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James Thompson: Thank you for standing by, and welcome to the AGL Energy Full Year Results Briefing Conference Call. [Operator Instructions] I would now like to hand over the conference to Managing Director and Chief Executive Officer, Mr. Damien Nicks. Please go ahead.
Damien Nicks: Good morning, everyone. Thank you for joining us for the webcast of AGL's full year results for the financial year 2025. I'd like to begin by acknowledging the traditional owners of the land I'm on today, the Gadigal people of the Eora Nation, and pay my respects to their elders past, present and emerging. I'd also like to acknowledge the traditional owners of the various lands from which you are all joining. Today, I'm joined by Gary Brown, Chief Financial Officer; Jo Egan, Chief Customer Officer; and Markus Brokhof, Chief Operating Officer. I'll get us started, and we'll have time for questions at the end. This slide provides a good overview of the 4 key themes which Gary and I will cover today. Firstly, our strategic execution in FY '25, with approximately $900 million deployed towards battery developments and strategic investments. You see here, our demand-side flexibility portfolio advanced through the acquisition of South Australia's virtual power plant from Tesla in July and excellent progress made on grid-scale battery developments. We've reached a final investment decision on the 500-megawatt Tomago battery, and encouragingly, the 500-megawatt Liddell battery remains on track for commencement of operations in early 2026. AGL also delivered strong results for the year, in line with guidance, which I'll cover shortly. Importantly, we continue to deliver for our customers. Amidst a year of heightened market activity, we increased our already strong customer satisfaction and continue to provide our customers with great products and services. Our Customer Markets business recorded good growth in overall customer services, primarily led by growth in telecommunications and Netflix customer services, with energy customer services marginally higher. Our customer satisfaction continues to remain very strong at 81.6. Strategic NPS has doubled to a score of plus 8, and we've maintained healthy spread to market churn of 4.3 percentage points. In July, we also launched AGL Community Power, sharing the benefits of the energy transition, including with customers who may not be able to directly access the benefits of solar and residential batteries. Importantly, our investment in our flexible portfolio mitigated the earnings impact of the lower fleet availability in FY '25, which was impacted by an additional major planned unit outage compared to the prior year, coupled with some unplanned outages in the second half. We're targeting a stronger performance in FY '26 as we continue to invest in the long-term availability and reliability of our thermal fleet, and I'll speak to this in more detail. Encouragingly, despite lower availability, volatility captured through trading was almost 2 percentage points higher, with a further improvement expected in FY '26 in line with stronger targeted fleet performance. We continue to invest in growth and the future of our business, particularly in flexible asset fleet capacity. I'll speak to how we're unlocking value through multi-asset orchestration and how we continue to capture a disproportionate share of the rapidly growing EV market and broader portfolio benefits this represents to AGL, particularly the ability to orchestrate EV battery load in the future. As I touched on, we're making excellent strides in progressing our grid-scale battery investments, and we've also strengthened our long-duration firming optionality through the acquisition of 2 early stage pumped hydro projects in the Upper Hunter region. Turning now to our strong financial results, which were in line with guidance. As we've previously announced, we expected a decrease in earnings compared to FY '24 due to lower wholesale electricity prices resetting through our contract positions. Consumer margin compression following a period of heightened market activity as well as our FY '25 pricing decision to not fully pass through the year-on-year cost increases to customers to help with customer affordability. Additionally, increased depreciation and amortization was driven by the continued strategic investment in our thermal fleet and the first full year of operations of the Torrens Island battery. This was reflected in our reduction in EBITDA and underlying net profit after tax compared to FY '24. We also saw the breadth of our flexible asset portfolio helped mitigate the earnings impact of outages in our thermal plants, particularly in the second half of the year, coupled with strong performance from the Torrens Island and Broken Hill batteries. Higher income tax paid, coupled with our prudent investment in sustaining CapEx resulted in lower operating free cash flow. However, we continue to maintain a strong level of cash conversion. You'll also see that we reported a statutory loss for this year, attributable to the key drivers noted on the screen, which Gary will explain in more detail. A final ordinary dividend of $0.25 per share has been declared, fully franked, bringing the total fully franked dividend for the 2025 financial year to $0.48 per share, which equates to a 50% payout ratio for the full year. We also provided our FY '26 financial guidance, which I'll discuss at the end of the presentation. Looking forward, as Gary and I will discuss, we aim to more than offset any earnings impact of coal and gas recontracting with earnings from our significant investment in flexible assets and the broader delivery of our strategy. Moving now to safety, customer and employee metrics. I'm pleased to report we've continued the momentum from our half year results and recorded a material improvement of our total injury frequency rate down to 2 per million hours worked, driven by acute and relentless focus on preventing injuries across the organization, which has included numerous safety awareness campaigns and targeted workshops. This is certainly an encouraging result. However, we must continue to strive to further improve this metric. I've already spoken to our Customer Satisfaction and Strategic NPS scores, and our employee engagement score has improved to 73% as we continue to see great engagement and momentum across the business. We're proud to be delivering real impact for our customers, community and First Nations people. And on the screen, you can see some key achievements for the year. We've delivered our 2-year $90 million customer support package, which included $76 million of payment matching and debt relief. Key learnings of the program have been embedded into everyday operations. I've already spoken to the launch of AGL Community Power, and we also recently announced that we'll be partnering with the South Australian government to build and operate 16 community batteries. We've also invested $6 million in the communities in which we operate, including the provision of EV subscriptions and charging units for OzHarvest and the Gunaikurnai Land and Water Aboriginal Corporation. And as part of our commitments in our Reconciliation Action Plan, we've purchased more than $13 million in goods and services from First Nations owned businesses, exceeding our 2-year reconciliation action plan target. Today, we are also pleased to present our 2025 Climate Transition Action Plan, or CTAP, which demonstrates our commitment and progress towards achieving our decarbonization strategy. I won't speak to this in too much detail as we'll have a separate briefing session to the market next week. But essentially, we've bolstered our interim Scope 1 and 2 emissions reduction targets, prioritizing direct emissions reductions and set a new ambition to reduce our Scope 3 emissions by 60% compared to FY '19 levels, following the closure of our coal-fired power stations. Importantly, we're on track to add 12 gigawatts of new renewable and firming capacity by the end of 2035 and have built on our ambition since the inaugural CTAP, increasing our interim target from 5 to 6 gigawatts by FY '30, of which we're targeting at least 3 gigawatts of grid-scale batteries. We are cementing our position