APA Group (APA) Earnings Call Transcript & Summary

Good morning. Thank you all for joining APA Group's FY '24 Full Year Results Presentation. [Operator Instructions] We will start today's presentation by APA Group's CEO and Managing Director, Adam Watson; and CFO, Garrick Rollason; and then we will open it up to questions. I would now like to hand the conference over to Adam Watson, CEO and Managing Director. Please go ahead, sir.

Thank you, and good morning, everyone. Thank you for joining us at today's FY '24 results presentation. I'm joined by Garrick Rollason, our CFO as well as the Broader 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 today. 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, present and emerging. As a sign of how APA is making a difference with our communities, we're at the halfway point with our reconciliation action plan, and we've already achieved 50% of our commitments. While this means we're on track and we have great momentum, we acknowledge we do have more to do. Moving to Slide 4 for a safety share. In June this year, we commissioned a new monitoring system on Basslink. It allows us to safely transport electricity above our nameplate capacity for short periods when there's heightened market demand. In simple terms, we've invested in technology that enables us to run Basslink dynamically based on the temperature of the asset. In the past, we were restricted to operate the asset up to its basic nameplate capacity even when, for example, seabed temperatures were low. Since commissioning in June, we've safely gone above the nameplate capacity for more than 30 hours collectively. The initiative speaks to our focus on ensuring we have assets that are safe and reliable for our customers and the community. And it speaks to our ingenuity as Australia's energy system becomes more dynamic. Today's agenda is on Slide 5. I'll start by covering our FY '24 highlights, and I'll touch on the outlook for FY '25. Garrick will cover our financial performance in more detail. I'll then finish with some observations on current market dynamics before we go to Q&A. Slide 7 provides the highlights of our FY '24 performance. There are 3 key messages from today's results. First, we've delivered a solid financial performance with earnings and distributions in line with guidance. Second, our recent investments are delivering to expectations. And the third key message is that we're making good progress with our business development activities. EBITDA growth was driven by recent acquisitions, inflation and another solid year of customer recontracting. Our corporate cost growth has moderated. Pleasingly, we've been able to keep our growth in costs below expectations. Our balance sheet is in a strong position. We've successfully refinanced a significant amount of debt during the year, and our FFO to debt is above target. Pilbara Energy and Basslink are both performing well, as is Stage 2 of our East Coast Grid. They've all been successfully integrated and generating returns in line with their business cases. Construction is progressing well on both our solar and battery project in Port Hedland and our Kurri Kurri Lateral Pipeline development in New South Wales. From a business development perspective, we've recently signed a new agreement with CS Energy to deliver twin pipelines in Queensland to support their new gas peaking plant. We see gas peaking requirements across the country as an attractive growth market for APA. And our business development pipeline is in good shape. We're actively engaging with customers to progress new opportunities, particularly in power generation. Importantly, we remain confident about the Pilbara business. We're working on a number of opportunities, which we hope to announce in the not-too-distant future. Slide 8 calls out several operational highlights for the year using our 3 delivery pillars as a guide. Our safety performance has improved. Representation of women across our workforce is up. We've continued to operate our assets at a high reliability standard. We've continued to progress our sustainability road map and our climate transition plan. We have the capability of the organization in a good place, having recently invested in areas such as business development, sustainability and community and technology and asset security. We delivered our ERP on time and on budget. We successfully acquired and integrated the Pilbara Energy business. We invested $833 million of capital in organic growth projects. Our balance sheet will support our growth ambition. And we've positioned the company well building capability to ensure we can generate strong returns from the organic growth opportunities before us. Our outlook for FY '25 is on Slide 9. EBITDA guidance for 2025 is between $1.96 billion and $2.02 billion. This is consistent with the internal expectations we've had for some time. It also reflects the statements we've made publicly on revenue and costs and the ramp-up of new assets. FY '25 distribution guidance is $0.57 per security. This too is consistent with our internal expectations. We remind investors that our intention is to consistently grow distributions over time while at the same time, preserving cash to partly fund our organic growth CapEx. From a cash flow perspective, we remind investors that in FY '25, we expect to see higher interest costs as we refinanced some $1.7 billion of debt in the period. We also expect to see our tax payments increase. That's because we conclude the period where we've been able to claim a full upfront tax deduction on our capital investments. While these higher tax payments will impact our free cash flow, it does mean that security holders will benefit as we move to being able to partially frank our dividends. We expect the level of franking to step up over time as we get closer to a more normalized tax payment profile. With that, I'll hand you to Garrick to take you through the financial results in more detail.

