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 Nicks. Please go ahead.
Good morning, everyone. Thank you for joining us for the webcast of AGL's 1st 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 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 1st 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 GW since our inaugural Climate Transition Action Plan was released in September 2022. We also now have 800 MW of new grid-scale batteries in operation, in testing, or under construction, adding to our 130 MW storage and 2.6 GW renewable generation portfolio. The 250 MW Torrens Island Battery became operational in August.
The 5 MW Broken Hill Battery is currently in testing, and construction has commenced on the 500 MW 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've seen across the business. Our stronger 1st 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 AUD 399 million, AUD 312 million higher than the prior half. An interim ordinary dividend of AUD 0.26 per share has been declared, unfranked, based on the targeted 50% payout ratio of underlying NPAT for the total FY 2024 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 NPS, finishing the half with a score of +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 at 1st half 2023. 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 2024 financial guidance ranges to the upper end, in line with a strong 1st 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 2023. 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 +7, an improvement on +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 AUD 70 million in FY 2024 and FY 2025. This is in addition and complementary to the Government Energy Bill Relief Fund and includes up to AUD 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 AUD 35 million of the AUD 70 million two year Customer Support Package utilized in the 1st half to deliver assistance to customers who need it the most. The greatest portion has been allocated to direct financial support, with AUD 20 million in proactive bill credits and AUD 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 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 FY 2027 four 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 MW reported for the next metric comprises the Torrens Island Battery, Broken Hill Battery, and Liddell Battery, totaling 800 MW, as well as the 178 MW 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 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 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 novated 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 while 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 +40. This is 38 points above the tier one average and 21 points above the tier two 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 GW to 5.8 GW since August, and we now have 800 MW 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'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 certificate source 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 agreements with CSL and NBN 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 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 GW 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 GW of targeted new projects by 2030 is more than covered by almost 1 GW of nameplate capacity in operation, contracted in testing and under construction, our existing 5.8 GW development pipeline and access to Tilt Renewables development pipeline of over 3.5 GW, as well as our growing portfolio of DER assets and external offtake options. This slide provides a good blueprint of the 5.8 GW development pipeline in terms of targeted financial investment decision dates.
For context, our current development pipeline is almost double the 3.2 GW 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 GW of early stage opportunities, including offshore wind south of Victoria. We also have access to the Tilt development pipeline via our 20% investment. As previously disclosed, of the 12 GW ambition, approximately 5.5 GW is expected to be funded on AGL's balance sheet, with the remaining approximately 6.5 GW expected to be procured by joint ventures, partnerships, third-party offtakes, and DER.
For the component which is expected to be developed on balance sheet, AGL expects to deploy AUD 3 billion-AUD 4 billion by FY 2030 and an additional AUD 5 billion-AUD 6 billion by FY 2036. 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 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, 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 1st half performance of the Torrens Island Battery.
Pleasingly, construction was completed within budget expectations, and the battery delivered AUD 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 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 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 MW, two-hour duration, grid-forming battery at the 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 AUD 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 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 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 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 decentralized 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, 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 AUD 12 million of portfolio benefits combined in the 1st half, through lower coal usage and avoided uneconomic running. We have almost 3,000 MW 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 2nd phase of our flexibility upgrade program will target an additional 30 megawatts for each unit, subject to further evaluation.
At Loy Yang A, progress to lower each unit to approximately 230 MW is on track for completion in FY 2024. Now over to you, Gary.
Thank you, Damien, and good morning, everyone. This slide shows an overall summary of our financial result, which I'll cover in more detail on the following slides. We are pleased to report an underlying profit after tax of AUD 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 AUD 0.26 per share, unfranked, AUD 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 2024 full-year dividend.
The proposed FY 2024 dividend is at the bottom end of our revised payout range of 50%-75% of underlying NPAT, and as we preserve capital towards the transformation of our business, in particular, the construction of the AUD 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 FY 2024 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 cashflow and improvement in our net debt position, both of which I'll discuss shortly. We also note that operating free cashflow 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 cashflows 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 1st half of last year, accounting for AUD 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 2nd item reflects the earnings impact of the closure of the Liddell Power Station in April 2023, which led to a 3 TWh reduction in generation and AUD 104 million worth of net reduction in margin and OpEx savings. Moving further to the right, the c ustomer 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. While initially a modest contribution in the half, we're pleased that the Torrens Island Battery contributed AUD 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 favorable movement you can see for depreciation and amortization 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 AUD 40 million-AUD 50 million in depreciation and amortization for FY 2024, 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 AUD 20 million-AUD 30 million uplift, attributable to the delay in spend of the 1st 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 AUD 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 Moranbah Gas Project.
