Thank you, and good morning, everyone. Thank you for joining us for today's first half FY 2026 results presentation.

I'm joined by Garrick Rollason, our CFO, as well as our investor relations team. Let me start by acknowledging the Gadigal people of the Eora Nation, traditional custodians of the land on which I'm speaking.

First Nations people have taken care of our lands and waterways for the past 60,000 years. We acknowledge and pay our respects to their elders, past and present.

As always, I'll start today's presentation with a safety share on slide 4. To prepare for extreme weather conditions, we conduct a summer readiness program, including activities such as site clearing and weed prevention.

I'm pleased to say that we haven't had any weather-related customer impacts so far this summer. I'd like to thank the APA operations team for the fantastic work they do to keep our people and our assets safe and to keep our customers' operations going 24/7.

Suffice to say, we are very pleased with today's results. I'll highlight three key takeaways per slide 5.

First, we've delivered a strong financial result. We're continuing to deliver against our commitments.

Underlying EBITDA is up 7.6%, and our EBITDA margins have expanded by 280 basis points. Much of this has been driven by our cost reduction initiatives, which included a 13.6% reduction in corporate costs.

Looking forward, we expect to see our FY 2026 EBITDA above our guided midpoint. Second, we have a compelling growth outlook.

The ongoing role of gas in the energy transition is now well understood. This has been reinforced by outcomes of the federal government's recent gas market review and the move to establish a domestic gas reservation.

These thematics, together with strong customer demand, give us confidence to move ahead with the next phase of our East Coast Gas Grid expansion plan. We've completed the first stage of our Beetaloo development.

We've announced an agreement with CS Energy to deliver the Brigalow peaker power plant. Our organic growth pipeline has increased from $2.1 billion to $3 billion, reflecting the strong growth we see in our target markets.

The third highlight is that we have ample capacity available to fund our growth. The S&P threshold modification announced in December 2025 has provided an additional $1 billion of capacity to fund new growth.

This threshold modification reflects our disciplined focus on our core growth markets of gas transmission and storage, and contracted power generation. By focusing on our core markets and applying our competitive advantages, we have delivered returns well above our cost of capital, creating value for our security holders.

Slide 6 sets out our financial highlights. The strength of our business is demonstrated by our 7.6% growth in underlying EBITDA for the half.

We have the confidence to say we can expect to exceed the midpoint of guidance for the full year. It's worth noting that the midpoint of guidance would represent growth of more than 7% in FY on FY 2025, which would be another very strong result.

Our EBITDA margins are now at 77.3%. The great progress we've made with our cost reductions, coupled with strong contributions from our recently commissioned assets and our inflation-linked revenues, puts the business in a strong position.

Free cash flow is higher, in line with expectations, noting we had a one-off working capital timing impact relating to the divestment of our networks business. Our distribution of 27.5 cents per security is up 1.9%, and our distribution guidance for FY 2026 is reaffirmed at 58 cents per security, which will be our 23rd consecutive year of distribution growth.

Let's move to slide 8 to cover our strategy. The key point to note is that our strategy remains unchanged.

We remain extremely confident in our ability to create long-term value. While it's easy to think about our business in terms of markets, our strategy is about creating value by developing energy infrastructure assets with inflation-linked revenues under long-term contracts with tier-one counterparties.

Underpinning this is our focus on core assets and projects that deliver returns well above our cost of capital. We remain focused on growth markets where APA has a clear competitive advantage.

Examples of what we're focused on are set out on slide 9. APA has two core businesses.

The first has been the foundation of our growth for the past 25 years, and that's our gas transmission and storage business. The growth here is centered on our East Coast Gas Grid expansion, supporting new basin developments such as the Beetaloo and Taroom Trough, and building laterals to support growing customer demand for GPG on Australia's east and west coast.

Our other focus is on contracted power generation. This includes growth coming from new gas power generation projects across the country.

AEMO forecasts the need for 13 gigawatts of new GPG investment in the NEM alone. More recent analysis from Griffith University suggests up to around 20 gigawatts may be required.

This is all largely before factoring in the likely growth in energy demand to support new data center developments. Demand for remote contracted power generation presents similar growth opportunities.

Slide 10 demonstrates the strong long-term demand for gas in Australia and the significant domestic supply available to service it. This supports the investment case for expanding our East Coast Gas Grid.

The chart on the right shows the significant volumes of domestic gas reserves and resources available to meet domestic demand. These reserves will also continue to supply Australia's critically important LNG export market.

Over 68,000 petajoules of 2P reserves and 2C resources are available in Eastern Australia to serve an east coast domestic market that consumes around 500 petajoules of natural gas each year. Domestic gas supply is simply not a constraint.

Taking steps to unlock this supply, including expansion of our East Coast Gas Grid and the proposed domestic reservation for the east coast, is in Australia's national interest. Moving to slide 11.

Given our announcement today of our East Coast Gas Grid expansion plans, I want to ensure we address the debate regarding LNG import terminals relative to the transportation of domestic gas. As we've said, at APA, we're somewhat agnostic as to whether we transport domestic gas or imported LNG.

Most of these molecules will end up flowing through our network in any event. What we advocate for, however, is the delivery of the lowest-cost, lowest-emissions, and most reliable energy source to service gas demand.

That, without question, comes from domestic gas supply. Now, some of the arguments used to advocate for LNG import terminals don't withstand closer scrutiny.

The main argument is that imported LNG can be cost-competitive. The truth is, multiple data points confirm that in the short and long terms, LNG imports will continue to present a higher-cost option than pipeline infrastructure expansion and domestic gas.

Asian LNG spot prices have rarely been lower than domestic wholesale gas prices. Modeling from Rystad forecasts long-term pricing somewhere between $8 and $12 per gigajoule for spot LNG arriving into Asia.

This is before you factor in transport and regasification costs and foreign exchange, which take the forecast delivered cost into Australia to be an average of over A$20 per gigajoule. Australian manufacturers and consumers generally cannot afford such high prices.

