Operator: Thank you for standing by, and welcome to the APA Group FY 2025 Results. [Operator Instructions] I would now like to hand the conference over to Mr. Adam Watson, Managing Director and Chief Executive Officer. Please go ahead.

Adam Jeffrey Watson: Thank you very much, and good morning, everyone. Thank you for joining us at today's FY '25 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 in 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. In the Pilbara region of Western Australia, which is prone to cyclones, APA's Port Hedland Solar and Battery Project was built to withstand wind speeds of up to 288 kilometers per hour, a one in 500-year event. In February 2025, cyclone Zelia brought destructive weather to the region. It was pleasing to see that notwithstanding these challenging conditions, APA's infrastructure enabled operational continuity for our customers and all of our people were safe. Moving to Slide 5. On 13 June this year, we marked 25 years since listing on the ASX. The photo on the top left is the day 1 management team, including the group's first CEO, the late Jim McDonald, as was Mick McCormack, who was our CEO for 14 years. This team set the pathway for growth and the generation of significant securityholder value. FY '25 marked the 21st consecutive year of distribution growth for APA, and we believe APA is 1 of only 2 companies on the ASX to have achieved this. Moving to Slide 6. There are three key takeaways from today's results. First, we've delivered a strong financial and operating result and have a strong outlook for the year ahead. FY '25 EBITDA is up 6.4% at the top end of guidance. EBITDA margins have increased. The midpoint of our FY '26 EBITDA guidance would represent a 7.2% increase on FY '25. And we've delivered and guided towards ongoing year-on-year distribution growth. Second, we've taken steps over the last year to simplify our business. In FY '25, we've delivered cost growth below inflation, and today, we have announced a cost-out target of approximately $50 million for FY '26. Yesterday, we announced the accretive sale of our noncore Networks business. And we've addressed regulatory risks with positive outcomes for both the Southwest Queensland pipeline and Basslink. Third, we have strong momentum executing our strategy. We've successfully commissioned a number of important construction projects. Our organic growth pipeline has increased from $1.8 billion to $2.1 billion. And our credit metrics improved from 10.1% to 10.4%, which means we can comfortably fund our organic growth pipeline from our existing balance sheet. Moving now to Slide 8. Suffice to say, we're very pleased with our financial results for FY '25 and for our outlook for FY '26. FY '25 underlying EBITDA, as I said, delivered growth of 6.4%, which is a great result. Underlying EBITDA margins increased, supported by the investments we've made in recent years in the foundations of our business, which have facilitated the delivery of our cost reduction initiatives. Growth in our operating cash flow was strong. Free cash flow is marginally higher than last year, remembering that we are back to taxpaying status and that we continue to use our cash flows to fund investments. As mentioned, our FY '25 distribution of $0.57 per security is up $0.01 on last year and in line with guidance. Looking to the year ahead, our distribution guidance for FY '26 is $0.58 per security, up further $0.01 in what we expect to be our 22nd consecutive year of distribution growth. Our underlying EBITDA guidance for FY '26 is between $2.12 billion and $2.2 billion, with the midpoint of this guidance, 7.2% higher than FY '25. That means earnings growth for FY '26 is expected to be even higher than FY '25. And it also means we're continuing to deliver earnings growth ahead of inflation. On Slide 9, we call out the continued progress we're making with our key nonfinancial metrics. While our safety performance was generally strong, we regrettably had one serious harm incident involving an all-terrain vehicle. This is a reminder that we must always be vigilant in our pursuit for safety excellence. We progressed a number of growth projects with our customers, completing construction of the Port Hedland Solar Farm and Battery Project, completing the Kurri Kurri Lateral and delivering early works on the East Coast Gas Grid expansion and the Sturt Plateau Pipeline in the Beetaloo. Employee engagement, as measured through our employee experience score was 70%, consistent with the previous year. We also delivered all commitments under our Reflect Reconciliation Action Plan and have now launched our Innovate RAP. And finally, on climate, we're delivering on our commitments, and we've reaffirmed our headline 2030 targets and goals in our 2025 climate transition plan. Slide 10 highlights our strong foundations for growth. We're being disciplined prioritizing growth projects that would deliver the highest returns for our securityholders. We're confident about the need for new gas transmission infrastructure to support new gas fields such as the Beetaloo Basin and to transport gas north to south via our East Coast Gas Grid. We see strong growing demand for gas power generation. And we remain confident about the value creation to be delivered by our recent acquisitions, that is Pilbara Energy and Basslink. Our balance sheet is strong with the ability to fund our $2.1 billion organic growth pipeline from existing capacity. We've successfully addressed regulatory concerns, ensuring the Southwest Queensland pipeline avoids heavy regulation, which is key to ensuring we can continue to expand our East Coast Gas Grid. And we've made a positive step forward with Basslink having received confirmation that it will be regulated, assuming we can agree a reasonable regulated asset base over the coming months. We've taken a number of steps to simplify our business and make it more efficient. Yesterday, we announced an agreement to divest our noncore Networks business, as I mentioned earlier. We've exited the contract early which was due to expire in 2027 to ensure we're focused on our core business and growth pipeline, noting the transaction is also value accretive. We recently made the tough decision to withdraw from the large East Coast electricity transmission projects to simplify our business, reduce costs and ensure our people are focused on our core growth markets that deliver the highest securityholder returns. And we're simplifying our business through a comprehensive enterprise-wide cost reduction initiative that's now well underway. I'll now hand it to Garrick for a deeper dive into our financial performance.

