AGL Energy Limited

Thank you for standing by and welcome to the AGL Energy 2023 full year results briefing conference call. All participants will be in listen only mode. There will be a presentation followed by a question and answer session. I would now like to hand over the conference to Managing Director and Chief Executive Officer Mr Damien Nix. Please go ahead.

Good morning everyone, Damien Nix speaking. Thank you for joining us for the webcast of AGL's full year results for the financial year 2023. 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 merging. 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 Brockhoff, Chief Operating Officer. I'll get us started and we'll have time for questions at the end. Before I cover the results, I wanted to recap a refreshed strategy and our accelerated decarbonisation plan, which we announced last September and discussed in greater detail at the Investor Day in mid-June, which has collectively reset market confidence and the outlook for AGL. We have a clear strategic plan to connect our customers to a sustainable future, helping them to decarbonise the way they live, move and work, as well as to transition to a lower carbon energy portfolio, underpinned by an ambition to add approximately 12 gigawatts of new generation and firming by the end of 2035. AGL has a leading and trusted brand, and our customer markets business is positioned well to navigate, grow and thrive in a complex energy retailing market, pursuing the focus areas outlined on the left-hand side of the screen. Importantly, the delivery of our 12 gigawatt ambition of new renewable and firming assets is underpinned by strong development optionality, and the near-term focus for integrated energy will be the execution of our expanded 5.3 gigawatt development pipeline, all while delivering operational and trading excellence and maintaining safe operations. This is all supported by robust financial stewardship, most notably a refreshed capital allocation framework to prudently allocate capital to the transformation of our business, strengthen core operations and drive shareholder returns. First and foremost, I'd like to talk about our customers and address how we are supporting them through the current period of cost of living pressures. As Joe Egan, our Chief Customer Officer, mentioned at the Investor Day, we've committed to increasing our customer support funding to at least $70 million for the next two years. This is in addition 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. We're using advanced analytics to identify and proactively engage with our customers who may be facing financial hardship, offering them guidance and support at an early stage, as well as referrals to relevant government and consumer assistance programs. We are also investing in specialised training for our contact centre agents to improve the effectiveness of communications with customers facing financial hardship. Our strong collections performance in recent years should position us well to manage this challenging period. And we are drawing on learnings from the past. We have seen high energy prices to ensure that we can both support our customers and carefully manage our costs. Turning now to our full year results, which overall reflect a materially improved second half due to increased plant availability as we forecast at the half year. underlying profit after tax was $281 million, 25% higher than the prior year. The stronger financial result reflects higher wholesale electricity and gas pricing realised in earnings, partly offset by increased operating costs and lower generation volumes due to the prolonged outage of Luoyang A Unit 2, which was caused by a generator rotor defect and also the closure of the Liddell Power Station in April 23. Our statutory loss of 1.264 billion was impacted by 680 million of impairment charges due to the targeted early closure dates of our thermal assets and a negative movement in fair value financial instruments of 890 million. A final ordinary dividend of 23 cents per share has been declared, unfranked, bringing the total dividend for the 2023 financial year to 31 cents per share, an increase of 19% on the prior year. Pleasingly, customer markets recorded strong organic growth across both energy and telecommunications in a challenging year for the energy retailers. Up 56,000 customer services with our strategic net promoter score remaining in a healthy position of plus five. Despite the challenging start to the year in terms of fleet performance, we've certainly had a much stronger performance across the portfolio for the remainder of the year, recording an equivalent availability factor of 76.8%, which is higher than the previous two financial years, and the benefit of the investment and flexibility in our fleet is now clearly evident. At our Investor Day in June, we announced an expected uplift in earnings. We've maintained FY24 earnings guidance and I'll discuss this further at the end of the presentation. I'll also touch on market conditions in my closing remarks. As I mentioned at Investor Day, we are certainly building positive momentum across the business and the market. as we forge ahead with the transformation of AGL. And this slide demonstrates key highlights and achievements since we announced the outcomes of our review of strategic direction in September last year. I won't speak to all of these, but we'll highlight some key milestones. Starting from the left, last September, we announced a refreshed strategy in one of the most significant decarbonisation initiatives in Australia. This included the accelerated closure of Luoyang A, together with our ambition to supply 12 gigawatts of new generation and firming capacity by the end of 2035, which will reshape AGL's generation portfolio. Our inaugural Climate Transition Action Plan was endorsed by shareholders at the 2022 Annual General Meeting, and the board renewal process was completed following the election of four new highly experienced non-executive directors. Our executive team is also settled and all permanent appointments finalised following the appointment of Suzanne Falvey as Executive General Manager of Corporate Affairs in May. In April, we successfully completed a partial refinancing of our existing debt facilities and priced new long-term debt in the US private placement market. A key point to note is that these facilities included a $500 million green capex loan with five and seven year maturities, which will be used to fund existing and future low carbon projects. Our weighted average tenor of debt increased materially and we expanded our lending group of both domestic and offshore banks. Late April also marked the first key milestone of our key decarbonisation pathway, with the safe and respectful closure of the Liddell Power Station after almost 52 years of operation. This is expected to deliver an average annual emissions reduction of 8 million tonnes of greenhouse gas emissions from FY24. And finally, at our investor day in mid-June, we had the privilege of sharing further detail on our business strategies and our accelerated decarbonisation plan, driving