AGL Energy Limited (AGL) Earnings Call Transcript & Summary

Thank you for standing by, and welcome to the AGL Energy 2024 Half 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.

Good morning, everyone. Thank you for joining us for the webcast of AGL's first half results for the financial year 2024. The 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're all joining from and any people of Aboriginal and Torres Strait Islander origin on the webcast. 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. Firstly, our strong first half performance, which I'll speak to in more detail shortly. Secondly, we'll continue to strive to connect our customers to a sustainable future. We've generated strong momentum on wholesale and large business contracts. OVO Australia continues to deliver growth, improve customer experience and rapid innovation. And importantly, I'll speak to how we're helping our customers manage ongoing cost of living pressures. We've also made significant progress in transitioning our energy portfolio. Our development pipeline has almost doubled to 5.8 gigawatts since our inaugural climate transition action plan was released in September 2022. We also now have 800 megawatts of new grid scale batteries in operation, in testing or under construction, adding to our 130-megawatt storage and 2.6 gigawatts renewable generation portfolio. The 250-megawatt Torrens Island Battery became operational in August. The 50-megawatt Broken Hill battery is currently in testing and construction has commenced on the 500-megawatt Liddell battery at our Hunter Energy Hub in New South Wales, following a final investment decision in December. I'll also cover how we're investing in flexibility to capture value from the changing energy markets. More specifically, our investment in grid-scale batteries growing DER portfolio and unit flexibility upgrades at Bayswater and Loy Yang A. Turning now to the financial results. Overall, I'm very pleased with the improvements we have seen across the business. Our stronger first half result was driven by increased plant availability and benefits of portfolio flexibility, more stable market conditions compared to the prior half along with the impact of higher wholesale electricity pricing from prior periods being reflected in pricing outcomes and contract positions. This was partly offset by increased operating costs as we indicated last August. Underlying profit after tax was $399 million, $312 million higher than the prior half. An interim ordinary dividend of $0.26 per share has been declared unfranked based on the targeted 50% payout ratio of underlying NPAT for the total FY '24 dividend. The targeted 50% payout ratio for the full year considers the upcoming capital requirements of the business, including the construction of the Liddell battery. In a period of heightened market activity where we saw customer churn reach the highest levels for several years, we saw good growth in our overall customer services numbers, largely driven by a growing telecommunications business. We've also maintained positive customer advocacy and improved strategic NPS, finishing the half with a score of plus 7 and maintained a healthy spread to overall market churn. We've had an excellent start to the year in terms of fleet performance, recording an equivalent availability factor of 84%, 9.7 percentage points higher than the first half '23, a testament to the prudent investment made in our thermal generation fleet, including unit flexibility, which continues to deliver benefits to AGL and the transition. We've narrowed our FY '24 financial guidance ranges to the upper end. In line with a strong first half performance, and I will discuss this at the end of the presentation. Moving now to our safety, customer and employee metrics. Disappointingly, our total injury frequency rate remains elevated at 3.7 per million hours worked, up from 2.8 in FY '23, noting that this is largely attributable to low-impact injuries. We continue to focus on preventing injuries across the organization, and the next slide will cover measures undertaken to help reverse the trend of this metric. I've already spoken to our strategic NPS score, which remains in a healthy position at plus 7, an improvement on plus 5 as reported in August. Encouragingly, we've seen further improvement in our employee engagement score from a Pulse survey taken in November. Pausing here on safety, and how fundamental this is to our business. On the left-hand side, you can see the numerous measures we are taking to improve our safety performance. Also acknowledging the importance of embracing ESG a foundational pillar for driving our strategy and the energy transition itself. And on the right-hand side, you can see key ESG-related highlights achieved in half. Before I move on, I'd like to talk about our customers and address how we are continuing to support them through this ongoing period of cost of living pressures. In August, I spoke to our commitment to increase our customer support funding to at least $70 million in FY '24 and FY '25. This is in addition and complementary to the Government Energy Bill relief fund and includes up to $400 of bill relief for our most vulnerable customers on the Staying Connected hardship program. To date, we've accelerated our support package spend with $35 million of the $70 million 2-year customer support package utilized in the first half to deliver assistance to customers who need it the most. The greatest portion has been allocated to direct financial support with $20 million in proactive bill credits and $13 million in debt relief to customers experiencing hardship and family domestic violence. We continue to proactively engage with customers who are experiencing cost of living pressures, providing customers with payment support and government grant assistance and have commenced our program to deploy free solar for low-income households starting in South Australia. We're also partnering with specialized empathy training providers for our call center and communication staff delivering programs to improve First Nation customer accessibility and increasing financial counselor coverage. I'll now spend a few minutes talking to the transition of AGL and how we're executing on our business strategies 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, underpinned by a strong foundation of embracing ESG, a safe, future-focused and purpose-driven business and importantly, leveraging technology, digitization and AI to enhance customer experience and strengthen our capabilities. We've made good progress against these objectives, which I'll be covering throughout this presentation. I'll briefly provide an update on where we stand today in relation to our FY '27 4-year targets. Starting with the top row, I've already spoken to our strategic NPS score, which is in a great position, and good progress continues to be made in achieving our digital-only customers target. Please note that this is the first time we're reporting the speed to market improvement and the cumulative customer assets installed metrics, and we will provide an update on the green revenue metric at the full year result. Turning to the bottom row. I've already discussed our excellent EAF result and we're aiming to further step this up to 88%. The 978 megawatts reported for the next metric comprises the Torrens Island, Broken Hill and Liddell Batteries totaling 800 megawatts as well as the 178-megawatt Rye Park wind farm PPA, which was signed in June. Decentralized assets under orchestration is 10% higher than the prior half and stable compared to what we reported in August. And encouragingly, we're in negotiations with 3 major industrial clients seeking to be located on or connected to one of our 3 energy hub sites. We have strong momentum across our strategic priorities to help customers electrify and decarbonize. Starting on the left, our carbon-neutral services have grown steadily, and we continue to scale the Peak Energy Rewards program, one of Australia's largest demand response programs. We're excited to have launched our exclusive energy partnership with Netflix, the largest and the most popular streaming service provider with over 9 million customers in Australia. This partnership recognizes the pivotal role entertainment plays in consumers' lives with 70% of Australians having a streaming service. Moving to the next pillar. Last August, we launched a partnership with bp Pulse in New South Wales, to provide