AGL Energy Limited (AGL) Earnings Call Transcript & Summary

Thank you for standing by, and welcome to the AGL Energy Full Year Results Briefing Conference Call. All participants will be in listen-only mode. There will be a presentation followed by a question-and-answer session. I would now like to hand over the conference to Managing Director and Chief Executive Officer, Mr. Damien Nicks. Please go ahead.

Good morning, everyone. Thank you for joining us for the webcast of AGL's full year results for the financial year 2024. 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 elder's past, present and emerging. I'd also like to acknowledge the traditional owners of the various lands from which you're 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 key themes Gary and I will cover today. Overall, an excellent year across the business. Firstly, our strong full year financial and operational performance, which I'll speak to in more detail shortly. Secondly, we've made great progress in our ambition to connect our customers to a sustainable future. In a period of heightened market activity, our customer markets business had a great year, recording significant growth in overall customer services numbers across both energy and telecommunications and now Netflix customer services. Strategic NPS ended the year in a good position with a score of plus 4, and we've increased our spread to overall market churn to just over 5 percentage points. In June, we were excited to announce a strategic partnership and equity investment in Kaluza as part of the next significant step of the Retail Transformation Program, and I'll discuss this later in the presentation. Importantly, we're continuing to support our customers through this ongoing period of cost-of-living pressures. We've increased our 2-year customer support package by a further $20 million to $90 million and accelerated the rollout of support with $63 million delivered to customers in the first year of the program. Integrated Energy has had an excellent year in terms of fleet performance, recording an equivalent availability factor of 85.8%, 9 percentage points higher than FY '23. A testament to the prudent investment made in our thermal generation fleet, including over 3.2 gigawatts of coal-fired unit flexibility, which continues to deliver benefits to AGL and the transition. We've also made significant progress in transitioning our energy portfolio. Our development pipeline has grown by a further 400 megawatts since the half year result to 6.2 gigawatts, almost double since our inaugural comment transition action plan and refreshed strategy, which was released in September 2022. We're also pleased to announce the acquisition of firm power and Terrain Solar, adding significant optionality to our development plans, particularly in terms of firming capacity. Turning now to the financial results. A great set of numbers. Overall, our stronger full year result was driven by higher wholesale electricity pricing, along with more stable market conditions and importantly, improve thermal fleet availability and flexibility following focused strategic work and capital being deployed to deliver this. We also delivered higher consumer electricity gross margin and benefit from a solid earnings contribution from the Torrens Island Battery in its first 9 months of operation. Underlying profit after tax was $812 million, 189% higher than the prior year, which in turn drove a significantly improved operating cash flow results. Our final ordinary dividend of $0.35 per share has been declared, unfranked, bringing the total dividend for the 2024, financial year to $0.61 per share, equating to a 50% payout ratio for the full year, in line with what we indicated at the half year results. Please also note that AGL intends to begin paying partially franked dividends from the FY '25 interim dividend. We've also provided our FY '25 financial guidance ranges, which I'll discuss at the end of the presentation. Moving now to our safety, customer and employee metrics. An area of concern for myself and the Board is our total injury frequency rate, which remains elevated at 3.5 per million hours worked, a small reduction from the half year but up from 2.8% in FY '23, noting that this is largely attributable to low-impact injuries. We've maintained our acute focus on preventing injuries across the organization, continuing to undertake measures, including increased focus on health and safety leadership training as well as site-specific safety awareness programs to help reverse and improve the trend of this metric. Safety is the utmost priority at AGL, and we must perform better in this area. I've already spoken to our strategic NPS score, which remains in a good position at plus 4 and has increased to plus 6 in July. Encouragingly, our employee engagement score has further improved by 5 percentage points, and we continue to see positive engagement and momentum across the business. Importantly, as an organization, we continue to make strong progress on our ESG focus areas. On the screen, you can see our 6 ESG focus areas with key milestones achieved for the year. I won't speak to all of these, but I want to highlight that in terms of gender equality and representation, we've met our targets for the proportion of women in our senior leadership pipeline and the overall workforce. And we've improved the median gender pay gap for total remuneration by 4 percentage points from 2023. Moving further to the right, we've procured over $5.9 million of goods and services from First Nation owned businesses, exceeding our reconciliation action plan target and importantly, we've invested $6 million in the communities in which we operate. I'll speak to customer affordability on the next slide. However, you can find a more fulsome update of these milestones in our annual report released today. Ongoing cost of living pressures continue to impact many Australians and some of our customers. And as mentioned at the beginning, we've stepped up our 2-year customer support package by an additional $20 million to $90 million. Importantly, we've accelerated our support package spend with $63 million of the 2-year customer support package utilized in FY '24, to deliver assistance to our customers who need it the most. Our customer support package is in addition and complementary to the government's National Energy Bill Relief Fund, which provides bill credits to our customers. At the bottom, you can see the significant amount of government bill relief that was provided to eligible AGL customers in FY '24 with over $1 billion projected to be delivered by the end of FY '25. Turning now to our FY '27 strategic targets. We have made strong progress, and we'll continue to push hard to deliver on these targets. Starting on the left-hand side, I've already spoken to our strategic NPS score, which is in a great position, and we've further improved digitization evidenced by our digital-only customer growth. Encouragingly, our speed to market improvement in cumulative customer assets installed metrics have almost doubled to what was reported at the half year, and we've almost reached our green revenue target. Turning to the right-hand side, I've already discussed a very strong EAF result, and we're aiming to further step this up to 88% over the coming years. Decentralized assets under management are 10% higher at 1.25 gigawatts, including demand-side management of smelters, a great result and with almost 1 gigawatt of new renewable and firming capacity in development contracted or in delivery. I'll now spend a few minutes talking to the transition of AGL and how we continue to execute on our strategy before handing over to Gary. First, just a recap of our 2 primary strategic objectives, connecting our customers to a sustainable future as well as transitioning our energy portfolio. I'll first address how we're advancing the customer pillar of the strategy and shaping customer demand, focusing on our strategic partnership and equity investment in Kaluza as part of a broader discussion on the Retail Transformation Program. I'll then deal into how we continue to optimize our future energy portfolio, enhancing optionality and continuing to accelerate the development of flexible assets to firm renewable generation projects as they progressively enter the NEM and ensure we have a broad range of flexible assets to meet our customer and market needs. Firstly, we have a leading customer portfolio, demonstrating strong growth in the core business and new value pools. I've already spoken to the significant growth in customer services to $4.5 million and decentralized assets under orchestration to 1.25 gigawatts. Notably, we've seen excellent growth in the orchestration of flexible load, such as hot water orchestration, which is more than double this year. We're also continuing to drive commercial decarburization at scale with material increases recorded in our contracted C&I power purchase agreements and commercial assets under monitoring and management. As we continue to invest in building a future-ready business, a key step I want to highlight again is the material increase in digitization and automated AI transactions, which is more than double this year. To continue this growth and build a future-ready business, we know that transformation is required. And in June, we announced our strategic partnership and 20% equity investment in Kaluza as part of the major next step in the Retail Transformation Program. This program will enhance the customer experience, further facilitating effortless digital experiences. It will allow us to innovate and deliver new products to the market at speed and enable AGL to leverage interconnected global technology platforms to improve how we operate, the data we leverage and our overall efficiency of the business. This