market confidence in AGL's direction through the transition. We also announced an over 60% increase in our development pipeline to 5.3 gigawatts. A new 15-year power purchase agreement with Tilt for almost 180 megawatts from the Rye Park wind farm, as well as competitive gas agreements with Cooper Energy, Cenex and ExxonMobil. In line with our ambition to help customers decarbonise, we were excited to share our new e-mobility partnership with BP Pulse, providing EV customers with a convenient and integrated smart charging experience at home and when they're on the road. We also discussed how our leading position in commercial energy solutions is enabling us to capture value through energy as a service at scale in a rapidly growing market. The Corabri Almond Farm in New South Wales is a great example where AGL designed a low carbon microgrid and once constructed will help lower the customer's energy costs, provide price certainty and help improve their reliability and their sustainability outcomes. Overall, we're in a strong position to deliver on our long-term ambitions for AGL, supported by the strength of our underlying business, defined business strategies and decarbonisation plan, and highly experienced board and management teams in place. Moving now to our safety, customer and employee metrics. Disappointingly, our total injury frequency rate increased to 2.8 per million hours worked, reversing a downward trend since FY20. This was largely driven by an increase in low impact injuries. As always, the safety of our people and the safe and reliable operation of our assets is our number one priority. And in response to this increase, we've bolstered our focus on preventing common injuries before they occur and continue to encourage our employees and contractors to report all events that have the potential to cause an injury. I've already spoken to our strategic NPS score, which remains in a strong position at plus five. Encouragingly, we've had a material improvement in our employee engagement score across the business as we pursue a refreshed strategic objectives and improved operational performance. Turning now to a more detailed discussion on customer markets performance, which was underscored by services growth, a focus on value and improved customer experience. Total services to customers increased 56,000 to 4.3 million, delivered through both energy and telecommunications services growth. Pleasingly, discipline management and scaling of growth business areas, including telecommunications and business energy solutions, delivered a $96 million improvement to gross margin. We've also maintained our number one brand awareness position in energy and launched our new brand platform, Join the Change. Looking forward, we'll continue to responsibly grow our customer base whilst prudently managing margin and carefully responding to anticipated increase in customer activity in a high inflationary environment as customers respond to cost of living pressures. We also delivered improved retention with our churn spread improving to almost 4.5 percentage points, an excellent result supported by our continued focus on customer experience, evidenced by the lowest market complaint volumes and a leading digital app. Encouragingly, underlying operating costs are broadly stable, excluding the impact of net bad debt expense. Looking forward, as Gary will discuss, we do expect an increase in overall operating costs associated with higher revenue and its impact on net bad debt expense and the transformation of our business as well as the impacts of inflation. One of our key ambitions is to be a partner of choice for customers as they electrify and decarbonise. Significant progress has been made in our priority areas with good momentum achieved in accessing future value pools. We are already a leader in energy solutions for our residential customers and continue to build out our offerings. We've seen a material increase in carbon neutral services and continue to scale peak energy rewards program, Australia's largest demand response program. Moving to the next pillar, AGL is actively unlocking access to e-mobility. I've already mentioned our partnership with BP Pulse, which will provide charging solutions for our customers, whether they are at home or on the go. Our EV subscription service is currently the largest of its kind in Australia, and we are facilitating smart charging trials to learn more about the flexibility management and capture home charging consumption. We're also driving commercial decarbonisation at scale. AGL has maintained market leadership in the commercial solar space, delivering three times more solar than the nearest competitor. Beyond solar, we've seen a material increase in our commercial assets under monitoring and management. We've also executed multiple energy as a service arrangements, entered into long-term renewable supply deals and commissioned a two megawatt hour battery for essential energy. Underpinning this, we continue to invest in our customer base, our operations and our decarbonisation objectives to build a future ready business. Decentralised assets under orchestration is 47% higher, and the power of technology in automation is being harnessed with over 5 million transactions managed by artificial intelligence. Additionally, we continue to grow our decarbonisation portfolio, with customer markets green revenue now representing just over 20% of total customer markets revenue. Moving now to fleet performance and operations, headlined by stronger overall availability across a generation fleet. Starting on the left-hand side, commercial availability of our thermal fleet was up over five percentage points, despite the impact of the prolonged Luoyang A Unit 2 forced outage. This was driven by a reduction in forced thermal outages compared to the prior year, a testament to the ongoing investment to improving thermal fleet availability and reliability, particularly enhanced by preventative maintenance on mills, precipitators and boilers. We've also completed minimum load testing at Bayswater and Loyang A, which I'll speak to shortly. Volatility captured through trading was broadly flat in the prior year. As discussed in February, the first half was impacted by significant market disruptions and weather events driving forced thermal outages across the NEM. Volatility captured in the second half was 14 percentage points higher than the first, supported by improved coal fleet availability. Normalised for the Liddell Power Station, which closed in April, generation volumes were down 4.5% due to forced outages across the remainder of the generation fleet, marginally offset by high solar and hydro generation volumes. As mentioned at the beginning, we achieved an equivalent availability factor across the fleet of 76.8%, 2.3 percentage points higher than FY22, a good achievement overall considering the impact of the prolonged Luoyang A Unit 2 outage. As you can see on the right-hand side of the graph, our stronger EAF was driven primarily by a reduction in thermal unplanned outages in FY23, particularly in the second half, denoted by the purple shaded