Garrick Rollason: Thanks, Adam, and good morning, everyone. I would like to make three key points today on our financial year 2025 results. First, the business has delivered strong earnings growth, with underlying EBITDA up 6.4% to over $2 billion. This is the first time APA has delivered annual earnings of over $2 billion. Second, our balance sheet remains strong, and we are well positioned to fund growth, along with growing distributions to securityholders. And finally, our inflation-linked cash flows, strong customer demand and disciplined focus on reducing costs means we are well positioned to create value with the organic growth opportunities in front of us. Moving to our headline financials on Slide 12. The FY '25 result delivers underlying EBITDA at the top end of guidance and continued growth in distributions. Pleasingly, underlying EBITDA margin has expanded to 74.2%, supported by the stronger operating result and corporate cost growth below inflation. Free cash flow was up by 1% to almost $1.1 billion. This reflects higher underlying earnings, partially offset by increased funding costs and cash tax payments. Moving to Slide 13 and I'll step through the drivers of our 6.4% uplift in underlying EBITDA. On the East Coast, there was increased demand from customers for seasonal capacity, inflation-linked tariff escalations and ongoing strong customer recontracting. Additionally, as disclosed at the half, we received $13 million in insurance proceeds relating to the Moomba Sydney Ethane Pipeline. In FY '26, following the MSEP conversion, we expect to recommence revenue from this asset. On the West Coast, higher ownership of the Goldfields Gas Pipeline and increased customer demand on NGI contributed to higher earnings. The Pilbara Energy assets drove strong growth in contracted power generation earnings in line with expectations. And finally, corporate costs increased by 2.5%. Pleasingly, we delivered corporate cost growth below inflation. And as Adam mentioned, we have progressed work to optimize APA's cost base with targeted reduction initiatives. I'll have more to say on this later in the presentation. Slide 14 summarizes the movement in free cash flow, which was up almost 1% to approximately $1.1 billion. The benefit from the uplift in underlying EBITDA was partially offset by higher interest and cash tax paid. Higher interest costs reflect the new debt issuances, a full 12 months of interest on hybrid securities, and an overall increase in net debt to support our organic growth. Looking forward to FY '26, increased underlying EBITDA will be offset by increased debt funding costs as we continue to invest in growth. Slide 15 takes a look at statutory NPAT. Net profit after tax, excluding significant items of $129 million is 8.4% higher than the corresponding period. This is despite an increase in depreciation and amortization due to the inclusion of the Pilbara Energy assets and increased net interest. Moving to capital expenditure on Slide 16. During the year, we invested in growth capital expenditure through the completion of both the Kurri Kurri Lateral Pipeline and the Port Hedland Solar and Battery Projects. These projects contributed earnings at the back end of the second half as expected. We also invested in the East Coast Gas Grid expansion, including the MSEP natural gas conversion and the MSP summer capacity expansion as well as the acquisition of the Atlas to Reedy Creek Pipeline. Foundational CapEx in FY '25 was lower than expected as we work to efficiently reduce and defer these expenditures. We're expecting foundational CapEx of between $100 million to $120 million in FY '26 and FY '27. This will moderate to around $80 million in FY '28 and further moderate beyond FY '28 with a principal focus on emissions reduction commitments. It's important to note that our investment in foundational technology CapEx is now being leveraged to drive productivity improvements from data and AI. Stay-in-business CapEx was slightly higher for the year than guided, but we expect to continue -- we continue to expect expenditure at around $200 million to $210 million per annum over the next 3 years. As Adam said previously, we've increased our organic growth CapEx pipeline from $1.8 billion to approximately $2.1 billion over the next 3 years, which we can fund from the existing balance sheet without ordinary equity raisings other than the DRP. Turning now to our capital management and debt metrics on Slide 17. We remain well positioned with a healthy spread of debt maturities and a significant amount of liquidity to support investment in growth. In the year, we undertook a number of capital management initiatives, which have further strengthened our balance sheet position. These included a very successful return to the U.S. dollar bond market, where we raised USD 1.25 billion with 10- and 20-year maturities. This enabled us to proactively repay early the outstanding U.S. dollar notes in September. We have no existing drawn debt maturities until March 2027. As noted earlier, funds from operation to net debt at June was 10.4%, comfortably above our target of 9.5%. This implies debt capacity at the year-end of $1.1 billion. This metric remains consistent with our BBB/Baa2 credit ratings and is in line with credit rating agency expectations. We remain committed to our current investment- grade credit ratings. Moving to Slide 18. I want to remind you of APA's capital allocation framework. This continues to be a key consideration for our decision-making as we assess our growth opportunities. The framework is designed to ensure we allocate our free cash flow to those initiatives that can create the most value for our securityholders. To that point, I'll outline our approach to funding organic growth on Slide 19. We have existing balance sheet capacity to fund that $2.1 billion organic growth pipeline over FY '26 to FY '28. Apart from the DRP, APA does not need to issue ordinary equity to fund this identified growth pipeline. The $2.1 billion includes in-flight and probable growth projects across gas transmission and storage, GPG and contracted remote power generation. This strong position combined with active capital management and the predictable capacity-based inflation-linked tariffs we have highlighted today leaves us well positioned to deliver on our organic opportunities. By focusing on an efficient cost base and increasing free cash flow, our balance sheet capacity increases year-on-year. The inflation linkage on our tariffs, combined with participation in the DRP provide incrementally up to $600 million of additional CapEx funding every year. This is before taking into account any funding benefits from cost optimizations and potential proceeds from asset recycling. In short, we are very confident in the funding flexibility we have to meet the attractive growth opportunities available to us. This growth agenda brings me to our FY '26 underlying EBITDA guidance on Page 20. Today, we are providing FY '26 underlying EBITDA guidance of between $2.12 billion and $2.2 billion. At the midpoint, this represents a 7.2% growth year-on-year, even higher than the 6.4% growth we have delivered this year despite the loss of earnings following the sale of the Networks business. Key drivers of growth in earnings include inflation-linked tariff revenues and contributions from new assets. Cost reduction initiatives are expected to contribute $50 million in FY '26, with full year of savings to come through in FY '27. The majority of cost benefits in FY '26 will be realized in operating costs. Savings from the change in our electric transmission strategy will be reported within the operating cost for electricity transmission rather than corporate costs. And further savings in corporate costs will come through in FY '27. These drivers of earnings growth are offset in part by the divestment of our Networks business as announced yesterday, which is expected to complete by the end of calendar year 2025. Importantly, this will significantly simplify our operating business by reducing head count by approximately 725 people. The contract under which we provided these services to the asset owner was due to expire 2027. The asset sale will reduce FY '26 earnings by about $15 million, and we expect a value accretive outcome from the sale, inclusive of the transition services agreement. With regards to Basslink earnings, as you are aware, the AER announced in June its final decision to convert Basslink into a regulated asset. We expect that this will take effect from July next year, subject to the agreement of an acceptable RAB. In the interim, we will trade the asset in the spot market. Our earnings guidance for FY '26 assumes Basslink contributes earnings in line with FY '25. However, earnings from the asset may be subject to potentially material volatility and fluctuations. My final slide is an update on our initiatives to enhance securityholder value. First, we have simplified the business by refining our electricity transmission strategy to focus on projects that complement our existing infrastructure and also signed an agreement to divest our Networks business as we move away from operating assets that we do not own. Second, we are targeting material productivity and cost improvements across the business with an initial contribution of $50 million uplift in underlying EBITDA in FY '26 and further savings in FY '27. And finally, we are pursuing organic growth opportunities of $2.1 billion over the next 3 years to be funded from the existing balance sheet. And with that, I'll hand back to Adam.