Thanks, Adam, and good morning, everyone. Moving to our headline financials on Slide 11. Underlying EBITDA is up 9.7%, reflecting inflation-linked tariff escalation, recontracting and earnings contribution of recent acquisitions, the Pilbara assets and Basslink, both of which delivered earnings in line with their business cases. Free cash flow was relatively flat year-on-year. This reflects a broader shift in higher interest costs relating to capital management initiatives implemented during the year and higher cash tax paid as accelerated depreciation allowances have been fully utilized. Net profit after tax of $119 million, excluding significant items, is a step down from FY '23 as a result of higher depreciation and amortization due to the recent acquisitions, and increased interest and tax as I've just outlined. The significant items after tax relate mainly to the accounting remeasurement of APA's existing 88.2% interest in the Goldfields Gas Pipeline, which we outlined in the half year results. The other noncash significant item of note for the year was the movement to Sydney Ethane Pipeline impairment, which we disclosed to the market in July this year. Moving to Slide 12. I'll step through the drivers of our 9.7% uplift in underlying EBITDA versus the prior year. Inflation-linked tariff escalation across our energy infrastructure gas pipeline assets contributed approximately $90 million of additional earnings. On the East Coast, there was strong recontracting and take-up of our increased capacity with haulage of Queensland gas to supply southern markets and Mount Isa mining customers. This was partially offset by the Moomba to Sydney Ethane Pipeline revenue write-off associated with the July impairment announcement. We also saw earnings rebaselined from the Roma to Brisbane Pipeline relative to FY '23, which included a half year of earnings for a now closed customer's manufacturing plant and additional demand due to LNG train outages. As discussed at the half year, we also continue to see lower earnings relative to the prior year at Diamantina Power Station. This was the result of a very strong FY '23 that benefited from minimal maintenance downtime and additional customer demand to support a generation shortfall. FY '24 earnings for the asset reflect the normalization of the maintenance program. As previously mentioned, the earnings contribution of our recently acquired Basslink and Pilbara assets also contributed to the step-up in earnings. Finally, corporate costs increased by about 6%, excluding the noncash mark-to-market accounting adjustment of long-term incentives. Pleasingly, we are seeing moderation in our corporate cost growth from the anticipated 13% growth compared with FY '23. We also anticipate further corporate cost growth moderation for FY '25 and beyond. Slide 13 summarizes the year-on-year movement in free cash flow, the result being relatively flat with a 0.3% increase to approximately $1.1 billion. The benefit from the uplift in underlying EBITDA was largely offset by a reduction in working capital and increased interest and tax paid. Looking forward to FY '25, free cash flow will incorporate a full year of the impact of increased debt funding costs and a more normalized cash tax position, which will likely offset EBITDA growth. Moving to Slide 14. I want to take the opportunity to remind you of APA's capital allocation framework. This will 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 security holders. To that point, we outline our progress in investment in our growth strategy on Slide 15. During the year, we invested in growth capital expenditure through the completion of both Stage 2 of the East Coast Grid expansion and the Victorian Western Outer Ring Main. In-flight projects, which will deliver earnings in FY '25, include the Kurri Kurri Lateral Pipeline and our Port Hedland Solar Farm and Battery Projects. Foundational capital expenditure was lower in FY '24 than we had projected due to the timing of grid solutions and emissions reduction projects. Expenditure in FY '25 and FY '26 will be focused around our investment in technology solutions, emissions reduction and enhancements to the physical security of our assets and will incorporate some of the deferred expenditure from FY '24. Staying business capital investment is in line with expectations. Going forward, we anticipate annual spend will be approximately $200 million. Overall, capital expenditure across the 3 areas remains consistent with our expectations in both FY '24 and in the coming 2 financial years. Moving to Slide 16. We have outlined here the focus of our growth investment over the coming years. As you can see, the focus of our $1.8 billion plus near-term organic growth pipeline is contracted power generation and continued expansion of our gas transmission and storage network. While ultimately the timing of many new growth projects is customer driven, the slide provides an indicative allocation and timing for growth across our 3 focus areas. We have not yet factored electricity transmission into our anticipated spend on growth capital in the near term. We will do so as we progress the execution of our strategy. As we have shown you previously, the slide also sets out ranges of our target indicative returns on growth projects. We will continue to apply discipline to our investments to achieve returns with a healthy margin above our post-tax WACC. We are confident we can continue to deliver returns on our growth projects, which are consistent with the returns you have been accustomed to over APA's long-term journey. Now turning to our balance sheet on Slide 17. Our balance sheet remains well positioned with a healthy spread of debt maturities and a significant amount of liquidity to support investment in growth. In FY '24, we undertook a number of capital management initiatives, which have further strengthened our balance sheet position, allowing us to fund our growth pipeline. These initiatives included our recent debt and hybrid raisings as well as the bond tender on the outstanding sterling bonds. Our funds from operations to net debt at the year-end is 10.3%, above our target of 9.5%. This metric remains consistent with our BBB flat Baa2 credit ratings and is in line with credit rating agency expectations. We remain committed to our current credit ratings. We are well positioned to refinance our near-term maturities and the associated costs are included in our free cash flow forecast. To wrap up, I want to reiterate 3 key points: first, we have delivered an overall solid operating and financial performance in line with our expectations and guidance we have provided to the market; second, we are well positioned to create value with the growth opportunities in front of us; and finally, the outlook for our business remains positive, with expectations of ongoing underlying EBITDA and distribution growth. And with that, I'll hand back to Adam.