bars. I'll now take a moment to discuss our flexibility upgrades at Bayswater and Luoyang A, which are delivering operational, environmental and financial benefits for AGL. As intermittent renewable generation progressively enters the NEM, the ability to flex our thermal fleet enables us to manage the impacts of lower customer demand or negative pool pricing during daytime periods of peak solar generation. This is illustrated by the graph on the right-hand side, which shows a duck curve from a typical mild summer's day in New South Wales with high solar generation during daytime hours. Importantly, our Bayswater and Loyang-A units can be flexed down approximately 70% and 45% respectively of their nameplate capacities, and we have plans to lower the minimum generation levels of the Loyang-A units by a further 50 megawatts each in FY24. Flexibility upgrades at Bayswater delivered approximately $7 million of gross margin benefit in FY23 through lower coal usage and by avoiding uneconomic running. Approximately 60 kilotons of carbon emissions were also abated. A key point I'd like to highlight here is that we are not flexing the Bayswater and Loyang A units beyond their original design parameters, but rather investing in the technology and the assets we have to operate more efficiently as a response to the transition and renewables entering the market. Before I hand to Gary, I'll discuss where we stand today in relation to our four-year targets ending in FY27, which we shared at our investor day. Starting with the top row, I've already spoken to our strategic MPS score, which remains in a strong position, and we are progressing well to achieve our digital-only customers and our green revenue targets. Please note that the speed to market metric is measured against a May 2023 baseline, and hence we didn't report a performance outcome for this metric for 23. Similarly, the cumulative customer assets installed metric covers installations from FY24 onwards. Turning to the bottom row, I've already discussed our strong EAF result, and we'll be aiming to step this up to 88%. The 478 megawatts reported for the next metric comprises the 250 megawatt Tyrens Island Battery, 50 megawatt Broken Hill Battery and the 178 megawatt Rye Park Wind Farm PPA. Commissioning has commenced for the Torrens battery and the Broken Hill battery is also to be expected to be operational soon. And we look forward to both batteries coming online and contributing to earnings in FY24. And finally, the 1.1 gigawatts of reported decentralised assets under orchestration includes our contracts with the Portland and Tomago aluminium smelters, which both have demand response mechanisms and provisions attached. Now over to 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. However, we are pleased to announce underlying profit after tax of $281 million, 25% higher than the prior year. In addition, we are announcing that a final ordinary dividend of 23 cents per share has been declared, unfranked, bringing the total dividend for the 2023 financial year to 31 cents per share, an increase of 19% on the prior year. The statutory loss of $1.264 billion included $680 million of impairment charges due to the targeted early closure dates of thermal assets in line with our accelerated decarbonisation plan, as announced in September 2022. and a negative movement in the fair value of financial instruments of $890 million, primarily reflecting the impact of a drop in the forward prices for electricity on a net buy position. Let me first take you through group underlying profit in more detail. The stronger customer market's performance was largely driven by improved margin across our consumer and commercial and industrial portfolios. The increase in consumer margin was a result of focused customer value management, increased margin from growth businesses and higher demand for gas customers. The improved C&I performance, which includes large business customers and sustainable business energy solutions, reflects growth in this business segment and an improvement in project delivery. The increase in operating costs was predominantly due to increased net bad debt expense, which I will talk about in more detail on the next slide. Turning now to integrated energy, where there was some material movements across both our electricity and gas portfolios. As discussed at the half year, we had a challenging start to the year with the confluence of planned and forced outages across our coal-fired fleet, including the prolonged outage of Luoyang Unit 2. This resulted in short generation position compounded by significantly higher pool prices. Both FY22 and 23 were impacted by generation outages during market volatility with additional investment in availability and reliability expected to restore this loss margin in future years. We have also highlighted the earnings impact of the staggered closure of the Liddell Power Station with the first unit closing in April 2022 and the remaining three closing in April 2023, leading to a 2.3 terawatt hour reduction in generation and approximately $70 million worth of net reduction in margin and OPEC savings. Looking forward, once Liddell's workforce has been fully integrated with Bayswater, broadly speaking, we are expecting to see a similar dollar per megawatt reduction to earnings on the remaining five terawatt hours generated in FY23. Turning to the net electricity portfolio management bar, the improved availability of our generation fleet in the second half of the year, along with hedging and trading gains, was a key driver of our materially improved earnings compared to the first half. The strong performance of our gas portfolio, consistent with the first half, reflected higher global commodity pricing which increased the revenue for our gas portfolio. Additionally, AGL's prudent trading performance during this period of high oil prices and AGL's net long position, combined with gas haulage optimisation, is reflected in the $92 million positive movement. I will address the movements in operating costs and depreciation and amortisation in more detail on the following slides. Finally, higher finance costs were largely driven by a combination of an increase in rehabilitation provision interest costs and an increase in borrowing costs due to interest rates and more specifically the impact of the increase in base rates, partially offset by a reduction in onerous liabilities. Last August, we indicated there would be an increase in operating costs for FY23, roughly in line with CPI. Pleasingly, we have managed operating costs across the business broadly consistent with CPI increases, adjusted for the two non-recurring items on the left-hand side. As I did at the half-year result, I'd like to call out the small yet prudent uplift in cybersecurity spend to further bolster protection for our operations and customers in an ever-involving cyber environment. Looking forward, we expect an uplift in operating costs in FY24 in line with CPI, plus the three key items highlighted on the right-hand side. Firstly, we anticipate that the impact of increased competition and higher revenue from pricing