as a responsible leader of Australia's energy transition and invite our shareholders to support the decarbonization commitments outlined in the CAP via the Say on Climate resolution at our upcoming 2025 Annual General Meeting. I'll now spend a few minutes talking to the continued transition of AGL, including our considerable strategic execution over the past 3 years since our refresh strategy was announced in September 2022, before handing over to Gary. First, just a recap of our 2 primary strategic objectives, connecting every customer to a sustainable future and transitioning our energy portfolio. This slide shows a great depiction of our considerable strategic execution over the past 3 years. I won't speak to all of these, but will highlight the key themes and announcements. We've made great progress in our ambition to connect every customer to a sustainable future, headlined by the material expansion of our suite of EV plans, propositions and partnerships, launch of the Electrify Now platform in 2023, execution of renewable linked PPAs and our strategic partnership and equity investment in Kaluza and more recently, the launch of AGL Community Power. The transition of our energy portfolio has been headlined by the material advancement of our development pipeline and focused execution on our growing grid-scale battery portfolio, including the FID we recently made on the Tomago battery. Our 300 megawatts of operational batteries are performing well, and we have 1,000 megawatts of batteries under construction and a clear pathway to FID for a further 900 megawatts of grid-scale batteries. Turning now to our FY '27 strategic targets, we have made strong progress. Starting on the left-hand side, I've already spoken to our strategic NPS score, which is in a great position, and we've almost reached our digital-only customers target with our app continuing to be the highest-rated energy app in the market. Encouragingly, our cumulative customer assets installed metric has more than doubled over the year, and we've now exceeded our green revenue target. Turning to the right-hand side, we are targeting higher EAF in FY '26 and continuing to drive improvements to step this up to 88% target over the coming years. Additionally, decentralized assets under orchestration are 20% higher at almost 1.5 gigawatts, a great result. Crucially, our investment in targeted M&A over the past 3 years has supported the delivery of our strategy. This slide contains 7 key deals, which I'd like to highlight. On the customer front, the acquisition of South Australia's virtual power plant from Tesla has advanced our demand-side flexibility and grown our decentralized assets under orchestration by almost 35 megawatts. Our strategic partnership and 20% equity investment in Kaluza is core to the delivery of the retail transformation program, and the acquisition of Everty has broadened our capabilities in EV charging and energy management solutions in a rapidly growing EV market. We also recently announced the acquisition of Ampol's Energy Retail customer book, with approximately 50,000 customers across New South Wales and Queensland joining AGL in FY '26. Turning to the transition of our energy portfolio, where we strengthened our optionality and firming and storage capacity through the acquisition of Firm Power and Terrain Solar and more recently strengthened optionality and long-duration firming capacity through the acquisition of 2 early stage Upper Hunter pumped hydro and wind projects. And finally, our joint venture with Someva Renewables, the development for the Pottinger Energy Park, which includes a proposed 830-megawatt wind farm and 400-megawatt battery is a prime example of how we're actively partnering to accelerate renewable asset developments. I want to spend a few more moments speaking to the transition of our energy portfolio. We have made great progress over the past 3 years, driven by the advancement of our development pipeline and material growth in our flexible asset fleet. Our development pipeline of 9.6 gigawatts has more than tripled in size since we announced the inaugural CTAP in 2022, supported by the acquisition of Firm Power and Terrain Solar last August. Additionally, we have 9 gigawatts of early stage opportunities. Overall, we are very well positioned with the size, maturity and the quality of our development pipeline. The focus remains on the continued timely execution of projects of the highest portfolio value, with the near-term priority on accelerating the development of our grid-scale battery portfolio. On the right-hand side, you can see that we're making great progress towards our expanded 6 gigawatt target of new firming and renewable projects by FY '30, with 1.68 gigawatts of projects in operation, under construction or contracted as well as a clear pathway to FID for a further 900 megawatts of battery projects. Crucially, our flexible asset fleet has grown to 8.3 gigawatts, including 3.2 gigawatts of coal-fired unit flexibility, enabling AGL to curtail generation during the daytime periods of low or negative pool pricing. Importantly, this spread across a diverse range of asset types. Our growing grid-scale battery and virtual power plant assets can respond to peak customer demand events in seconds, whilst our hydro and gas peaker assets can start up and generate electricity in a couple of minutes. Turning now to an update on how we continue to deliver for our customers in FY '25. Our Customer Markets performance in FY '25 was headlined by sustained growth in the customer base and continued strong customer satisfaction in a competitive market. Total services to customers increased by 78,000 driven by growth in Telecommunications and Netflix services, with a marginal increase in Energy Services. Importantly, we've maintained strong customer metrics, including our leading energy brand, digital offering and loyal customer base with a favorable churn spread to rest of market of 4.3 percentage points, a pleasing result in a competitive market. On the right-hand side, as we previously flagged, you can see the decrease in consumer customer gross margin. However, this has now stabilized and is expected to improve in FY '26. Pivotal to the delivery of our CER strategy is unlocking value through multi-asset orchestration, delivering benefits to AGL and its customers. On the left-hand side, you can see 5 key components of our multi-asset VPP. Firstly, residential batteries enable rapid response load shifting that benefits the networks, our customers and AGL. I've spoken in the past how we can orchestrate hot water systems to solar soak and optimize load profile management. Importantly, we are capturing value from the opportunity to orchestrate ever-increasing flexible load of EV batteries through smart charging and enabling vehicle-to-grid integration. Added to this is our EV night saver plan, empowering customers to optimize their assets and consumption through AGL initiative signals and incentives. And finally, demand response and in particular, Peak Energy Rewards program is driving shared value by encouraging and rewarding customers to shift or reduce load during peak periods. And on the right-hand side, you can see the clear year-on-year momentum that helped drive a 20% increase in decentralized assets under orchestration to 1.5 gigawatts, with material increases in our customers who have a demand-side flexibility product, are on our Peak Energy Rewards program will have their customer controlled order load orchestrated by AGL. We continue to make good progress on building a future-ready business through the retail transformation program. We've deployed our first technical releases, including the introduction of Salesforce in Kaluza, and we've made a range of operating model changes, which are already delivering benefits. As with any large and complex customer transformation program, we continue to evolve and enhance our delivery and planning approach. Pleasingly, as you can see on the left-hand side, Kaluza has announced key updates, headlined by its expansion in the Australian market through the acquisition of Beige Technologies and internationally through strategic partnerships with Mitsubishi and PG&E in North America. Within OVO Energy Australia, Kaluza Retail and Flex Solutions are delivering