Thanks, Garrick. The intent of the next section is to address some of the questions we're receiving from investors. That is how do we ensure we generate strong returns from our growth strategy and what are the potential implications of regulation on APA and on the energy market more broadly. Slide 19 sets out our strategy, which remains unchanged. The market opportunities within Australia's energy transition are significant. Our focus is on markets where we have clear competitive advantages. Our focus will ensure we deliver strong returns on investment and deliver value for our customers and communities. We've recently defined a new purpose for APA, securing Australia's energy future. It links to our strategy and reflects the unique role APA plays in the energy market. We have good momentum with our pipeline of growth projects. And as I said earlier, we're confident we will bring to life some of these opportunities over the next 12 months. Moving to Slide 20. We have confidence that our strategy positions us well to capitalize on the trends we're seeing in the market. We call out 3 important trends on this slide. First, the commitment our customers are making to decarbonize their own businesses is driving significant opportunity in the remote grid market. The Pilbara alone represents a $3 billion pipeline of organic growth projects for APA. Second, the need to retire coal and diesel means there's strong demand to support the rollout of renewables with gas power generation and electricity transmission infrastructure. As an example, we've recently executed an agreement with CS Energy to deliver twin gas pipelines, akin to storage bottles, to support new gas power generation in Queensland. We've also teamed up with EDF, one of the world's largest electricity transmission companies, to create a formidable partnership. This brings together APA's strength in infrastructure development and community engagement with EDF's strong technical capability and procurement power. The third trend is that gas supply sources are shifting, creating significant opportunity in gas transmission. We're in the early stages of working with our customers to bring much needed new gas supply to the domestic market from places such as the Beetaloo Basin. It's important to acknowledge the significance of the Beetaloo Basin for energy security in the Northern Territory. Challenges with existing gas supply from within the territory are well known. And this has driven the NT government to recently sign new gas supply agreements with the developers of the Beetaloo Basin. I'm going to get a little deeper into gas supply and demand consideration in the coming slides. The intent is to provide context regarding the important role we believe gas will play in Australia for many years to come. It also informs our belief that heavy regulation of pipelines would be detrimental for Australia's industry and consumers. Slide 21 presents AEMO's forecast of supply shortages in Australia if we fail to invest in new gas sources. To plug the supply gap, AEMO states that we need to bring to life new developments in regions such as the Beetaloo and the Surat. Without new gas supply and the associated transportation and storage infrastructure, we will fail to meet Australia's renewable energy targets. We will fail the federal government's future gas strategy, and we will put at risk Australia's energy security. As you can see on Slide 22, Australia has played a significant role in safeguarding Australia's energy security in recent years. The charts show that incremental investments we've made over the past 3 years to expand the Southwest Queensland Pipeline and the East Coast Grid more broadly. Growing demand for transportation services along the SWQP has been driven by several factors, most notably the shift in supply. With southern gas basins rapidly diminishing, we're seeing a generational shift. Southern demand centers are increasingly being serviced from northern gas basins with gas being transported down along the East Coast Grid. APA has spent around $700 million over the past 3 years to incrementally expand our East Coast assets. This was done at APA's risk ahead of demand, and demand has been strong. In matching demand with supply, we're playing our part to support energy security in Australia. And by delivering these expansions incrementally, we've kept energy transmission costs low for our customers and consumers. Now let's take a look at the data, compare demand and supply in Winter 2022 to Winter 2024. Over that same period, we've increased the capacity of the East Coast Grid by 25%. Without APA's incremental expansion of the East Coast Grid, supply would not have met demand. We're confident there would have either been gas shortfalls or substantially higher energy costs or possibly both. Let's not forget that in a world of gas shortfalls, Australia's industry can't operate. Consumers don't have gas for heating or cooking facilities. Restaurants can't operate. Hospitals can't operate and will create shortfalls in electricity supply. Slide 23 takes a look forward with AEMO's forecast gas demand from the SWQP in 2027. Quite plainly, without immediate further investment in the SWQP and the East Coast Grid more broadly, Australia is unlikely to have the supply of domestic gas it needs to meet demand. AEMO assumes that absent further investment in the SWQP, the supply of gas for the East Coast will need to come from other sources. That means until new gas resources are brought to market, Australia will likely need to source gas from offshore, and I'll come back to the implications of this in a moment. It's worth noting that AEMO obviously can't predict in their models material prolonged market failures, failures such as wind routes, the failure of aging coal-fired generators or issues with existing gas production facilities, failures we've all become accustomed to. Why do I bring this to your attention? Because we've had to pause our Stage 3 expansion of the East Coast Grid because of the uncertainty caused by the AER's review of the SWQP. The AER is looking to review all major pipelines in Australia, starting first with SWQP given its importance to the East Coast. Now I should start by saying that we've been working collaboratively with the AER to assist with their process. We acknowledge the important role the AER plays in ensuring there is no market failure. The current light-handed regime, governed by the AER, provides APA's customers with transparency about pricing. The current regime, it works, and it works well. With the current frameworks in place, we've seen pricing on our SWQP remain constant in real terms since the asset was acquired in 2012. The key issue should SWQP become subject to heavy regulation is that we can't see a clear pathway where APA can continue to incrementally expand the East Coast Grid and certainly not at the pace the market requires. Why? Because we won't know what return will generate from the investment for several years. More broadly, the time frames to approve expenditure under a heavily regulated model simply don't accommodate the urgent and dynamic needs of the East Coast Grid. From an APA perspective, we have existing contracts on foot that would continue until expiry and regardless of the regulatory outcome, and we're confident based on a wide level of analysis that the returns we currently generate from the SWQP are fair and reasonable. I must, however, caveat that we're in unchartered territory. We can't be confident about how the AER would price the SWQP under heavy regulation. Again, we're in unchartered territory. What we are confident about is that under heavy regulation, the cost to consumers through delayed investment in capacity will likely outweigh any potential benefits. It's clear from the public submissions made to the AER that the light-handed regulation that currently exists is the most appropriate way to govern assets such as the SWQP. There were no public submissions made to the AER that supported a change to heavy regulation. None. There has been no suggestion of a market failure under the current arrangements. None. We, therefore, remain hopeful that the AER will conclude that the current form of light regulation for the SWQP remains the most appropriate model to deliver the best overall outcomes for Australia's energy consumers. A likely unintended consequence of moving to heavy regulation on the SWQP is that it will increase domestic gas prices, as highlighted on Slide 24. That's because heavy regulation will likely constrain or delay investment on our East Coast Grid. And that will likely create a market dependency on imported LNG. From an APA perspective, LNG imports is likely to simply represent an alternative source of gas for the market, which you would expect will be transported by our existing assets. But the market impacts are likely to be profound. Our energy market will be beholden to international gas markets. Reliability and security of supply will likely be diminished and emissions will be higher. A recent study by the U.K. North Sea Transition Authority compared the emissions intensity of imported LNG against U.K. domestic gas. They found LNG was 4x more emissions intensive than domestic gas, 4x. The other big issue with LNG imports is one of price impacts for consumers. Frontier Economics, their modeling suggests prices could double for industrial customers if LNG imports were to set the domestic price throughout the year. Australia's industries, most of which are dependent on gas, simply can't absorb the higher costs that will result from LNG import. Retail consumers will also bear the brunt of higher gas costs. It's worth remembering that the government's price cap intervention 2 years ago was introduced in part because LNG exports were setting the price of domestic gas. That is international LNG prices, which are beholden to global issues, were setting the floor price for Australia's domestic gas. A likely unintended consequence of a world where heavy regulation constrains investment and Australia becomes dependent on LNG imports is that it effectively risks recreating the issue that the federal government was trying to avoid in the first place. That is having international LNG prices set the floor price for Australia's domestic gas. Put simply, relying on LNG imported gas sets a floor in the domestic gas price, not a ceiling. In summary, heavy regulation of our East Coast gas pipelines will risk supply. It will risk higher prices for industry and consumers, which is why we remain hopeful that the AER will determine that the current form of light regulation, which is working well, remains the best mechanism to protect consumers. Domestic gas supply and the expansion of the existing network is the solution to AEMO's forecast energy supply issue, not imported LNG. To wrap up on Slide 26. A reminder of today's 3 key takeaways. First, we've delivered a solid financial and operational performance with outcomes in line with our expectations. Second, we're creating value from our recent investments: Pilbara Energy, Basslink and the East Coast Grid expansion. They've all been successfully integrated and are delivering returns consistent with their business cases. And finally, we have strong momentum with our business development activities, and the outlook for APA remains positive. With that, I'll now open to Q&A.

[Operator Instructions] And today's first question comes from Rob Koh with Morgan Stanley.

Thank you for the presentation and the very clear arguments in terms of regulatory change. So I guess I've got one question on regulatory and one question on debt if that's okay. Just on regulatory, could you perhaps remind us what the East Coast Grid Stage 3 expansion was going to look like? From memory, it was compression on Moomba Wilton and Bomen to Culcairn or something like that. And I guess is it possible that -- and you've obviously hit pause on that. But is it possible to do that under a greenfield exemption and have it in parallel to the regulatory process?

Yes. Thanks, Rob, and I'll be conscious of the fact that you've got a second question to follow up. So look, just on the regulatory process, we look at the East Coast Grid as a network, so when we consider investments along the East Coast, it's really not about looking at asset by asset. It's about looking at it as a network. It's obviously a range of -- principally compresses along the various parts of that network. And we're really basically trying to address bottlenecks that occur. So whilst it may be not sitting on an asset that is the SWQP in this case, it actually impacts the SWQP if you can't get the compression on the connecting asset. We were going to do Stage 3 effectively in 2 parts. And the key to our expansion of the East Coast Grid is that we've been trying to do it incrementally, principally to keep the cost as low as possible for our customers. And effectively, we were ready to press go on that. We had taken the business case to our Board over the last couple of months. But as you can imagine, we simply can't make those investments when we don't know what the return is going to look like. So we are ready to press go on that investment once we get through the regulatory process. In the event that we maintain the light-handed regulatory arrangements, we will continue with that program of works. We've got a lot of the long lead time items ready and on the ground. And we would start that process early in the new year, which would, we believe, continue to meet the requirements of the market.