charging solutions to our customers at home and on the go. Since then, we've expanded this offering to Victoria. Additionally, we launched our EV night saver energy plan and our EV innovated subscription service, both complementing our existing EV subscription offering. We've also made excellent progress in driving commercial decarbonization and scale, and AGL continues to maintain its leadership in the commercial solar space. Beyond solar, we've recorded a material increase in contracted C&I Power Purchase Agreements as well as commercial assets under monitoring and management. Importantly, we continue to invest in our customer base and operations to build a future-ready business evident in our growing number of digital-only customers, increased automation of transactions and growth in decentralized assets under orchestration. Moving now to AGL's investment in OVO Australia. We are thrilled with the performance of OVO Australia and the Kaluza platform in the Australian market. Since 2021, OVO Australia has grown its customer base and delivered excellent customer experience whilst also partnering with Kaluza to localize the platform. OVO Australia operates on the Kaluza platform and has successfully migrated 100% of its customer base to Kaluza. The Kaluza platform has enabled OVO to rapidly launch and host new innovative products in the market with an average time from inception to product launch of 16 days. OVO also launched an app that includes integrated EV smart charging insights for Tesla owners. These innovations and investments have resulted in significant customer satisfaction with OVO reporting a Net Promoter Score of plus 40. This is 38 points above the Tier 1 average and 21 points above the Tier 2 average. OVO Australia has also added approximately 40,000 customers taking their total customer base to 72,000. We are continuing to consider AGL's future technology ecosystem while growing Kaluza's local capabilities in partnership with OVO. Importantly, we continue to make significant progress in transitioning our energy portfolio. Our development pipeline has grown from 5.3 to 5.8 gigawatts since August and we now have 800 megawatts of new grid scale batteries in operation, in testing or under construction. As we build our pipeline, we'll periodically review market dynamics, customer demand and development pipeline options and seek to accelerate options and the decarbonization pathway where possible. We are also advocating for streamlining the approval and the connection process for grid scale assets to accelerate the transition. We have also generated strong momentum on wholesale and large business contracts. In September, we signed a 15-year renewable certificate contract with Microsoft, with certificates sourced from the Rye Park wind farm project in New South Wales, under our recently announced PPA with Tilt Renewables. We also entered into renewable linked purchase agreement with CSL and NBN Co and as announced last August, signed a 9-year agreement to continue to supply Alcoa's Portland smelter until 2035. Our structured transition agreement entered into with the Victorian government last August was also key to providing all stakeholders with a high level of certainty around the ongoing operations of the Loy Yang A power station until its targeted closure in 2035. The right-hand side of the slide illustrates the strong progress made against our interim target to supply 5 gigawatts of renewable generation and firming assets by 2030. As mentioned last June, we continue to source energy and capacity as efficiently as possible via a combination of owned and controlled assets, joint ventures and partnerships, including our investment in Tilt Renewables as well as via offtakes and decentralized energy. Importantly, our 5.4 gigawatts of targeted new projects by 2030 is more than covered by almost 1 gigawatt of nameplate capacity in operation, contracted, in testing and under construction, our existing 5.8 gigawatt development pipeline and access to Tilt Renewables development pipeline of over 3.5 gigawatts as well as a growing portfolio of DER assets and external offtake options. This slide provides a good blueprint of the 5.8 gigawatt development pipeline in terms of targeted financial investment decision dates. For context, our current development pipeline is almost double the 3.2 gigawatt development pipeline that was disclosed in our inaugural climate transition action plan in September 2022. On the right-hand side, you can see we have reconfirmed our targeted returns for new projects as disclosed at the Investor Day last June. You'll also see approximately 4.2 gigawatts of early-stage opportunities including offshore wind South of Victoria. We also have access to the Tilt development pipeline via a 20% investment. As previously disclosed, of the 12 gigawatt ambition, approximately 5.5 gigawatts is expected to be funded on AGL's balance sheet, with the remaining approximately 6.5 gigawatts expected to be procured by joint ventures, partnerships, third-party offtakes and DER. And for the component, which is expected to be developed on balance sheet, AGL expects to deploy $3 billion to $4 billion by FY '30 and an additional $5 billion to $6 billion by FY '36. I'd like to spend a few moments discussing how AGL is investing in flexibility to capture value from the changing energy market, particularly in response to the impact of growing variable renewable energy penetration in the NEM driven in part by growing uptake of solar in the residential and the large business segments. The 2 graphs on the left-hand side clearly show the impact on mass market demand as well as the resulting negative or duck curve pricing observed during day time periods when solar generation is at its peak. On the right-hand side, you can see that we've made significant investment and progress in 3 key areas to respond to Australia's changing energy markets as well as optimize realized merchant pricing outcomes. Firstly, our growing and strategically positioned grid scale battery portfolio is well placed to leverage the increasing volatility in the NEM as renewable penetration grows. Distributed energy and orchestration includes our ability to shift loads and orchestrate rooftop solar generation in response to network, pricing and market signals. And finally, as discussed at our full year result in August, ability to flex our thermal fleet enables us to manage the impacts of lower customer demand or negative pool pricing during periods of day time periods of peak solar generation. I'll begin by talking to the first half performance of the Torrens Island Battery. Pleasingly, construction was completed within budget expectations, and the battery delivered $7 million of EBITDA for the 3-month period to the 31st December. Encouragingly, initial performance supports AGL's investment thesis to deliver on our targeted post-tax returns for firming assets, and we're aiming for the top end of this range. We've also included additional detail on early operational performance relating to the 3 main revenue drivers on the left-hand side, being capacity, arbitrage and FCAS. On the right-hand side, you can see that capacity revenue is the largest component of the indicative lifetime revenue stack. We expect to drive additional capacity and portfolio benefits as an integrated energy business compared to a merchant battery operator and will continue to optimize its dispatch strategy to maximize returns for the battery over its life. Last December, we announced a final investment decision on a 500-megawatt 2-hour duration grid-forming battery at our Hunter Energy Hub in New South Wales, one of AGL's largest investments in the energy transition. As announced, Fluence is the EPC provider, and the project will receive both ARENA and LTESA support. I'd just like to highlight that the $750 million estimated construction cost includes engineering, procurement and construction costs as well as project management cost contingency and interest during construction. Importantly, we'll be incorporating experience from the construction of the Torrens and the Broken Hill batteries into the delivery of the Liddell Battery. We expect the Liddell Battery to play a critical role in managing AGL's customer load in New South Wales, especially following Bayswater's targeted retirement between 2030 and 2033. The battery will help reduce our short capacity position in New South Wales and bolster our ability to meet peak customer demand as energy