an excellent NPS score of plus 35. OVO Energy Australia is also leading the market with the EV tariff and smart charging experiences and has seen strong adoption of load shifting products like the Free 3 plan, which offers 3 hours of free energy from 11:00 a.m. to 2:00 p.m. And finally, a reminder that the retail transformation is a 4-year program and is expected to deliver pretax savings of approximately $70 million to $90 million from FY '29 as previously announced, as well as the targeted digitization, speed to market and customer experience improvements you can see on the screen. Now to a discussion on the growing flexibility in our portfolio, starting with an overview of fleet performance and operations. After a year of excellent thermal fleet performance in FY '24, the commercial availability of our thermal fleet was down 12 percentage points, mainly due to an additional major planned outage compared to the prior year, coupled with unplanned downtime in the second half. Encouragingly, volatility captured through trading increased despite a lower availability result, and we aim for this to further improve in FY '26 in line with higher targeted thermal fleet availability. Overall, generation was 1.2 terawatt hours lower, again, impacted by lower coal-fired generation, partly offset by the longer running of the gas fleet and a stronger contribution from our renewable generation assets. Looking forward, we are targeting stronger fleet availability for FY '26. The decline in EAF was driven by 2 key factors: first, an additional planned major outage compared to FY '24 and second, a rise in unplanned downtime in the second half, largely due to boiler tube leaks and one-off component failures. Please note that the 6.3 percentage point decrease in EAF largely accounted for the 1.2-terawatt hour decline in generation volumes in FY '25. In response, we've taken targeted and proactive actions such as the engagement of global allergy specialists to confirm failure mechanisms and guide targeted tube replacements, improved operating practices and strengthened quality management systems at both Bayswater and Loy Yang A. Of note, FY '25 EAF performance for both Bayswater and Loy Yang A remained above the NEM median. We recognize that we must invest strategically in EAF improvements, and we continue to evaluate the balance between cost, risk and performance to meet our asset objectives. Looking ahead, we are targeting higher EAF in FY '26 and a continued upward trend in thermal fleet performance. Despite the overall weaker availability performance, our flexible asset fleet continues to capture value in an increasingly volatile energy market. The first graph shows how our growing portfolio of flexible assets has enabled AGL to realize a premium above the average market price for the period. This premium has steadily increased since FY '22, with a slight moderation in FY '25. Importantly, our continued investment in flexible assets is expected to grow this premium further over time. A key point I'd like to highlight is that our growing portfolio flexibility and, in turn, our ability to optimize realized pricing outcomes on the supply side is a material contributor to earnings, considering our significant annual generation volumes of over 30 terawatt hours per annum. The second graph breaks this down by asset type. Encouragingly, also showing premium we were achieving for our coal-fired generation assets through our investment in unit flexibility. As I've mentioned at the half year results and just as importantly, we can observe the premium that hydro, gas and batteries are able to achieve based on being very flexible assets. It is these asset classes that we continue to focus on delivering as we progress through the energy transition. Turning now to how we're investing in growth and the future of our business, beginning with a thematic discussion on future expected electricity demand growth within the NEM. Encouragingly, the tailwinds for future electricity demand growth continue to be positive, with flexible capacity key to unlocking future value. Starting with the graph on the left-hand side, which shows that 2025 has recorded the highest winter daily electricity demand for New South Wales, Queensland and Victoria since 2017. Of particular note, in 2025, Victoria recorded the highest daily winter demand ever achieved. Moving further to the right, where AEMO predicts significant growth in electricity demand over the next decade, with the major driver of this growth being in the electrification of the home, transportation and broader industry, including data centers. And we continue to see increasing demand for electrification products from our consumer and our large business customers. Added to this is a significant opportunity to orchestrate the ever-increasing flexible load of EV batteries, encouraging of off-peak charging and thereby shifting load to the overnight period through pricing signals, which I'll talk to on the next slide. And the graph on the right-hand side shows a significant amount of grid-scale battery storage as well as storage through consumer energy resources that are acquired by 2035 as the NEM transitions away from coal-fired generation. At the half year results, I highlight that we're capturing a disproportionate share of the rapidly growing EV market. And as you can see on the left-hand side, we've continued to outpace the growth in the number of EVs on the road over the last 6 months. We have a compelling suite of EV plans, propositions and partnerships, which will form the foundation of future expected growth. And we now have approximately 35,000 EV energy plan customers with excellent NPS score of plus 41 for our EV night saver customers. On the right-hand side, you can see the success of incentivizing off-peak charging, with regards to our EV night saver plan, which has seen up to 22% of customers' daily load shifted the lower tariff overnight window, optimizing both pricing and portfolio outcomes for AGL and our customers. We're also leveraging our scale to accelerate growth in the consumer battery portfolio unlocking value for customers and the market as well as presenting earnings and supply portfolio benefits to AGL. By delivering an integrated customer experience, we're enabling growth at pace and scale, giving customers greater connection and control to maximize the value of their assets. On the right-hand side, you can see clear value pools that support potential future earnings and portfolio benefits. These include enhanced consumer peak load management through greater demand-side flexibility with residential batteries able to respond very rapidly to large market demand events. Additionally, we're able to realize an arbitrage spread and avoid the purchase of caps on the orchestrated loads. We also have the potential to access behind-the-meter demand growth through innovative models. And importantly, we observed significantly lower churn rates for our residential VPP customers over the past 5 years. Our new grid-scale battery projects will further enhance our flexible asset capacity and broader portfolio management. As I mentioned a few moments ago, our grid-scale battery portfolio can respond to peak demand events in seconds, crucial in a transitioning energy market, which is shifting away from baseload thermal generation to variable renewable energy. We'll also continue to leverage our innovative in-house capabilities to optimize the performance of the grid-scale battery assets as part of the integrated portfolio, targeting returns above what a merchant operator would typically achieve. Pleasingly, the Torrens Battery has consistently operated at at least 99% availability, demonstrating excellent reliability. Additionally, our sophisticated state of charge coordination delivers peak performance during market volatility events and our advanced analytics across all asset types maximizes asset value and operating efficiency. On the right-hand side, you can see our portfolio of operational and contracted and grid-scale batteries as well as the 1,000 megawatts of battery projects under construction in New South Wales. Finally, denoted in dark blue are the additional 900 megawatts of grid-scale battery projects, we have a clear pathway to FID. I'll now hand over to Gary.