Great. And then my second question is probably for Mr. Rollason. With your debt refinancing coming up this year, I believe you've got a sort of U.S. 144A issue. I think that's still denominated in U.S. dollars. So could you maybe just give us some guideline -- or how should we think about the plans there and the currency hedging impacts against the WGP, please?

Thanks, Rob. So we're well positioned in terms of the refinancings. As you mentioned, there's 2 near-term refinancings. The first is the sterling notes that mature in November. It's worth noting that we undertook a tender process for those notes in the past couple of months. So the outstanding maturities there is about AUD 200. They were relatively expensive notes, and the balance is the March U.S. dollar maturities in the 144A market. You should think of maturities effectively as being fully hedged to -- or the cost of those maturities being fully hedged back to Aussie dollars at the rates that we've shown in the investor presentation. When I look forward to refinancings, we're seeing pricing for 10-year new debt sitting in the range of about 6.5% all-in swap back to Aussie pricing. So really, what you should be doing is comparing the disclosures we've shown in terms of the existing maturities relative to where we're looking to refinance our new maturities in the market. Obviously, as we complete those deals, we'll make announcements to the market with full transparency around those pricings.

And the next question is from Ian Myles with Macquarie.

Good results. Just a quick one. Ethane Pipeline, did that actually make an EBITDA contribution to the group this year? Or is that what you're saying, a $22 million loss to the group in the New South Wales part?

MSEP, so this for everyone's benefit, this is a pipeline that we announced the impairment of in July. There was no revenue recognized through the course of FY '24 for that asset.

So you effectively unwound -- could you recognize some of the first half so you unwound in the second?

So we effectively wrote off any revenue that we had recognized through the course of the year, and there was obviously a portion that was post the announcement of administration where we didn't recognize any revenue. So it's a good point to note when you do look at particularly the MSP earnings that we show in the supplementary materials that that's obviously net of the MSEP revenue that we did not receive through the course of the year.

Okay. When you sort of look at your guidance of sort of 5.5% to sort of just under 6% growth, given the contribution that you've got from the Goldfields Pipeline regulatory reset, you have Alinta full year benefits coming through. Are the underlying businesses able to achieve CPI? Or are we still sort of tracking slightly below CPI as a core business? I was sort of interested why you might think that's the case.

Yes. Thanks for the question, Ian. So look, we are able to effectively generate the inflation-linked revenues consistent with CPI, so that's not really an issue. We're seeing obviously strong demand along a lot of our network. In particular, you know that we've been fully contracted for some time, and whilst the contracts are shorter in nature than what they have been historically, but assets such as SWQP, MSP, RBP are all fully contracted at least through next year and most through to 2027. So it's not really a recontracting issue. I think it's the swings and roundabouts, [ some new raise ] one of them. So the MSEP, which obviously Moomba Sydney Ethane Pipeline, which we're assuming obviously no revenue for next year. Diamantina has come off a really strong period over the last couple of years with one of our customers' power generators being offline and it now being back online. And effectively, we had been through a period of fairly heavy maintenance, which the last couple of years we effectively been able to run the asset at full capacity, but we're back now to a more normalized. Maintenance program on Diamantina, you're aware and we've been transparent around assets such as the MSP over the last couple of years and will continue into the future. But the integrity works that we're doing on that asset obviously limits some of the supply of that asset, and we try and manage that through the warmer months, through the summer months, but it does still restrict some of the supply. In terms of the Alinta business, we see that being on track, the new assets that we expect to come online, which would be the Port Hedland solar and battery asset later this year and even Kurri Kurri. Albeit it won't have a huge impact in FY '25, it will come online next calendar year, so towards the back end of FY '25. So it's really just the timing of those assets. But I think really, hopefully, that's given you a flavor of it, Ian. It's really just some of the smaller movements that are impacting the result. Everything else, we're confident about.

Okay. Look, that's great. Just one final question then. Stage 3 development, which Rob asked about, is that actually in your CapEx guidance? Or is that going to be added on top of CapEx guidance?

Yes. With the guidance, and you're referring to the $1.8 billion and you're looking at -- I think we've provided you with a little bit more detail this year in terms of the years and how we split that across. So we've obviously got assets in there that are underway, so we can now put in the CS Energy asset. You've got Kurri Kurri, the Port Hedland Solar Farm, some of the laterals that we're building, including things like Beetaloo. We take a probability weighted approach to those. We really look at assets that we're in early works agreements or preferred or exclusive. It obviously includes things in FID. But basically, for us, the East Coast Grid is included in there in a small way, but again, if that didn't happen, then from a probability weighting that $1.8 billion is sort of not a fixed number. It could mean that another asset steps in, in front of that and takes its place. And I should say it's staged out over a couple of years as well.

Next question comes from Dale Koenders with Barrenjoey.

I just was hoping for a question in terms of how you're seeing the outlook for free cash flow and the outlook for gearing. When you sort of said, over the next couple of years, you're going to see EBITDA growth being offset by higher cash tax and higher interest costs, how are you thinking about that gearing trajectory? Are we gearing up over the next couple of years?

Yes. Thanks for the question. I'll take that. So free cash flow, as you alluded to and as we talked to in the presentation, certainly, next year into FY '25, we expect to see the impact of the higher cost of debt and also the normalization of cash tax payments. So that will mean that we effectively see relatively flat free cash flow from '24 into '25, and then we start to expect to see that growing as some of the -- as those items normalize and earnings from new assets start to kick in as well. In terms of the gearing, principally, we look at our FFO to debt credit metric. And we've talked for some time about seeing that come to about 9.5%, which is in line with S&P's metrics forecast and in line with our expectations given the amount of growth we expect to fund over the coming years. So really, that's the target that we're aiming for in order to achieve the most efficient use of our balance sheet. There will be periods and again, consistent with S&P, where it may soften through that, but we expect it to recover in the years that follow.

Okay. So is that kind of over the next 3 years given CapEx guidance is trending towards 9.5%?

Yes, correct.

Can I also then ask about the risk profile for the growth CapEx, the $600 million per annum? How are you thinking about sort of the probability of all that progressing? Is it risk-weighted? Commentary would be good.