consumption profiles become more segmented. More specifically, it allows us to modulate our customer load during evening peaks and charge during day time periods where wholesale spot pricing is typically low or negative. The battery is also expected to contribute positively to portfolio value by ensuring we optimize the sourcing of cap products on market to meet the capacity shortfall potentially in illiquid markets. I'll quickly cover the key components of the earnings stack. Similar to the Torrens Island battery capacity is expected to be the largest component. The Liddell Battery is also expected to participate in all available FCAS markets and the additional benefits this asset provides includes portfolio insurance for planned generator outages. Arbitrage revenue is expected to increase with greater price volatility as variable renewable energy grows in the NEM. And you can see this on the graph on the bottom right-hand side, which shows the 2-hour daily price spread in New South Wales increasing since mid-2020. Turning now to the role DER plays in delivering benefits to customers and the system while complementing AGL's portfolio. The graph on the left-hand side, albeit illustrative demonstrates the combined role AGL's utility scale storage and decentralized energy resources play in improving load profile management in South Australia. DER provides flexibility that can support a grid with higher penetration of renewable energy. Daily cycling of energy storage increases net demand in the middle of the day when renewable energy is typically plentiful. This includes utility-scale assets like the Torrens Island Battery as well as battery assets in customers' home that form part of AGL's virtual power plant or VPP. These assets are typically then available to offer energy during the evening peak. AGL's Solar Grid Saver product also rewards customers for allowing us to manage their solar production and their daytime load profile. Load flexibility is a significant opportunity that makes use of existing assets in homes and businesses. Electric hot water systems represent a significant flexible load throughout the NEM and AGL is orchestrating approximately 20,000 customers as part of the ARENA SA demand flexibility trial. For business customers, AGL offers demand response products and is helping customers with flexible load response as part of the ARENA Load Flex trial. Our Peak Energy Rewards demand response program for both residential and C&I customers incentivizes our customer in the energy transition and rewards them for reducing energy consumption during peak events. We discussed our ability to flex our thermal fleet at our full year results in August. The flexibility upgrades at Bayswater and Loy Yang A continue to deliver operational and financial benefits with approximately $12 million of portfolio benefits combined in the first half through lower coal usage and avoided uneconomic running. We have almost 3,000 megawatts of total flexing capacity across Bayswater and Loy Yang A, approximately 60% of their combined nameplate capacities and designed to flex within their original design parameters. At Bayswater, the second phase of our flexibility upgrade program will target an additional 30 megawatts for each unit subject to further evaluation. And at Loy Yang A, progress to lower each unit to approximately 230 megawatts is on track for completion in FY '24. Now over to you, 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. We are pleased to report an underlying profit after tax of $399 million 359% higher than the prior half driven by increased plant availability and portfolio flexibility, more stable market conditions and the impact of higher wholesale electricity pricing from prior periods reflected in overall pricing outcomes. We've also announced an interim ordinary dividend of $0.26 per share, unfranked. $0.18 per share or 225% higher than the prior half. As Damien mentioned earlier, we are targeting a 50% payout ratio of underlying net profit after tax for the FY '24 full year dividend. The proposed FY '24 dividend is at the bottom end of our revised payout range of 50% to 75% of underlying NPAT and as we preserve capital towards the transformation of our business, in particular, the construction of the $750 million Liddell Battery over the next 2 years. Please note that the interim dividend payout ratio is slightly lower than 50%. This is consistent with prior periods, whereby the interim payout ratio is lower than the total full year dividend payout ratio However, just to reiterate, we are targeting a 50% payout ratio for the total FY '24 dividend. Importantly, in line with our refreshed capital allocation framework, we are committed to maintaining our Baa2 investment-grade credit rating and material headroom to covenants. We're also striking the right balance between investing in core operations and the transition of our business and our new flexible and sustainable dividend policy will help us to achieve this. Please note, our targeted payout ratio will be reviewed on an annual basis. You'll also see the material increase in operating free cash flow and improvement in our net debt position, both of which I'll discuss shortly. We also note that operating free cash flow is the metric that we'll be focusing on going forward as the key measure of financial performance to ensure the core operational business generates strong cash flows to support future investment in growth. Let me first take you through group underlying profit in more detail. Starting on the left-hand side, you'll see 2 nonrecurring items for the first half of last year, accounting for $146 million of net favorable movement. In relation to the first item, July 2023, which is impacting last year's result, was a particularly challenging month for AGL with the confluence of planned and forced outages across our coal-fired fleet, resulting in a short portfolio position. Compounding this short position, AGL experienced significantly higher pool prices, which were driven by heightened winter energy demand as well as elevated fuel input costs driven by the spike in global commodity prices. This item also includes the lost generation earnings caused by the prolonged Loy Yang A Unit 2 outage in the prior half. The second item reflects the earnings impact of the closure of the Liddell Power Station in April 2023 which led to a 3 terawatt hour reduction in generation and $104 million worth of net reduction in margin and OpEx savings. Moving further to the right, the stronger customer markets performance consisted of higher margins, driven in part by energy customers moving off lower fixed rates, coupled with the earlier implementation of annual price changes. As anticipated and flagged prior, we've seen greater retail market activity with an increase in operating costs primarily reflected increased net bad debt expense associated with the higher revenue rates, higher channel and marketing spend associated with increased competition as well as costs associated with customer support program. In addition, we have a portion relating to the retail transformation program, and I'll talk about these in more detail on the next slide. Turning now to Integrated Energy's performance, which was underscored by the significantly higher availability of our generation fleet and portfolio flexibility coupled with stronger wholesale electricity pricing realized in earnings. The improvement in gas margin reflected the lagged reset of customer tariffs, coupled with gains from short-term market trading strategies. Whilst initially a modest contribution in the half, we're pleased that the Torrens Island battery contributed $7 million of earnings for the 3 months of full operation after reaching practical completion on 30 September. This and other batteries will continue to have an increasing impact on our earnings mix going forward as we deploy more assets. The favorable movement you can see for depreciation and amortization relates to the customer markets digital assets reaching their end of depreciable life. Last August, we mentioned that we would expect an uplift of $40 million to $50 million in depreciation and amortization for FY '24 based on the increased investment in our thermal assets and retail transformation program as well as the Torrens Island and Broken Hill batteries coming online. Please note that we now only expect a $20 million to $30 million uplift attributable to the delay in spend of the first phase of retail transformation program as well as the delayed completion of the Torrens and Broken Hill batteries. 