outcomes will increase variable costs, such as net bad debt expense, as well as channel and marketing spend, coupled with additional costs associated with our customer support program. I'd like to emphasise, however, that our bad debt management and anticipated increases to retail market activity is broadly in line with FY18 and FY19. Affordability challenges arose, and as Damien mentioned, our strong collections performance in recent years should position us well to manage this challenging period. The second item relates to the ongoing transformation of our business, more specifically bolstering capability to deliver upon our ambition to add 12 gigawatts of new renewable and firming capacity, the transformation of our coal-fired power sites into low carbon industrial energy hubs and the implementation of phase two of the Retail Transformation Program, which is expected to be approved later in the year. The last item relates to our continued investment to maintain the reliability, flexibility and availability of our thermal generation fleet and renewable assets including hydro. It is imperative that we continue to invest in our cash generating fleet to ensure we are available when the market and our customers need us most. Now, turning to CAPEX, focusing on our FY24 CAPEX forecast. You will notice a marginal uplift in our thermal sustaining CAPEX forecast. This is primarily driven by additional spend to strengthen the flexibility, availability and reliability of our thermal asset fleet to support the energy transition. Approximately $70 million is also forecasted for the commissioning of the Torrens Island and Broken Hill batteries. As I mentioned at the investor day in June, in the near term, AGL expects to deploy up to $1 billion over the next two financial years, focused on the development of the 500 megawatt Liddell battery. And as you can see from the gray shaded bar, we're forecasting to spend approximately $200 million in FY24. Please note that this forecasted growth spend is contingent on a targeted final investment decision in FY24. As indicated on the right-hand side, medium-term sustaining capital spend on our thermal assets is forecasted between $400 and $500 million per annum, which will fluctuate each year subject to asset management plans. This will improve the availability and flexibility of the fleet. Additionally, customer-sustaining capex over the medium term is forecast to include $40 to $50 million per annum of ongoing spend on customer markets technology, plus one-off technology and transformation programs. Overall, we are prudently deploying capital towards the transformation of our business, while also maintaining the strength of our core operations, in line with our refreshed capital allocation principles. This investment in the transformation of our business is expected to drive higher depreciation and amortisation over the medium term. On the left-hand side of the graph, you can see that depreciation and amortisation for FY23 was $11 million higher due to the increased investment in our thermal assets and the earlier closure of the Bayswater and Loyang A power stations in line with our accelerated decarbonisation plan, partly offset by the impairment impact resulting from this earlier closure date. In FY24, we expect an uplift in depreciation and amortisation by approximately $40 to $50 million, and overall high depreciation and amortisation expense over the medium term, driven by the accelerated closures of Luoyang A and Bayswater, resulting in the shortening of the useful lives of these assets, combined with recent flexibility and reliability upgrades. As expected, there will be additional depreciation from the investment in the Torrens Island and Broken Hill batteries, which are expected to come online in FY24, as well as the retail transformation program. Encouragingly, we had strong cash flow generation in the second half of this year, which lifted the full-year cash conversion rate, excluding margin calls above 80%, reflecting an improvement to 118% in the second half, compared with 37% in the first half. Pleasingly, we saw stability in the second half. Overall, net cash from operating activities of $912 million was 26% lower than the prior year, driven by working capital outflows, particularly in payables and margin calls due to significant volatility and market price movements in the first half. Looking forward, we will continue to monitor cash conversion closely. Cash conversion will be impacted as our rehabilitation programs broaden over the next two to three years, and as we enter a period where revenue uplift and affordability pressures impact the market. In particular, we call out that the revenue uplift will require an increase in working capital to support higher receivables, which is effectively a timing difference. We also note that rehabilitation spend is expected to increase in FY24 following the closure of the Liddell Power Station in April, as well as decommissioning, well plug and abandonment works at Camden. As shown on the bottom left-hand side of this slide, our cash conversion rate excluding margin calls and rehabilitation was 86% for FY23. Please note that this will be the key metric that we will be monitoring and reporting going forward. It is normalised for lumpy nature of rehabilitation spend. As mentioned in June, we completed the successful partial refinancing of our existing debt and priced new long-term debt in the US private placement market. In the coming months, our focus will turn to refinancing our FY25 and FY26 maturities and targeting additional green capital. In terms of rating and headroom, we have maintained our BAA2 stable investment grade Moody's rating and hold a significant headroom to Covenants. Additionally, our weighted average tenor of debt increased materially from 2.9 years to 4.3 years following the refinancing process. As at 30 June, we have a healthy liquidity position of over $1.2 billion of cash and undrawn committed debt facilities available, and our net debt was marginally higher, driven by the movement of margin call obligations. The borrowings component of net debt was broadly flat, which was a good result considering the reduction in operating cash flow and higher capital spend on improving generation asset fleet availability, flexibility and reliability. Overall, our balance sheet is in a strong and robust position as we head into FY24. Before I hand back to Damien, I'd like to reiterate our refreshed capital allocation framework, which we announced at the Investor Day in June, and which includes a more flexible and sustainable dividend policy of 50% to 75% of underlying NPAT, noting that our FY23 final dividend is based off the 75% of underlying NPAT policy. We believe this framework will help maintain our strong credit profile and enable us to continue to invest in our existing business whilst allowing prudent capital allocation to lead the energy transition as we connect our customers to a sustainable future and transition our generation portfolios and importantly, drive strong future returns for our shareholders. Thank you for your time and I'll now hand back to Damien.