Another argument for import terminals is that domestic supply to meet southern market demand is entirely dependent on the Beetaloo. While opening the Beetaloo will no doubt benefit Australia's gas market, domestic gas demand on our east coast can be met from multiple existing basins, including the Surat and Bowen basins in Queensland.

Quite simply, domestic gas is the clear solution for the Australian market. Slide 12 provides detail about stage 3 of our East Coast Gas Grid expansion plan, which would increase the capacity of the east coast network by around 30%.

Final investment decision has been reached on stage 3A with an investment of $260 million to deliver three new compressors. This will increase north-to-south capacity by 11%, including a 20% increase in capacity for northern gas into Victoria, and it will be ready by winter 2028.

We're also investing $220 million in stage 3B to enable continued early works and procurement of long-lead items for the Booligal Interlink, including the purchase of 342 kilometers of 28-inch line pipe. It's worth acknowledging that the favorable regulatory outcomes for the Beetaloo development, along with the federal government's support to implement a domestic gas reservation on the east coast, builds confidence to make these investments.

Strong interest from customers is also driving our progress on the Beetaloo. The demand for stage 3 is clear, and domestic gas supply is not a constraint.

This expansion plan is a timely and cost-competitive solution to our predicted southern market supply shortfalls. In short, APA's expansion plan will deliver the capacity that ensures certainty of supply into Victoria and the east coast more broadly.

Gas supply, whether it be molecules or transport, is no longer a constraint. It's now up to our federal government to bring this to life.

Moving to slide 13. We're also continuing to support new basin developments in Australia, including the Beetaloo, which is showing particularly strong near-term momentum.

We've completed construction of the Sturt Plateau Pipeline with gas to flow to Darwin from mid-2026. We're now working on plans to expand the SPP with additional compression that would increase capacity to around 100 terajoules a day.

In December, we announced that the Northern Territory government granted APA a pipeline permit to survey a potential route for the North to East Australian Pipeline. The NEAP, as we call it, has the potential to connect to APA's East Coast Gas Grid, utilizing our existing Carpentaria corridor.

We're also planning work for a new pipeline to go north to Darwin, with one option being to utilize the same existing corridor as our Amadeus Pipeline. The key point is that we're well prepared to support our Beetaloo customers with either a northern or eastern transport route as developments in the basin continue to progress.

Moving to slide 14. We were pleased to announce late last year that we're partnering with CS Energy in Queensland to develop the 400-megawatt Brigalow Peaking Power Plant.

The project expands APA's footprint in GPG and deepens our partnership with CS Energy. The peaker will connect into APA's Roma Brisbane Pipeline via a new transport and storage lateral, which is currently being developed separately by APA.

There's a strong list of opportunities for similar GPG developments that we're currently investigating across the country. Moving to slide 15.

Our Pilbara business continues to perform strongly and in line with our acquisition business case. It's worth noting that the vast majority of the value ascribed to the Pilbara acquisition was allocated to existing assets, not to growth.

These assets are generating a lot of cash, about $140 million of EBITDA last year, representing a yield of around 10%, which is obviously very strong. While demand for new power generation developments by our customers in the Pilbara is a little slower than anticipated, the development pipeline is now larger, supported by new opportunities such as the Burrup transmission line.

We remain confident about the opportunities ahead in the Pilbara and other remote regions such as Kalgoorlie and Mount Isa. With that, I'll now hand to Garrick for a deeper dive into our financial performance.

Thanks, Adam, and good morning, everyone. I'll start with our headline financials on slide 17.

In the first half, we have delivered strong growth in underlying EBITDA, up 7.6% for the half year, as the benefits of inflation-linked tariffs, earnings from new assets, and cost reductions were realized. Pleasingly, underlying EBITDA margin increased to 77.3%.

Free cash flow was up slightly, as the benefits of higher earnings were offset by increased funding costs and cash tax payments, as well as movements in working capital and SIB capex. I'll have more to say on this on a subsequent slide.

Moving to slide 18, where I'll step through the drivers of our 7.6% uplift in underlying EBITDA. 1H 2026 represents a strong, clean result, and I'll call out some of the key period-on-period movements.

We delivered new earnings from the Kurri Kurri lateral and Atlas to Reedy Creek pipelines, as well as the Port Hedland solar and battery, alongside inflation-linked tariff escalations and savings from cost reduction initiatives. Offsetting this was the non-recurring $13 million in insurance proceeds relating to the Moomba Sydney ethane pipeline that was received and disclosed in the corresponding period.

Corporate costs of $70 million decreased by 13.6% in the half compared with 1H 2025. We are making strong progress with our enterprise-wide cost reduction initiatives, and I'll touch on this further later in the presentation.

Slide 19 summarizes the drivers of free cash flow, which was up slightly half-on-half to $556 million. Consistent with our previous statements, the uplift in underlying EBITDA was partially offset by higher interest and cash tax paid.

Higher interest costs reflect increases in net debt to fund growth and a marginally higher average cost of debt. Higher cash tax reflects the continuation of tax installment payments, which recommenced in the second half of last year.

The change in working capital in the first half is primarily related to one-off timing impacts arising from the divested networks business. This will unwind upon the conclusion of this service under the TSA, which is expected in the first half of FY 2027.

Stay-in-business capex was lower due to timing of expenditure in the first half of last financial year. Looking forward to the full year, we continue to expect broadly flat free cash flow.

Beyond this year, we expect to see free cash flow growing as earnings continue to increase and tax begins to normalize. Moving to slide 20, which outlines our statutory results.

Net profit after tax of $95 million was higher than the corresponding period, noting that higher reported EBITDA and lower net finance costs were offset by higher depreciation due to the inclusion of new assets. Within non-operating items, aside from the non-cash hedge and technology transformation-related items that you have seen before, there were two one-off items in the first half.

First, a $15 million non-cash loss on the sale of the networks business, primarily due to the write-off of historical goodwill. Secondly, a $14 million payment for the settlement of a legacy revenue-related legal claim that has been in dispute since 2015.

Moving to slide 21 and an overview of capex. We continue to invest in projects to support long-term growth, strengthen our foundations, and maintain safe and reliable asset operations.