is not just a technology program, but a business transformation that will simplify our business and operating model and further enhance our culture focused on customer experience. Kaluza is an exciting technology platform developed in the U.K. that supports OVO Energy, one of the U.K.'s leading retailers. Kaluza is more than a billing platform. Its intelligent energy and data architecture was designed with the future of energy in mind, centered around the orchestration of distributed energy resources. This focus and purpose have driven a distinctive offering based on cutting-edge modular technology, unlocking the ability to manage enormous amounts of data and connect quickly and adaptively to other platforms. The Kaluza platform delivers advanced retail automation, reducing costs and enhancing customer engagement by unlocking deep insights. Powered by AI-driven customer service, it features capabilities such as agent copilot, sentiment analysis and account health insights. It's accurate consumption forecasting helps to minimize bad debt and unbilled energy. Furthermore, the platform offers innovative tariffs and energy-use disaggregation enabling customer proposition development. At the core, its industry-leading demand response system optimizes real-time energy usage, unlocking value in energy management. AGL began working with Kaluza 3 years ago through its joint venture with OVO Energy Australia. During that time, Kaluza was localized to the Australian market to support the OVO Energy base whilst also demonstrating rapid deployment of product to market, amazing growth and delivery of exceptional strategic NPS with recent scores above 40. So the next phase of our partnership will see AGL deploy Kaluza at its core retail platform, establish AGL's future state architecture and the migration of our customer base to Kaluza over the coming years. Importantly, the Retail Transformation Program is expected to deliver efficiencies and unlock material financial benefits. AGL is expected to realize net benefits from FY '28 and reached sustainable pretax savings of $70 million to $90 million per annum from FY '29. The benefits are expected to be derived from onshore and offshore labor savings, reduction in net bad debt expense, other operating costs and lower ongoing capital expenditure. The multiyear licensing agreement and investment will build on market-leading results we've already seen in OVO. In June, we also announced that we have agreed to acquire a 20% stake in Kaluza for approximately AUD 150 million. Please also note, we'll be hosting an investor briefing on Kaluza in early September with OVO Energy. Turning now to the transition of our energy portfolio, headlined by the expansion of our development pipeline to 6.2 gigawatts as we continue to focus on building optionality within our development plans. On the left-hand side, you can see the steady growth in our development pipeline, which has almost doubled since the CTAP, and our fresh strategy was released in September 2022. The key point here is our 5.4-gigawatt target of new projects by 2030 is more than covered by almost 1 gigawatt of nameplate capacity in operation under construction or contracted as outlined in the middle of the screen, our expanded development pipeline of 6.2 gigawatts as well as our access to Tilt Renewables 3.5 gigawatt development pipeline and AGL's growing portfolio of [indiscernible] assets and external offtake options. Longer term, however, to achieve our ambition to add 12 gigawatts of new renewable generation and firming capacity by the end of 2035, we'll continue to build out the breadth and the optionality of the development pipeline. You will also note on this slide, we've added over 400 megawatts of fast start gas generation options to our development pipeline, highlighting the critical role of gas to firm renewable generation as thermal baseline generation exits the NEM whilst continuing to develop our hydro and other long duration projects. Ultimately, this market will need a range of flexible asset types to support the orderly transition to renewables. Before I move on, I'll recap some of the recent milestones and achievements which you can see on the right-hand side. We've now received planning approvals for the first stage of the Bowman's Creek Wind Farm. In April, Gippsland Skies was awarded a feasibility license for a 2.5 gigawatt offshore wind development off the coast of Victoria, we entered into a joint venture with Someva Renewables, the development of the Pottinger Energy Park. And importantly, the Muswellbrook Pumped Hydro Project received critical state significant infrastructure declaration from the New South Wales government providing an acceleration pathway for this project. Importantly, in line with our strategy, you can see that we're seeking to accelerate the transition of our energy portfolio where possible, targeting earlier final investment decision dates for the 3 projects marked within [indiscernible]. Just as a reminder, we expect the majority of higher returning firming capacity to be funded on balance sheet and the majority of renewable generation capacity be sourced by joint ventures, partnerships and offtakes. Today, we're also pleased to announce the acquisition of firm power and Terrain Solar, adding significant optionality to our development plans, particularly in terms of firming capacity. Firm Power is a battery energy storage system developer with over 20 projects in development and Terrain solar is primarily a solar project developer with 6 projects in development. Importantly, the combined development pipeline includes several midsized bed projects ranging between 200 and 500 megawatts and 2 to 8-hour storage duration, primarily across New South Wales and Queensland. We also welcome the broad development expertise of these 2 companies, having successfully developed and sold over 10 projects combined, totaling approximately 1.3 gigawatts, the majority of which are now operational. Now taking a high-level look at the firming concept capacity options under assessment and development, as we seek to further expand our portfolio of flexible assets. You'll see that we've added fast-start gas options across the 4 NEM states as well as Western Australia. Overall, we are well positioned for these incremental development options with access to flexible gas supply underpinned by sizable storage and haulage portfolios. We'll also continue to assess and develop a range of long-duration storage options, including the Bluefield development of Pumped Hydro. As mentioned earlier, along with our joint venture partner, Idemitsu, we are pleased to have received critical state significant infrastructure status from the New South Wales government for the Muswellbrook Pumped Hydro Project, which we believe will provide an acceleration pathway for this vitally important long-duration energy storage project, forming part of the backbone of our future firming portfolio. We're targeting a final investment decision for this project in FY '26. As you can see on the screen, this project is expected to have an asset life of approximately 100 years, almost 5x the typical useful life of grid-scale batteries, approximately 3 gigaliters of upper reservoir water storage will be in close proximity to transfer 330 kilovolt substation and will have full underground waterways to minimize environmental impacts. What makes this project particularly unique is that if constructed, it will be the first coal mine in the world to be converted into a long-duration energy storage project. The development of our integrated Energy Hub is also progressing well, with 10 MoUs secured with various parties across 3 major sites. Additionally, our aim of building a value chain of partners to create a circular economy at the energy hub is making good headway. Our partnership with SunDrive announced in March to explore the development of solar PV manufacturing at our Hunter Energy Hub and our MoU with ElecSome for recycling of solar panels could see us hosting several parts of the solar energy value chain of this hub. If established the SunDrive advanced manufacturing facility is expected to be the first of its kind in Australia, creating new jobs and career opportunities in the renewables industry in the New South Wales Upper Hunter region. I've been talking about adding flexible asset optionality to our development pipeline. This slide, however, provides an overview of the flexible capacity currently in operation or under construction. Approximately 7.4 gigawatts in total spread across a diverse range of asset types. Starting at the top, both our growing grid-scale battery and virtual power plant portfolios can respond to peak customer demands in seconds. Moving further down the page, both our hydro and gas peaker assets can start up and generate electricity in a couple of minutes. And finally, with the completion of the Phase 2 flexibility upgrades, we now have over 3,200 megawatts of coal-fired flexibility across Bayswater and Loy Yang A, with both of these power stations now being able to be flexed down approximately 75% and 60%, respectively, on nameplate capacity. Just a final word on the importance of a favorable external operating environment for our industries before I hand to Gary. There is a significant amount of change underway in the sector as reflected in this slide. Support for renewables and firming generation and long-duration storage is critical to substantial investment necessary for the transition as is getting the policy settings right for integrating consumer energy resources. While these changes provide us with opportunities, clear policy and effective regulation will be necessary to the substantial long-term investment decisions we need to be making, and we welcome collaboration across the industry and government. Now over to Gary.