Thanks Gary. Taking a closer look at market conditions, forward curves currently observable in the market for FY25 are broadly in line with FY24 pricing levels, noting that these are subject to market conditions and may change. AGL's generation portfolio is realised through a contract book comprising consumer, large business and wholesale customers, as well as hedging arrangements in place. The two horizontal lines denote our weighted average wholesale realised electricity price across the portfolio for FY22 and FY23, and the broken orange line indicates our expected realised price for FY24. Through our prudent risk management approach, broadly speaking, the realised wholesale price for a given year should reflect the average of up to 24 months of forward prices preceding the start of the financial year. Importantly, as an integrated business, we are well positioned to benefit from any sustained periods of strong wholesale pricing, supported by the Bayswater and Loyang A power stations, which are the lowest cost baseload generation assets in New South Wales and Victoria, respectfully, on a short-run marginal basis. I'll now conclude by talking to FY24 guidance and our outlook. As mentioned at the beginning, we've maintained our FY24 earnings guidance ranges as announced at the investor day on the 16th of June, 2023. We expect a material uplift in earnings for FY24 based on the drivers you can see on the screen. Firstly, sustained periods of higher wholesale electricity pricing, which have been reflected and recovered in pricing outcomes and reset through contract positions. The second key driver being the expected improvement of planned availability and flexibility of the asset fleet, including the commencement of the Torrens Island and Broken Hill batteries, as well as the non-reoccurrence of forced outages and market volatility impacts from July 2022, which totaled approximately $130 million pre-tax. As Gary discussed, this is expected to be partly offset by the closure of the Liddell Power Station and higher operating costs mainly attributable to the four key drivers. Firstly, the impact of increased competition and higher revenue from pricing outcomes, increasing variable costs such as net bad debt expense and channel and marketing spend. Secondly, ongoing investment and growth and transformation of our business. The third driver being increased maintenance spend to improve asset fleet availability and reliability. And finally, the ongoing impacts of inflation we are seeing. Broadly speaking, we expect underlying net profitability for FY24 to be split broadly evenly between the two halves. I'd also like to note that we've certainly seen a warmer start to the financial year, with mightier than expected weather in July, which has contributed to reduced gas consumption and lower spot prices and volatility. Thank you for your time, and we're now open to any 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. First question comes from Tom Allen with UBS. Please go ahead, Tom.