We invested in growth capital expenditure through early works on the East Coast Gas Grid expansion, the Sturt Plateau and Brigalow pipelines, and the proposed Brigalow Peaking Power Plant. We are maintaining our full year guidance for foundational and stay-in-business capex.

As Adam said previously, we've increased our organic growth capex pipeline from $2.1 billion to approximately $3 billion over the next three years. All of this capital expenditure is consistent with our capital allocation framework, which is outlined in the appendix, and is expected to achieve returns over our hurdle rate of 150 basis points above post-tax WACC.

The framework is designed to ensure we allocate our free cash flow to those initiatives that can create the most value for our security holders. To that point, I'll cover funding on the next slide.

We have existing balance sheet capacity to fund in excess of our $3 billion organic growth pipeline over FY 2026 to FY 2028. Apart from the DRP, APA does not need to issue ordinary equity to fund this identified growth pipeline.

The $3 billion organic growth pipeline includes in-flight and probable growth projects across gas transmission and storage, GPG, remote grid, and other on-grid contracted power generation projects. This strong balance sheet position, combined with active capital management and the predictable capacity-based, inflation-linked revenues, leaves us well positioned to deliver on our organic growth opportunities.

In short, we are very confident we have the funding flexibility required to deliver the attractive growth opportunities available to us. More detail on our key balance sheet metrics, near-term maturities, and capital management activities are provided in the appendix.

Finally, I'll cover our progress on our cost reduction target on slide 23. The key message is we are making strong progress towards our $50 million cost reduction target in FY 2026.

We are achieving this by leveraging the foundational investments made into the business over the past three years. These included investments in technology, business resilience, climate and community, and capability uplift.

These investments have enabled the initiatives which are reducing costs and driving margin expansion across the business. We now have the business set up to drive ongoing, enduring, and sustainable cost improvements.

We will provide a further update at the full year results, along with our target for FY 2027. With that, I'll hand back to Adam.

Thank you, Garrick. As you can see on slide 25, we believe we have APA in a strong position.

We've simplified our business. Our core business is performing well.

We continue to drive a lean and efficient cost base. There's good momentum in our growth markets, and we remain disciplined in capital allocation, prioritizing projects with the highest returns.

Our balance sheet is strong, and we have ample capacity to fund growth. Which takes us to the wrap-up on slide 26.

We've delivered another strong half-year result with underlying EBITDA up 7.6%. The outlook for the full year is also strong.

We're well placed to capitalize on emerging opportunities with a $100 billion-plus addressable market and a $3 billion organic growth pipeline for FY 2026 to 2028, which we can fund from our existing balance sheet. Thank you for your time.

Let's now move to Q&A.

Morning, guys. Just wondering first around the reduced downgrade trigger with S&P.

Could you maybe provide some color about how you were able to negotiate that and if you had to give anything away by getting the more favorable balance sheet settings?

Thanks, Dale. It's Garrick.

I'll respond to that. As you'll be aware, we speak to the rating agencies often and frequently and provide them with a lot of detail around operations and our forecast.

We've been talking to S&P specifically around the downward threshold for some time. I suppose really pushing them relatively hard on the underlying basis of our earnings and the strength of the contracted inflation-linked revenues, both today and going forward, and the nature of the assets and the contracts we have.

Through those discussions, S&P obviously continually review the business metrics and what's appropriate for our rating and came out with a threshold that we think makes a lot of sense. Certainly, there was nothing that we were required to give up in order to achieve that.

It's just consistent with the nature of our earnings and nature of our business.

When we think about slide 22 then, and we think about this increased growth capex outlook, it looks like it really has been facilitated by the increased balance sheet capacity. The generation and uses of cash looks like you've only got kind of $100 million spare balance sheet capacity over the next three years even with the DRP running.

Can you talk a little bit about what balance sheet capacity you'll have left over the next three years?

Dale, I might just take the first part of that question, and then I'll hand it over to Garrick in terms of what additional capacity, but strategically, there's no shortage of opportunities, and we're conscious of that. We're very focused on making sure we're working on projects that are customer-led and in our core markets where we can deliver returns above our cost of capital, and effectively, we have the organization fighting for capital, which is where you want it to be.

We always look at that also in the context of the balance sheet and making sure we're not taking on too much. Obviously, the capacity provided through S&P has been helpful to be able to continue to progress the opportunities ahead of us.

I just want to make sure that people are left with the understanding that it's really a disciplined approach to how we allocate capital, of which the balance sheet is just one part of that.

Then I'll address the question around balance sheet capacity. The S&P downward threshold did create about $1 billion of additional debt capacity at the time.

I think we announced that when we went to the market and told them about the downward threshold. That's obviously pleasing from our perspective because it means that we have the capacity to fund more accretive organic growth on balance sheet.

As we stand here today, and clearly, balance sheet capacity increases as our operational cash flow also increases, but sitting here today, we're certainly not capital-constrained. When I look on page 22, we actually have capacity in excess of the $3 billion of growth opportunities that we've talked about in the presentation today.

I'd actually say well in excess of that $3 billion. It's also worth reminding you, and I might sound like a broken record here, but we have many levers available to us to deliver balance sheet capacity.

That includes the existing balance sheet capacity we have. It includes things like issuance of hybrid instruments, which are efficient use of balance sheet.

There's partnering. There's asset recycling.

There's structured equity. We have a number of levers available to us to manage that accretive organic growth that we see ahead of us.

Thanks. Then just finally, is the $3 billion the new run rate you'll look to sort of hold or grow from going forward?

I think we've just got to assess that as the projects come forward. As that $3 billion is a portfolio of projects.

There are projects in there that are probability-weighted, some more certain than others, which tells you that the opportunities there ahead of us are more than $3 billion. You don't necessarily win every one of them.

Ultimately, if the right projects come along that are highly accretive to our security holders, makes sense for our customers, all those things that we hold ourselves accountable to, then we'll always consider those opportunities. Again, then we'll look at it from the lens of the funding.

Garrick's already commented on the different levers we've got to be able to address the funding of any opportunities that are before us.

Thanks, gents.