Yes. Thanks, Dale. And look, as I mentioned to Ian's question, it is risk weighted. Our pipeline is incredibly strong. The number of early works agreements that we've got in our pipeline has -- is as healthy as it's ever been, I suspect, and I would argue in the company's history. So that's a good sign. And what that means is that we can be really selective in the projects that we want to target and that we want to focus on and obviously areas where we've got a competitive advantage and areas where we can generate the best returns for our investors. Our growth is across a range of areas. We feel quite positive about the remote grid space and the power generation remote grid opportunities. Obviously, the Pilbara is one. We're working on some projects there. And I think many of you would have been up to site a couple of months ago, and we've got really good tenure there. We've got -- made really good progress, and I'm really pleased with the way that the teams made progress with consents and traditional owner activities and working with our communities and working with our customers. So we will continue to progress those with our customers, and we feel as though that is really strong. And maybe just to cover that off, the Pilbara acquisition has been integrated. Its earnings are in line with our expectations. And if anything, the outlook for us remains stronger having spent more time there. And we've increased our business development team over the last 8 to 9 months since ownership as well. So we're trying to position that positively for our customers. We continue to see good growth in areas like Mount Isa and other remote grid regions, and then there's a lot of activity going on in that space. GPG is a really interesting one. Obviously, CS Energy, we've announced the twin pipelines there. And it's a bit like Kurri Kurri, whilst they're laterals and they connect to, in that case, the RBP, and that's good for our business because it enables us to transport more gas along our existing infrastructure, but not only are they laterals, they're actually having to act like a storage bottle. And as you can imagine, GPG is all about having the gas and having the generator going when you need it not 100% of the time. So you've got to make sure you've got enough energy supply, in this case, gas supply to support that market. So we're seeing a lot of interest there and just generally, for us to actually get involved in the development of GPG directly as well. We see good growth opportunities there. And then in the pipeline space, I've just mentioned some of it, but obviously, we're making good progress in that arena. And then electricity transmission, we think that there are some good opportunities there. It's a bit longer term for us, and we're making the investment because we want to take a long-term approach there. And you know that infrastructure development is always a long-term strategy. But again, we're feeling quite confident in the capability we've built in that space. So look, we feel confident just generally in the $1.8 billion. In terms of exactly how it plays out over the next 3 years, it will always move around. And it may come in a rush or it may be staggered out. But again, we think we've got the balance sheet to support it, and we've got the capability, and we're really focused on creating value through that pipeline.

Just on that final point, sorry, the exclusion of REZ in your growth program, what are you saying here? Are you saying it's uncertain and you will include it maybe over the next 3 years if it progresses? Or it's just long dated and won't be in the next 3 years?

Look, we remain very confident that because it's in its infancy as an opportunity, not just for us but for the market, we don't think that it's appropriate to probability weight as we do with some of the other initiatives, to probability weight and include that in our pipeline. We've obviously partnered with EDF and we think that's been well received by the market. The New England REZ is potentially going a little slower in terms of the starting gun, but we would hope that that's because the government is doing the work to ensure that when it does start in terms of its procurement process that they can move quicker than they did on their first process in New South Wales to get to the right outcome. And I'm sure that they've got lessons learned through the first process that they'll apply to the second one. So -- and then we've got opportunities that we're looking at in Victoria and other regions like WA. So -- and I think, again, the team took you through some potential opportunities with our potential corridor through the Pilbara. So again, we think that it's not a shortage of opportunities. In fact, we were talking about it the other day. I think there's almost a question, is there enough capability? Is there enough capacity in terms of developers in Australia to meet the requirements of the electricity transmission required over the next decade? So it's not an issue of will there be enough opportunities. It's just how they are rolled out and making sure that organizations like us focus on the ones where we can create value.

And our next question comes from Tom Allen with UBS.

We can see there's been some new contracting for winter capacity on the South West Queensland Pipeline and the Moomba Sydney Pipeline over the last year. Plus, I should mention the Reedy Creek Pipeline GTA, which is clearly positive. The SWQP and MSP now look heavily contracted in winter for the next 36 months. However, on the new pipeline contracting reporting obligations where MDQ contracting terms are now publicly disclosed, can you please confirm whether you're seeing any value leakage by discounted tariffs and the shift away from those flatter, larger annual volumes on that pipeline route to a new seasonal shape?

You can have Garrick take the question if you wanted to. No, the -- on the SWQP and more broadly -- and in fact, this is a theme of the light-handed regulation that exists under the AER. You've effectively now got a Board onboard that shows your nominations, your to and from transportation arrangements and the pricing with complete transparency. Basically, the only thing you don't see is the name of the customer. So -- and again, that's one of the arguments we're putting forward to the AER and others in that there is full transparency in terms of pricing. We've kept our -- and I mentioned it before, we've kept our pricing flat in real terms. So we've really -- we've only increased our pricing by inflation since we've owned that asset, and we acquired that in 2012. So -- and that's sort of been a -- that's been a theme of all of our assets for a long, long time. So no, we haven't seen any pricing pressure there. Obviously, when you renegotiate contracts, they're commercial contracts, so you go through a negotiation process as you would expect. But what we try to do on our assets in SWQP is a great example, is that we're providing our customers with a service, and the customers have to be able to ensure that they're getting value for money there. And that's why we maintain asset reliability to the right standards. That's why we've got a really sophisticated IAC and the commercial team that are working with our customers on a daily basis, if not, an hourly basis to try and transport gas where they need it. And I think one of the things that we're seeing is a broader market dynamic and is, in particular, as coal's being retired, renewables are coming in and GPG plays a bigger role, where the customers are going to need that gas is becoming a lot more dynamic. So one of the things that we can do is continue to expand those assets and be able to provide that service to the customers.

Just a second question for me, recognizing there's some uncertainty over how the AER might price access on the Southwest Queensland Pipeline under a heavy regulated access regime, but no doubt your regulatory team have a detailed estimated EBITDA at risk. If we applied the AER's current rate of return guideline to an SWQP asset base implied from APA's current reported [ rig ] account, is it reasonable to estimate that over $100 million of EBITDA could be at risk on the SWQP alone if the AER applied a heavy access regime?