Good morning, Damien, Gary and the broader team. Just following your comments at the end on the outlook where you've guided that average futures prices over two years will set AGL's average realised electricity portfolio price. Is it fair to say that there's little liquidity in the current New South Wales futures for mid-calendar year 25, which would reflect the potential closure of some capacity from the Ararang power station? But towards the end of this calendar year, as futures move into that 18-month liquidity timeframe, futures should better reflect that possible market event?

Let me try and break that question down a little bit. So I think what we're trying to do in that chart is demonstrate where we see the forward prices between 24 and 25. Clearly, what we're saying right now, they are consistent between the years right now. There's a long way still to play out over the next year. You know, clearly, you know, a huge number of factors, whether it be weather, plant availability and so forth. But what we're trying to do right now is, you say, consistent between the years is what that chart's trying to do. And we'll continue to monitor that as we go. The other thing I'd say is we have seen, you know, as you saw my comments towards the end there, lack of volatility in July. We're seeing a much warmer start to July. And that's what we're seeing globally as well.

Okay, and then given AGL's reported really strong performance over the second half in the gas portfolio, how should we expect the gas portfolio margin to perform into the near future, particularly if you partner with an LNG import terminal, as you noted at the June Strategy Day, where you're bringing in higher cost gas to the portfolio?

Yeah, so for 24, there is clearly no LNG in the portfolio for 24. We've recently contracted over 100 PJs of gas with Exxon, Cenex, Cooper for that sort of out of years, which is going to be important to support our customer base. What we saw through gas for the period just gone is... The team's done a huge amount of work to improve our haulage, our haulage costs through optimisation. We also saw in the retail space higher customer numbers and a colder winter. And the other thing I would just say is what we saw was we ended up being slightly long in the market where we saw oil prices rising, so we saw a benefit there as well.

Thanks, Damien.

Thanks, Tom. Next up, we have Dale Kernders from Baron Joey. Go ahead, Dale.

Morning, Damien and team. Just coming back to the electricity price commentary for FY25, am I right to assume that if the forward curve doesn't change and everything else all equal, what you're inferring is that the earnings level of the business should be relatively flat in 25 on 24, just purely for electricity prices?

Let me make it really clear on this call. We won't be giving 25 guidance. What we're just trying to show is, at the moment, what we are seeing is consistency between those forward curves, a huge amount still to play through over the next 12 months.

Okay, thanks. And then just for, I guess, that comment that you've said that the milder start to winter reduce gas consumption, is that a headwind to FY24 guidance? Or is that really taking away from the top end of the range? How do you think about that impact for 24?

Look, it will ultimately depend how the whole year plays out. I mean, the reason I'm calling it as I am now, yes, so we saw lower gas volumes. So, yes, that is a small headwind. But what you will see then is it depends how it plays through summer. If summer becomes a very hot summer, as is being predicted, then that could be the upside to it. So, again, very early in the year, I wanted to call it, I think we've all seen the warmer start to the year, and we'll continue to utilise that gas across our portfolio.

Okay, thanks so much. I'm back in the queue.

Next up, we have Anthony Mulder from Jefferies. Go ahead, Anthony.

Good morning, all. I just wanted to ask about retail churn. Obviously, second half, 23, that churn remains low relative to the market, but I wondered if you'd start to see the retail market becoming a bit more competitive, given that wholesale pricing consistency.

Jo, you want to take that one? Yeah, sure. Yeah, look, we certainly have seen higher churn and competition over the last few months, and I think particularly in response to recent price increases. But what I would say is that's not unexpected or unusual. We've planned for that. We've got strong retention programs in place, and we do expect that to stabilise as we move throughout the year.

All right, thank you. If I can say one more about call flexibility. Obviously continuing to invest into call flexibility this year, but I wondered where you're at as far as whether or not the majority of that benefit is now already in place. Mark, do you want to take that one?

No, I think, you know, we will further test particular the min generation levels of base water and also of low yang. We will check what kind of additional investment we need to do in order to even lower and maybe get another 400 megawatt of flexibility in our coal generation. But it's also fair to say with the closure of Lidl, I think some of the generation which we are lacking in New South Wales, there will be also a bit stronger running of base water. So we have to see how the market plays out. Today is a typical yesterday and today were typical days. where we have all run at min generation our fleet at Luoyang at Bayswater.