Morning, Adam, Garrick, and the broader team. Yes, congratulations on committing to stage 3A of the East Coast Grid expansion today.

I'd like to ask about stage 3B, please. APA's committed $220 million to order long-lead items.

I assume that that's the compressors for the Booligal Interlink. You've outlined the total project cost of that at $800 million.

Can you confirm the level of customer underwriting that you have for stage B given the commitment for that today?

Hey, Tom. Look, just to be clear, we break stage 3 into two components.

3A is compressors. That's three new compressors.

We've already got them ordered, and then we'll continue to deliver those now in line with our project plans, which get that delivered by winter 2028. They're no different to what we've delivered in stages 1 and 2.

As we don't underwrite those projects. They're incremental to our existing capacity.

Obviously, we do that off the back of the demand and the inquiries and the process that we go through with our customers to ensure that the demand is going to be there. Stage 3B is not compression; it's pipeline.

It's the Booligal Interlink. What we've ordered there is the line pipe, the 28-inch line pipes, 342 kilometers of that.

We're well progressed with landholder consultation and engagement, planning, and approvals. We wanted to get ready for our ability to be able to hit go on the next stage, which is what we've done today around ordering those long-lead items, but also give ourselves enough capacity and flexibility to be able to sit here and monitor how the National Gas Review would play out.

Now, the National Gas Review in draft that came out just prior to Christmas from the federal government was positive for domestic gas supply. It sent the right signals around the need that the demand's not an issue, right?

Everyone understands industrial demand is incredibly strong. As you see demand for GPG, for other sources of intermittent capacity being required or supply being required requiring capacity, there was no question around the demand.

It was making sure that we had the supply capacity available. Quite frankly, the biggest constraint, or almost the only constraint there was pipeline capacity.

We've addressed that today. We're now sending a strong signal to our customers, to the industry, to government that capacity is not a constraint now, and we're just waiting for the federal government to finalize the policies that they've drafted.

From a customer perspective, as you'd expect, we've had deep engagement with our customers. There's a lot of interest there.

They, too, are sitting there waiting for the National Gas Review to play out. I can get into the details behind that, but you know very well what the implications are there, that it's pretty hard to sign up to long-term contracts when the producers aren't able to do that because they're not sure about how the National Gas Review is going to play out.

I think we've made really good steps in the last couple of months with the federal government's announcement and with our announcement today. I think that's really positive.

Obviously, we'll continue to work forward with our customers over the coming months.

Thanks, Adam. If the customers are waiting for the National Gas Review to play out, and you comment then that they're finding it hard to sign long-term commitments to transport, why won't the board also wait for underwriting before making such a material commitment to stage 3B?

Because it's effectively lifting the risk profile of the business by taking such a merchant risk position on that asset. Why not wait if the demand's so strong?

It's a chicken and the egg issue, Tom. If we don't come out and provide the capacity and the transport that's required to move that gas north to south, then the government is sitting there saying, "Well, you've got a constrained market, I need to look at potentially other options."

What we're doing is allowing industry, allowing our customers, and allowing the federal government to be able to have comfort that we are committed to moving forward to ensure that capacity is not a constraint, which then allows the government to be able to put the right policy in place, which, again, in draft is very encouraging, to be able to make that happen. I know it's a big financial commitment, but again, we've spent well north of $500 million over the last couple of years, which was uncontracted.

You've got to have comfort that the demand for our product is there, which we have deep comfort from, and that you can continue to recontract that capacity. We've been incredibly successful at recontracting that capacity.

In fact, we haven't had any negativity there at all. Again, when you get comfort around the demand thematics and the supply thematics, and obviously, we've got a gas market model that takes into consideration all the potential risks, we are incredibly confident to move forward.

Again, we just want to ensure that we don't make that final decision until we've got the parameters laid out with the National Gas Review.

Thanks, Adam. I guess the challenge, obviously, being on such a long-life infrastructure is that the demand outlook can change.

I don't mean to draw a negative tone to it, but APA's internal demand estimates also expected that the Northern Goldfields Interconnect over in Western Australia, when that was committed in November 2020, would also be contracted by the time the asset was commissioned. It was commissioned two years ago, and looking today on the bulletin board, it still looks like the asset's roughly only 20% contracted.

There's obviously commercial risks out there. It's some good information in the pack on how APA see those around import terminals.

I note the analysis on import terminals is using a current North Asian spot LNG price at over $12 / MMBtu. When this Booligal Interconnect would be commissioned is winter 2028, which independent forecasts and even the current futures curve have at $8 / MMBtu, which on our analysis using the ACCC approach would have landed gas in Australian dollars a gigajoule leaving Port Kembla at comfortably below A$15 a gigajoule, which would make it look like very in-the-money competitive-cost gas for southern flexible demand.

Are you able to confirm that if an import terminal were built and in winter 2028, gas prices were $8 / MMBtu, that you'd still be comfortable that long term you're going to make your return on and of equity on this investment?

I'll dress your address your first part of that, Tom, around contracting risk and demand and supply. Again, I'm repeating myself, but I I do want to ensure that I answer the question that you've got to look at the demand for gas and the supply of gas and the and the gas market model that supports that on the East Coast Gas Grid.

We remain very confident about that. The the customer inquiries are there, the customer demand is going to be there.

You've got to remember that we continue to build out the East Coast Gas Grid in an incremental way, principally through through compression. Now, the Booligal Interlink is obviously not compression, and that is a bigger lick of capital than an individual compressor.

It does it has been built in a way that addresses the shortfalls out to the early 2030s. We're not trying to overcapitalize on that beyond that time period because we know beyond the 20 the early 2030s, we can continue to build out the East Coast Gas Grid through further compression.

We're trying to do it in a way that's cost-competitive and price-competitive for our customers, which we're very confident about. Look, the NGI, you're right, it's been slower to ramp up.

It's very similar ramp-up to what we had with the Goldfields Gas Pipeline a number of years ago. We've we said that that's going to take around five years to to ramp up, and it's going to be dependent on a number of customers in the region.

You the Goldfields is an example to procure into that. It's a very different market to the East Coast Gas Grid.