Adam Jeffrey Watson: Thanks, Garrick. Slide 23 sets out our strategy, which is unchanged. Within this strategy, we've sharpened our focus, we've got strong momentum and our balance sheet will support the delivery of strong securityholder returns. Moving to Slide 24. Our growth pipeline is centered around markets that are large in opportunity and where we have a competitive advantage. Gas transmission and storage has been the foundation of APA's growth over the last 25 years and will remain a core part of our growth story going forward. In February, we announced our East Coast Gas Grid expansion plan, which will play a vital role in avoiding southern market gas shortfalls. We continue to progress work in the Beetaloo, and we're supporting the required investment in GPG across the country with new lateral and gas storage infrastructure for customers such as CS Energy in Queensland. The outlook for GPG is compelling. AEMO's 2024 ISP Step Change scenario forecast the need for 13 gigawatts of new GPG investment in the NEM as coal retires. More recently, analysis undertaken by Griffith University suggests around 20 gigawatts of new investment is required. The opportunities in the GPG market for APA are significant. APA is well positioned to support delivery of the new GPG capacity with strong existing capabilities in the delivery and operation of these assets. And we know energy demand growth through data centers and AI could provide additional opportunities for APA well above these current AEMO forecasts. Remote contracted power generation also represents a significant addressable market where our capability is clear. Major mining customers continue to look for reliable, low cost and lower emissions energy. With a 4-gigawatt project pipeline in the Pilbara and other opportunities in places like Mount Isa and Kalgoorlie, delivering bundled energy solutions for our customers in remote locations remains a key part of our growth agenda. While the timing of commitments from our mining customers has been impacted recently by commodity prices, we remain confident about the near- and longer-term demand for our infrastructure as our customers decarbonize. Importantly, our strategy more broadly, spans across a number of key energy markets, thereby avoiding exposure to any single market dynamic at any given time. Slide 25 confirms the strong long-term demand for gas in Australia and the significant domestic supply available to service it. Strong demand is underpinned by industrial demand, and electrification as coal retires. This is evidenced by AEMO's long-term view of gas, which is presented on the left of the page. The chart on the right shows the significant volumes of domestic gas reserves and resources available to meet domestic demand and to underpin Australia's critically important LNG export market. There are over 68,000 petajoules of 2P reserves and 2C resources available in Eastern Australia to serve an East Coast market that consumes around 500 petajoules of natural gas each year. The key point, domestic gas supply is not a constraint. Domestic supply can meet demand. The focus of government and industry must be to develop the necessary steps to unlock this domestic supply. We strongly believe that these domestic reserves and resources offer a lower cost and lower emissions option when compared with LNG import terminals. As you can see on the left graph, there has only been a handful of days in the last few years where Asian LNG spot prices have been lower than domestic wholesale gas prices. Now I'll remind you that Asian LNG spot prices only accommodate landing unprocessed LNG into regions such as Japan. It doesn't include the additional transportation and processing costs, which are required to compare these spot prices to Australia's domestic wholesale gas costs. The graph on the right highlights the significant additional costs imposed to land imported LNG into Australia. With high spot prices and multiple cost inputs to process land LNG into Australia, it's just ludicrous to think that LNG imports can be delivered into Australia at prices substantially lower than domestic gas. Now from an APA perspective, we're agnostic to whether we transport domestic gas or imported LNG. The key message is that we want market certainty for our customers and consumers. We need to stop the distracting debate about supporting LNG import terminals and instead provides certainty for the development of low-cost, reliable domestic gas. We must support domestic gas. So we don't allow LNG imports to set the price of domestic energy as we've seen in places like the U.K. where consumers are suffering with some of the highest energy prices in the world. Slide 27 shows the volumes of domestic gas available in Australia and their relative wellhead prices. It suggests that our Northern basins including the Surat and the Beetaloo, will provide lowest cost options to meet demand. Most notably, the forecasted production cost of Beetaloo gas of $5.67 per gigajoule demonstrates its long-term potential as an affordable source of supply. Again, domestic gas is not a constraint. Slide 28 is a reminder that pipeline capacity also isn't a constraint. The plan we outlined earlier this year for Stages 3 to 5 of our East Coast Gas Grid expansion will play a vital role in avoiding southern market gas shortfalls. This is confirmed by AEMO's 2025 GSOO that identifies the pipelines expansions and upgrade scenario to be the only option where supply gaps are fully addressed out to 2044. We're moving forward with our expansion plans, including progressing delivery of our short-term enhancements. This includes the MSEP conversion project and upgrades to boost year-round capacity on the MSP via compression. We're continuing to work with customers and progressing the next stages and with governments to implement the right regulatory and investment settings needed to unlock gas supply. Moving now to Slide 29. As mentioned significant new gas power generation capacity is essential to support Australia's energy transition. GPG already plays a critical firming role for our energy market. As more renewables come online and coal exits, GPG's role will become even more important. The demand for new GPG is compelling and presents a significant opportunity for APA. And the data on the slide doesn't yet accommodate in any material way the significant potential upside in demand for GPG to support data centers and AI. Moving to Slide 30. Contracted power generation in remote regions will also require significant investment. The Pilbara region alone is expected to see a 40-fold increase in electricity demand from 2024 and to 2050. APA's credentials and strategic advantages in this space are significant. We have a record of successful project delivery and operational reliability. We've built our reputation as a trusted partner with our customers, and we've established and continue to strengthen meaningful and lasting relationships with traditional owners. We remain confident about the growth prospects in our remote regions. We continue to progress projects across the Pilbara, Mount Isa and Kalgoorlie, and we're making sure we have the best sites available for our customers' future demand. Moving to Slide 32. To wrap up, EBITDA is up 6.4% on last year, well above inflation and towards the top end of guidance. The midpoint of FY '26 EBITDA guidance would represent 7.2% growth. We've expanded our EBITDA margins delivering cost growth below inflation and announced a $50 million cost out target for FY '26. Distributions are high year-on-year and are expected to grow again in FY '26. Our credit metrics have improved from 10.1% to 10.4%. We've simplified APA through our cost-out initiatives and by divesting our noncore Networks business. We've also successfully addressed regulatory risks. And finally, our organic growth pipeline has increased from $1.8 billion to $2.1 billion, and we have the balance sheet capacity to fund it. We've delivered a strong FY '25 result and our FY '26 outlook is even stronger, which all form part of our compelling investment thesis. Thank you for your time. Let's move now to Q&A.