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, a very strong financial and operational performance for the year. Underlying profit after tax was $812 million, 189% higher than the prior year, driven by higher wholesale electricity pricing, along with more stable market conditions, improved thermal fleet availability and flexibility, higher consumer electricity gross margin as well as the ongoing strong operational performance of the Torrens Island Battery. After a challenging FY '23, we are very pleased with the stronger earnings results and continued progress we are making in relation to the delivery of our strategy. The total dividend for the 2024 financial year was $0.61 per share, an increase of 97% on the prior year, equating to a payout ratio of 50% of underlying net profit after tax. As flagged at the half year results, this is at the bottom of our payout ratio of 50% to 75% of underlying NPAT as we preserve capital towards the transformation of our business, in particular, the remaining construction cost of the $750 million of Liddell Battery over the next 2 years, roughly $550 million. Importantly, we maintained our Baa2 investment-grade credit rating as well as having material headroom to covenants. We have significantly derisked our debt portfolio as well as materially increasing our debt tenor through the strong refinancing outcomes achieved in the first half of the year. And finally, as you can see at the bottom of this slide, a strong improvement in operating free cash flow due to higher earnings has driven materially lower net debt, providing greater capacity and financial headroom as we continue to invest in the transformation of our business. Please note, the operating free cash flow number excludes the $381 million worth of Energy Bill Relief received from the government, which is expected to be remitted to customers in early FY '25. I'll first take you through group underlying profit in more detail. We can see a significant step-up in profitability from $281 million in FY '23 to $812 million in FY '24. Starting on the left-hand side, you'll see 2 nonrecurring items from last year, accounting for $63 million of net favorable movement. In relation to the first item, as I mentioned at the half year results, July 2022 was a very challenging month for AGL, which impacted last year's results due to the confluence of planned and forced outages across our coal-fired fleet, resulting in a short portfolio position. This item also includes the lost generation earnings caused by the prolonged Loy Yang A Unit 2 outage in the prior year. However, we're pleased with the availability we've seen across our thermal generation fleet since these events as demonstrated in this year's results. The second item reflects the earnings impact of the closure of the Liddell Power Station in April 2023, which led to a 5 terawatt hour reduction in generation and $187 million worth of net reduction in margin and OpEx savings. Moving further to the right. Customer markets was $30 million higher year-on-year. The stronger customer markets performance was primarily driven by higher consumer electricity gross margin. As previously indicated, in line with greater retail market activity, particularly in the first half of the year, we've seen an increase in costs, primarily reflecting increased net bad debt expense, which is directly associated with the higher revenue rates that came through this year. In addition, and as a result of increased market activity, we've incurred higher channel and marketing spend as we look to grow our customer base, coupled with costs associated with our customer support program. As you can see, a portion of this bar includes $26 million of nonrecurring Retail Transformation Program costs. Integrated Energy's excellent performance was underscored by the significantly higher availability and reliability of our generation fleet and portfolio flexibility. In addition, we have exercised prudent portfolio management of our risk positions coupled with stronger electricity energy and capacity pricing, which is realized in our earnings. I'd also like to highlight the strong $28 million earnings contribution of the Torrens Island Battery in its first 9 months of operation. We are very pleased with the initial performance of this asset, which is generating returns at the top end of our targeted expectations for this asset class. This and other batteries will continue to have an increasing impact on our earnings mix going forward as we deploy more assets, which is supported by the higher cap prices and earnings observed across the NEM in FY '24. Moving further to the right, higher finance costs were largely driven by 2 factors, being the cash impacts on interest of an overall increase in base rates following refinancing and noncash impacts from increases in the discount rate and its associated impact to our provisions. Finally, higher income tax paid reflected the significant increase in earnings. As broadly indicated last August, our increase in operating costs were largely driven by CPI, customer affordability, increased retail market activity, investment in our thermal generation fleet as well as costs associated with customer growth and the transformation of our business. We've seen the benefit of this spend in our financial results this year. However, we remain diligent on operational efficiency across the business. Operating costs have finished approximately $40 million higher than our forecast provided at the half year results. $15 million of this is in relation to a nonrecurring inventory provision due to a detailed review of aging items. In addition, we've seen higher spend on plant availability, which again, we see the benefit through improved plant performance. Looking forward, as you can see on the right-hand side, we expect FY '25 operating cost to remain broadly in line with FY '24, with inflation and costs required to support electrification and Energy Hubs growth to be broadly offset by productivity and business optimization benefits. Pleasingly, this includes operating model benefits realized through the Retail Transformation Program. Turning now to customer markets performance. Overall, an excellent year. Total services to customers increased 211,000 to 4.5 million services driven by strong growth in energy, telecommunications and now Netflix services. It's also been pleasing to welcome 94,000 energy services recognized as part of the 100% acquisition of OVO Energy Australia as part of these