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 which is in line with commercial terms and an increase in the discount rate in provisions being noncash. Finally, higher income tax paid reflected the significant increase in earnings. Last August, we indicated that there would be an uplift in operating costs driven by CPI, variable customer costs, business transformation and investment in our generation fleet. This graph shows that we continue to manage the cost base materially consistent with this position. On the left-hand side, you can see that operating costs have been normalized for $72 million of nonrecurring savings largely associated with the closures of the Liddell Power Station and the Camden Gas Project as well as the divestment of the Moranbah Gas project. Moving to the right. the impact of CPI is expected to be $60 million and is consistent with broader inflation expectations. In line with higher retail market activity, costs associated with customer support is forecasted to be an additional $9 million and channel and marketing uplift relates to higher campaigns and advertising spend to retain and attract new customers. Higher net bad debt expense is attributable to the higher revenue rates, coupled with the growing cost of living pressures some of our customers are facing. We note the customer support package we have in place, as mentioned by Damien. Moving further to the right, the energy hubs another growth bar largely relates to increased capability in our development business in integrated energy to deliver upon our ambition to add new renewable generation and firming capacity over the next decade as well as costs associated with the practical completion of the Torrens Island Battery. An increase of $31 million is also forecasted in relation to the implementation of the retail transformation program, which will enable us to embrace digital technologies, transform operations and position AGL to thrive in a rapidly changing digital era. You will also see prudent uplifts related to bolstering plant availability and reliability and cybersecurity, which are essential as we look to the future and support our asset base and business systems. The risk, compliance and regulatory bar reflects higher insurance risk and compliance costs largely within Integrated Energy. Overall, whilst operating costs are an increase on FY '23, it is important to note that customer revenue and associated rates are higher which led to increased variable costs such as customer support and bad debt expense. And competition remains high, leading to increased variable costs to maintain our position. The increased spend on our thermal coal fleet is aligned to our business case to strengthen availability and flexibility and thereby future generation margins. Turning now to a more detailed discussion on customer markets performance. Total services to customers increased by 13,000 to 4.3 million services with energy customers largely stable. Overall, a very solid result despite elevated market activity. Our focus has been on improved digitization and proactive outreach to support customers and deliver quality service. Customer markets delivered $132 million gross margin improvement compared to the prior half, as I discussed earlier. We've also maintained our #1 position of brand awareness in energy and maintain other strong customer metrics, including favorable churn spread to rest of market at 5.1 percentage points. And I've already spoken to the uptick in operating expenditure, as indicated last August, which was largely being driven by variable costs associated with the market activity, retention and customer support. Moving now to fleet performance and operations headlined by excellent overall availability across our generation fleet and increased volatility captured. Starting on the left-hand side, commercial availability of our thermal fleet was up over 11 percentage points driven by the significant reduction in forced thermal outages compared to the prior half. I'd also like to highlight the successful return to service of Bayswater Unit 1 in mid-December. A major planned outage as part of our summer readiness plans, which included critical integrity assessments, repairs and upgrades to this unit. Volatility captured through trading was also up almost 5 percentage points through improved thermal fleet availability. Normalized for the Liddell Power Station, which closed in April 2023, generation volumes were 1.7% lower than the prior half. Now briefly touching on CapEx. You may notice a slightly different format to how this slide was presented last August, albeit the historical numbers are the same. As I noted in August, growth CapEx for this year will focus on the construction of the Liddell battery, approximately $200 million of the total estimated $750 million construction cost as well as approximately $30 million for the remaining construction cost for the Torrens and Broken Hill batteries. As also mentioned at the full year result, medium-term sustaining CapEx spend for 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. Customer sustaining CapEx over the medium term will focus on customer markets technology solutions initiatives and investments in regulatory programs. Encouragingly, we had a strong cash flow generation performance in the first half with underlying operating cash flow of $840 million, $735 million higher than the prior half, largely driven by improved earnings and lower margin calls. Operating free cash flow also improved by $573 million due to the above-mentioned drivers, partly offsetting higher sustaining capital expenditure to improve and maintain thermal fleet availability and reliability. As you can see on the bottom left-hand side, our cash conversion rate, excluding margin calls and rehabilitation almost doubled to 84%. Just to reiterate what I mentioned in August. As our rehabilitation programs broaden over the next 2 to 3 years, this will be the cash conversion metric that we will be monitoring and reporting going forward given it is normalized for the lumpy nature of rehabilitation spend. As mentioned last June with our revised strategy, we're focused on derisking our maturity profile and improving our liquidity position. We've completed the successful partial refinancing of our existing debt and priced new long-term debt in the U.S. private placement or USPP market. We continued this momentum in the first half with a new Asian term loan secured for a total of $510 million with 5 and 7 year maturities as well as new USPP debt priced for a total of over $460 million with 10- and 12-year maturities. Importantly, our weighted average tenor of debt has almost doubled to 5.3 years, and we have an improved spread of maturity dates, noting no significant refinancing is required until FY '26. Our liquidity position has also improved to almost $1.3 billion from cash and undrawn committed debt facilities. One point I'd like to note, however, is that our derisked maturity profile and stronger liquidity position have resulted in higher borrowing costs. Moving to the right-hand side, we achieved $193 million reduction in debt, driven by the stronger cash flow performance partly offset by higher capital expenditure. This continues the reduction in debt from 31 December 2022 of over $400 million. In terms of rating and headroom, we continue to maintain our Baa2 stable investment-grade Moody's rating and hold significant headroom to covenants. We're well placed as we plan to deploy $3 billion to $4 billion on balance sheet capital by FY '30 towards the transition of our generation portfolio, supported by strong operating cash flow generation as well as a larger and more diversified pool of capital. Turning now to market conditions. Whilst FY '25 prices have moderated in recent months, stabilizing lower than FY '24, they are still materially higher than FY '23. With a few weeks of summer remaining and another 5 months left in FY '24, it's too early to comment on the pricing outlook for FY '25. On the left-hand side are the observable volume-weighted New South Wales swap prices for FY '23, '24 and '25. The FY '25 curve is the observable volume-weighted average price as at February 2024, with several months still to play out. The curves for the Victoria on the right-hand side of the slide comparatively have been less impacted. Thank you for your time, and I'll now hand back to Damien.