It's much more individual contracts than the East Coast Gas Grid being with customers who run portfolios in terms of their gas movement. Again, we remain confident around the long-term value of the NGI as well, and and it's consistent with our expectations.

If you go to LNG import terminals, it's a really interesting argument. Look, the the most recent credible long-term forecast that came out was Rystad.

It's actually in the pack, I think it's slide 44. That has long-term average U.S.

dollar LNG spot prices into Asia of somewhere between $8 and $12. There there will be days where it goes below that.

I understand that. LNG producers, importers, if they want to sell into the market on particular days that are below the domestic price, and that's great.

They they can be free to do that. From a sustainable perspective, it doesn't make any sense to think that LNG imports can be price-competitive.

That you've got to take into account regasification. You've got to take into account transportation against the Asian spot price.

The counterfactual argument is that if if prices LNG global prices were getting to those lower numbers that you were talking about, those $5, a couple of things happen. One is if prices are so low, then Australia's LNG exporters will be selling into the domestic market because it'll be more attractive to sell domestically than for an, for an LNG import.

We don't need LNG imports under that scenario. The second one, the only other scenario where LNG imports make sense is when a government agency or the government directly subsidizes principally the regasification of that, which means that either the consumers will end up paying for that higher cost directly, or you'll be every taxpayer will be paying for that through higher taxes.

I don't think politically that's going to be something that that anyone's want going to put their name to. Not saying that LNG doesn't LNG imports won't exist in Australia.

We just don't have any confidence at all that it's sustainably going to make sense.

Thanks, Adam. I'll let others ask some questions.

Thanks again.

Morning, team. Thanks for the updates.

Over in the Pilbara, we've seen GIP enter, acquiring a share of BHP's network. Could you share how you're expecting that would influence competition and the pipeline you see for your position in the Pilbara?

Look, the Pilbara, the first thing we remind everyone, and we get a lot of questions on this, we wanted to be upfront about this, is that the Pilbara business is performing really well. The vast majority of the value that we ascribed to the business when we acquired it was to existing assets, and they're performing bang-on line with expectations.

The business case, which we monitor and do post-investment reviews on is doing really well. From a growth perspective, the growth opportunities are still there.

There's nothing in our pipeline that we announced at the time of acquisition that doesn't exist today. It's just that they have been pushed to the right from a timing perspective, which is effectively customers, you know who they are, have pushed out their ambitions somewhat to the right.

We are confident that the ones that we're bringing to market, which are closest to the customer, lowest levelized cost of energy, all of those sorts of important elements from a customer perspective, will be absorbed at the right time. The size, as I said in my intro, the size of the opportunity is now bigger in terms of there are more projects that are available.

The Burrup Peninsula is one of them. Certainly, good progress in terms of planning and approvals and the work that we're doing with customers and government there.

We've always said that that'll be a bit of a longer game for us. We're comfortable with how it's progressing in the Pilbara.

We are seeing good interest in other areas outside of the Pilbara, Mount Isa, Kalgoorlie, which we see good opportunities where we can deploy capital and create value. Again, we run a portfolio, we continue to monitor those and look at them relative to the other opportunities in the other markets.

Thanks, Adam. Diving into the asset results, we've seen a bit of a pullback in earnings on the South West Queensland Pipeline, MSP versus this time last year.

Could you maybe just step through what's driving some of that and expectations if that continues or reverses, if this potentially lower northern haul contracting that could be reversed going forward?

Garrick and I might tag-team this one. I'll just provide some highlights and, if I've missed anything, Garrick, jump in.

Look, South West Queensland Pipeline and Roma Brisbane, firstly, they're fully contracted out to 2027. That's important.

You do get swings and roundabouts in our portfolio every year, which is understandable. We are capacity-constrained on some of those assets, there's limited upside, which is part of the reason why we've announced our East Coast Gas Grid expansion today to alleviate those bottlenecks.

From a contracting perspective, we've got lots of interest there. We want customers to recontract over the longer term.

Again, as I've said before, a lot of them are waiting for the National Gas Review and understanding how that plays out, which is, again, why we feel encouraged about what we expect to be happening over the coming months with the completion of that review. Look, RBP has been an interesting one because there's been less gas flow principally to the west as the LNG exporters have reduced their supply because of the price cap effectively that was introduced a couple of years ago.

They're not big volumes at all, but, yeah, in the periods prior, there was a bit more supply coming from them. SWQP's been impacted a little bit by Blacktip up in the Northern Territory.

When Blacktip wasn't flowing, there was more supply going through the South West Queensland Pipeline. When it was flowing, it's now not flowing to the degree that it should be.

As a result, the flow's east along the NGP and SWQP. It's not going there anymore; it's only going north to Darwin.

There's small swings and roundabouts, but the point is that there's been nothing material that's driven any of that movement.

Yeah. Thanks, Adam and, Henry, welcome on board.

I won't add a lot to what Adam said. Maybe the only other thing to note is just on MSP, bear in mind that in the prior period, we had the non-recurring insurance recoveries relating to MSP.

That was $13 million. If you take that out, you actually see good growth on MSP.

Adam touched on the fact that it's a portfolio of long-term core infrastructure assets, we will see some small fluctuations at the margin. What's interesting for me this period is we've obviously seen really strong performance across our contracted power generation, even after you normalize for the impact of the Port Hedland solar and BESS new earnings as well.

There's a lot of good stuff in the asset-by-asset performance as well, and then some assets have just had particularly good prior periods.

Sounds good. Thanks, team.

Hi, everyone. Just a question on your $3 billion organic growth pipeline.

As you can appreciate, we don't get a lot of visibility on the composition of the projects in there. On my numbers, the combination of Brigalow and the East Coast Gas Grid stage 3 announced today gets us around two-thirds of the way there on that $3 billion number.

Can you just talk about what's driven the increase from 2.1 to 3 today? Is it primarily de-risking of those two projects, or have you increased the risk-weighting on other projects in your portfolio of opportunities, or have you added new projects in there?

Thank you.