Gary Brown: Thank you, Damien, and good morning, everyone. This slide shows an overall summary of our financial results, which I'll cover in more detail on the following slides. Overall, our strong financial performance for the year was in line with guidance. As we previously announced, we expected a decrease in earnings compared to FY '24 due to lower wholesale electricity prices, resetting through contract positions, consumer margin compression following a period of heightened market activity as well as our FY '25 pricing decision to not fully pass through the year-on-year cost increases to customers to help with customer affordability. Additionally, increased depreciation and amortization was driven by the continued strategic investment in our thermal fleet and the first full year of operation of the Torrens Battery. This was reflected in our reduction in EBITDA and underlying net profit after tax compared to FY '24. We also saw the breadth of our flexible asset portfolio help mitigate the impact of outages in our thermal plants, particularly in the second half of the year, coupled with a strong performance from the Torrens Island and Broken Hill batteries. As we committed to, our operating costs were broadly flat. We also announced a fully franked dividend of $0.25 per share, bringing the total dividend for the 2025 financial year to $0.48 per share fully franked, which equates to a 50% payout ratio for the full year. This is at the bottom of our targeted dividend payout ratio of between 50% and 75% of underlying net profit after tax. As we flagged at the FY '24 full year results, operating free cash flow was impacted by the one-off impact of $381 million worth of government bill relief credits received in FY '24, with the majority of this amount remitted to customers' accounts in FY '25. We also note that we have invested heavily in growth this year, with approximately $900 million deployed towards battery developments and strategic investments as we press forward with the delivery of our strategy. I will also speak to the strong earnings stream these batteries are expected to deliver once they are operational. This significant cash outlay for growth, combined with the timing of energy bill relief were 2 key drivers of the higher net debt of $2.9 billion. Importantly, we maintained our Baa2 investment-grade credit rating with headroom to covenants. I'll first take you through group underlying profit in more detail. Starting on the left-hand side, you will see one small nonrecurring item attributable to the closure of the Camden Gas Project and divestment of the Surat Gas Project. Moving further to the right. As we flagged previously flagged, we expected a softer customer market's performance, primarily driven by the pricing decision to not fully pass through year-on-year increases to support our customers, which resulted in margin compression across the consumer electricity portfolio. Additionally, margins were impacted as customers switch to lower-priced products, affecting both the consumer gas and electricity portfolios, with consumer gas margins also impacted by lower average demand due to milder weather. It's important to note that we expect an improvement in consumer customer margin in FY '26 and for this to stabilize going forward. This was partially offset by a stronger margin performance by our Perth Energy and Telecommunications businesses, coupled with a favorable movement in retail transformation operating expenses and lower net bad debt expense. Integrated Energy's performance was impacted by expected lower wholesale electricity prices resetting throughout -- through contract positions with the breadth of our flexible asset portfolio, helping to mitigate the earnings impact of outages in our thermal plants. The softer Trading and Origination Gas margin was driven by increased gas costs resulting from the roll-off of lower-cost legacy supply contracts. Our growing battery portfolio continues to deliver very strong performance with the $17 million bar for batteries, reflecting a full year of operation of the Torrens Battery compared to only 9 months in the prior year as well as earnings contribution from the Broken Hill battery, which commenced operations in the second half. This takes our total EBITDA contribution for the operational batteries to $45 million for the year. The higher growth expenditure related to increased development capability as we deliver upon our ambition to add new renewables and firming capacity over the next decade. The bar of the Integrated segment relates to increased spend to maintain and improve thermal fleet plant availability, coupled with higher labor costs. Moving further to the right, the increase in central managed expenses is attributed to technology spend driven by additional licensing costs to support the retail transformation program and other initiatives, including cybersecurity. At the FY '24 full year results, we indicated an uplift in depreciation and amortization in FY '25 that has come in line with our expectations. This increase was attributable to the investment in our thermal assets and thereby the resulting asset bases of these assets as well as the full year depreciation impact of the Torrens Island battery. In addition, we see an increase in the environmental rehabilitation asset, relating to the impact of a reduction in the discount rate. And finally, lower income tax paid reflected the marginal decrease in underlying profit before tax. In a period of ongoing inflationary pressures, and investment in growth, we are really pleased that we have kept operating costs flat as committed to last August through disciplined cost management, digitization and automation. As you can see, the impact of inflation was more than offset via significant productivity initiatives implemented across the organization. We are committed to controlling operating costs in our core business. And in FY '26, the impacts of inflation are again expected to be offset by productivity and business optimization benefits. Looking forward, we expect an increase of approximately 3% in FY '26, primarily driven by the growth part of the business as we continue to deliver on our strategy. In addition, we expect a small increase in variable sales costs. Briefly touching on CapEx. As previously indicated, the uptick in thermal sustaining capital was primarily due to the 2 major planned outages for this year, compared to 1 in FY '24. Just a reminder that over the medium term, sustaining capital spend on our thermal assets is forecasted between $400 million and $500 million per annum. This prudent investment is to improve the availability and reliability of our thermal asset fleet, which is critical to the NEM whilst we undergo the transformation of our operating fleet. In line with our strategy, this year's growth expenditure centered on the construction of the Liddell battery, approximately $375 million of the total $750 million forecasted construction cost. FY '26 will follow a similar theme as we press ahead with the construction of the Tomago battery. Broadly speaking, FY '26 growth capital spend is expected to comprise roughly $185 million for the remaining construction of the Liddell battery, approximately $485 million of the estimated $800 million total construction cost for the Tomago battery, with the bulk of the remaining spend expected in FY '27. In addition, our Customer Markets growth spend will focus on further advancing our distributed energy and electrification solutions initiative being approximately $80 million. This significant investment in growth is the key to unlocking future value for the business, and I'll explain more on the next slide. Looking forward, AGL aims to more than offset any earnings impact of coal and gas recontracting with earnings from its significant investment in flexible assets such as batteries as well as the broader delivery of our strategy. You can see that our 300-megawatt fleet of operational grid-scale batteries are already delivering strong performance and returns, and we have 1,000 megawatts of projects, which are under construction and expected online in the coming years. the Liddell battery is expected to commence operations in early 2026, and the Tomago battery is expected to commence operations in late 2027 after already reaching FID in July of this calendar year. Please note that the graph shows actual and expected earnings for existing and committed projects only, noting that we have a clear pathway to FID for a further 900 megawatts of grid-scale battery projects with each project expected to take roughly 2 to 3 years to build once it's reached FID. Just a reminder that we are targeting ungeared post-tax asset level returns at the upper end of the 7% to 11% range for our grid-scale battery projects, and these assets will be depreciated over 20 years on a straight-line basis. Crucially, we are well positioned to navigate through coal and gas recontracting over the medium term. Our ongoing coal recontracting strategy leverages Bayswater's major key