Moving to the right, the impact of CPI is expected to be AUD 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 AUD 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 Battery. An increase of AUD 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, while operating costs are an increase on FY 2023. 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 AUD 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 maintained other strong customer metrics, including favorable churn spread to rest of market at 5.1 percentage points. 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 One 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 AUD 200 million of the total estimated AUD 750 million construction cost, as well as approximately AUD 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 AUD 400 million and AUD 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 1st half, with underlying operating cash flow of AUD 840 million, AUD 735 million higher than the prior half, largely driven by improved earnings and lower margin calls. Operating free cash flow also improved by AUD 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 normalized 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 a 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 1st half with a new Asian term loan, secured for a total of AUD 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 FY 2026. Our liquidity position has also improved to almost AUD 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 AUD 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 AUD 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 AUD 3 billion-AUD 4 billion on balance sheet capital by FY 2030 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.
While FY 2025 prices have moderated in recent months, stabilizing lower than FY 2024, they are still materially higher than FY 2023. With a few weeks of summer remaining and another five months left in FY 2024, it's too early to comment on the pricing outlook for FY 2025. On the left-hand side are the observable volume-weighted New South Wales swap prices for FY 2023, 2024 and 2025. The FY 2025 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.
Thanks, Gary. Before I conclude.
Hi, Damien.
A quick recap on our past six 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. 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 2024 guidance. Encouragingly, as mentioned earlier, we've narrowed our FY 2024 financial guidance range towards the upper end, in line with a strong 1st half performance.
FY 2024 financial guidance reflects the drivers you can see on this slide, which are consistent with what we disclosed at the FY 2023 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.
We will now open for questions. To ask a question, press the star key followed by the number one. Can I please ask you to mute any other devices before asking questions over the conference line? We will take one question at a time, and if time permits, we will circle back for any further questions. The first question comes from Dale Koenders from Barrenjoey. Please go ahead, Dale.
Morning, and thanks for taking the question. Just regarding slide 30, where you've gone to the effort of pointing out the weighted average price versus traded forward curves, should we be implying that the differential between the volume-weighted average price is more indicative of the impact to FY 2025 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 shut Liddell, and also starting to implement these battery programs? Thank you.
Morning, Dale. Thanks for the question. Look, we are absolutely focused on delivering FY 2024. 2024, it's been a really strong half of the year. We are focused on delivering the 2nd half. At this point in time, we won't be providing guidance into FY 2025 until we get round to, you know, the next August results. What those curves are doing is showing exactly what you can see in the marketplace today. You know, 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, you know, performance of our plant, performance of the assets, and importantly, the flexibility within our drive over this period of time.
Thank you, Dale. Next question comes from Mark Busuttil from JP Morgan.
Hi, everyone. One number I was particularly interested in was your realized prices to wholesale customers. I think you realized AUD 84 in the half, the last half was AUD 90, but historically it's sort of been around that AUD 70-AUD 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 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, you know, we're constantly resetting our book and prices through the customer base, you know, certainly in the C&I level. Over the course of the last year, we've had, you know, some good recontracting of our customer base in both the elec and the gas space after what, you know, the prior year was a, 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, it, it...
Without giving a direct answer, what we're seeing is, you know, 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?
Yeah, look, last June, I think we announced about 100 PJs of gas that we procured, and that provides us sufficient gas out to roughly 2027. That means that we're continuing to source gas, we're continuing to source through a number of players domestically. And, you know, you still have some of the lower cost gas in our book as well today, which also rolls out to 2027. But Markus, do you want to just add to that comment?
... Yeah, 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, to previous periods. But it is 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, to this lower procurement cost.
Fabulous. Thanks, [Team] Appreciate it.
Thanks, Mark.
Thank you, Mark. Next up, we have Ian Myles from Macquarie.
Hey, guys. Can you maybe just on the, the book which 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?