Operator: [Operator Instructions] Your first question will come from Tom Allen of UBS.

Tom Allen: Adam, Garrick and the broader team. Just picking up your comment, Adam, during the presentation that the growth strategy hasn't changed, you can certainly see a lot of elements there that haven't, but -- it appears that the East Coast electricity transmission is no longer on strategy. And just given that, that asset class had made up near half the addressable market that APA had presented to in May. Can you just expand a little bit more on the asset classes and specific opportunities that are expanding to fill the void in the growth outlook?

Adam Jeffrey Watson: Yes. Thanks, Tom. And look, the strategy hasn't changed. Obviously, our core focus is to deliver energy infrastructure that is supported by long-term contracts that's inflation-linked and that can support the energy transition. So when you look at where we've focused, that still remains completely on track. We've got a role to play in the energy transition, but we've also got a role to play for our securityholders, and that's all about capital allocation and focusing our capital and focusing our people on those projects that deliver the best returns. So when we weigh up the opportunities and the opportunities are significant across the entire portfolio. So we were talking over $100 billion worth of addressable market over the last couple of years. Even with the removal of our focus on the larger electricity transmission projects on the East Coast grid, we've got an addressable market in excess of $100 billion. So the addressable market is significant. And again, in those core areas of focus, gas transmission and storage, remote grids, GPG and then you can add to the longer term, the future fuels, there's more than enough opportunity there for us to create value for the securityholders.

Tom Allen: And so on the reference there to the growth in gas transmission and storage, for growth opportunities like stages 3, 4, 5 of the East Coast Grid expansion and others, are your discussions with shippers indicating a willingness to sign 10-year-plus contracts that would underwrite APA's minimum return hurdle on these incremental expansions? Or should we expect that APA would need to take some underwriting risk on these types of expansions?

Adam Jeffrey Watson: Yes, Tom, we said from the outset when we announced this back in February that we weren't expecting the market to be fully underwriting the projects like they were 10, 20 years ago for 10, 20 years. That's -- their days gone by. And we've invested well over $700 million in the first few stages of the East Coast Grid taking on a level of market risk and the demand has been incredibly strong. We're fully contracted out through calendar 2027. So the demand is there, and I think I've produced the relevant data as does AEMO and others that supports the demand for our services. We clearly want to work with our customers and work with the government to be able to get the right level of support we need to have the confidence to make some of those bigger investments. We're already continuing on with projects like the MSEP conversion and the compression activity along a couple of our major pipelines. But for some of those bigger projects like the Bulloo Interlink, we want to work with our customers on that. Look, the market is dynamic at the moment. And one of the reasons why we're hitting it pretty hard, just wanting to call out the need for certainty around regulatory and policy arrangements to support the supply of domestic gas is because that the shippers are sitting there and basically looking at the market and trying to work out where they're going to be sourcing gas from. It's not a matter of will there be gas to source. It's just where do they get that from. So we'll work through that. We're confident -- we've still got time up our sleeve. And again, AEMO made it very clear that the only way to achieve the supply requirements for the East Coast was through the pipeline's expansion scenario and that's where we play a role.

Tom Allen: And do you expect that APA's organic growth pipeline into the medium term can deliver the additional earnings that are required to offset the EBITDA decline ahead of the Wallumbilla Gladstone Pipeline capacity tariff expiring? Or if you think that organic growth doesn't solve that equation alone, can you outline some color on the types of inorganic opportunities that might fit the strategy, how you might fund it? And also just to comment on storage, really interested in how APA might get some leverage to some storage in southern markets.

Adam Jeffrey Watson: Yes. So we've been crystal clear that we are not trying to replace WGP earnings. We have made that clear, and I'll make that clear again. So we are not trying to replace dollar for dollar there. But what we are trying to do is to continue to grow the business as we have done for the past 25 years. And one of the things that we try to do, we've done it for 21 years consecutively is continue to deliver returns for our shareholders by way of distribution growth and obviously, by the allocation of capital that delivers returns well above our hurdle rate. So we feel confident about that. We operate a portfolio of assets, and that enables us to move as the market moves, which is always going to be dynamic. We always know that the energy transition will be dynamic. Look, the opportunities in things like storage are really important. One of the things that I call out regularly is as we transition away from coal, someone said to me the other day that the only thing that is meeting the energy transition timetable is the exit of coal, the coal-fired power generators. We need more gas-fired power generation coming into the market, and that gas-fired power generation capacity requires storage, which is best serviced through pipeline storage. So again, we think that there's a significant amount of opportunities on the horizon, and we're feeling very confident about the long-term growth outlook.

Operator: The next question will come from Rob Koh of Morgan Stanley.