advantages, including its strategic location and significant coal infrastructure, large stockpile capacity of around 4 million tonnes and ability to accept lower quality coal. Pleasingly, in the second half, we were able to procure an additional coal supply for FY '26 and FY '27 at a material discount to the prevailing Newcastle coal prices. Note that with some legacy contracts rolling off, Bayswater's coal fuel costs are expected to increase in FY '26. However, this impact is expected to be largely offset by the pass-through of cost increases under existing wholesale contracts. Turning to gas where our portfolio remains well balanced through to 2027. With the QGC supply contract expiring in December 2027, we are evaluating several supply opportunities beyond 2028, including new gas service agreements from domestic suppliers and LNG imports. Our approach to recontracting is supported by our market-leading gas storage capacity and geographical breadth of our demand base. With legacy contracts other than QGC rolling off, our gas input costs are expected to increase in FY '26, noting that we expect gas margins to revert to historical levels, with the impacts of elevated commodity pricing easing 3 years after the commencement of the Ukraine-Russia conflict in 2022. As we have previously indicated, the investment in the transformation of our business is expected to drive higher depreciation and amortization over the medium term. Depreciation and amortization for FY '25 was $56 million higher, driven by the continued investment in thermal assets, updates to rehabilitation provisions and the resulting higher asset bases, coupled with the full year depreciation impact of the Torrens Island Battery and commencement of the Broken Hill Battery. As you can see, we expect an uplift of up to $100 million in FY '26 based on the drivers on the right-hand side of the screen, noting that the expected commencement of the Liddell battery in early 2026. Our grid-scale battery assets will drive up depreciation over the medium term. However, as I've covered, are expected to be a significant contributor to earnings. A key point I'd like to highlight is our strategic cumulative sustaining capital spend on our thermal assets will be capitalized and depreciated over shorter asset lives as both Bayswater and Loy Yang A near their targeted retirements in the coming years. Our strong operating cash flows have been deployed towards significant investment in growth, with approximately $900 million spent on battery developments and strategic investments, coupled with our strong cash conversion result. I'll quickly speak to some of the key movements. The reduction in operating cash flow was driven by the unwind of most of the $381 million worth of government bill relief that was received at the end of FY '24. If you exclude the cash flow impact of the bill relief from '24 to '25, the main driver for the reduction in underlying operating cash flow was lower EBITDA in FY '25. You will also see the cash tax payment of $268 million, reflecting PAYG installments for FY '25 combined with final tax payments for FY '24. Just a reminder that we paid a fully franked interim dividend and declared a fully franked final dividend with the expectation that fully franked dividends will continue. Additionally, much of the significant items cash flow relates to implementation costs for the retail transformation program. The significant uplift in investment -- investing expenditure was driven by strategic investments to accelerate the delivery of our strategy, namely the acquisition of Firm Power and Terrain Solar and our strategic equity investment in Kaluza. Overall, operating free cash flow normalized for the impact of bill relief was $567 million lower at $788 million. As you can see on the bottom left-hand side, our cash conversion rate, excluding margin calls, rehabilitation and the timing of bill relief remains strong at 97%. Moving now to net debt and funding. We have spent approximately $900 million on growth in strategic investments funded from operating cash flows. The other drivers of higher net debt were the $390 million worth of fully franked dividends paid to shareholders, the prudent spend on the flexibility and availability of our assets and the unwind of the majority of the $381 million worth of energy bill relief received in FY '24. Our funding position remains strong following the successful amendment and extension of our syndicated facility agreement in April, which was increased by $310 million to just over $1.5 billion, with all tranches extended by over 2 years. This is a great outcome and evidence of strong lender support as we continue to deliver on our business strategy and decarbonization plan and importantly, maintain our investment-grade credit rating. Following the refinancing of the SFA, we don't have any major debt maturing until FY '27. Our liquidity position remains at almost $1.3 billion in cash and undrawn committed debt facilities. Before I hand back to Damien, I want to talk to our disciplined approach to capital allocation and balance sheet management that is designed to fund growth, strengthen the core business and deliver shareholder returns. Firstly, we have a commitment to maintain a strong credit profile and Baa2 investment-grade credit rating. Secondly, we will continue to allocate growth capital to projects of the strongest portfolio value and strategic fit, whilst also driving value from our core business. Crucially, we have multiple pathways, funding optionality and flexibility available to AGL in terms of our portfolio rebuild ambition, including assets funded on our balance sheet, where we're targeting returns at the upper end of our 7% to 11% range for firming assets. In addition, we have projects that are developed through joint ventures and partnerships where we have the ability to share the costs as well as the ability to contract and offtake. Our flexible dividend payout ratio also helps us to strike the right balance between realizing timely opportunities in the energy transition and strengthening the core business whilst delivering sustainable dividends to shareholders. In terms of capital management, we see potential in capital partnering as well as capital recycling, unlocking value from completed projects and redeploying capital into new growth initiatives. We also expect to commence a sales process during FY '26 to explore a potential divestment of our 20% equity investment in Tilt Renewables. And finally, on the right-hand side of the slide, you can see an indicative depiction of the forecast sources and uses of cash over the medium term. Thank you for your time, and I'll now hand back to Damien.
Damien Nicks: Thanks, Gary. I'll now conclude by talking to the FY '26 guidance, which reflects a continued strong outlook for underlying EBITDA with an expected increase in depreciation and amortization as well as higher finance costs impacting underlying NPAT as we press forward with the delivery of our strategy. As you can see on the screen, FY '26 underlying EBITDA guidance reflects an expected improvement in plan availability and asset fleet flexibility, including the commencement of the Liddell battery in early 2026 as well as stronger Customer Markets earnings due to the improvement in margin and growth. These drivers are expected to be partially offset by gas margin compression due to the expiring gas supply contracts, noting that the gas margins are expected to revert to historical levels with the impacts of the elevated commodity pricing easing 3 years after the commencement of the Ukraine-Russia conflict in 2022. Higher operating costs largely reflect our continued investment in growth. Of note, the impact of inflation is expected to be offset by productivity and business optimization benefits. FY '26 underlying NPAT guidance reflects higher underlying EBITDA, expected to be more than offset by an increase in depreciation and amortization due to the continued investment in the availability and flexibility of AGL's assets as well as the anticipated commencement of the Liddell battery, coupled with higher finance and interest costs. As I mentioned at the beginning, looking forward, we aim to more than offset any earnings impact of coal and gas recontracting, with earnings from our significant investment in flexible assets and the broader delivery of our strategy. Please note that we do intend to continue paying fully franked dividends in FY '26, noting that future franking levels and the dividend payout ratio is subject to Board approval. Concluding with market conditions, this slide shows the observable curves for both swap pricing as well as cap curves. As you can see, FY '27 forward and cap pricing is broadly in line with FY '26. Of course, it is too early to predict how pricing will eventuate for the remainder of FY '27 and onwards. However, overall, we believe our portfolio is well positioned with a growing portfolio of grid- scale batteries and flexible assets. Thank you for your time, and we'll now open to any questions.