It's fair to say you'll continue to see the benefit in us doing that and that's why very deliberately we had that slide in there. Bayswater down to 70%, I think Luoyang 45% and potentially take Luoyang to another 50 megawatts a unit is the work that we're doing. But largely the spend has been done, it's now continuing to optimise in the market.

Thanks, Anthony. Next up, we have Mark Bustatil from JP Morgan. Go ahead, Mark.

Thanks, everyone. This year, you provided guidance for 24 in June. Typically, you haven't provided guidance until August, so it's sort of three months early. So I'm sort of interested in understanding how conservative or otherwise you've been with that guidance provision. what areas of the business could result in risks to the upside or downside in terms of fiscal 24 numbers?

Yeah, sure. Thanks, Mark. Look, you're right. We haven't provided guidance that early in the past. We had Investor Day was the rationale for doing that. Clearly, we provided a broader range in the guidance to allow for the potential ups and the downs. What I would say is the key factors for me when I think about performance of this business will be one, plant performance. And again, we've seen a real positive step up and we've planned for further step up in availability over the course of this year and then over the next three to four years. Weather will play a big part, Mark, in both winter and in summer. You know, so again, there's lots of commentary around where the weather is and where the weather will be for summer. That will be obviously, you know, will play a part as well. And then I would say, as the earlier question, just around market competition, you know, we are well placed, as Joe said, We've planned for this. We expected this. We've seen it in the past. We've got a lot of proactive measures underway to manage that. But they'll be the three key drivers, I think, that I would think about in terms of the positives and the negatives.

Okay. Specifically, have you allowed for... sort of the instances of unplanned outages that you generate a fleet?

Oh, look, we always have an allowance for unplanned outages. I might get Marcus to talk to how we think about that across the fleet. But yes, we always have unplanned outages forecast. So, Marcus, you want to talk to that?

Yeah, I think we have always assumed certain outage factors, which we are factoring in our budget and then also in our guidance. I think that's included. I will not contemplate now the number. But there is a provision in for forced outages. And this is related to historical performance. And I think that's what we are factoring in.

Okay. And if I could just sneak in a really quick one. How much of your electricity in fiscal 25 have you already forward sold?

You should assume that maybe around the level of 10 terawatt hours is not sold.

is not sold. Okay. Thank you.

Thanks, Mark. Next up, we have Gordon Ramsay from RBC.

Thank you. Just a question on CapEx Outlook. If you go ahead with the Liddell battery, you've indicated that you could spend $200 million in FY24. Does that imply the spend in FY25 would be $800 million?

um so let me just take that question will it be 800 million we haven't we haven't disclosed what the total cost but it wouldn't be up to uh 800 no it wouldn't be that high um i think 200 in this year and then a further maybe you know 600 or so would probably be the number we'd be looking at but again we haven't got to fid on that number yet and then that might spread across the years so um we'll come back once we hit fid on that battery

Okay, because I think in the commentary, you said you expect it to play up to a billion dollars over the next two financial years?

That's not... Oh, yeah, sorry. That's not just on that battery. It's across the breadth of what we're doing in the market in terms of that growth and whether we bring on any other batteries over that period of time as well. But think about the Liddell batteries, circa 800.

Okay, thank you. And just lastly, just on variable costs, you're saying that they will go up on the back of that net bad debt expense, channel marketing, and the additional customer support. If we looked at those two items, are they kind of evenly split or is one higher than the other, just in general terms?

Net bad debt expense would certainly be higher than what we call customer market activity. So if you look back historically at the organisation, when we go back to sort of 18, 19, where we saw market activity, you know, on the back of pricing, we saw the debt rise at the same sort of percentage level as revenue. So if you take at the same sort of percentage across the revenue. That's a sort of lift you'll see. And then from a market activity perspective in our forecast and in the guidance we've got today, we are assuming because of market activity stepping up, we'll have additional spend to manage that market activity.

Okay. Thank you very much.

Thanks, Gordon. Next up, we have Rob Coe from Morgan Stanley. Go ahead, Rob.

Good morning. Thank you and congratulations on the result. I'm just looking at your annual report page, I think it's 31, and just looking at the provided costs for Luoyang A, which seem to have gone up about $1.2 billion year-on-year in real terms. Just wondering if you could give us a bit of colour on that one, please.