Robert Koh: Congratulations on the result, and good to hear Mr. Watson getting a bit fired up about the domestic gas debate. Great to see. I guess just drilling into the growth CapEx bucket of gas power generation. Just two questions on that. Can you maybe give us a sense of where you sit in the queue for orders for turbines? Or do you even have some ability to convert compressors into power? That's the first part of the question. And then the second part of the question is, how does the additional GPG fit into your electricity carbon intensity target? Is there like a megawatt of renewable that you would need to check in for every megawatt of gas, please?

Adam Jeffrey Watson: Yes. Thanks, Rob. So look, from a GPG perspective, supply chain, really for all major electricity transmission equipment and for GPG power generation equipment is a challenge. One of the things that we're -- we've worked really hard on for a long period of time now is the relationships we have with our suppliers. I personally spend a lot of time traveling, meeting with suppliers and ensuring that we can provide them with the confidence that we're going to be there to meet their supply ambitions as well. So obviously, that's something we've worked on, and we feel confident about that. It is an important thing to remember that ordering this equipment is time consuming and that you have to wait a couple of years for it to be delivered. So one of the things that we're doing with our customers is ensuring that we work with them and try and get those early orders in to ensure that we're not falling behind in the delivery of that equipment. So we're alive to it. It is -- I'm not going to suggest that it's not a challenge, but we feel very confident that with our scale and with the relationships that we have that we can manage that better than most. Look, just generally around GPG and the emissions intensity, one of the things that we've said in our climate transition plan, and we've been very clear with this and really deep engagement with our shareholders on this is that we are really focused on supporting the energy transition and taking the economy-wide emissions down. If that means that we end up putting more GPG into the system, and that impacts our intensity targets, then we'll continue to monitor that and look at that. We've still feel confident that we will be bringing renewable power generation to market, particularly in the off- grid space. Again, timing of all of these things really is customer-led. So we'll continue to monitor that. But over the longer term, we're confident that we're going to be doing the right thing by taking broader economic emissions down, and if it means that we're putting more on our balance sheet, then we're being very open and candid that, that could be the case.

Robert Koh: Second question is, I'm just having a look at the annual report of the FX hedging. It looks like the FX hedging for Wallumbilla Gladstone has now come down to a rate of $64.81. Is that the rate we should be using? And can you maybe just remind us about when the timing of that comes in, please?

Garrick Rollason: So you mean the revenue hedging, Rob?

Robert Koh: Yes.

Garrick Rollason: Yes. So we're fully hedged out for the next 3 years on the revenue associated with WGP. We've hedged that in '26 at about $0.67, '27 about $0.66 and '28 at about $0.64. So they're the numbers you should use.

Robert Koh: Excellent. That's even easier. I don't have to work it out. Last question for me, if I can. I noticed you submitted a greenfield exemption request for the Bulloo Interlink, which mentions an FID possibly as early as October this year. I wonder if you could just provide some color to that project and the timing, please.

Adam Jeffrey Watson: Yes. Thanks, Rob. Look, that all forms part of the East Coast Gas Grid expansion. One of the really positive things about that expansion plan is that we've got multiple levers to pull to expand as required in support of not only demand and supply equation but what our customers want. So the initial focus is on, as I said, before the conversion of the MSEP and also on some compression along a couple of our corridors. The Bulloo Interlink, we think, is a really important transportation piece of infrastructure that will move gas from northern gas fields to southern gas fields. FY '26 was our target FID. And look, these things can always change. Again, we just need to work with our customers on whether or not we continue to that timetable. It's not a matter of if, it's a matter of when, Rob. So we remain confident on FY '26, nothing's changed. And we'll continue to monitor it as we work with our customers over the coming months.

Operator: Our next question today will come from Nathan Lead of Morgans.

Nathan Lead: First question for me is to do with your assets under construction, your PPA note. It looks like $969 million of assets actually were commissioned during the year. Can you just provide that split between sustaining and growth CapEx, please?

Garrick Rollason: Thanks for the question, Nathan. Predominantly, the growth capital, about $600 million of it related to the Kurri Kurri Lateral Pipeline, largely the balance is stay in business capital.

Nathan Lead: Great. Second question is, I mean, you obviously got this commitment to keeping your investment-grade credit ratings. But if we look out in time with the reduction in earnings that comes out of the Wallumbilla Gladstone Pipeline capacity charge decline 10 years out. You've obviously got to prepare your FFO-to-debt metric for that. Can you talk through about where you need that metric to be in the year just before that actually occurs? And therefore, how much true capacity do you actually have in your balance sheet to fund growth with that coming up?

Garrick Rollason: Yes. So Nathan, thanks for the question. We obviously don't provide guidance on our metrics out 10 years. But I'd reiterate what Adam said, the focus for our business is on taking advantage of the growth opportunities in front of us given the large addressable market and ensuring that over that period of time, we continue to grow our distributions to securityholders. And with the pipeline available to us, we see the ability to deliver that with the existing balance sheet credit metrics staying intact through the course of that time.

Adam Jeffrey Watson: And if I could just add, Nathan, we did say a couple of years ago, we effectively reset the way that we go about distribution. So we moved away from quasi paying out distributions in line with free cash to a strategy, which is more about year-on-year distribution growth. We did a lot of work with our investors. In fact, we spoke to every investor that we've met with around their appetite for the different options. That was the option that we had overwhelming feedback on in terms of trying to continue to grow that distribution as well as deploying capital for growth. And the reality is then is that free cash that we generate will be used to support those credit metrics over time.

Nathan Lead: Yes. Okay. And then just a final one for me. Your sustaining CapEx guidance the $200 million to $210 million per year. Could you just talk through about whether that includes the, I suppose, spike in CapEx that comes through when you have major overhauls of power stations?

Garrick Rollason: Yes. So obviously, same business CapEx is cyclical, particularly around power generation. But the guidance we provide obviously, is over 26% to 28%. So pretty comfortable that, that stay-in business CapEx will land across that. A lot of the same business CapEx as noted on Page 16 does relate to integrity works on our pipelines as well as maintenance on Moomba to Sydney.

Nathan Lead: Okay. So when is the next sort of major spike coming in, in power station overhauls, I'm imagining Mount Isa. And yes, if you could just sort of talk through that and what sort of size you expect that to be?