So just so clear on your question, Ian, of the 5.8 gigawatts, you're asking how much we have development approval?
Yeah, how much-
Okay, go on.
How much actually has got genuine approval that you could go make an FID decision versus you're still going through EIS approval processes?
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 the, 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. You know, obviously, the Liddell, the Liddell Battery, we obviously clearly have planning for... You know, you saw, and I saw your note a couple of nights ago on Bowmans as well, so they're the things we'll continue to work through. But the short answer is, and Markus might just add to it, we don't, you know, the planning processes continue to proceed.
As we execute on those planning and work with the communities, then we move forward to FID if it makes sense commercially. But, Markus?
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. We believe the next battery, where we take FID, will be in Queensland, a specific battery which we are, which is at the, at the mature approval stage. Then, as you have seen also, I think Bowmans Creek have received for phase I approvals of 58 turbines, and we are now going for another approval stage of another 21 in order to enlarge the footprint of the, of the, of the wind farm.
I think, Ian, the way to think about this table, it's to provide the market, you know, an update, and every six months we'll be providing an update. As that continues to evolve, you know, new assets will be coming on, and also just an update of where we see, you know, both planning and FID processes at.
That, that's great. Can I just, to extend that, you talked about the battery, and you gave us some indication of what the Torrens Island Battery earned, AUD 7 million . I think that's post-tax, so circa AUD 10 million pre-tax. Is that consistent with what you would expect, given I think you sort of talked about 11%-13% returns on these style of projects, or has it got a bias? I guess why would it have a bias?
So, Ian, that was the first three months of operation. You know, really pleased in terms of what it delivered in terms of the investment thesis. You know, and it's probably at the top end of where we thought it would be for those three months, but again, it is three months in.
Mm-hmm.
So, we, you know, we wanted to make sure really clear that the asset was performing. It goes to obviously making a decision on the Liddell Battery. But yeah, absolutely delivering what we expected it to do, you know, on both FCAS, arbitrage, and also, capacity being the largest part.
Thanks, guys.
Thanks, Ian. Next up, we have Gordon Ramsay from RBC.
Oh, thank you very much. I'd just like to focus on cost. Just referring to your slide on CapEx costs, where you've given a forecast for sustaining CapEx in FY 2024, seems to be lower than your guidance of AUD 400 million-AUD 500 million per annum. Does that imply that sustaining CapEx will be higher in future years, FY 2025 and onwards?
Yeah, so what we've done there is, you know, firstly, we've put in what the sort of forecast is there for 2024, and you can see how that plays through. And yes, that is sort of at the lower end, but the AUD 400 million-AUD 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, you know, within that band, and it really... You know, we're trying to sort of say, going forward, you should expect it will be in that AUD 400 million-AUD 500 million range, but it will be really dependent on the activity in that particular year.
Just to add to that-
Thanks.
Sorry, oh, Gordon, just to add to that, it's when those major outages take place is when, you know, you see you probably—if there's more than one, then it'll be at the top, at the upper end. If it's one, it'll be at the lower end.
Yeah, your operating costs are up 14% year-on-year. Is there anything we should be looking at going forward that is an area of risk for higher costs, FY 2025 onwards on the operating side?
Yeah, 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 three buckets. The first is, there's been, you know, 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, you know, 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 AUD 70 million, of which AUD 35 million of that was delivered in the 1st half.
So we do expect that some of that cost will come out of our cost base going forward. The next bucket's around the business transformation, and, you know, 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, you know, 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.
Okay, thank you.
Thanks, Gordon. Next up, we have Reinhardt van der Walt with Bank of America.
Hi, good morning, folks. Thanks for taking my question. 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 1st half. Normally, we see a bit more churn in the 2nd half. Do you think we're at a stage now where barriers to entry maybe come down a little bit, especially because that duck curve is starting to slide back down again?
Thanks for the question there. Look, we're really pleased with the overall result 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 normalize. So I'm confident 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. Thanks. And then just if you could 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 maybe looked like an FY 2022 kind of figure. I appreciate that you've managed to use flexibility to your advantage on the wholesale cost side, but I mean, is the gas retailing industry just sort of structurally tight, sort of low competition at this stage?