Thanks, Gary. Before I conclude, a quick recap on our past 6 months with the numerous operational and strategic highlights. Firstly, a strong period of operational and financial performance, which provides headroom for investment in our future business and the energy transition. Our ongoing support for our customers in need and strong momentum and progress in our strategy to help our customers to decarbonize. And finally, we continue to make strong progress executing upon and advancing our development pipeline. The pipeline has almost doubled in size in just 12 months, providing the ability to accelerate our decarbonization pathway options and underpin future earnings. I'll now conclude by talking to our FY '24 guidance. Encouragingly, as mentioned earlier, we've narrowed our FY '24 financial guidance range towards the upper end, in line with a strong first half performance. FY '24 financial guidance reflects the drivers you can see on this slide, which are consistent with what we disclosed at the FY '23 full year result in August. Overall, our strong business performance and our progress against our strategic objectives positions us well to continue our transformation and invest in our future business to deliver benefits for our customers, our shareholders and communities. Thank you for your time, and we'll now open for questions.

[Operator Instructions]. The first question comes from Dale Koenders from Barrenjoey.

Just regarding Slide 30, where you've gone to the effort pointing out the weighted average price versus traded forward curve. Should we be implying that the differential before between the volume-weighted average price is more indicative of the impact to FY '25 earnings for yourself? And then just on that, should we also be inferring anything in terms of the exposure between New South Wales and Victoria as you've shut Liddell and also starting to implement these battery programs?

Thanks for the question. Look, we are absolutely focused on delivering FY '24. '24, it's been a really strong half of the year. We are focused on delivering the second half. At this point in time, we won't be providing guidance into FY '25 until we get around until the next August results. What those curves are doing is showing exactly what you can see in the marketplace today. There's been a slight softening in the wholesale price. We'll continue to assess that softening as we work our way through summer, but been really pleased with performance of our plant, performance of the assets and importantly, the flexibility we've been able to drive over this period of time.

Our next question comes from Mark Busuttil from JPMorgan.

One number I was particularly interested in was your realized prices to wholesale customers. I think you realized $84 in the half. The last half was $90. But historically, it's sort of been around that $70 to $75. You did allude in the presentation to the fact that you are resetting some of those wholesale contracts higher. But can you tell me how far through your suite of contracts, I guess, you are resetting those prices, if there's more to come. And if we can expect that price to go up as you continue to reset prices.

Look, I think the way to think about it, Mark, is we're constantly resetting our book and prices through the customer base, certainly in the C&I level. Over the course of the last year, we've had some good recontracting of our customer base in both the elec and the gas space after what the prior year was, a much tougher year. We'll continue to contract depending where the price is and depending where the customer is. I think what we're seeing through the customer base is a difference in customers, what they're wanting to contract to in terms of length of tenure, whether it's firmed or unfirmed. So that sort of -- without giving a direct answer, what we're seeing is we'll continue to contract our book as we move forward, and that will move as the wholesale price moves as well.