Garrick Rollason: Yes. So again, we're not going to provide detailed guidance beyond what we put on the page, but probably the next significant overhaul in the power generation space is at the back end of this decade.

Operator: The next question will come from Ian Myles of Macquarie.

Ian Myles: Congratulations on the result. A couple of questions on the Bulloo expansion in that East Coast Grid. How much of this is being delayed by the government calling for a gas reform or to review of all the different gas policies out there. So no one actually has that strategy yet.

Adam Jeffrey Watson: Yes. Thanks, Ian. I'm trying not to laugh at the question. Look, firstly, we say that the government doing a review is a good thing. We do need policy certainty, and we're obviously participating in that review. So that's a positive. It goes back to what I said earlier is that what we're seeing with the shippers is that they are pausing on making commitments. Not all of them, by the way, but as a general rule, as you'd expect, they're sitting to -- sitting there and waiting to see what will come of all of this. But ultimately, at the end of the day, it's all about supply. So demand is there, and they're just trying to work out where the supply will come from. We're obviously advocating for stability in the market as are our customers, and we've seen a number of big customers come out quite publicly over the last couple of weeks advocating for that. You get announcements, for example, around capacity coming -- potentially coming online in southern markets and along the Bass Strait. At the end of the day, any supply or any domestic supplier, I should say, is good for the market. and we'll be transporting that along our pipeline. So look, again, there's no change at all as we sit here today in terms of the timing around our East Coast Grid expansion plans. And we remain confident that certainly, over the near term, we'll be delivering those in so far that we get to the right outcomes, which we're confident we will with our customers and with the government.

Ian Myles: Okay. You changed your CapEx from $1.8 billion to $2.1 billion, which is probably not surprising. But just interesting, is that reflective of more going into the hopper or derisking of the existing sort of projects all being changed to lower or becoming more probable?

Adam Jeffrey Watson: Yes. Look, it's a bit of both. There's probably more going into the hopper though. So as you know, it's a probability weighted for want of a better term number. So there are a bunch of projects in there. We've got obviously some that are already in flight. We've got some that are very high probability and some where we have to take a probability assessment. But particularly with the GPG opportunities that are before us now and the East Coast Grid expansions that we just spoke about, has given us more confidence around a number of projects and hence, why it's increased.

Ian Myles: Okay. On a more mundane thing, Mount Isa in the second half had a really good performance. So I was sort of wondering is there some one-offs in there? And probably the second part that is we're hearing talk of [ Dongara ] potentially and Glencore reviewing their plants out there. What's the implication for you as the major power supplier in that region?

Adam Jeffrey Watson: Yes. So just on the first one, it's more of a timing thing, Ian. We -- it's just timing of when our assets were available. When we started the Sabella Solar Farm there, we had a couple of issues with inverters and effectively, as we were doing that, we were supporting our customers with more gas than solar energy, and that cost us a little bit. So it was really just a timing issue around that. So we would ask you to look at the full year number rather than trying to extrapolate anything from the second half. So that's that. I have just forgotten your second question. What was the second question, Ian.

Ian Myles: Half of Mount Isa might shut down. How are you actually sort of positioned?

Adam Jeffrey Watson: Yes. Look, it's an interesting one, and there's a lot of -- the miners just generally are having a lot of public conversations with government at the moment around the viability of mining assets and requirements for support and so forth. So we obviously monitor that really closely. Look, these assets that you know that Diamantina was always meant to move to more of a peaking operation in the middle of the next -- in the middle of the next decade. A lot of these assets, if they were to close down would be closing down over time and continue to be supported by our assets. And there's also just new growth coming through in those markets. So look, we're watching that with interest. I keep coming back to the fact that we've got a portfolio of energy opportunities. And if Mount Isa slows down, then inevitably, what we see is there will be another part of the market which will offset that.

Ian Myles: And that's really the segue to Newman. BHP put out some comments yesterday about the diesel program slowing down in terms of the conversion to electrification. Does that have ramifications for the time lines for wind farms and the needs for wind farms over there.

Adam Jeffrey Watson: Yes, I watched it as well, Ian. And what they've said is -- and maybe I'll take a step back to what we've always said is when you look at -- and it's not -- as you know, our infrastructure in the Pilbara is not targeted to any single customer. It's about having multiple customers being able to use that infrastructure. And we've always said it was going to be in three stages, the electrification of the Pilbara. Stage 1 was the stationary equipment, so conveyor belts, loaders, et cetera, that are effectively at the pits and at the port today. And obviously, to meet those decarbonization commitments, we're seeing that that's where the customers are focused first and foremost. The comment, I don't want to speak on behalf of BHP, but the comment that was made yesterday was about Stages 2 and 3, which was the electrification of trains and the electrification of their trucks. And that is what I heard, and we are hearing that from our customers in the market that, that is being a little slower than expected. And we're not saying that it's been pushed out by a decade, but it's been pushed out by a couple of years just as the technology is progressing. But when you look at our 4 gigawatts of opportunity in the Pilbara, it is based on the stationary equipment. It's based on Stage 1. So hence, why we continue to have confidence in that market. Customers will have capital allocation decisions being made, and that may move timing around. And then I keep coming back. I'll be boring, but I keep coming back to the portfolio where we've got if we have one part of the portfolio a little slower, often what we're seeing is another part of the portfolio going faster. So that actually suits us quite ironically.

Operator: The next question will come from Uwan Minogue of Barrenjoey.

Dale Johannes Koenders: It's actually Dale from Barrenjoey. Just building on Rob's questions around the shape of growth CapEx over the next 3 years. I'd be interested in -- is there a risk of a slowdown in transition that we see like, I guess, a back-ended weighted of your growth CapEx in the $2.1 billion?