I think broadly we're seeing competition normalize. Obviously last year we had, you know, some unusual events with the market suspension and then, as I noted, you know, really high competition off the back of those, price increases. But what we're seeing in market now is just more normal, consistent levels.
Mm-hmm.
I think just adding to that, it's going to be going into the future around, you know, access to gas into this market going forward. You know, we've obviously contracted our gas book out to 2027. 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.
Got it. Thanks.
Thanks, Reinhardt. Next up, we have Rob Koh from Morgan Stanley.
Good morning. Congratulations on the result, 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 two-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 firming 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 2nd part of this question is, even though this is very different to a merchant battery, does this increase the likelihood that you could look at capital recycling for it? Thanks.
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 factor, Rob, is exactly what you are saying. It's around this, it's around the 50%.
I think, Rob, what you're going to see in this market, the market will continue to evolve. You know, I think through both our automation and our technology around battery trading, we continue to evolve that space to sort of maximize the making 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, would we look to capital recycle 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 our proprietary assets for us. I think they will go a long way for, you know, building in, you know, profitability into the future.
Yeah. Okay, thank you very much. 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 AUD 46 million contribution from associates, but then at the EBIT line, it's a -AUD 6 million. I'm just given that 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?
Yeah. So, Hey, Rob. So there is a, 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.
Yeah, righto. Thanks very much.
... Thanks, Rob. Next up, we have another question from Dale Koenders from Barrenjoey.
Hi, guys. Thanks for the question. I'm just wondering, when we look at quite a strong performance in the 1st half from gas trading, and origination margins and consumer electricity margins, you've called out the, the shifting tariffs and cost recovery. Do you think that the, the number you've reported in the 1st half for those two margins is indicative of, of a forward level on a mid-cycle basis, or are there any sort of one-offs or, 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 2nd half or into 2025? What's... Just so I'm clear on the question.
Well, as we go into the 2nd half and 2025, I'm just wondering: should we anticipate that the strong level of performance-
Oh, okay.
-from those consumer margins repeating, or, you know, were they one-offs, or is there more cost recovery to come?
No.
How do you think about the outlook for-
Look, look, I think if you look at our, our updated guidance, so that would guide to a slightly, you know, slightly lower 2nd half than 1st half. So there'll be a little bit coming back out, but not a lot. I think you can to assume that the 2nd half is broadly similar. It might come off a little bit through a little bit of churn and so forth, that we saw in the 1st.
that was really the 2nd part of the question: when we look at the pullback from full-year guidance applied in the 2nd 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, I think that, that's largely it. I mean, there's not a lot of difference between the halves, really. Ultimately, summer will determine how the 2nd half plays out. You know, I think we've had a really strong 1st half. You know, we're driving the business really hard for a good, strong 2nd half as well. You know, I think you ask me that question in a few months' time, post-summer, I'd be able to give you a different answer, but, you know, we've still got a few months to play out. Asset availability's been really strong. Reliability of the fleet's been great. So, you know, for me, that will ultimately go to a strong 2nd half.
Okay, thanks.
Thanks, Dale. Next up, we have another question from Mark, from JP Morgan.
Hi, everyone. 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?
Yeah, 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 derates. 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 parts which were failing, ID fans and so on. There were specific programs where we have invested more and where we maybe have also lacked some investment in the past. So there is a clear... And this is paying now off, yeah.
Yeah, and I think that spend has been, Mark, I think it's Mark, over the last, you know, 12-18 months at least, maybe even two years, you know, very directed spend, and I think we spent a bit of time talking about that, either in Investor Day or August. And so, you know, I think the direction of the spend's been right, but also importantly, it's about putting spend into the flexibility of those assets at the same time. You know, those assets are flexed now that we're getting. You know, Bayswater, we're up to 70%, Loy Yang, 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 gonna 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, on reliability, on asset lives, or anything like that with, with adjustments to flexibility?
No, I think, you know, that is a good question, and we asked this ourselves as well. I think we have used then Uniper as well, and I think there is also a specific power plant which our engineers have visited, Ratcliffe. The power plant, which is, also most probably more on the age of Liddell, but they are running it very flexible. And we had a very, 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, you know, 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, that has not to and has not increased our OpEx.
Also just, just so we're clear, too, it is within the design parameters of these units.
Yeah.