Okay. If I may squeeze in just one more. I was interested in your gas procurement costs as well. They still seem relatively low compared to prevailing rates. Can you just maybe touch on your gas procurement book and where that's at?

Yes. Look, last June, I think we announced about 100 PJs of gas that we procured and that provides us sufficient gas out to roughly '27. That means that we're continuing to source gas. We continue to source through a number of players domestically and you still have some of the lower cost gas in our book as well today, which also rolls out to '27. But Markus, do you want to just add to that comment?

Yes, I think that's true. And then I think we are also -- and that is most probably what you are pointing out. I think our gas volumes are quite down compared to previous periods. But it's fair to say that we use the flexibility in our long-term contracts and plus also our flexibility in the overall portfolio. And I think the trading team has done an excellent risk management and optimization. So that has led to this lower procurement costs.

Next up, we have Ian Myles from Macquarie.

Maybe just on the book that you've got coming forward. Can you tell me how much of your gigawatts you've got in this development book, which have actually got EIS approval.

Just so I'm clear on your question, Ian, of the 5.8 gigawatts, you're asking how much we have development approved.

How much actually has got genuine approval that you could go make an FID decision versus still going through EIS approval processes?

The majority of those are still going through development processes. And what's really important, I think, Ian, is we'll continue to build out that pipeline. We'll work through both the planning and the connection process and some will go faster, some will go slower. So it's about having that optionality to be able to execute quickly once you get the approval. And of course, the economics make sense on each of the transactions. Obviously, Liddell Battery, we clearly have planning for. You saw and I saw your note a couple of nights ago on Bowman's as well. So the other things we'll continue to work through. But the short answer is, and Markus might just add to it. We don't -- the planning processes continue to proceed. And as we execute on those planning and work with the communities, then we move forward to FID if it makes sense commercially. But Markus?

And maybe, Ian, I think the FID target dates, which we have put in should be reflective where we are standing on our permitting, I think, and approval stages. And we believe the next battery where we take FID will be in Queensland, specific battery, which is at the mature approval stage. And then as you have seen also, I think Bowman's Creek have received for Phase 1 approval of 58 turbines, and we are now going for another approval stage of another 21 in order to enlarge the footprint of the wind farm.

And I think, Ian, the way to think about this table, it's to provide the market an update every 6 months, we'll be providing update as that continues to evolve. New assets will be coming on and also just an update of where we see both planning and FID processes at.

That's great. Can I just add to extent that you talked about the battery. You gave us some indication of what the Torrens Island Battery earned at $7 million. I think that's post-tax, circa $10 million pre-tax is that consistent with what you would expect given I think you sort of talked about 11% to 13% returns on these style projects? Or has it got a bias, I guess, why will it have a bias.

So that was the first 3 months of operation, really pleased in terms of what it delivered in terms of the investment thesis. And it's probably at the top end of where we thought it would be for those 3 months. But again, it is 3 months in. So we wanted to make sure it's really clear that the asset was performing. It goes to obviously making a decision on the Liddell Battery, but yes, absolutely delivering what we expected it to do on both FCAS, arbitrage and also capacity being the largest part.

Next up, we have Gordon Ramsay from RBC.

I'd just like to focus on costs. And just referring to your slide on CapEx costs, where you've given a forecast for sustaining CapEx in FY '24 seems to be lower than your guidance of $400 million to $500 million per annum. Does that imply that sustaining CapEx will be higher in future years, FY '25 and onwards.

Yes. So what we've done there is firstly, we've put in what the sort of forecast is there for '24, and you can see how that plays through. And yes, that is a sort of at the lower end. But the $400 million to $500 million that we talk about is really projecting going forward. We think depending on the schedule of majors and minors in terms of some of the work that's going on in the major plants, it will move between within that band, and it really we're trying to sort of say, going forward, you should expect it will be in that $400 million to $500 million range. But it will be really dependent on the activity in that particular year.

Sorry, just to add to that, it's when those major outages take place is when you see -- you probably -- if there's more than one, then it will be at the upper end, if it's one, it will be at the lower end.

Your operating costs were up 14% year-on-year. Is there anything we should be looking at going forward that is an area of risk for higher cost FY '25 onwards on the operating side?

Yes. Look, I think the way to look at that is and we sort of step it out in the graph there, we break it up into 3 buckets. The first is there's been quite a lot of market activity this year, particularly in terms of high levels of churn within the industry. And we're pleased to say that we sort of maintain that 5% buffer to the rest of the market. But of course, there's a lot of retention activity and those sorts of costs that come through channel and marketing, et cetera but also as we continue to support our customers through the customer support package that we've talked about, it's roughly $70 million, of which $35 million of that was delivered in the first half. So we do expect that some of that cost will come out of our cost base going forward. The next bucket is around the business transformation. And there's a couple of areas there. The first is within Integrated Energy, where we're continuing to invest back into our development teams as we continue to push the pipeline going forward. And in addition to that, we continue to invest in our technology stack within our retail business. So we think they are all good spends that we'd look to continue going forward. And then, of course, we're not immune to the impacts of inflation as well. So we do what we can to manage those costs as well. And we do think that probably we're at the peak of inflation, and we do expect there might be some downward pressure on that over time as well.

Next up, we have Reinhardt van der Walt with Bank of America.

Just got a question about the retail that you've set up going into 2025, both for electricity and gas. I mean the churn is up so far in the first half. Normally, we see a bit more churn in the second half. Do you think we're at a stage now where barriers to entry maybe come down a little bit, especially because that forward curve is starting to slide back down again?