Adam Jeffrey Watson: The thing that I know about infrastructure, Dale, and I've been in the industry for a very long time is that it's not a perfect science. It's the crystal ball. Crystal balls in infrastructure are always foggy. And particularly because we're customer-led, we're not taking speculative risk building assets and hoping that our customers will come. We're working with our customers. Look, we've got some really attractive projects that we're working on with our customers now that could come to market quite quickly. We would like to think that we can bring some projects to market during FY '26. And then we have other assets that goes back to Ian's question before around the $2.1 billion pipeline with probability weighting. We have multiple projects that we're working with customers that may accelerate or they might push back by 6 months or a year. So we just have to work with that, but it is why we run a portfolio of projects. And again, my point about it being ironic around some opportunities slowing down is because as we've got some opportunities accelerating it actually helps with our funding and the way that we deploy capital. So the most important thing is that we've got the balance sheet to be able to fund that $2.1 billion regardless of the timing of that. And ultimately, we'll deploy that capital at returns that are well above our hurdle rates. We're really confident about that. We're very disciplined about that, and we'll continue to work with our customers to meet their demands.

Dale Johannes Koenders: Okay. In terms of Basslink, thanks for giving the guidance, I guess, for FY '26, but how should we think about the range of outcomes that you've assumed within your group EBITDA guidance?

Adam Jeffrey Watson: Do you mean for FY '26? Or do you mean the RAB longer term?

Dale Johannes Koenders: For FY '26.

Adam Jeffrey Watson: Yes. Look, we've positioned it so that we assume that we're effectively generating the same returns as FY '25. And obviously, it's traded. So it can move around that. We'll obviously come out with our first half result to provide you with some guidance. We'll provide you with the actual numbers, obviously, but provide you with some more clarity around expectations there. But I think in terms of the regulated asset base, you can see that we've made a submission to the AER on that, and you can back solve where you think that, that will come out.

Dale Johannes Koenders: Should we assume though that the increased range in guidance for '26 versus what's historically been done in [ low Bass ]?

Adam Jeffrey Watson: Yes, good pickup, Dale. Yes, is the short answer. We've provided more range to accommodate a bit more volatility potentially from Basslink .

Dale Johannes Koenders: Okay. And then finally, any comments you'd give on sort of the outlook for D&A and interest expense, technology big items, anything else sort of there as we're thinking about the outlook for profit to build on your EBITDA guidance?

Garrick Rollason: Yes. So we do expect, as I touched on the presentation, expect interest to increase, I mean, in FY '26. And probably the best reference point there is when you look at free cash flow, just interest offsetting some of the increase in underlying EBITDA. In terms of -- sorry, what was the other part of the question? The interest and...

Adam Jeffrey Watson: D&A.

Garrick Rollason: D&A. I think -- I don't expect any potentially material step-up in D&A over the next few years.

Dale Johannes Koenders: And then your technology costs that have been a big item that has slowly been reducing over time. Do they continue at the current level?

Garrick Rollason: Yes. So technology transformation probably is obviously the big step down from '24 to '25 was completion of the ERP program. We've also completed some of the other tech-focused program, including a data warehouse and the like. So going forward, I really see that focused on the ongoing SaaS cloud projects, which comes around $20 million per annum. The other big on the CapEx side, the foundational CapEx side, the other big technology program is the Grid Solutions program. So that's a hydrocarbon accounting program. That will continue through the course of FY '26 and FY '27. And that's about $30 million per annum and then it will be complete thereafter.

Operator: The next question will come from Gordon Ramsay of RBC Capital Markets.

Gordon Alexander Ramsay: Adam, I'd like to comment about the withdrawal from the large East Coast electricity projects and a refinement to work on projects that complement existing assets. It sounds like a lower risk strategy potentially better from a timing and funding perspective. Just want to focus on GPG because you said the outlook for that is compelling. And I want to understand how APA is going to play that going forward. Clearly, you'll look at contracting structures, storage increase, pipeline capacity. Are there other aspects of the GPG opportunity that APA is prepared to look at and invest in.

Adam Jeffrey Watson: Yes. Thanks, Gordon. Look, a couple of things. One, there hasn't been a lot of GPG built in Australia for the last decade. Obviously, the Hunter Power Project which now is building, which effectively is our Kurri Kurri Lateral project is the one in flight, and there were a couple of smaller ones that have been built 10 or so years ago. So there hasn't been a lot built, but the demand, I think, I've well articulated is quite significant. In terms of our capability, we are obviously already own GPG, particularly in regions like Mount Isa and the Pilbara. So we've got the capability and the credibility there as an operator. We've developed these assets before, and we've got the capability, and we've worked really hard at making sure, we've got the right people in our organization to be able to support our customers in the delivery of these projects. I look at GPG as a network in and of itself. So for every GPG that needs to get built, it also needs a pipeline to connect that GPG to the pipeline transmission asset. It obviously needs storage, as I mentioned before, because when the GPG is required, you can't just call up APA and say, "Hey, I need some more volume." You've got to be able to have extra volume there through storage facilities. And you need a long-term GTA so that you can -- there's no point having an insurance product sitting if you don't have the gas to be able to feed it. So it's a really compelling thing for us that it creates its own network. And ultimately, in terms of the construct of the GPG itself, we obviously want to take low risk. We want long-term contracts. We want inflation-linked revenues. So when we're working with our customer on projects, which we're doing at the moment, we're working up models where effectively, they trade the asset and they take the trading risk of that asset, which suits them because most of the customers that we're working with want to operate the GPG as part of a broader portfolio of energy. So they would take effectively the trading risk or at least the vast majority of the trading risk and we would be there trying to take, think of it like a tolling arrangement, but a base fee effectively for the investment that we've made in the asset and the ongoing operations.

Gordon Alexander Ramsay: Excellent. That's really good. And just one more from me. You said earlier that you're customer led, and I can't help but asking you, does that mean no more gas pipelines built without customer contracts, and I'm referring to the Northern Goldfields Pipeline. Obviously, you weren't running the company back then, but is -- I mean, are you basically saying, you were not going to do anything like that going forward...