The challenge we've got, Tom, is that the AER actually doesn't have a guideline for doing this. This is the first time it's ever been done by the AER to try to apply RAB to an existing asset. And again, we have searched the world. I think Rob Koh might have mentioned last results presentation that they were somewhere in the Nordic region or somewhere that they've looked at this once, but this is really uncharted territory. So that's the challenge we've got, is we don't know how you can calculate it. And like anything, you can try and hypothesize and come up with 50 different ways of calculating it, and we could all be right and we could all be wrong. The thing that we look at is when the AER is working through their process, they're going to be looking at whether or not there's a market failure and they're going to be looking at whether or not there is pricing power being exercised on the asset. And I just go back to the comments that I made before that there is no market value. All the public submissions made to the AER, none of them suggested that there should be a change to the current regulatory regime. We've got the pricing transparency that we just mentioned before. And again, I can show you a chart, but you can look at the pricing for each and every customer on the SWQP since we acquired it in 2012. And when you adjust it for inflation, there has been no increase in those prices over time. So there's no evidence of market power being exercised. So look, the AER is following a process. It's uncharted territory for them as well. We're trying to support them as best we can. There's no views being expressed by them or us in terms of how it will play out. But the one thing that we've got a role to do and we've got our investors asking us to do this is making sure that we put forward our case on what the potential implications would be if we were to move to heavy regulation, in particular, in a period of time where the Australian energy market is undergoing significant change, and we need to be incredibly dynamic.

The next question is from Nik Burns with Jarden Australia.

A couple of questions from me. First of all, just on growth CapEx pipeline. Adam, can you just confirm of the $1.8 billion over the next 3 years, how much of that is currently committed? Is that -- should we take the FY '24 numbers of circa $600 million as being locked in? Or is there other CapEx in future years, which is also locked in?

Yes, there's a fair bit of it locked in. Do you want to take -- and it's particularly the -- obviously the next year, the FY '25 numbers, but do you want to take that one?

Yes, certainly. Thanks for the question. So as Adam's explained previously, over '25 to '27, we look at both committed capital expenditure and also risk weight the opportunities. And as I said during the presentation, clearly, that is -- a lot of that is customer driven. So putting exact numbers on it is obviously challenging. Some of the projects that you're obviously aware about -- aware of include the ongoing commitment or the completion of the Kurri Kurri lateral, we've also announced works with -- on both Brigalow Pipeline with CS Energy as well as work with Senex. As Adam mentioned also, we -- there is some no-regrets spend, which is relatively smaller on the East Coast Grid Phase 3 as well, and there are assets that can be deployed elsewhere if we do not go ahead with that expenditure as well. So they're probably the key projects that -- as well as I should mention the Pilbara solar farm and Bass project as well. So they're the in-flight and committed projects that we've announced the market. The balance of which, as and when we're able to, we'll provide further guidance to the market in terms of what they actually are and the amount of CapEx associated with them.

Are you able to quantify at all that level of committed CapEx?

So when I look at the FY '25 guidance on the gas transmission and storage, I'd say at least 2/3 of that is committed. On the contracted power generation, probably a lower level around that. So we're still waiting on some of the customer positions on contracted generation. But as I said, we'll obviously let the market know once we're in a position where we are able to.

Got it. And then just on funding your growth, Adam, I think in your introductory remarks, you made the comment that your balance sheet can support your growth ambitions. I'm just trying to reconcile that comment with your prior commentary that investors should expect future growth to not just be funded out of debt. Can you just talk about your updated thoughts on your views here?

Yes, Nik, it's Garrick. I'll take that question again. I think, again, we've been relatively clear with the market that we will look at the type and nature of each growth opportunity as to how we fund it. We've got a lot of flexibility on the balance sheet. We showed that through the course of FY '24. There was the hybrid issuance that we've seen through the benefit in our FFO to debt. There's clearly capacity to use debt to fund growth. But for large strategic projects, I think, clearly, we would look at other alternatives, whether that be equity markets or whether that be opportunities to recycle assets. So I think consistent with what Adam said, we see a lot of flexibility in our balance sheet, and it won't be restricted just to pure-play debt financings.

The next question is from Alistair Rankin with RBC Capital Markets.

Just first question, you mentioned that your FY '24 earnings benefited from some recontracting. Could you just give a bit more color on how this recontracting went and how customers are approaching the contracting at the moment?

Yes. Thanks, Alistair. And look, it sort of depends on who the customer is. It's been an interesting few years as the market has been trying to work out what's -- what role gas is going to play and where the gas is going to be required and where the gas is actually coming from. So you've got -- you got both demand and supply, having to work through how that was going to play out. And I think what's happened is that's really levelized over the last 12 months or so. I think there's a really acute understanding by the market and there's general acceptance now that gas is going to be around for a long time, and that can be evidenced by the federal government's future gas strategy, which we all note that it's titled 2050 and beyond, and the and beyond is really important. So in terms of long-term trends, there's been quite a shift in what we've seen with some of our C&I customers or commercial and industrial customers, is that they are coming back to long-term contracts. Obviously, when we do pipelines and laterals such as the one that we've just announced with CS Energy, they're trying to shore themselves up with long-term supply arrangements. So you're basically going into a world of longer-term contracts in terms of the development of the infrastructure. And then more on the shipping side, that is one where it has -- I guess from a generational perspective, it has shifted over the last couple of years to be much shorter term. So sort of 18 months to 24 months, sometimes 36-month type arrangements. And I think the best example of that is when you look at those charts towards the back of the presentation that show how the SWQP caps out in 2027 if we don't expand the East Coast Grid, that's just evidence that if you're a shipper, you don't want to be locking into long-term contracts and basically being short supply at a point in time. So that's really the reason why that market has -- one of the reasons why the contract terms there has shortened. What we are seeing though is that demand generally is strong. So I mentioned before and Tom sort of raised it again before around SWQP, MSP, RBP. The contracting there is quite healthy, and that means that you're not seeing any deterioration in pricing. And again, we're signing up a lot of contracts as well. And we announced -- through the media anyway, we announced one with Senex just recently, so in terms of new gasfields coming onboard. So it's actually -- it's not to say that the commercial team aren't working incredibly hard, which they are and having to work really closely with their customers. But I think it's a market now, which to a level is much more confident about the future. If we can get through this hump in the short term with some of the regulatory and policy uncertainty that we're seeing, I think if we end up in a world with LNG import terminals, then that can -- that will probably create a bit of drama for the market and no doubt end up with an issue in terms of higher prices for consumers. So -- but hopefully, we can get through that.

That's a very comprehensive answer. I might just shift gears over to the Pilbara. You've mentioned you've got your $1.8 billion growth pipeline, which is across the whole group. But also on Slide 8, you've mentioned again, the over $3 billion pipeline for Pilbara projects. Could you just give an update on this pipeline and which projects in that $3 billion you're most excited about and which is the most mature as well?