James Thompson: [Operator Instructions] The first question comes from Tom Allen at UBS.
Tom Allen: On the result, if it wasn't for higher electricity procurement costs arising from weaker generation availability over the half, the business looks to be performing okay. So despite having capacity to pay out more, you've called out in today's result that part of the Board's conservatism and again, only paying out 50% of NPAT in dividends is to preserve liquidity and to support the retail transformation. So can you please elaborate on that in more detail? And what's driving the need for such conservatism here? What scenario do you see pressure building on the balance sheet? And what changes to the outlook would the Board need to see to award shareholders with a stronger than 50% dividend payout?
Damien Nicks: Thanks, Tom. Let me see if I can unpack that question a little. Clearly, what we've released today is we saw really strong performance from our flexible assets. That's the key point here. It offset some of the major outages we saw in the first half. We had 2 versus 1, but in the second half, we did have some unplanned outages. Those flexible assets absolutely performed well above where we anticipated them. And that is why you see us investing in the likes of the Tomago battery in -- just recently. In terms of paying the dividend, the dividend is at 50%. We have a big capital outlay over the course of the next year. We still retain that flexibility in our dividend policy, and that flexibility will continue to exist in years where we potentially have either higher or lower capital deployment. But what's important, we see absolutely the ability to offset the impact of coal and gas recontracting by the deployment of our flexible assets, particularly batteries, and that's why we're going after these as quickly and as hard as we can.
Tom Allen: Okay. And last week, the draft recommendations in the Nelson review were released, recommending some sensible changes to wholesale market settings that seek to overcome this tenor gap that's restricting investment in new capacity that the market needs. So I was wondering if you could please outline how the draft recommendations might impact the outlook for AGL. How do you think that might impact prices for common capacity contracts and also baseload swaps in New South Wales and Victoria?
Damien Nicks: Look, I think the first thing to say is there's been really good engagement across both the industry and AGL through the Nelson review. I think it's still very early days to comment precisely how all of it will work. I mean, I think the tenor gap is an important one. The tenor gap is a gap that we need to sell for those outer years of 8-plus years. I think for us, we want to make sure through the Nelson review, there is the right mechanisms for things such as firming capacity, whether it be gas peakers or long-duration storage such as pumped hydro. They're the sort of things we want to make sure is appropriately in the mechanisms going forward. Again, it's pretty -- it's early. There's not a lot of detail yet in terms of how the mechanism work. I think they've talked about a warehousing mechanism for those outer years. Again, that's something we want to understand how that's all going to work into the future.
James Thompson: Next question from Anthony Moulder at Jefferies.
Anthony Moulder: I want to start on guidance, if I could. So the increase you've put through for FY '26 EBITDA at the midpoint is more than offset by that increase in D&A and net interest costs. Is that a reflection of the earnings from Liddell being obviously staged over several years? Or are you seeing that rehab cost now expected to be a bigger drag on earnings going forward and can be offset by the operating earnings of the business?
Damien Nicks: I think the way to think about it, you see EBITDA at the midpoint lifting year-on-year. That is on 2 fronts, or 3 fronts, should I say, one, improvement in consumer Customer Markets result. We expect that to step up next year. The second being, we expect higher generation levels going forward. Also, we see the Liddell battery coming into play from early 2026, plus the broader flexibility of our assets. Again, I'll keep reiterating that. The performance we're seeing out of those flexible assets and the way they're operating in the market is -- it certainly helped offset some of those impacts we saw through generation. But again, we do expect higher generation, and we're standing behind those commitments around high generation into '26 and '27.
Anthony Moulder: With the higher rehab costs, I guess, is the point of what detracts from that though?
Damien Nicks: Gary?
Gary Brown: Yes. Look, what I'd say is if you look at the depreciation slide, there's sort of 3 key buckets there: one is investment in thermal assets. And you can see that we are continuing to invest in that fleet as the life of those assets comes towards its end, it's depreciating over a shorter period. So of that circa $100 million increase, a decent chunk of it is that. Then you've got the growth bucket, which is primarily depreciation in relation to the batteries, which you should be able to calculate. And then you've also got the impact of rehabilitation assets as you're talking about as well as that asset value increases and it depreciates over the period, it's a small proportion of that $100 million uplift as well.
Anthony Moulder: Okay. And just lastly, if I could on tax, the expectations around the tax paying level for FY '26, it was a particularly low level of tax rate in the second half of '25 at 25.4%?
Gary Brown: Yes. So we would expect that, that would normalize towards that sort of 28% to 30% range.
James Thompson: Next up, we have Henry Meyer from Goldman Sachs.
Henry Meyer: It's good to see the expected battery earnings forecast and comments around more than offsetting the impact of coal and gas contracts expiring long term. Could you share perhaps whether you expect those earnings and cost reduction to completely or more than offset the impact of those contract expires in 2028? Or if it's further out in this long-term horizon when that could be?
Damien Nicks: No, look, that's absolutely what we're saying. So over the duration, as we build these batteries and have them in the market, they will more than offset those contractions of both the coal and gas recontracting. We're already seeing today the value of Liddell battery, the Broken Hill battery and again, the Liddell battery coming in, in 2026. And that's why we've taken the FID as quickly as we have. Again, on the Tomago battery, we want those in the market as quickly as we can. We've got a slide there that demonstrates just where we see those returns growing into the future.
Henry Meyer: Okay. Just to double check, so we're saying 2028, you can more than offset the earnings impact from the coal and gas expiries?
Damien Nicks: That's what we're saying, yes.
Gary Brown: Yes, that's correct.
James Thompson: Next up, we have Gordon Ramsay from RBC.
Gordon Alexander Ramsay: Just wanted to comment on the FY '26 guidance on gas margin compression and outlook going forward. It seems to me like you have a high dependence on signing up for LNG imports to be able to kind of balance your gas book beyond 2027. And are you prepared to be an anchor buyer in support of one of these projects getting off the ground?
Damien Nicks: Thanks, Gordon. Look, the way to think about it is we're in discussions with many players in the market, not just LNG players. LNG players, we certainly are in discussions with, but both local production, both Bass Strait, both local, both LNG. And that will be from -- we are contracted out to '28. So we're comfortable from that point in time. But we're in many discussions as you'd expect, about getting the right gas in the portfolio. And the important thing from a value point of view, it's how we use that flexibility of gas, how we use the storage of gas, how we get that back into the market. But Markus, do you want to comment?
