, further capacity to bring that gas back to Moomba. It will completely transform.

Excellent. Thanks, David.

G'day, Kevin, Brett, Lachlan. Two questions, one on the Beetaloo and one on the LNG marketing book.

Firstly, on the Beetaloo, with improved well costs over time, we feel pretty optimistic that outcome there. Could you provide some perspective just on pipeline and the GLNG and the willingness of that JV to process Beetaloo gas through Train 2?

It has been one of the more challenging JVs. Is there a risk that you appraise the Beetaloo but face delays on the commercial structuring?

Look, that's a great question, Mark. There's a lot of parts to it.

Brett said we're looking to drill the two to three appraisal wells, start half the next year and then put them on production for nine to twelve months, producing them to get the information we need to fully appraise where we would be confident to go forward and develop. That hopefully will get us pretty close to 5 TCF of resource, confident about going and developing.

We've already done a lot of work in what that sort of development would look like. We're looking at Permian developments and stuff like that to identify how to do this very efficiently and what the cost of supply would be.

We've looked at that cost of supply, both to GLNG and also to work with both governments on pipeline approval processes. We're not in that sort of loop that we have been in for a long time, same with Beams and different processes doing those approvals for a long, over the longer term.

We're very confident in the timeline in terms of when would you be ready? Earliest sometime late '28 or something like that, probably the time you'd be producing the wells, more likely probably early '29.

If you just think of that as being development, probably three, four years, because pipeline is probably the critical path there. That's the earliest you're looking then at any sort of feedstock opportunities for, say, GLNG.

Although I'm pretty confident when it comes to when that becomes available. The pipeline for any material resource to come through is the value I would expect.

If you start to look at GLNG through GLNG, it's still pretty strong in the early 2030s per annum in the 2030s. I think it's still around about a full train just based on a natural decline curve for the CSG fields.

It's a very strong production profile, but that is mid-2030s. You shouldn't discount the opportunity to go north to Darwin as well.

Economic and lower cost of supply option, and of course Santos does have EIS approval for a second train. It has an approval for a second train already.

We have that. With the right partners, the right opportunity to expand Darwin, GLNG would be a more expensive pipeline operation, but of course you already have a train in place, so that's an advantage for GLNG.

Darwin has the opportunity to expand further out to Barossa backfill, a success backfill opportunities, relatively low cost backfill opportunities for Barossa in the future as well. The Beetaloo Basin is that it's got the potential to fill all of our LNG operations or assets in Australia, if, and it's a big if at this stage, the appraisal program goes well and we're able to develop.

That's fantastic, Kevin. Thanks.

Perhaps to my second question on, you mentioned 83% contracted. Is there more work to do on the LNG book?

As you gain confidence in Barossa and you start to hit nameplate there, do you layer in more contracts and reduce your spot

exposure? Look, Mark, our plan is to try and maintain the portfolio round about the 80% to 85% contracted, leaving about as well.

That also allows us to do some of that portfolio optimization if we don't have wells. Our guys have done a great job.

If you look at that chart, I think on slide 26, you can see this is in terms of slope to Brent, well above benchmark. You can see on the WoodMac chart that are relatively pretty high.

The guys, we've got a great M&T team led by Sean Pettit, delivering a lot of value, and you can see the results in that chart. That's a chart that's done independently of us.

We'll continue to. We've got some of our portfolio contracted much longer than that, ten years plus out into the distant, over a five-year horizon.

As we keep rolling one year to the next, we'll continue to do short- and mid-term contracts. It makes sense for us.

We'll continue to try and more new partnerships with end users, very strong relationships, long-term relationships with great partners, great customers, and we need to do that going forward. Now I'm getting the hook now.

I believe I'm 15 minutes, 60 minutes overdue. I think there's two or three people to go to, I apologize for that, and I look forward to catching up with some of you week.

Thank you very much.