Thanks, Nick. Look, short answer to the second part of your question, going from 2.1 to 3, that's principally the East Coast Gas Grid.

We had small components of it in there at the 2.1, and again, it's portfolio-weighted. You're right.

Getting further along the journey with the East Coast Gas Grid takes the overall portfolio to 3. Just to give you some color, and again, it's portfolio-weighted, and I won't get into some of the specific customer projects for reasons which I trust you can appreciate, but the overall $3 billion includes the East Coast Gas Grid.

As you said, it includes the Brigalow peaking power plant and the Brigalow pipeline that we're also building. There's some laterals that we're working on at the moment, and we hope to bring those to market in terms of announcing them shortly.

The work that we're doing in the Beetaloo, it includes the Sturt Plateau Pipeline. I know we can finish construction of that, but that was included in there.

Then you've got some probability-weighting around other potential opportunities there. Then we've got some opportunities in the remote grid.

Again, Garrick and I look at a long list of projects and how that all plays out. We don't probability-weight every single one of them, but how we probability-weight those.

I hope that gives you color of what's included in there.

Definitely. Thanks for that, Adam.

Probably makes the next question a bit moot, but just focusing on your, I guess, contracted power generation opportunities beyond Brigalow. That seems to be a really good space.

You can be active in. Can you talk about how many other opportunities are out there that you think APA could participate in, and when you think they might come through?

You probably can't name names at this point, but just interested in the pipeline of opportunities in that space there. Thanks.

It's an important question, and probably at the full year we will come out with a little bit more clarity on the first part of my response, which is around the fact that we've got a number of sites, our own sites, and I'm not suggesting that we're necessarily self-developing. Our strategy is to partner with customers.

One of the important things as part of the recipe to be able to partner with the customer is to have the site, and the secret sauce there is to be on a site that traverses the electricity transmission link as well as the gas pipeline transmission link. We've got a number of sites that are earmarked, and that's been really positive for us because it enables us to have rich conversations with customers around meeting their needs.

Then we're also working with a number of customers who have their own sites, and we would play a different role, which is similar to what we've done with the Brigalow Peaking Power Plant where CS Energy had its site. They wanted a development partner, not only to develop it, but from an ownership perspective as well.

We're obviously their preferred partner in that regard. It's a long list, actually.

Timing will be interesting. Getting equipment is a question that I'll get asked at some point.

We work really hard at making sure we can try and get in front of the queue as much as we can in terms of getting equipment supplies. We've built the capability, and we had existing capability, but we've really strengthened our bench in terms of capability to be able to deliver and operate those GPG projects.

We think we've got a really strong competitive advantage. We're just working closely with a number of customers.

We'll continue hopefully to announce good progress with that strategy over the coming months and years.

That's great, Adam. I might leave it there.

Thanks.

Oh, thank you very much. Adam, I want to ask about the Beetaloo.

We heard yesterday from Kevin Gallagher was some very encouraging and positive commentary about the potential of the area. He made the comment that he felt that the gas pipeline was a critical path item.

Just kind of wondering how that fits in with the work that you're doing right now with Tamboran. I guess particularly I'm referring just to phase 3 because Kevin did make the comment that the Beetaloo gas could support Darwin LNG expansion and GLNG backfill for what looks like decades.

Can you just comment on how I guess APA Group has positioned to get involved potentially with not just Tamboran, but also Santos down the road, or are they doing their own work separately?

Thanks, Gordon. It's a really interesting one because I'm sure many of you have seen it.

When you look at the flow rates, when you look at the rocks, and it's a significant acreage. There's no debate about that.

People will tell you that the acreage is bigger than the Permian Basin in the U.S. and Marcellus basins.

It's a big, big acreage. That's great until such time as you find the gas.

The flow rates have been really, really positive. It's dry gas.

It's incredibly low emissions relative to other markets. With those flow rates, it looks like it's going to be very cost-competitive as well.

Our strategy has been to partner with all of the active participants in that market. Tamboran, obviously, with the Sturt Plateau Pipeline, and Daly Waters, who have also been part of that acreage connection there, are people that we're working closely with.

Then our strategy is to be positioned really well not only it works for us because we want to use that as a competitive advantage, but it works really well for our customers and for the basin development generally. We've been getting on with the planning and approvals.

What's one of the, I guess, really positive things around our position is that we have two really important existing corridors along the Carpentaria, which would facilitate going east, obviously going south for the domestic market. Given the size of the acreage, there's no question that Beetaloo is principally going to be an LNG export play.

There's obviously opportunity to send that gas east. We've done an enormous amount of work on planning and approvals, pipeline permits, et cetera, to be able to take that pipeline, connect it down, and allow that gas to flow out of Gladstone.

The strategy there clearly is you would imagine some existing LNG exporters in that region whose facilities effectively are coming to their end of their gas flow life would be able to utilize that gas to keep their sunk infrastructure going. Equally, we're doing work going north as well, going north to Darwin.

There's principally two routes that are being looked at there. One, the Northern Territory government has put a proposed route in play for some time.

We're working with the NT government and our customers on exploring that route. Equally, we're also doing our planning and approvals work to move along our existing pipeline corridor there, which is obviously incredibly efficient because you're dealing with the same landholders and the same traditional owners.

We think we're really well positioned. We're doing the heavy lifting to ensure that we're ready.

Kevin's right. You can't bring it to life without the pipelines.

We don't want to be the constraint there; we want to make it happen.

Thanks, Adam. A question just for Garrick on the cost base.

In your guidance, you're saying you're targeting further efficiencies in FY 2027. What would they be?

Can you give us a hint on where you can see for the cost gains?

Thanks for the question, Gordon. Are you asking for hints on the nature of the savings or the dollar amount associated with them?

Not the dollar amount, just where you see them coming from and you can relate it back to dollar amount, great, but where do you see opportunities to reduce costs further?

Definitely. I won't relate it to a dollar amount.

We'll announce that at year-end when we provide guidance for the full year. On page 23 of the presentation, we have obviously set out some of the savings that we've delivered in the way in which we've done that.