numbers. Importantly, we maintained other strong customer metrics, including a favorable churn spread to rest of market of 5.1 percentage points through a period of heightened market activity. On the right-hand side, you can see the improvement in consumer EBITDA per services, driven by the consumer gross margin improvement for the year. Now to fleet performance and operations, headlined by excellent overall availability across our generation fleet and higher volatility captured. Again, we wish to reiterate through these financial results, the benefit of our ongoing focus on maintaining our asset base. Commercial availability of our thermal fleet was up 15 percentage points, driven by the significant reduction in force thermal outages compared to the prior year. Importantly, our fleet was available when it mattered with the volatility captured through trading up over 9 percentage points to 66.7%. Normalized for the Liddell Power Station, which closed in April 2023, generation volumes on the right were almost 7% higher than prior year. Overall, coal-fired generation was higher. However, gas and renewable generation were both lower, attributed to the factors mentioned on the right-hand side of this slide. Briefly touching on CapEx. FY '24 CapEx has ended broadly in line with our projection at the half year results. And overall, we are pleased that our prudent step-up in thermal sustaining spend has delivered a significant increase in thermal fleet availability and reliability. Focusing on FY '25, the uptick in thermal sustaining spend is primarily driven by one additional major planned outage compared to FY '24. Just to reiterate, over the medium term, sustaining capital spend on our thermal assets is forecasted between $400 million and $500 million per annum, which will fluctuate each year subject to asset management plans. This investment is expected to continue the strong performance of our thermal asset fleet. We've reported property refurbishments of sustaining capital. However, a substantial proportion of this spend will be recovered in FY '25 through incentives in our various lease arrangements. In line with our strategy, growth spend will focus on the construction of Liddell Battery, approximately $500 million of the total estimated $750 million construction cost is forecast to be spent in FY '25 with approximately $50 million remaining in FY '26. Customer Markets growth spend will focus on advancing our Energy-as-a-Service and electrification solutions initiatives. As 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 '24 was $19 million higher, largely driven by the increased investment in our thermal assets at Torrens Island Battery coming online. In FY '25, we expect an uplift of approximately $70 million to $80 million, reflecting the continued investment in our thermal assets and changes to the rehabilitation provisions, the completion of the first phase of the Retail Transformation Program as well as the full year depreciation impact of the Torrens Island Battery and commencement of the Broken Hill Battery. We've had an outstanding cash result for the year with underlying operating cash flow of just over $2.4 billion, $1.4 billion higher than the prior year, largely driven by significantly improved earnings and lower margin costs. Operating free cash flow more than doubled to $1.4 billion due to these factors, partly offset by higher sustaining and growth capital spend. Please note, both numbers exclude the $381 million worth of government bill relief mentioned earlier. As you can see on the bottom left-hand side, our cash conversion rate, excluding margin calls, rehabilitation and the bill relief received improved to 98%. Turning now to our debt portfolio and funding position, where we've made excellent progress this year. Overall, we've significantly derisked our debt portfolio with our weighted average tenor of debt increasing to 5.3 years and an improved spread of maturity dates achieved. No significant refinancing is required until FY '26. Our liquidity position has also increased to $1.7 billion in cash and undrawn committed debt facilities. Moving to the right-hand side, we achieved a $942 million reduction in debt, driven by the stronger cash flow performance, noting that this also includes the bill relief received, partly offset by higher capital expenditure. In terms of rating and headroom, we continue to maintain our Baa2 stable investment-grade Moody's rating and hold significant headroom to covenants. Overall, we end the year with stronger operating cash flow generation as well as larger, more diversified pools of capital. Turning now to market conditions. Starting with the left-hand side, we've seen a good recent recovery in FY '25 and FY '26 swap pricing, which are broadly consistent in terms of VWAP at this stage. And while lower than FY '24, they are still materially higher than FY '23. On the right-hand side, you can see cap pricing for both New South Wales and Victoria remain strong, boding well for our growth portfolio of grid-scale batteries and flexible assets. Continuing on the theme of market conditions, I want to talk through some of the tailwinds expected for longer-term electricity demand. This slide focuses on EV penetration as well as potential data center growth. At our Investor Day last June, we highlighted AEMO's projection of electricity demand within the NEM, likely doubling by 2050, largely driven by the electrification of the home, transportation and broader industry. Encouragingly, we are continuing to see some of these expected tailwinds come to fruition with the growing demand for electrification products from our consumer and large business customers, which includes a sharp uptick in EV market share recorded in 2022 and 2023, ahead of strong medium-term projections by AEMO. However, most recently, there has been significant step change in data center development pipelines globally, fueled by the rapid rise in the demand for AI-led data center capacity. We are seeing this trend mirrored on a domestic front as well. Broadly speaking, we could see data center capacity almost triple across over the medium term in New South Wales, Victoria and the ACT. Assuming an announced data center development pipeline of roughly between 1.5 to 2 gigawatts is built and operational over the medium term. Overall, the portfolio and development pipeline is well positioned to capture this upside of any future energy demand growth. Thank you for your time, and I'll now hand you back to Damien.