Yes. So look, obviously, we're in the middle of developing the Port Hedland Solar and Battery for BHP, which is really exciting for that region. Really, I think it's going to be great for BHP in a showcase when you've got an iconic customer like that undertaking these developments. I think it sets the bar for the rest of the region to say, well, if it's good enough for them, then it's good enough for us. We've obviously been operating in that region. And so I should say the business we acquired has been operating in that region for a long time. I think one of the things I probably personally underestimated at the time of acquiring the business is how much great work the team had done at getting sites and working with traditional owners and some people -- and I know people on this call don't, but some people simplistically just assume you're going to get a plot of land and you stick a wind farm or a solar farm on and away you go. But it goes so much into the load factors. It goes so much into approvals and access to sites. And they've done a really good job in that space, which is why we've got confidence that the sites that we've got are really attractive for our customers. And when our customers are looking, which they will do, look at all the various alternatives, we hope that they will get to that position where they know that not only can we produce an outcome for them that's really competitive from their perspective, from a cost perspective, but we can bring it to market arguably quicker than the next best alternative. I think we're in a fairly strong position in that we are one of the few players that can bundle the services. So if something goes wrong, you don't want to have to be pointing a finger at 3 different suppliers of energy. They can actually point the finger at us and say, "Well, I don't care whether it was your solar farm or your battery or your GPG. Ultimately, you're running all this, so you need to make sure that it's reliable." And that's what we've been doing for years, and that's what we're good at, is bundling those services. So I think it's quite strong. We've got good sites at Port Hedland. We've got good sites in and around Newman. And we've done a lot of work, and we're doing a lot of work. I mentioned before, we've quite significantly increased the team since we acquired the business at making sure we're continuing to look forward and getting sites in the right regions and putting up our wind barometers and all those sorts of things to make sure that we can test those sites for adequacy to support our customers. Now in one breath, that's really good and exciting. The other breath is you're then going to work closely with your customers, and it takes time. So I'd love to be coming out today and telling you about the pipeline and putting names and all those sorts of things out there, but I can't do that. And we just have to work closely with our customers. And we're basically working to their timetable, which we know that -- we know how it works, and we're trying to partner with them to work through that.

And the next question comes from Reinhardt Van der Walt with Bank of America.

I'd just like to revisit the growth pipeline again. I'm conscious you don't want to name names. But can you just give us maybe some general timing milestones we should keep in mind around when some of the big tenders are going to drop in this space, just sort of broad timing that we can expect this investment pipeline to be derisked over? And maybe just related to that, can you just give us your comments or thoughts around any delays in investment decisions because of the macroeconomic environment?

Yes. Again, there's not much more I can say, but maybe to be succinct, we've got the Port Hedland Solar and Battery that will be coming online later this year. We're working with other projects, with other customers in and around the port and in and around Newman as we speak. So I can't give you any definitive time line, but I would like to think that we can support our customers and get to the right outcome for them over the next 12 months, and we'd like to be able to come out with announcements over the next 12 months. And in terms of the market dynamics -- and I'm assuming you're pointing to the fact that iron ore prices have softened and so forth. Ultimately, again, I come back to the solutions that we're confident we can deliver to our customers. We'll deliver them with -- not only with a cleaner energy solution, and they've made -- all of that -- we're targeting customers who have made commitments through their climate reports. So they've all made commitments to decarbonize, so that's a motivator and an important one. But we can actually deliver the level -- a cost of energy for them, which is lower than their current cost of energy. So there's actually an incentive. You'd argue that there's an incentive for the customer to move faster, not slower as a result of this because we can deliver a better financial outcome as well.

Got it. That's very helpful. And maybe just, I suppose, related to that, I was referring to the commodity price, just your guidance for next year. Can I just get a sense of your gas volume assumption in that guidance? Conscious that there have been a couple of mine closures sort of all around the place. Just want to understand kind of how you're thinking about cyclicality in that part of the business.

Yes. Look, remembering we sell capacity, so we don't sell volumes. So generally, volumes don't matter too much to us. It obviously has an impact on VTS down in Victoria, which is more weather related, and you get some swings around about whether or not you have a warmer or colder winter. But generally, it's all capacity-based. So we don't see a lot there, Reinhardt, in terms of changing those dynamics. So -- and look, probably the only one to call out is the NGI and WA, which -- that has been a little bit slower than what we expected. We've shared that with you recently. And we just expect -- again, long term, we're really happy that that's the right investment. And we stress test the investment case. We think the investment case remains very compelling. But that's probably going to be a little slower. And I'm not saying it's more slow than what we told you last time, but that's going to be a slower ramp-up on the NGI.

And can I just check, finally, if there have been any sort -- anything noticeable in personnel turnover at Alinta since your acquisition? Have you had any sort of senior personnel departing?

Yes, it's a good question. And no, we're really pleased. We went in there, as you'd expect, with the identification of all the people that we wanted to have in the business, and everyone has stayed in the business. So that's really positive. Again, we acquired a business with a really strong team who did a fantastic job at developing that business over time. And it was one of the reasons why we wanted to acquire the business, not just the assets but the people. We've got a great team in terms of the -- not only the development, but also, operationally, it's really positive. And as I said to you before, we've actually increased the size of the team, particularly in the development side. And I'm really, really happy with how that's going. Same with Basslink. It's been really positive.

And our next question comes from Nathan Lead with Morgans Financial.

Two or 3 for me if you don't mind. So first up, you've got $1.1 billion of capital work in progress on the balance sheet. How much of that relates to growth projects?

Nathan, I'll get Garrick to take that one.

Nathan, thanks for your question. Let me -- I might actually take that on notice and provide the detail back to you because I need to look back on the balance sheet, but the majority of it would relate to growth projects.

When we roll that in with the $1.8 billion that you've talked about in terms of your growth pipeline, pretty decent chunk of capital being deployed there. Can you talk about just how the phasing of the earnings comes online? And also, can you sort of provide us with a bit of steer about just how much EBITDA that lump of investment could deliver for investors?

Yes. Again, Nathan, good question and a question, I think, we've received a number of times from investors and sell side. Page 16 is really trying to deliver that sort of information to the market. Obviously, it is challenging to provide detailed information given the nature of the projects, given that they're customer driven and the like. So in terms of the projects that are in construction at the moment, namely Kurri Kurri and the Bass and solar farm in the Pilbara, we'll see those earnings come in the latter half of FY '25 and will be relatively immaterial relative to the balance of it. When I look at the opportunities that we're setting out here, earnings will start to come through, maybe perhaps initially some in '26 but more so '27 onwards. The earnings related to that will reflect the indicative returns above our post WACC that we're showing on Page 16 there. So that's intent of that slide, which we've obviously shown that particular table a number of times now. As it relates to the capital work in progress, a large chunk of that will obviously be related to those 2 projects that I've mentioned, being Kurri Kurri and the Pilbara assets that are in construction. A lot of that construction and the CapEx has been spent with a smaller amount, residual amount to be spent into FY '25.