That's through simplification that's enabled us to look at our organizational structure and drive improvements through that in terms of front-line efficiencies. We've really looked at how we work and what we do.

That's things like integrated works planning. It's things like planned maintenance.

Fundamentally, it means that we reduce our reliance on external contractors, we're doing more work more efficiently in-house. When we look forward, a big focus continues to be on the operational side of the business, but it's how we work smarter.

It's using the data we have to drive things such as predictive maintenance, to look at strategic sourcing. We've got approximately $350 to $400 million external spend per annum across both opex and capex.

If you can drive some efficiencies in the way in which you spend that, this is external spend, then that obviously delivers significant value to the business. There's some of the opportunities that we see available to us.

It's really how do we work smarter and how do we reduce our external spend.

Congratulations on expanding the EBITDA margin again. Thanks for that.

Thanks, Gordon.

Good morning. Just want to ask a question around slide 42, which is where you're kind of tweaking your guidance to be above the midpoint.

Possibly silly question, why not just raise the lower band of the guidance, or maybe if you could give us some color on what are the pluses and minuses that could happen in this half?

Thanks, Mr. Coe.

Nice to hear from you. Look, from our perspective, there's still a number of months to go, and you can see the key assumptions on the right-hand side of that chart are consistent with the key assumptions that were there when we put forward that forecast.

We're just being conservative and prudent, we believe, to make sure that we don't get over our skis in terms of changing the guidance. Quite simply, what we can give you with a level of confidence is a view that we think will be above the midpoint, and principally because of the strong progress that we've made with the cost reduction target that Garrick spoke to before.

We're just trying to be prudent.

Okay. Can I also ask where in that bridge would you be putting the currency impact from the Wallumbilla Gladstone U.S.

dollar net revenues, because it's my recollection, I might have this wrong, that we were at 72 in 20 in FY 2025 and we should be using something like 67 for this year?

Yeah. Thanks, Rob.

It's Garrick. I'll address that.

It is a simplified bridge on page 42, there are buckets where there's ups and downs. Principally, when we look at the inflation-linked tariff, that will include the inflation associated with WGP.

If we think explicitly around the exchange rate, we lock in revenue, and we've discussed this previously. We lock in the exchange rate around the U.S.

dollar revenue associated with WGP. We do that on effectively a rolling five-year basis.

Looking forward from today, we are fully hedged out for the next three years, and then that decreases over the two years that follow.

Effectively, when we approached our guidance for FY 2026, we looked at that revenue as relatively fixed within those buckets of what was shown.

Okay. All right.

Cool. Then can I ask a little bit about, I think it's the slide on your capital framework, which you've said very clearly is unchanged, but you're now telling us that your threshold return is WACC plus 150 bps, and that 150 bps minimum is new information.

Have you changed your WACC or anything with the availability of debt, or am I reading too much into it?

I think you're reading too much into it, Rob. Look, we've been You might be right that it hasn't been may not have been put in print.

I can't remember. It has been in print.

I'm getting nods from the team. That that is not new information.

We take a long-term view as we look at our WACC, as you'd expect. We look at it every six months, and our board signs off on that as well.

We try and look We use assumptions that try and look through the cycle. Really, that's just us we get a lot of questions, as you can imagine, on the growth pipeline in in particular about how we're deploying capital and what returns we're getting.

Obviously, it's all very sensitive, and I feel for everyone on the call because, we'd love to give you what those numbers are, but then that makes it hard for us to run our business. The best we're trying to provide you is with a with a guide and and and a minimum threshold, same with the cash flow.

We try and get cash payback within the first half of a contract life or an asset life just to give you the framework that we look at, and then obviously, we look at each individual project on a cost and risk relative basis and come up with an outcome for our customer that we think works for both of us.

Then maybe just a slightly more detailed question on East Coast Grid Expansion stage 3B with some pre-FID expenditure on pipes. Can you talk to us about, heaven forbid that project doesn't happen, can you use those pipes elsewhere in the business?

Is there some kind of element of hedge to that?

We've obviously looked closely at that, Rob, and it's a good observation. Of course, I have to say we don't expect to get to that position because of the confidence we've got with our customers and because of the way that the National Gas Review is currently drafted.

We're very confident. Of course, you would expect us to have done the diligence around what you would do.

Quite simply, you would redeploy that line pipe. It's going to go offshore obviously, if it's not going to be used domestically by us, then it's going to go offshore.

We've made sure that there is sufficient market demand for that. Hopefully, that's all academic.

Absolutely. That makes sense.

I guess there'll be someone who needs a gas pipeline somewhere. For the Beetaloo pipeline, which is a much more distant proposition, should we be thinking that there'll be a similar kind of pattern for long-lead item expenditure, or is that different?

Yes, and it is a bit different to the East Coast Gas Grid, and Tom made the good observation before around contracting and, as the East Coast Gas market for us is multiple customers who have multiple portfolios of gas flows and different customers and suppliers, whereas the Beetaloo is, as you'd expect, because it's a big basin with some developers, the contracting will be different there. Just given the size of the capex involved relative to a Booligal Interlink, they're big licks of capital.

We would have to have a very different approach to how we would develop that. You'd be wanting to partner with somebody and have that confidence, partner as in with the customer, to be ordering those long-lead items.

What we are doing, though, so that's the line pipe. What we are doing is spending time and money on planning and approvals and all of those sorts of things at our cost.

We are backing ourselves in that regard, and we've been doing that for some period of time.

Yeah. Okay.

That's clear. Maybe one last question, if you will indulge me.

For your Pilbara assets, and you've said a number of times about how the clients are pushing right their aspiration and so that's why there hasn't been growth announcements just yet. Can you talk to I think at the time of the deal, there was a four-year weighted average contract life.

I presume that contracts just move to an evergreen-type basis. Are there any actual physical constraints if you don't have repowerings or extensions?

No, we will have recontracting, and the way the customers will always look at it is do I recontract with APA's existing asset, existing infrastructure, or do I pay for somebody else to build a new piece of equipment, which has got a time issue with it, it's got a cost issue with it, and quite frankly, our sites are very close to their operations. You'd have to assume with cost escalations and transmission line costs that the next best alternative is going to be more expensive than ours.