I'll conclude by talking to FY '25 guidance. Overall, we expect a reduction in earnings for FY '25 based on the drivers you can see on the screen. Firstly, lower historic wholesale electricity prices resetting through contract positions, combined with the roll-off of heightened volatility driven by market interventions in mid-2022. The second driver is consumer margin compression following a period of heightened market activity and lower wholesale prices. As Gary discussed, operating costs are expected to remain broadly flat. However, we do expect an uplift in depreciation and amortization. Please note that we do intend to begin paying partially franked dividends from the FY '25 interim dividend, knowing the future franking levels and the dividend payout ratio is subject to Board approval. Thank you for your time, and we'll now open to questions.

We will now open for questions. [Operator Instructions]. The first question comes from Tom Allen with UBS.

AGL has printed solid operating cash flows. And so I was hoping you could please share more in detail on the capital demands in the business over the next 2 to 3 years, particularly given you've announced an acquisition today that adds 8 gigawatts of capacity and development options. Given there's a lot of greenfield development in the pipeline, which has more exposure to cost overrun risk due to all of the development challenges that we're seeing across the industry. So I was hoping you could also just comment, perhaps, Gary, on where you're comfortable taking FFO to net debt and gearing over the next few years.

Thanks, Tom. Look, I'll kick it off first and then I'll hand over to Gary. This acquisition, I think, importantly, provides us some great flexibility and some optionality in that portfolio. We now need to do the work post the due diligence. There’re some great options in there, we'll obviously then assess how that fits within our portfolio from a state by state and the development pipeline. In terms of where we see the actual capital spend, we're not announcing any major changes to that. This is about all about optionality. Some great options in New South Wales and Queensland when you look at that pipeline. But again, there's some opportunity across the whole Australian Board there. So we'll keep looking at that. But Gary, maybe just touch on from a capital perspective.

Yes. Tom, probably what I'd add to that is, firstly, our investment-grade credit rating of BBB is-- we're absolutely committed to that. So if you look at the thresholds there, you're looking quite significant headroom to the 22%. We obviously talked at 62% for the full year results. So we've got quite a bit of headroom there. What I would also say is a lot of those cash flows are spread over a number of years as well. So we're quite confident with where we're sitting at the moment.

And are you able to just extend on that, Gary, just a comment on where you're given the amount of greenfield development in the pipeline, just where you're comfortable taking leverage to?

As I said, Tom, we've got quite a bit of capacity in relation to the broad level of debt that we could absorb into the business, particularly as some of these assets start generating profits and cash flow into the future as well. But as I said, we're committed to that investment-grade credit rating, and we've got quite a bit of room all the way down. Obviously, we wouldn't get to 22%, but we've got quite a bit of headroom to get down to that.

The other thing I'd say too, Tom, is just as we've always said, between what will go on our balance sheet and what will go off our balance sheet, largely the renewables will have off our balance sheet. That doesn't mean we won't put some on there. From a firming perspective, largely we'll put more firming on our balance sheet. But again, you can even see today we've got some of those assets off our balance sheet as well. So we'll continue to evolve that to make it the most capital-efficient way we can deliver these assets into the market.

And just following up your comments on the acquisition. Can you just comment, please, on how much of the 8.1 megawatt development pipeline within the firm power portfolio currently has DA approval? And maybe just a comment on how you landed at the $250 million valuation, just given that the early phase development sites, it's tricky to prosecute the transaction price.

No, we're not going to go into that sort of level of detail on this call. Clearly, we see this as an exciting opportunity that the optionality of this development pipeline to add to the pipeline that we had in the locations that it provides to us is, we think, a huge opportunity. As I said, we'll continue to work through each of those. There’re roughly 20 sites that we're looking at there. Those 20 sites will continue to assess which of those will go first and how we continue to invest in those.

Next question we have from Anthony Moulder at Jefferies.

I just wanted to talk about this, the additional $400 million to $500 million of investment into the thermal availability and reliability. Obviously, it looks like you're now close to your FY '27 target space on which you delivered in FY '24. So just trying to understand as to whether or not that's the peak level of investment that you'll need to make in FY '25, and it should taper off from there? Or is there an expectation that you can up that target than FY '27 target, given that how close you are already at that place.

Just if I understand that question correctly, I mean, what we've always said is, we'll spend roughly $400 million to $500 million on capital on our thermal plants per annum. Next year, you can see that slight step up. The reason for that is we've got 2 major outages next year. We've got both Loy Yang A and Bayswater in the first half that are planned outages. So that's why you see a slight difference between the years. We'll continue to provide those updates as when those outages will occur. But I think continue to use that range to $400 million to $500 million when we think about ensuring that we get the availability of the plant. And look, this year has been a fantastic year. We've seen availability up almost 9 percentage points up to 85.8%. We've got the target to bring the total portfolio up to up to 88%, which is where we're targeting the plan. But it's not just about availability, it's also flexibility. And we've seen the benefits of that over the course of this year. The flex in those thermal assets. We're now at about 3.2 gigawatts of thermal flexibility. And if I look at the overall assets that we have now, our total flexibility is 7.4 gigawatts, which is a fantastic amount of flexibility, which we have in our overarching fleet.