Thanks for the question there. And look, we're really pleased with the overall results of the customer business. As you noted, we did see really high churn, but that was really in the first quarter. It was across the industry. And as Gary mentioned, we were really happy to maintain a good spread to that churn. Off the back of some significant price increases, we did anticipate that kind of activity. We've absolutely been investing in customer retention. And in the second quarter, we've seen that completely normalized. So I'm confident that, that has stabilized now. And I think if you look at our broader results on NPS digitization and broader growth, we're seeing our customers be really happy with our service.

Got it. And just if you could just maybe give us a bit more color just on the gas part specifically. I think you've previously guided to gas retailing margins, probably normalizing back down again to something that may look like a FY '22 kind of figure. I appreciate that you managed to use flexibility to your advantage on the wholesale cost side. But I mean, is the gas retailing industry just sort of structurally right, sort of low competition at this stage?

I think broadly, we're seeing competition normalize. Obviously, last year, we had some unusual events with the market suspension and then as I noted, really high competition off the back of those price increases. But what we're seeing in market now is just more normal consistent levels.

And I think just adding to that, it's going to be going into the future around access to gas into this market going forward. We've obviously contracted our gas book out to '27. It will continue to look to contract that out in the future. I mean customer electrification will happen, but it will happen over a long period of time. So we'll look to continue to supply and source gas for our customers at both the C&I level and the residential level as well.

Next up, we have Rob Koh from Morgan Stanley.

Congratulations on the results, and in particular, the employee engagement score. I'm sure you must have worked really hard on that and you'd be particularly pleased with that one. May I ask a question, a 2-part question on Slide 16, which is the Torrens Island Battery with the chart there of the revenue makeup and you've drawn a distinction between this battery and merchant batteries. Within the capacity revenue, you've got a firmness factor, and I'm just back of the envelope working that out to be about, I don't know, 50% or so. Can you just maybe let me know if I'm on track on that front. And then I guess the second part of this question is, given that this is very different to a merchant battery, does this increase the likelihood that you could look at capital recycling for it?

So I might get Markus to take the question on the firmness side of it and then capital recycling, I'll get Gary to take that one.

I think the firmness sector, Rob, is exactly what you are saying, it's around 50%.

And I think, Rob, what you're going to see in this market. The market will continue to evolve. I think through both our automation and our technology around battery trading, we continue to evolve that space to sort of maximize, the making of the decision of when you charge versus when you discharge, that's also important from a technology perspective. I think in terms of your question, will we look to capital recycled batteries? We see batteries and firming assets like that on our balance sheet. I think if that's your question, I would see them on a balance sheet, not recycling those sort of assets. They're our trading assets. They're a proprietary asset for us. I think that will go a long way for building in profitability into the future.

Yes. Okay. I appreciate that. May I ask a subsidiary question, which is more on the modeling front. Looking at the contribution from Tilt, within the earnings, it's like a $46 million contribution from associates. But then at the EBIT line, it's a minus 6. I'm just -- given the development of renewables is a big part of the go-forward upside, I just wonder if you could clarify how that accounting works for me.

So Rob, so there is a gain within a derivative there within the Tilt. So when we actually get to the P&L we effectively normalize it out of that position.

Next up, we have another question from Dale Koenders from Barrenjoey.

I'm just wondering, when we look at quite a strong performance in the first half from gas trading and origination margins and consumer electricity margins. You've called out the shift in tariffs and cost recovery. Do you think that the number you've reported in the first half for those 2 margins is indicative of a forward level on a mid-cycle basis? Or are there any sort of one-offs or further cost recovery we should be anticipating in the next couple of years?

So I'm just trying to pick apart your question there. So are you asking the question in terms of margins into the second half or into '25, what's -- just so I'm clear on the question.

Well, as we go into the second half and '25, I'm just wondering, should we anticipate that the strong level of performance from those consumer margins repeating or were they one-offs? Or is there more cost recovery to come, how you think about the outlook.

Look, I think if you look at our updated guidance. So that would guide to a slightly lower second half than first half. So there will be a little bit coming back out, but not a lot. I think you can -- to assume that the second half is broadly similar. It might come up a little bit through a little bit of churn and so forth that we saw in the first.

So then -- and that was really the second part of the question. When we look at the pullback from full year guidance implied in the second half, is that just the cost inflation and a bit of margin coming off plus electricity prices? Or are there other headwinds or moving pieces in the earnings of the business we should be thinking about?

No, I think that's largely it. I mean there's not a lot of difference between the halves really. Ultimately, summer will determine how the second half plays out. I think we've had a really strong first half. We're driving the business really hard for a good, strong second half as well. I think if you asked me that question a few months' time post summer, I'd be able to give you a different answer, but we still got a few months to play out. Asset available has been really strong. Reliability of the fleet has been great. So for me, that will ultimately go to a strong second half.

Next up, we have another question from Mark from JPMorgan.

Can you talk about what specific initiatives in the maintenance program have been implemented to increase availability of the thermal fleet. What have you changed to improve availability of your assets?

Markus?

Yes, I think we have started and I think we elaborated on this. I think there was more maintenance on our precipitators, we have enhanced our mill program and invested in this. So that has also contributed to less DER rates. We had also a critical spare part program in order to shorten the outages. And then we have put quite some CapEx also during major outages in part parts which were failing ID fans and so on. There were specific programs where we have invested more and where we maybe have also led some investment in the past. So there is a clear and this is paying now off.

Yes. And I think that spend has been, Mark. I think it's Mark, over the last 12 to 18 months, at least, maybe even 2 years, very directed spend. I think we spent a bit of time talking about that either Investor Day or August. And so I think the direction of the spend has been right. But also importantly, it's about at the same time, putting spend into the flexibility of those assets. Those assets are flexed now that we're getting Bayswater up to 70% Loy Yang A, 40%, and we're working to get more flex out of those assets. So that's the next phase over the next 12 months as well because being able to bring those assets up and down with the same maintenance and managing that maintenance on the way through is going to be really important as well.

