AGL Energy Limited

Thank you for standing by and welcome to the AGL Energy 2024 half-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 Nix. 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. I'd like to begin by acknowledging the traditional owners of the land I'm on today, the Gadigal people of the Aurora 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, Joe Egan, Chief Customer Officer, and Marcus Brockoff, 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 gigawatt 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 Luoyang A. Turning now to the financial results. Overall, I'm very pleased with the improvements we've 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 26 cents per share has been declared, unfranked, based on the targeted 50% payout ratio of underlying NPAT for the total FY24 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 our growing telecommunications business. We've also maintained positive customer advocacy and improved strategic MPS, finishing the half with a score of plus seven 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 a 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 FY24 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 FY23, noting that this is largely attributable to low-impact injuries. We continue to focus on preventing injuries across the organisation, and the next slide will cover measures undertaken to help reverse the trend of this metric. I've already spoken to our strategic MPS 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 the 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 FY24 and FY25. 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 two-year customer support package utilised 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 specialised empathy training providers for our call centre and communication staff, delivering programs to improve First Nation customer accessibility and increasing financial counsellor 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 two 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 FY27 four-year targets. Starting with the top row, I've already spoken to our strategic MPS 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 four-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. Decentralised 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 three major industrial clients seeking to be located on or connected to one of our three energy hub sites. We have strong momentum across our strategic priorities to help customers electrify and decarbonise. 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 recognises 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 decarbonisation and scale, and AGL continues to maintain its leadership in the commercial solar space. Beyond solar, we've recorded a material increase in contracted CNI 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're 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 now 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 and innovative products in the market with an average time from its 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 decarbonisation pathway where possible. We're 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 Ryde Park Wind Farm project in New South Wales, under our recently announced PPA with TILP Renewables. We also entered into renewable link purchase agreements with CSL and MB&Co, and as announced last August, signed a nine-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 Luoyang 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 five gigawatts of renewable generation and firming assets by 2030. As mentioned last June, we continue to source energy and capacity as efficiently as possible by our combination of owned and controlled assets, joint ventures and partnerships, including our investment in tilt renewables, as well as by off-takes and decentralised energy. Importantly, our 5.4 gigawatts of targeted new projects by 2030 is more than covered by almost one 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 our growing portfolio of der assets and external offtake options this slide provides a good blueprint of a 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 off-takes and DER. And for the component which is expected to be developed on balance sheet, AGL expects to deploy $3 to $4 billion by FY30 and an additional $5 to $6 billion by FY36. 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 two 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 daytime 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 three key areas to respond to Australia's changing energy markets, as well as optimise realised merchant pricing outcomes. Firstly, a 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, our ability to flex our thermal fleet enables us to manage the impacts of lower customer demand or negative pool pricing during periods of daytime 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 three-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 three main revenue drivers on the left-hand side, being capacity, arbitrage and efficacy. On the right-hand side, you can see that capacity revenue is the largest component of the indicative lifetime revenue stack. We expect to derive 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 two-hour duration grid forming battery at a 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 ALTESA 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 costs, 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 batteries. 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 daytime periods, where wholesale spot pricing is typically low or negative. The battery is also expected to contribute positively to portfolio value by ensuring we optimise the sourcing of capped 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 FTAS 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 two-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 decentralised energy resources play in improving load profile management in South Australia. DER provides flexibility that can support a grid with higher penetrations 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' homes 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 incentivises 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 Loyanga 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 Loyang 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 Loyang A, Progress to lower each unit to approximately 230 megawatts is on track for completion in FY24. 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 26 cents per share, unfranked, 18 cents 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 FY24 full year dividend. The proposed FY24 dividend is at the bottom end of our revised payout range of 50 to 75% of underlying end part. And as we preserve capital towards the transformation of our business, in particular, the construction of the $750 million Liddell battery over the next two 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 FY24 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 two non-recurring 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 pull 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 Luoyang 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 three terawatt hour reduction in generation and $104 million worth of net reduction in margin and OPEC 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 energies 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 three 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 favourable movement you can see for depreciation and amortisation relates to the customer market's digital assets reaching their end of depreciable life. Last August, we mentioned that we would expect an uplift of $40 to $50 million in depreciation and amortisation for FY24, based on the increased investment in our thermal assets and retail transformation programs. as well as the Torrens Island and Broken Hill batteries coming online. Please note that we now only expect a $20 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 two 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 non-cash. 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 non-recurring savings, largely associated with the closures of the Liddell Power Station and the Camden Gas Project, as well as the divestment of the Murrumbah 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 high 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 and other 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 batteries. 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 FY23, 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 number one position of brand awareness in energy. and maintain other strong customer metrics, including favourable 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 five 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 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 offset 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 two to three years, this will be the cash conversion metric that we will be monitoring and reporting going forward given it is normalised for the lumpy nature of rehabilitation spend. As mentioned last June with our revised strategy, we're focused on de-risking 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 US 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 five and seven 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 FY26. 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 de-risked maturity profile and stronger liquidity position have resulted in higher borrowing costs. Moving to the right-hand side, we achieved a $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 to $4 billion on balance sheet capital by FY30 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 FY25 prices have moderated in recent months, stabilising lower than FY24, they are still materially higher than FY23. With a few weeks of summer remaining and another five months left in FY24, it's time to comment on the pricing outlook for FY25. On the left-hand side are the observable volume-weighted New South Wales swap prices for FY23, 24 and 25. The FY25 curve is the observable volume-weighted average price as at February 2024, with several months still to play out. The curves for 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.