And just quickly for Gary, if I talk to net interest. Obviously, not a lot of increase through FY '24, but likely having some more capitalized interest coming into expenses. How are you thinking about the interest cost going through FY '25, please?

Yes. So I think with interest, it's important to note there's a couple of different elements there. One is the base level of debt that we've got that's obviously reduced over the last 12 months. We've seen a slight increase in the base rates there. But there's also a lot of noncash items in there as well. So you've got provision unwinds lease expenses and the impacts on rehabbing onerous contracts as well. So I think you should expect that it would be relatively consistent going forward.

Thanks Anthony. Next up, we have Dale Koenders from Baron Joey.

I was just wondering if you could provide some more color on FY '24 guidance, how you're thinking about generation given you just called 2 major outages, battery earnings, electricity market volatility as well, given we've seen a bit guidance on one real market event. So color there would be great.

Yes. Look, I'll kick that off and maybe I'll hand over to Gary as well. So when you think about the spread of that guidance, you can see some of the wholesale prices starting to moderate, which we've seen from the last couple of years. So that is a driver of it. But again, importantly, the performance of our plant around availability and flexibility is incredibly important. The 2 major outages are in those numbers. So clearly, to put out a guidance like we have has those 2 major outages in there. We've obviously set up our portfolio and our book to account for that. Again, for us, it's about continuing to run those plants extremely well. Maybe, Markus, just want to touch on sort of performance over the last year.

I think it was a good performance for sure, this is not coming overnight. That took us most probably 4 years to get it back because that are then 4-year outage cycle. So each of the units would have been then undergone real refurbishment and uplift. So that has now taken us to where we are and has uplifted not only the equivalent availability but also the commercial availability, which is more important for us. So yes, that's a great success.

And then battery earnings cost?

Yes. So look, again, we're keen to -- clearly our strategy is to deploy onto our balance sheet firming assets to support our customers going forward. For 9 months, we've reported $28 million of EBITDA. That's a really, really strong result. We think it's important to continue to demonstrate to the market the strength of our strategy going forward. That is 9 months of generation again, so it's not 12 months. It is not necessarily a prediction of how it will perform into the future. But we're really pleased with how that's looked in the first 9 months of operation.

Probably just to add to that, with Broken Hill is now operational as well and we've got Liddell Battery in construction also. So we'll continue to build that out.

Next up, we have Reinhardt Van der Wilt from Bank of America.

Congratulations on the results. Can I please just check, the timing of the Liddell Battery COD. You mentioned that there's that last little bit of CapEx that's falling in FY '26. When should we expect operations to kick in within FY '26? And if we're then just thinking about returns, again, I mean, the Torrens Battery seems like it's printing a pretty solid ROIC so far. But sort of high teens, but your IRR target is still sort of low double digits. Can you just maybe kind of just characterize sort of what's special about Torrens why does it seem to be kind of almost over earning at this point?

Maybe let me start with the first question. I think when it comes to the Liddell Battery, we have a 2-stage process of commercial operation date. We are targeting the first stage, 250 megawatts in December '25, and then April '26, the other 250 megawatts, and that's the reason why you see then also CapEx flowing into '26. I just want to point out that each of the market is for sure different and also the spreads and arbitrage opportunities, but also cap prices are different. And then our portfolio setup is also different for each of the battery locations. But Gary?

Yes. And probably, what I would just add is we've talked about sort of firming assets being somewhere around 7% to 11% post-tax IRRs. Sure, to date, these South Australian assets performed at the top end of that range, but we would certainly sort of talk as a portfolio, we'd expect to sit within that range.

Next up, we have Mark Busuttil from JPMorgan.

Just one of the numbers that really stood out to us was the $93 a megawatt hour you received from wholesale customers. I'm just sort of interested in sort of delving into that. That was 15% higher than what it was in 2023, and it's almost 50% higher than what it was only 2 or 3 years ago. Is it all related to re-contracting with long-dated customers? So have you been active in doing that in resetting some of those long-dated contracts at substantially higher prices? And if that's the case, could we anticipate it being at that level going forward?

Partly it's a reset, as you said. But partly, it's also that I will not go into detail, but partly also our customers have chosen more spot exposure. So they are then buying quarterly contracts and so on, and that's then flowing also into the profitability of our prices. So we have a product out, which is called pump where a customer can choose and also how we want to contract, and that is most probably also contributing to this.

And that pump products often on a quarterly basis for those customers as well. So that's what's driving some of that. But again, we won't go into customer-by-customer detail on that one.

So could you give us a bit of a sense of how material those on variable contracts would be? Or and how many would be on those sort of much more longer-dated contracts?

I think we'll not do.

Yes. I think the way to think about it, and I think we've spoken about this consistently over the last couple of halves is these customers tend to sort of roll off every on average every couple of years type things. So that will just gradually roll through the book.

Next up, we have Ian Myles from Macquarie.

I'm seeing you put 1.5 gig gas plants on your sort of outlook. Just curious what's the sort of time frame you sort of seeing you need to have these gas plants probably into the market to provide you that long period storage as opposed to just that sort of battery storage type of exposure.

Yes. Look, just what you're calling out there is on our development pipeline, we've added about 400 megawatts of gas peakers on the broader pipeline, we also have gas peakers there for future development. The way we think about it is just if you think what's happened over the last 3 or 4 months with some of the wind drought and the performance of where our SA gas plant that's been very important. So for us, it's about having flexibility of assets across our fleet. So it's going to be both batteries. It's going to be both pumped hydros. It's going to be potentially some peakers as well. In terms of the timing of when we bring them in, it's going to come down to a decision both economically as to when we think we need it for our market and the particular states that we're operating within. So again, we'll continue to provide updates to the market as and when we see those assets coming in. But we do see them playing an important role for long-duration storage long duration storage is going to be, I think, really important. We see that today in SA.

Maybe you can ask this slightly differently. When you do those projects, particularly the big ones in New South Wales and Berman, Queensland at a point that you've got through approvals, you've got a connection agreements and a bit like where it's about actually making an FID decision as opposed to doing all that preamble or the predevelopment work.