Okay. Just on the flexibility side, like clearly, black and brown coal-fired power plants aren't meant to be turned on and off during the course of the day. I mean is there any potential impact on reliability, on asset lines or anything like that with adjustments to flexibility?

I think that is a good question, and we ask this ourselves as well. I think we have Hughes and Uniper as well. And I think there's also a specific power plant which our engineers have visited, Ratcliffe, the power plant, which is also most probably more in the age of Liddell, but they are running it very flexible. So and we had a very intense dialogue with them, what is the increased wear and tear. And at the moment, to be honest with you, we don't see any severe wear and tear. For sure, when we have minor outages and major outages, we look at critical parts and look more carefully where we would discover wear and tear, but at the moment, it has not increased our OpEx.

But also just to be clear too, it is within the design parameters of these units. So it's not outside of design parameters and we'll continue to work to make sure -- and I think, Mark, you use the question turn off. We don't -- we certainly do not turn them off. We're certainly just flexing them down over the middle of the day and then bringing them back up. And you can see that we've been doing that quite successfully now. Over 6 months, you can watch it through the NEM as it's happening, and we can make decisions on those units where we see both the weather going the day, demand of the day and solar. Because it was just as a note, it was quite an interesting period over sort of, I don't know, August, September, October, where we saw from a weather perspective, much higher levels of radiation, which therefore, much bluer skies. We saw much higher solar and then that sort of has swapped around as well. So weather also has an impact on how solar performs in the market. So we use all those sort of factors from a trading and an operational perspective to determine what we're doing.

Next up, we have another question from Reinhardt from Bank of America.

I've just got a follow-up question on Loy Yang. We can obviously see that you did run that pretty flexibly going into Christmas. But it looks like you would have still been caught out doing some of those low mid-day price periods. Sort of the net derivative position in the first half didn't look all that bad. Can you comment on whether that state government support arrangement that you had actually kicked in? I mean that sort of $30 per megawatt hour, that's pretty low. I would have thought that the floor probably kicks in?

No. But that's definitely not the case. Our structured transition agreement has nothing to do at the moment, hasn't kicked in for this. It's an economical insurance. I will not disclose the details of this agreement, that's clear. But this performance of our Loy Yang power station has nothing to do with any of these mechanisms, which we have agreed with the Victorian government. It is really what we have hedged forward. We were long. Our portfolio is set up. We always said Victoria is long. So we have hedged quite some energy there. So that has led that -- and how we set up the portfolio in Victoria has led to that we have not suffered when the prices were relatively negative during the day. So we still were not losing money. But we have -- as you said, we have flexed down Loy Yang quite successfully. And I think we are now -- and we indicated this or Damien indicated this in this slide. We will further invest in flexing it down by going down even to 230-megawatt per unit. So in order to cope with this flexibility, but Damien?

Yes. And just to add to that, I mean, if you're watching the market back carefully, we did have over sort of the new year period, we had a tube leak in one of the units, prices were negative. We didn't need to get in the market, you take it out then you bring it back in within 3 or 4 days. So again, the ability to make those decisions and having all the assets around you is incredibly important and valuable as well.

Next up, we have Rob Koh again from Morgan Stanley.

Hello again. Can I just make sure I understand Slide 30, which is the forward curve slide. That those averages that you're showing there, they're like kind of last 12-month type averages. And so this is we're looking at this to look at your progressive hedging and what remains to be done. The retail regulator, the AER uses a different averaging period, right? I just want to double check that we're not confusing 2 separate things, yes.

So what we're doing there is they are the market observable ASX, effectively the quarterly curves there. They're the life-to-date volume-weighted curves. So again, that is the observer ones on the ASX.

And maybe just to go to your question then on the DMO. So the DMO is over a 2-year average with Victoria's over the 1 year on average.

Oh so the Vic's now on the 1 year, right. Okay. That's good. May I ask another one, just maybe directly this question to Ms. Egan, just on the new product, the EV night saver, which, I guess, makes all kinds of portfolio benefit sense for AGL and hopefully a nice customer win. Can I maybe just ask for your comments on take-up on that and a bit of a background to it.

Yes. Thank you, Rob. Yes. Look, we've seen really strong take-up on that product with our EV propositions. We're trialing a lot of different options for customers being it's such an emerging area. We've done some smart charging trials, which have been really strong. I think for now, this type of tariff that just incentivizes customers to charge during low-demand periods overnight has proved really popular. So we got great take-up really quickly, and we're continuing to see that grow.

Last question now from Nik Burns from Jarden.

And thanks for the detail around the project pipeline and time line on Slide 14. Can I just ask about the implications of the expanded capacity investment scheme on your plans? Has it changed your thinking around scope, location or timing of your investments? And I assume you expect to participate in the CIS tender process. I'm just wondering what happens to your plan if you're not successful in a particular tender. Does it just shift your time line to the right.

Look, I'll take that one. So look, the CIS, whilst there's still -- we haven't yet got the detail as to how the financial mechanism the CFD will work in terms of the floors and caps and so forth. But really my take of what that is doing is driving renewables into the marketplace. If it has the outcome of also helping planning and connection. I think that's a net positive to the market. We will always assess our projects on an economic basis with and without those sort of mechanisms in place to ensure that we're comfortable before we take an FID. So it would depend on the project. I think something like a long duration story, like a pumped hydro and there are certain assets in there that maybe will be more suited than others. But we'll continue to work through that and where the assets line up nicely I think every quarter, they're going to put out a form of auction. We'll see where it makes sense for us to be in that or not similar to what we did with the Liddell Battery and LTESA.

There are no further questions, this concludes our Q&A session. Thank you.

Thanks all.