Yes. Okay. Second question, FFO to debt, 10.3%. You're saying it's trending downwards towards 9.5%. Wallumbilla Gladstone Pipeline contributes, what, 32% of your EBITDA, but that's going to be dropping away in, say, 11 years. In your business plan, are you factoring in debt repayment? I'm just trying to understand how you're balancing this growth funding, debt repayment and then DPS growth. I mean should we be thinking that DPS growth remains below CPI to be able to sort of cater for all those things?

Yes. So again, a good question, Nathan. So as we look ahead of the business and our capital management initiatives and funding of our growth CapEx, we take into account our cash flow projection. So that's all our contracts on foot and recontracting expectations over the long term. We obviously fund all of our assets at a portfolio level. So when we look at the cash flow that we have available to us over the long term and we look at our balance sheet position, we obviously balance those to ensure that we provide or longer term, will provide a glide path across all the elements of our capital allocation framework, which we set out in the presentation.

Yes. So you're expecting to sort of enter FY '36 with credit metrics that meet the current credit ratings?

We're not providing guidance into FY '36, but I would reiterate what I've said in the presentation around our commitment to our current credit ratings.

Yes. Okay. Just a final one for me. You made the comment about how the Northwest Power -- sorry, Northwest Power System earnings are now at normalized levels after the maintenance events, et cetera, you've been having. But the second half '24 EBITDA looks like it's quite a bit below first half and also below the second half of '23. So just wondering, should we be taking the second half and annualizing it, and that's the normal run rate? Or is FY '24 overall reflective of where the other normalized earnings are?

When we look at Northwest Power System, overall result for FY '24 is largely in line with where we expected to be. There will be some earnings revenue coming through from Dugald River as well, which sits within the Northwest Power system.

And the next question comes from Scott Ryall with Rimor Equity Research.

Hopefully, mine's fairly easy. I wanted to refer to Slide 16. Thanks very much for the whole presentation actually, and Adam, I love your passion on government policy in particular. But I wondered just on this chart, there have been, over the last, call it, 6 to 12 months, a number of investors who have broad-based portfolios across the energy sector, suggests that power generation in the renewables side has deteriorated in terms of investment attraction. So I'm just wondering if you can give a bit more color as to why, if I'm just looking from a top-down level, the contracted power generation now looks the most favorable relative to your post-tax WACC given the low point is significantly higher than the other 2 bars. And I'm just wondering if you can give a bit more color as to why you think the return opportunities are so attractive for you in this space. That may be because that includes your storage assets, but I'm just interested in why that looks to be the most attractive for you guys and particularly relative to what I would call your traditional core business, gas transition and storage.

Thanks for the question, Scott. So contracted power generation is principally -- if I break it into 2 core buckets, 1 is remote grid power generation, which would be solar farms, wind farms and GPG in remote regions of Australia. So think of the work that we're doing in the Pilbara. Think of the work that we're doing and we've done in Mount Isa regions and obviously, Goldfields and other regions where we're looking to expand our business there. And the reason why we can attract, we believe, better returns there than what we would be able to do as an infrastructure player, and I'll come back to why underlying infrastructure player, than what we could do on the grid is because, effectively, we are partnering with customers under long-term arrangements to effectively provide them with a bundled solution in there. Being remote grid, the criticality of your service, if you have an outage, then the mine is out of operation for a long period of time and impacting their revenue generation capability. You have different abatement regimes and so forth in place to warrant returns, which -- and by the way, it's just consistent with what we've been able to get on our pipeline business traditionally. So they're not exorbitant returns by any means, but you're able to get decent returns in that region. If I contrast it to on-the-grid renewable power generation and solar farms, wind farms, I think what the market has seen is that the ability as an infrastructure owner to be able to create a lot of value by finding a site and then building a solar farm or wind farm and plugging it into the grid and hoping that sun shines and the wind blows and so forth, that's a lot more challenging. Often you don't have long-term PPAs and the like. So -- and the ones who I think will make money will deliver long-term value for investors on the grid are either the ones who have been really disciplined in contracts -- in long-term contracts, in long-term PPAs with high creditworthy customers or the ones who can make extra money by trading the energy with their trading houses. And that's -- the latter part is definitely not us. So that's really the reason why we wanted to focus on that side of the market. I think GPG, generally, whether it's on the grid or off the grid, but GPG, I think, on the grid will be a bit of a different story because, again, because it's more -- people are calling it insurance product because it's more of a dynamic asset. You will be in a world, we believe, where you're signing long-term contracts with your customer. In many cases, it might be the government, to be able to provide you that asset or for us to be able to provide them with that asset when it's available. So it's really just a different dynamic, Scott, and it's one of the reasons why, again, we've got no shortage of opportunities. We just want to really focus on areas where we're confident we can create value.

That's a great answer. And given your comments on the AER process around your gas infrastructure, just do you think in terms of the grids and particularly given the third bucket there, which you've talked about the potential for electricity transmission, is there a regulatory change that you would like to see happen there in terms of making the investments more attractive for people like yourself?

I think the current regulatory framework works well, and I'm separating regulation in terms of how you price -- manage and price monitor assets separate to regulation and policy in terms of, for example, upstream developers trying to get access to be able to build out new supply arrangements. And I think we are making generally good progress in both regards. But certainly, the current -- I think the AER has done a really good job at setting up a framework. And again, we spoke about it earlier, whether you've got real transparency on assets. And from a customer perspective, it's quite positive. Again, my concern -- and this was new legislation that was brought in because of the dislocation that occurred with LNG exports setting the price of domestic gas a couple of years ago when there was global dislocation. That basically gave the power to the AER to be able to review existing pipelines to ensure that there was no market power being exercised and that pricing for consumers was at the forefront. And again, we'd like to think that, a, the current dynamic works. And I already -- I won't speak to that again; and b, that you've got to make sure that you create the right balance so that you can continue to expand assets that need expansion because we've all done economics 101, supply and demand. If you constrain supply when you've got heightened demand, then you're going to have higher prices. So -- and you'll end up with a broader market dislocation, which will not be good.

And at this time, I would like to turn the conference back over to Mr. Adam Watson for any closing remarks.

Thank you, everyone, for taking the time. And I know it's a really busy season, so again, please reach out to the Investor Relations team if you've got any questions. I do appreciate everyone's support and your patience listening to us today. Just 3 key messages. Again, we're comfortable that the results today for FY '24 was a solid set of results. Our acquisitions, our investments are performing well, and we're really pleased with how that's going. And we think, again, the outlook for APA is positive, and we need to continue to remain disciplined about how we deploy capital with the significant opportunities ahead of us. So thank you, everyone, for your support, and we look forward to speaking with many of you over the coming weeks.