Look, and so the way to think about it is in some state, we have locations in some states, we have planning. For those who are at the Torrens Island, we have obviously a site there. We have planning there. In Victoria, we have a site. Clearly, we have to continue to work through planning and so forth. Other states, there's probably further work to be done in that space. So I don't want to go through location by location, state by state, but that's the work that we're doing. We're doing that with all of our assets, whether that be in the hydro space or in the renewable space or the firming that is part of this process. So we have been actively building our development pipeline team quite materially over the last year or 2, having also now will Berman Terrain bringing in additional resources and capability, I think, is going to be also very beneficial to us. But Markus?

I think on Slide 16, we are mentioning even the FID target for the Kwinana Swift Gas plant and also for the Barker Inlet Power Station, and then you can add another 2.5 to 3 years and then you have the commercial operation date.

Can I ask on just retail? Second half electricity gross margins were quite soft relative to the first half. Is that seasonality or are we seeing some a bit more aggression in the market for customers? And secondly, you talked about your pursuit of customers. But if we take off the $94,000 of OVO, your customer growth hasn't really changed a lot year-on-year. Wondering how you can actually accelerate that number?

So a few things there. I think in the second half you're seeing a few things play out in electricity margin. We saw some impact from competition and customers switching to lower price plans. But linked to growth, you would see in our underlying services growth for AGL. We had really strong customer services growth across gas and LEC in the second half. So there's also some one-off impact on acquisition offers such as bill rebates in that result as well. And yes, I think we'll always continue to grow when the market conditions see us to do so. So we're really pleased with that overall growth. Obviously, we've completed the 100% acquisition of OEA as well. So that 93,000 customers now rolled into the AGL portfolio.

And Ian, maybe just to add to that. What I would say on that OVO piece is in 3 years, we've taken that business from about 4,000 or 5,000 customers when we first came on board to now over 90,000. So that's been us up the board at 51% driving that as well. So I think that it's a great result overall. We obviously took the other 49% back in April this year.

Yes. And I mean well on that topic, it was a great growth outcome. But at the same time, we were localizing the Kaluza platform, deploying a lot of new product innovation to market, and we saw really strong NPS in that portfolio, too.

Then next up, we have Gordon Ramsay from RBC.

Great results, gentlemen. Gary, a question on the dividend guidance for FY '24, you said you would be at the lower end of the range because of capital commitments towards transformation of the business. The guidance is still 50% to 70%. What can we look for though FY '25?

Our guidance range or our policy remains 50% to 75% of underlying NPAT. And at the same time, we've talked today about likely having a partially franked dividend from the FY '25 interim dividend as well. I mean where we reside within that range is ultimately up to Board discretion. But the way we look at it is what are our capital commitments in the sort of near to medium term, and we'll do what's in the best interest obviously, of shareholders.

And maybe just if I can call it, I mean sorry, go just around the table as well. We have a range. I know you used them gentleman, but I just want to call it that we have a range of males and females at the table as well. So I want to make sure we call that out.

Apologies. In terms of the customer support package, it increased by $20 million to $90 million. You spent $63 million in FY '24. Are you giving us a signal that for FY '25, you're not going to spend as much on customer support?

Yes. I think, Gordon, how we've been approaching that is really investing where we saw customers need it most. And last year was obviously an incredibly challenging year off the back of those significant electricity price increases we saw, which is why you would see a lot of that investment was front loaded. I think what's important to note is that package has been really effective, not just supporting customers experiencing vulnerability, but also keeping our debt position in a really good outcome. We've implemented a range of programs, not just direct relief, like payment matching, but proactive outreach to customers, getting them on payment plans, monthly billing and government support where it's available. And you'll see that in quite a difficult market. We've managed to keep our net bad debt as a percentage of revenue broadly flat, which is a really great outcome. So we'll continue to provide those measures. We've announced an extra $20 million, which we'll deploy over the next year, and we'll continue to review that over time.

Next up, we have Robert Koh from Morgan Stanley.

Congratulations on the results from me as well. Okay. First question, I just want to work out how to think about the bill relief, which was $381 million in FY '24. And on Slide 7, you're kind of roughly estimating $1.1 billion of bill relief with the increased rebates this year. And kudos, you've stripped it out of your cash conversion and your FFO to debt. But I just want to understand, should we be thinking that your FY '25 debt balance this time next year should also be benefiting from like $700 million net benefit?

Maybe look, I'll take it, and we sort of, we're looking around at each other at the table to answer this one. So the bill relief, we received some before the end of the financial year at 381, that's why we stripped that back out. The rest of the bill relief largely should be delivered to customers over the course of the year. So you shouldn't expect to see a change, it should all go through in the one financial year. There might be some carryover, but we'll know by the end of the year. Most of it will get delivered over the first 6 months or so. But Jo, do you want to comment on that?

Damien, so that 381 million to net debt, the impact we called that out very deliberately at the $1.7 billion of $1 billion of net debt. That $381 million will gradually trickle out, which will effectively increase that level of net debt or normalize it back.

And in terms of customer impact, I mean, we were really pleased to see the continuation and expansion of that we advocated for it strongly for our customers. Obviously, it's being applied very broadly, though, this year across the entire portfolio. So in terms of our actual performance on customer debt, there's definitely some benefit there, but not significant.

And then my next question, I guess, relates to Slide 33, where historically, you've given us baseload strip prices, you're now calling out cap prices because I guess they've been a lot more volatile. Should we be thinking you've got your 7.4 gigawatts of Flex, should we just kind of look at cap price change year-on-year and a firmness factor and the capacity as a way to help calibrate our modering? Is that what you're inviting us to do?