That gives us a level of confidence around recontracting. When we look at assets like that in the mining regions, the thing that we're looking closely at is mine life.

What we're seeing from a mine life perspective in and around the Pilbara is that there's plenty left there. We've got a high degree of confidence there in terms of recontracting.

We've got to be very smart in how we work with our customers to give us the solution they need there. In terms of new projects, it's really about additional demand from our customers rather than aging assets or anything like that.

It's new demand.

Okay. All right.

Thank you so much.

Just a couple of simple ones. What do you see the risk of slippage on decisions around 3B if, and I see GSOO may come out and say the shortfalls are being pushed further to the right per gas market?

Look, we've staged it and designed it so that we address the most pressing constraint. It's obvious from a timing perspective, 2028.

Stage 3A addresses that and addresses the bulk of that. 3 3B is more around bringing northern gas down to southern markets.

As Ian, there's swings and roundabouts, and our gas market model plays out all these scenarios around additional Bass Strait gas, for example. We're not saying that it's going to be there well into the 2030s, but if there's more molecules coming from southern supply, then that could relieve some of the pressure.

Again, it's hard to time it precisely. What we've done is staged it in a way that we're within, call it, 24 months of when it's needed.

The other way to look at it is we're not expecting 3B to go to 100% capacity on day one. We're expecting it to ramp up over time.

If it comes in a little earlier than is required, it just means that there's a bit of a longer ramp-up in that regard, and that's okay. Our return thresholds are conservative and accommodate that.

Again, we're confident that it'll be delivered on time to address any shortfalls.

Okay. That's fine.

The other one is Taroom Trough. You've mentioned it, I think a few other people have mentioned it.

Just sort of interested, does that have implications for Beetaloo development? If the Taroom Trough actually proves viable, do we see Beetaloo get pushed to the right, and those projects sort of move off the agenda?

I don't think so. Look, what we're seeing early days in the Taroom is it's wet gas, more wet gas than it is Beetaloo very dry gas.

Obviously, when you think about the gas that's flowing out of Gladstone, for example, then that's very dry gas. The processing facilities there and the gasification facilities there are set up to take dry gas.

It'll be interesting to see whether or not Taroom is a strong export product or is it better off being used as a domestic product. The other thing I'd say is that Beetaloo, the really good thing about Beetaloo, where it's positioned, and the size, and the way that the acreage has been structured is that it's got as much viability going north as it has going east.

You might find that it goes north first and east second, or it could go east first and north second. Again, we're not trying to back any particular horse in that regard.

We're just trying to get prepared with all the planning and approvals to be able to accommodate both. Same with Taroom Trough where, as you can imagine, we're working with all the producers who have acreage in the Taroom and doing work, and because we know that pipeline capacity is critical for them to be able to commercialize their operations.

One final one. In the generation side, did you guys bid in the South Australian firm option, or have you passed on that opportunity?

No, we did not.

Yep, thanks.

G'day, Adam and Garrick. Just a couple from me, please.

Just in terms of the growth pipeline, obviously, upsized from 2.1 to $3 billion. Mightn't be particularly easy thing to do, but can you give us an idea of the projects that are in that pipeline, how much spend is required beyond FY 2028 to bring those projects into operation?

Then, if you can sort of give us a steer in terms of when you think the earnings from those projects will be fully ramped up?

I'll try my best, Nathan, not because I don't have it in front of me, but just, obviously, I can't provide any information that's not already out there. Look, if you think about the list that I went through before, East Coast Gas Grid, some of that will fall out of the FY 2028 because the Booligal we said is going to be available by the end of calendar 2028.

There'll be some additional flow-on there. Again, I've just sort of answered your question around when we start generating cash flows there.

We've been clear in our announcement today that we're targeting a winter 2028 for stage 3A and a end of calendar 2028 for 3B. With the Brigalow peaking power plant, you're stretching my memory, but I think we're able to provide you with some guidance around the timing of that.

That principally falls into this period. From memory, there's a little bit that stages beyond the FY 2028 period.

The pipeline would obviously be there before the power plant is commissioned, which is important. Obviously, pardon the pun, but we've got a pipeline of opportunities in laterals both to service GPG and other gas fields that fall outside of 2028.

Beetaloo, some of those big developments are in the $3 billion. They all fall outside of that.

We've obviously got the SPP within, but those bigger ones would fall principally outside of that. Remote grid, again, portfolio-weighted, we've got some in the 3, but when you look at the opportunities that we've outlined before in places like the Pilbara, most of that falls outside of that $3 billion FY 2028 period.

One of the things that we look at is how we stage all of that and how we fund it. The team's got models after models, as you can expect, to be able to ensure that we can create value in the way that we deliver those.

That's easy to say on a spreadsheet. It's the team doing an enormous amount of work having to work with our customers to try and time it to perfection, which is not always the case.

Yep. Great answer.

Second one, probably more for Garrick, but the increased debt capacity, that's with reference to the S&P downgrade trigger being reduced. Can you just talk through the Moody's credit rating and whether that's a constraint on debt capacity or there's an opportunity there for you?

The constraint has always been S&P. Moody's is eight the downward threshold is 8% FFO to debt.

There is slightly different calculation between the two rating agencies, but there is more debt capacity when we look at Moody's relative to S&P. Again, we have great discussions with both rating agencies, and they're really comfortable with nature of the revenues and nature of the growth we've got ahead of us.

That's really exciting that we can sit here, have confidence in our debt capacity and confidence in delivering that accretive growth.

Yep, great. Thanks.

Thank you very much, and look, thanks, everyone. I know it's a super busy day, thanks for taking the time and thanks for your questions.

If I can just leave you with the key takeaways from today's result: first, we've delivered a strong financial and operating result, which we're really pleased with, and we've provided what we believe is a strong outlook for FY 2026. Our growth outlook more broadly is compelling, and the returns that we can generate from those projects are really positive.

Thirdly, our balance sheet is strong. Again, I do appreciate your support, and thank you for taking the time, and we'll speak to you soon.