Markus Brokhof: Yes. I think we are not bound by LNG imports. It's one source of supplies, which we are targeting. But I think we want to have competitive gas in the portfolio going forward, and that's the reason why we have not made a decision so far on one or the other project. We want to mature the negotiations and then we are coming back to the market. I think it's very clear that we are a foundational buyer. I think that has been acknowledged by the market, as you said. So if we are committing to one project that will then most probably going up, but we have made no decision so far.
James Thompson: Next up, we have Dale Koenders from Barrenjoey.
Dale Johannes Koenders: I just want to ask around your operating cash flow conversion and the impact to the provisions you've made today in the -- for FY '25, I think there was a $98 million onerous contract impact. And I think the current provision is $141 million for onerous contracts. So out of a total of about $1.4 billion on the balance sheet now. So what sort of cash draw should we assume from those onerous contracts going forward?
Gary Brown: Yes. So I think the first thing to think of is the onerous contract has gone up by -- the provision has gone up by $398 million post tax. That's primarily driven by a reduction in the green price in the future expectation of the curves. I think it's important to note, firstly, that we've risk-managed that position, particularly in the next 12 to sort of 24 months. So we've already effectively priced that through to customers. Towards the back end, as we've seen in the past, there's a lot of volatility in those curves. It's mark-to-market valuation. They go up, they go down. So we'll have to wait and see how that plays out. The way you should think about it is it's circa $400 million increase. That's over a 10-year period. Again, these numbers will bounce around. From a cash conversion perspective, we're reporting a 97% cash conversion adjusted number today. And the impact as a result of this, should it play out the way that it's provided for in the books is probably a few percentage points across that period. So it's, again, an area that will continue to bounce around and has bounced around in the past as well.
Dale Johannes Koenders: So that $140 million is kind of the right level unless green certificate prices or power prices recover?
Gary Brown: Yes. I mean, again, it's difficult to talk exactly how that is into the future, but you're talking about those types of quantums you've got, I think, through the -- through the cash flow this year was $98 million, and it will be a little bit bigger again into the future. So it's circa that number you talked about.
Dale Johannes Koenders: Okay. And then just on the comment about replacing the earnings losses. Can you just sort of give us a steer on what CapEx you're assuming? Is it still that $3 billion to $4 billion growth CapEx or maybe towards the upper end as you're accelerating batteries?
Gary Brown: Yes, yes. So the way you should think about that, Dale, is all of the batteries that we've currently deployed. So we've got -- obviously, Torrens is done, Broken Hill is done. Liddell, which is $750 million of capital, and we've also got Tomago, which is about $800 million. So when we talk about those assets being deployed and the last one of those is the back end of '27, we're confident that the earnings stream out of that will have the -- we'll be able to offset any reduction that we could see in both the coal and gas recontracting. In addition to that, we've got another 900-odd megawatts that we would expect to get to FID in the next sort of 12 to 18 months, which would also contribute across that period as well.
James Thompson: Next up, we have Rob Koh from Morgan Stanley.
Robert Koh: I just wanted to get a little bit of color perhaps from Mr. Brokhof, on commentary about forward curves, very helpful commentary on forward baseload and cap. Just any early indication from the new evening and morning peak contracts and how they'll flow through, if you could, please?
Markus Brokhof: I think at the moment, as we said, I think the curves are drifting sideways. If you look at '26, '27, '28, there's a small backwardation even on the back on the caps and on the swaps, but it's very slightly. So you can say it's staying stable. I think it's too early to say how -- what the impact of the new products have an influence on the market. I think it's still too early to define the impact.
Robert Koh: Okay. All right. And on a personal note, congrats on your next stage, Mr. Brokhof, and I guess it's a compliment that it takes 2 people to replace you. Well, my second question is, I guess, referring to the Nelson review. One of the other recommendations was the market-making obligation or MMO, which AGL currently has, I think, in a couple of states. Just if you could provide your views on that proposal, please?
Damien Nicks: Look, I think through our submissions, Rob, we were promoting a certificate mechanism. Again, we're -- would I say we love the market-making obligation? No, we don't. However, again, we're looking at this from an overall package perspective, what is the right thing for the market going forward. Again, there's still a lot of detail to flow under a lot of -- under the bridge right now. We'll continue to work with them. It's now up for discussion right now. And so we'll continue to work at what do we think is the right package of measures for this market going forward.
James Thompson: Next up, we have Ian Myles from Macquarie.
Ian Myles: Can you maybe just give a little bit of color about your confidence in the recovery of the consumer gross margin, particularly where we saw gas being quite weak?
Jo Egan: Thanks, Ian. Jo here. Yes, look, we did as flagged, see a reduction in consumer margin and that was really driven by our decision to hold back some of the price increases last year. We also saw quite a lot of competition in the second half with some retailers really chasing growth at big levels of discounting, where we didn't really see value in that level. But very confident in a return to stronger margins next year as we've flagged. And importantly, I think it's good to note that our customer satisfaction remains really strong. So we're in a really good position. We've also got the Ampol energy portfolio joining us this financial year. So yes, we see good outlook there.
Ian Myles: Okay. And you made a comment in your speech, Damien, with regards to gas gross margins sort of falling backwards. And I was sort of intrigued like I understand the step-down of gas when the contract comes to an end. But can you give us some color again around what's driving that lowering for FY '26 and '27 and how material that is to the business?
Damien Nicks: Yes. Look, it's -- I'll get Markus to comment. It's not majorly material. What we're trying to call out there is what we saw that step up, particularly through that '24 year. In terms of year-on-year movements, that was a component of that year-on-year movement. When we saw those higher prices roll through into '23 into '24, what we're seeing is that then come back out. But Markus, do you want to make any other comments on that one or?
Markus Brokhof: No, I think that you have seen most probably out of the report that the overall gas portfolio price has increased by $0.9 per gigajoule going forward for FY '26, we see also a slight increase in the portfolio price, not at this scale, but it will be lower, but there will be a slight increase due to the fact that some of the contracts are rolling off. So there is still a bit of compression in the gas margin, but I think we are coming back to levels from '23. I think we have seen quite a risk premium in the gas margins due to the Ukraine crisis and so on, as Damien also elaborated on. So we are coming back to normal levels.
James Thompson: We have another question from Anthony Moulder from Jefferies.
Anthony Moulder: I just want to follow up on the fleet availability. Obviously, you've got a target out there for FY '27. You had expectations of improving that through second half of '25 that didn't really deliver. We've now seen further outages at Loy Yang. Are you investing enough into the fleet availability at this particular point? Or does that need to move higher?