I think broadly, what we're trying to do here is to message. There are a few data points out there that are very visible. So you can see the SWAP pricing, you can see what that's doing in New South Wales, it's gone up a little bit in Victoria. It's remained relatively flat. But we're also trying to message there that the cap prices have gone up in New South Wales and remain relatively flat in Victoria. So all of these elements, again, it depends on how it goes. There's still a long way to go in the year. We're only what, 6 weeks into a 52-week period, roughly, but we are saying that those cap prices are increasing, which ultimately do flow through to customer pricing. But again, there's a long way to go. So we'd have to wait and see how that plays out.

And Rob, very deliberately, there's also another slide in there. It just shows where that 7.4 gigawatts of flexible capacity comes from across both from a customer level, BPP from batteries, gas peakers, hydros, all the way through to the coal thermal plants as well, which were now up around about 3.2 gigawatts of Flex as well. So, I think it's just a demonstration of the Flex we're putting to this portfolio and thus the thesis also for the investment into firm and terrain.

Yes, makes a lot of sense. Maybe can I sneak in one third question, just on Slide 4, where you've called out data center contribution to load growth. Those numbers there that you've got for data center capacity, is that ICT nameplate including POE? Or is that an actual kind of observed AC load, just if you just confirm that one.

Yes. So basically, that's sort of the nameplate announced data center development. So it's sort of nameplate expected megawatts that would be required to service them. I mean, of course, there's efficiency that would be have to come into that equation, which we haven't necessarily accounted for because a lot of these things will have to play out over time. Really, what we're trying to demonstrate here is that there are tailwinds that are coming both from electric vehicle and from a data center growth perspective. What is clear is we don't know exactly how that will play out. But certainly, we think it will have a positive impact on demand going forward in terms of increasing it.

I don't think, Rob, there's a whole range of forecasts out there right now from 1x growth to 5x growth, it is something we will continue to watch incredibly close as we think what is the portfolio that we need for the future, and that means our portfolio will also continue to evolve with it.

Next up, we have Nik Burns from Jarden.

Look, I noted there was almost no details on consumer and wholesale gas side of the business in your presentation today. The fact that I think gas contributed around 30% of your FY '24 gross margin despite mild weather events is a pretty good outcome. I'm just wondering if you could give us an update about the outlook for gas volumes, gas margins and any update on the state of your gas book as well.

So and I'll then hand over to Markus in terms of where we're at on that front. We have contracted sufficient gas for our customer load apps or 27, 28. As you'd appreciate, we're in a range of conversations there, whether it be through local producers, whether it be through LNG, whether it be from smaller producers as well. So those conversations clearly continue. When we've got a sort of a material update for the market. We'll clearly provide that. But you're right. We had again another strong result this year. We started with a mild winter weather, if you like, and that was mild in the first half. What we've seen though is a much cooler start in the second half as well. But Markus, I don't know if you want to just add to that at all?

I think most probably you have seen also that we had a drop in sales volume by 30% better, quite sizable. But I think that's most probably something which we will not see in the future. I think our portfolio is set up for the next few years that we are keeping this level what we have also sold this year. I think profitability, most probably is very much depending how short the market will come. I think we are very well placed. I think with our storage facilities, particular with our flexibility and our haulage contract, but also the one storage, I think we can still serve a lot of wholesale customers, but also supply our retail portfolio and that is adding to the margin. But it's also quite a sizable cost which we have in the portfolio.

Next up, we have Henry Meyer from Goldman Sachs.

Just kind of curious on treatment of impairments from PPAs in the past. We've had some write-offs historically, but prices keep increasing. Curious if you could touch on whether you see any risk of those reversing in the future?

So the way the impairments work with the contracts, is it effectively, you've got the short-term ASX curves and then you've got the longer-term market reference cars as well. And depending on how those curves move, both short and long term, does have an impact on those particular contracts that are taken out of which, obviously, we don't disclose the commerciality of those. So they do move backwards and forwards over time. And this year as an example, we saw originally the curves came off, and then they've sort of strengthened a little bit in the second half as well. But so the overall movement in the Onerous contracts wasn't significant at all. But that will continue to move up and down depending on where the market reference curves are.

And we've got one more question from Gordon Ramsay.

Actually, I don't, it was about the gas book. It's been covered.

We've got another question from Robert Koh from Morgan Stanley.

So I just want to know you'll be presenting on Kaluza in early September, but just wondering if I could just get any comment on the timing of the benefits. I mean, you're spending or investing the 300-ish now. Is FY '29 17 to 90 benefits, is that like the peak benefit so that the benefits ramp up ahead of that? Or do they start in '29?

Yes. Thanks, Rob. Yes, starting in FY '29, once the full completion of the program is. However, there will be some incremental benefit over the next few years from existing investments in our Phase 1 of our transformation deployment. So we're already seeing that come through. As we've shared before, we've been focusing on our CRM and our operating model changes. So yes, it will ramp over time, but the full run rate from '29.

Yes. I think if you were going to model it, Rob, model that full run rate from sort of that '28-'29 onwards, but there will be that ramping as we go. I think we talked about ramping, as Jo said, it's starting as we go through the program, but there will be some ramp into 28 as well.

Last question comes from Reinhardt van der Walt from Bank of America.

I just wanted to see if you had any updates for us on the MacGen coal contract expiry. I just want to see if you're in the market at the moment? Anything we should be aware of in terms of liquidity in that market and maybe where you're seeing pricing for low CV domestic coal?

Yes. I think as you are well aware, I think our contract with Peabody is running out in '28. For sure, we are in the market to contract at the moment. But we will not give any indication what is the discussion at the moment of the commercial terms of these agreements. I think there is chances of contracting coal, but we for sure we are properly screening the market and want to get the best outcome for Bayswater. So that's ongoing. And most probably also depending how our Bayswater Power Station is running. We have to also recontract some spot prices as well. So yes, we are very much close to the market and watching and see some potential post '28 to contract some sizable volumes.

I think the other way to think about to just remembering where Bayswater is located, we have access to the coal right and the rail there, but also that power station can take lower quality coal as well as opposed to what's going down to export quality as well. So that is where some of the different slides as well between the power stations.

As there are no further questions, this concludes our Q&A session. Thank you, everyone, for joining.