Adam Jeffrey Watson: Yes. Yes. Look, it's a good point, Gordon. Look, we always look at it through a risk lens. As I said, there will be some things which are complementary or adjacencies like the compression on the East Coast Gas Grid expansion. We didn't try and underwrite that. We took a level of risk. But when you look at the supply demand and the order book, we were so confident about the growth and hence, the conversion of the MSEP that we're doing now, and the additional compression that we're putting on the East Coast Gas Grid. So one of our roles too, that we see is that we've got to create stability in the market through the infrastructure that we provide because that creates the market to do some of the bigger projects as well. So one could argue that we're taking risk on that because we don't have those developments fully underwritten, but I think that risk is very low, and we've proven that. For some of the bigger projects, yes, we do need a level of underwrite. It's just natural that we need to be able to get a level of support to be able to develop those. Again, the days of doing 15-, 20-year 1 customer underwrites are well behind Australia. But again, we're very confident that we can get levels of underwrite there. And it's just really for us to be able to look at that through a risk lens and then obviously a return lens as well. And look, NGI, that will be a great long term investment for us. It's still above our cost of capital. It still going to deliver good returns for our securityholders. Absolutely, it's been slower than what we would have liked. And -- but we'll also reflect on the fact that -- the reason why we built the NGI is because the GGP was at capacity. We had no more capacity for the market. And we also took advantage of the tax breaks that were provided during COVID to be able to effectively get an immediate tax write-off. So that always shielded us from a returns perspective. And we look at the GGP and that took 4 or 5 years to ramp up, we're confident that the NGI will ramp up as well. So it is a timing matter. Again, it's a when, not an if question, and we remain confident about our infrastructure more broadly.

Operator: Our next question will come from Nik Burns of Jarden Australia.

Nik Burns: Look, I might just follow-on from the question Gordon just asked. You've outlined a pretty compelling case for more gas from Queensland to meet decline in southern gas markets versus LNG imports. But I guess if you look, say, 10 years out, when Bass Strait has ceased production, it could be argued that there's room in the market for both increased supply from Queensland as well as the LNG imports. And in the event one or more LNG import terminals are approved and do attract customers, how should we think about the impact on APA? And is the potential threat of LNG imports one of the reasons you're willing to take on more risk on pipeline capacity expansion than you might be otherwise willing to take?

Adam Jeffrey Watson: Yes. Look, I need to make it clear. We -- LNG imports are here. There's an LNG import terminal in Port Campbell that hasn't been able to sign a customer, but that's still there. So LNG imports are there, and they may play a role, whether or not the economic stack up for the developer is not a question that I need to worry about. That's for somebody else to worry about. But our point about LNG imports is you can't have a market like what has occurred in the U.K. as an example, where effectively LNG imports are setting the price of not just gas, but of energy. And I've spoken before around how the energy market has played out in the U.K. because of its reliance on LNG imports, which have effectively set the base price of electricity in that market. And again, when you look at the cost, yes, there might be a bit of trading -- if LNG imports get up, there might be a bit of trading that's done. But ultimately, if it's not sustainable for the customer. If it sets that price too high, you'll end up just having industry and consumers rejecting it because they can't afford it. The real point is when you look at the abundance of supply that there is no issue about domestic supply in Australia. The only issue is making sure that there's the appropriate regulatory and policy settings to enable the producers to produce it. So the fact -- these views that there's not enough supply, it's just not right. We've demonstrated that. And then when you look at it from a pricing perspective, again, we've shown you costs there. And you look at things like the Beetaloo, which is producing incredible well results at the moment at $5.67 per gigajoule. That is low cost. And yes, you've got to transport it. But the landed cost into Melbourne from a field like that will still be at or below the current government price cap, which is about 50% to 80%, even just at the spot price, lower than LNG imports. And then when you take into account the processing and transport costs, I don't know how anyone can sit there and say that it makes any sense. And that's our whole point. We just want stability in the market.

Nik Burns: That's great. And just a question on your organic growth pipeline, $2.1 billion. I think again, you've been pretty clear on the reasons why you can't give too much granularity on that. But just focusing on FY '26 and you talked -- made the point around the need to preorder long lead items. So in theory, most of your capital spend for FY '26 should be locked in by now. Can you give us any indication about what we should be expecting from a growth CapEx perspective this year?

Adam Jeffrey Watson: Yes, I'll hand it to Garrick just to go through that in a moment. But just so that we're clear around these sort of things that are in the $2.1 billion. So the $2.1 billion includes some in-flight projects. We've got the Brigalow pipeline which we've already announced. We've got the Sturt Plateau pipeline for the Beetaloo which has already announced. There is more, obviously, opportunities to bring more volume for the Beetaloo into the market. We're not talking the big Neep project yet, but there is further expansion opportunities there. Obviously, the East Coast Gas Grid, we've announced, which is a significant investment. You've got opportunities in the remote grid space, and you've got opportunities in GPG. So again I'm not -- as you said, I can't get into specifics for the projects that we haven't announced yet because they're customer projects that we're working through confidentially with them. But when we look at that list of projects, it's very real, and we feel very confident about that. But I'll hand it to Garrick in terms of what's in '26.

Garrick Rollason: Yes. So Adam has touched on the three key areas of in-flight projects that are being delivered in '26, which you know about, which is Sturt Plateau Pipeline. The Brigalow pipeline and also the East Coast Grid expansion early works that we've talked about at half year. So those numbers are available per our announcement per the discussion at half year, additional or incremental CapEx related to that will come with further announcements as it relates to new customer works.

Operator: There are no further questions at this time. I'll now hand back to Mr. Watson for closing remarks.

Adam Jeffrey Watson: Great. Well, look, again, really appreciate everyone for being here today and for your questions. Again, just the key takeaways. EBITDA for FY '25, up 6.4% top end of guidance. FY '26 EBITDA guidance would represent a 7.2% increase on '25. So even higher than '25's growth. We've delivered year-on-year distribution growth in '25 and again, guide to an extra $0.01 in FY '26. We've simplified our business. We're delivering cost growth below inflation in FY '25 and announced cost-out targets in '26, simplifying the business through things such as the value-accretive sale of a noncore business in the networks, assets. We've addressed regulatory risks. Our organic growth pipeline increasing from $1.8 billion to $2.1 billion. Credit metrics improved from 10.1% to 10.4%, which means we can comfortably fund our organic growth pipeline from our existing balance sheet. So we think it's a really positive outcome for APA and a really, really positive future ahead. So with that, again, thank you for your time and we look forward to speaking with you soon.