So it's not outside of design parameters, and you know, we'll continue to work to make sure... and I think, Mark, you used the question, turn them off. We don't, we certainly do not turn them off. We're certainly just flexing them down over the middle of the day, then bringing them back up, and you can see that, you know, we've been doing that quite successfully now over six months. You can watch it through the NEM as it's happening, and we can make decisions on those units where we see both, you know, the weather going in the day, demand of the day, and solar.
Because it was, you know, just, 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, has swapped around as well. So weather, also has an impact on, you know, how solar performs in the market. So we use all those sort of factors as, from a trading and an operational perspective, to determine what we're doing.
Great. Thank you so much. Appreciate it.
Thanks, Mark. Next up, we have another question from Reinhardt from Bank of America.
Yep. Thanks, James. I've just got a follow-up question on, on Loy Yang. You can obviously see that you did run that pretty flexibly, going into Christmas, but it looks like you would have still been caught out during some of those low midday price periods. The sort of the net derivative position in the 1st half didn't look all that bad. Can you comment on whether that state government support arrangement that you had actually kicked in?
No.
Because, I mean, at sort of AUD 30 per MWh, that's, that's, 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, it hasn't kicked in for this. It's an economic insurance. I will not disclose the details of this agreement. That's clear. But, you know, this performance of our Loy Yang Power Station has nothing to do with any of this, mechanism, which we have agreed with the Victorian Government. It is really what we have hedged forward. We were long... We, you know, our portfolio is set up. We always said Victoria is long, so we have hedged quite some energy there. So that has led. And, and how we, how we set up the portfolio in Victoria has led to, to that we have not suffered when we- when prices were relatively negative during the day.
So we still, we are 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 MW per unit. So, in order to cope with this flexibility, but Damien?
Yeah, and just, just to add to that, I mean, if, if, if you're watching the market that carefully, we did have over sort of the New Year period, we had a tube leak in, in one of the, the units. Prices were negative. We didn't need the unit in the market. You take it out, then, you bring it back in within, you know, three or four days. So again, the ability to make those decisions and having all the assets around you is incredibly important and valuable as well.
Yep, got it. Thanks.
Thanks, Reinhardt. 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. 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. And the retail regulator, the AER, uses a different averaging period, right? I just want to double-check that, we're not confusing two separate things, yeah?
Yeah. Hi, Rob. 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, they're just the observable ones on the ASX.
And maybe just to go to your question then on the DMO. So the DMO is over a two year average, with Victoria's over the one year, on average.
Yeah. Oh, so the Vics now are on the one year. Right.
Vics-
Thank you. Appreciate that.
Yeah, Vic's been at one year for a while.
[crosstalk] Okay, okay, okay. Thank you. That, that's, that's good. May I ask another one, just maybe directing this question to Ms. Egan, just on the new product, the EV Night Saver, which I guess makes all kinds of portfolio benefits sense for AGL and hopefully a nice customer win. Can I maybe just ask for your comments on, on take-up on that and a bit of the background to it?
Yeah. Thank you, Rob. Yeah, look, we've seen really strong take-up on that product. With our EV propositions, we're trialing a lot of, you know, different options for customers, being, you know, 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, you know, during low-demand periods overnight, has proved really popular. So we got, you know, great take-up really quickly, and we're continuing to see that grow.
Cool! Sounds good. Thank you very much.
Thanks, Rob. Last question now from Nik Burns, from Jarden.
Hi, yeah, thanks, everyone. Thanks for taking my question, and, thanks for the detail around the project pipeline and timeline 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 timeline to the right? Thank you.
Look, I'll take that one. So look, you know, the CIS, while there's still, you know... We haven't yet got the detail as to how the financial mechanism, the CFD, will work in terms of, you know, the floors and caps and so forth. But, you know, really my take of what that is doing is driving renewables into the marketplace. If it has the, 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, you know, economic basis, with and without those sort of mechanisms in place, to ensure that, you know, we're comfortable before we take an FID. So it would depend on the project.
I think something like a, you know, a long-duration storage, like a pumped hydro, you know, and there's certain assets in there that maybe will be more suited than others. But we'll, you know, we'll continue to work through that, and where the assets line up nicely, and 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.
That's great. Thank you.
As there are no further questions, this concludes our Q&A session. Thank you.
Thanks, all.