Markus Brokhof: No, I think, Anthony, it's always a trade-off. I think we are not satisfied with the fleet performance. I think that's very clear. I think particularly in the second half. What is more important for us is when we looked and when we also consulted some specialists, it's not a systemic issue. I think we had a lot of one-offs when it comes to induced draft fence outages, submersible conveyor issues and so on. These were one-offs. And I think we are proud to be honest with you, and we are also confident that we are targeting a higher availability. And I think the first 6 weeks, if you follow how we are performing in this financial year, have shown that this is not a systemic issue. I think at the moment, we have an availability on the coal fleet around 93%. But I don't want to continue now to forecast that this will stay like this. We have still 2 major outages of around 170 days, which are coming up at Bayswater Unit 3 and Loy Yang Unit 2. But I think we have not a systemic issue and availability should -- we are targeting a higher availability this financial year.
Damien Nicks: And I think the other thing just to call out is, again, the breadth of our flexible assets now means we're making and can make the right decisions at the right time. Like we can run a unit to whether it be a weekend or take it out over a weekend, so you can manage the impacts as well from a trading perspective. So you're seeing us do a lot more of that as we manage unit outages. And look, again, we are standing here today confident that we will lift the availability into '26 and still have that target into '27.
James Thompson: We have another question from Rob Koh from Morgan Stanley.
Robert Koh: I just thought I'd ask a little bit more color, if I may, on Slide 37. This is perhaps for Mr. Brown on the capital allocation. And you've talked about capital recycling in the past, but it's now explicitly written in the preso, and you've also talked about exploring, selling down the Tilt stake. Can you just maybe get some color on how you're thinking about that now that the -- for example, the Torrens battery is up and running and delivering. Is that now a candidate for capital recycling? And how you're seeing the market, please?
Gary Brown: Yes. So I think the way you should think about capital recycling, it's probably more focused in our development pipeline. We've got some very promising wind developments in there. It's those types of assets that we would look to bring up to FID. And then at some point, they're yet to be determined. That's what we're talking about in terms of asset recycling. Our plan is to keep the batteries on our balance sheet because we think that they are best suited both from a cost of capital perspective and also the trading abilities that we have internally as well. So that's really the focus there.
Robert Koh: Okay. And maybe just to follow up. I guess there's been a very interesting deal done in New South Wales by Ampyr Energy and Wambal Bila people First Nations group. Is that something that you've looked into? Is there any possibility with any of your pipeline for innovation on that front?
Damien Nicks: Off the cuff, Rob, I'm not across that particular one, but we work very, very closely with our First Nations groups and all the areas we work in. There's actually a slide in the pack about the amount of work that we are doing there. With the Liddell battery, again, we can engage very closely with the First Nations at that site as we do all sites. But let me take that on notice, and I'll come back to you. I'm not across that one specifically.
James Thompson: We have another question from Henry Meyer from Goldman Sachs.
Henry Meyer: I just want to come back to Slide 32, looking at the battery earnings. Could you share what assumptions you're using here for ARB spreads? What the split of earnings might be between cap contracts, storage ARBs and ancillary services, which are now getting quite saturated?
Gary Brown: Yes. So I think the way to look at that, and we've actually shared some information probably about 18 months to 2 years ago. I think it might have even been at one of our strategy days where you should think about the caps of being roughly 60%, 70% of the revenue stream. You should think about arbitrage at being 20%, 30% of the revenue stream, and you should think of FCAS have been anywhere from up to 10% type thing of the revenue stream. Clearly, the value of these batteries is in the capacity and the ability to sell or defend caps there as well.
Damien Nicks: I think nothing has really changed in what we've said in the market there. It's absolutely playing out precisely as we thought strategically with those batteries. And different batteries in different states will also, depending on the market, will perform different tasks. And for us, it's about finding those constraints on the market or those best areas where we can place them not only to get them stood up quickly, but also where they're best placed in the network as well.
Henry Meyer: Great. Would you be willing to quantify the assumed spread in cap prices in that forecast?
Gary Brown: No. But I think what you should do is if you look at the back, we sort of give a little bit of indication as to at least where they've traded historically and also where the current curves are. But yes, we're not forecasting or talking about where we see those in the future other than to say, we are very confident when we talk about the returns profile of these batteries over 20 years. We've talked about a 7% to 11% return. We are currently seeing these assets perform in the upper end of that range, and we're very confident they will continue to trade across the period at those levels.
Damien Nicks: And maybe just also just to pick up a comment you made. I think you said with so many batteries coming into the market, don't underestimate the sheer amount of batteries that required in this market over the coming decade. It is enormous. So again, getting into the market also early is, I think, an important part of what we are trying to do. But so many batteries and so much capacity needs to be built in this market. That's why strategically, it makes a huge amount of sense for us to be putting our capital there now.
James Thompson: We have another question from Gordon Ramsay from RBC.
Gordon Alexander Ramsay: Just want to refine the view on the sustaining CapEx on your thermal assets. I know the guidance is $400 million to $500 million. You mentioned today 170 days downtime for planned outages at Bayswater and Loy Yang. Should we be thinking at the upper end of that range, considering the amount of work that's being done and your goal to increase reliability and availability in FY '26?
Damien Nicks: Look, I think the way to think about it is the year just gone, we did 2 majors. Next year for '26, we've got 2 majors. For Loy Yang, Loy Yang, we do a major every 6 years per unit, whereas Bayswater, we do a major every 4 years. So in every, if you like, third year, we will have a lower amount of capital, give or take. So that's when we're at the lower end of that scale. When we get to the end of the life of these assets, those capital numbers also come right down. We are spending now the major outage work to get those assets and those major components. So in many cases, they can run all the way through to closure. So you will, towards the back end of this decade, start to see those numbers come right off as well.
Gordon Alexander Ramsay: Aren't you worried that's going to affect availability, reliability, though?
Damien Nicks: No, because the work that we're doing now is that major outage work, whether that be on the turbines or whether -- and I'll get Markus to talk to this, but some of that major work that you won't need to do again. It's that 10-year work you're doing right now on the turbines and so forth. When you get towards the back end, it's in more of that maintenance work you're doing to bring it through to the end of its life.
Gordon Alexander Ramsay: Assuming like things like tube leaks happen all the time, so we just have to expect maybe there is a little bit more...
Damien Nicks: Absolutely. And we forecast for tubes and unplanned outages through our guidance numbers. You're going to continue -- you will continue to see tube outages and that maintenance required on the plant. I'm talking about that strategic large-scale outage planning that happens under the 5- to 10-year asset planning. That will start to come off towards the back end of the decade as you've got through that final phase.
James Thompson: Thanks, Gordon. That's all we have time for today for our Q&A session. Thank you for listening.
Damien Nicks: Thank you all. Cheers.