Rob, let me take that one to start with, and I'll hand over to Gary. I'm not sure where the 1.2 has come from. We did increase the rehabilitation by bringing forward the closure dates at the half year, so that certainly happened. I might need to take on notice, unless you've got it in front of you, Gary, that step up, but certainly the rehabilitation did go up, and we did that at the half when we brought forward Loyang by that sort of 10 years. We also saw back then when we looked at it, we had a look at, you know, because of the change of the way the mine would operate that also increased the rehabilitation, that space as well. But again, that was back at the half. I'll just take it on note if I can, Rob, and come back to you on that number. But Gary?

Yeah, I don't have too much more to add to that. It's obviously nominal and real dollars in there as well, Rob, but there's obviously impacts on discount rates as well as the actual cash flows and the shortening of the life of those assets and the impacts on rehabilitation as well.

Yeah, yeah. OK, thank you. All right, and then my second question, I guess... probably should have asked this back in June when you gave us your new flexible DPS policy, but you have a payout range, 50 to 75%. Just wondering if you could elaborate on what are the kinds of things that would push you to the lower end or to the higher end of that DPS range, and if you've got an eye on progressivity and things like that, please.

Yes, obviously the historical dividend there, Rob, was 75% of underlying NPAT. And obviously today we've announced an increase on the actual size of that dividend compared to the prior year. It was important as part of the transition that we're going through. We'll be deploying between $8 and $10 billion between now and 2035. that we retain as much flexibility on our balance sheet as possible. And as a result of that, we thought it was prudent to have that 50 to 75%. It really will depend on what we're looking at that point in time throughout that transition, where our balance sheet is sitting, how our cash flows are looking, how much we're going to need to deploy in the following few years. So we'll always make, you know, decisions that are in the best interest of our shareholders as well. But obviously, having that range gives us flexibility to make sure that we're you know, looking at both our shareholder returns as well as deploying that capital back into the transition.

Thanks. Sounds good. Appreciate it.

Thanks, Rob. Next up, we have Ian Miles from Macquarie. Go ahead, Ian.

Hey, guys. One which, looking back to FY22, your capex sort of maintenance capex levels, particularly in thermal, you sort of flagged closure below the aim was going to reduce the expense expenditure. And we now come to FY23 and it would appear that your capex spend is actually, or that maintenance level is probably $50 to $100 million higher. I was just wondering if you could give us a bit more colour on what's shifted your thinking over the last 12 months that you're going to have to spend more on those plants to keep them operating?

Yeah, Ian, I'll come back on your first part of your question. In 22, we didn't have any CapEx related to Liddell. That was all through OpEx because of the closure date. So anything we would have spent would have gone through OpEx there. In terms of the spend today, and I'll get Marcus to sort of go a bit deeper, but... We have been spending clearly that $400 million to $500 million around both availability to ensure the plant is up, and Marcus spoke to that at Invest Today, but also the flexibility. That's where that spend's been. I think going forward, it will continue to be around ensuring our plant availability is up where we need it to, and therefore continuing to hit that target by 27% of 88%. But Marcus, maybe just talk to some of the focus areas at the moment around that plant.

I think we wanted to minimize and I think we were successful to minimize the D rates of our power station because we had quite some issues with mill, with precipitators and so on. That was one root cause where we said we have to invest more. more in this space than also, I think, the supply chain issues. We wanted to have a clear stock on spare parts at our sites. Particular, I think at the moment, we have two rotors in Germany, one in Germany and one in Switzerland for refurbishment. And I think we want to have our clear target and what you see also next year and the years after, we want to increase our equivalent availability factor. And this has led to a decision that we want to invest more. It should generate a positive NPV and that was a main driver.

And Nick, as a longer term perspective, do you see maintenance CapEx across the, or sustaining CapEx across the broader business as sitting at that sort of 550 to 600? Or are some of these things just temporary that it goes back down to maybe a lower number?

I think while the key plant is in place, you know, those assets, both Luoyang and Bayswater, while that key plant is in place, that's the sort of level of spend, that $400 to $500. We'll continue to update the market each year because the other thing that changes, Ian, is depending which years you're doing your major outages and where those outages are falling. So sometimes it can move between the years. The other thing we've done is obviously recently looked deeply at the plant availability, plant maintenance in the run between now and when we close the plant. So again, we'll optimise that to ensure that those major outages when they're happening are done at the right time so that you're not overspending before you actually close the plant as well as you get closer.

Okay, and on the consumer side, you sort of flag 40 to 50. Is there any risk that actually starts to go higher in the sector as more technology is being implemented to engage consumers? Absolutely.

I think over time, Ian, we'll probably see more of a shift to OpEx. A lot of the future platforms are more SaaS provided solutions. So yeah, over time, I think we'll see more of a shift of that sustaining CapEx come down and an increase to OpEx.

And when that switch is happening, we'll obviously provide an update so you can see, you know, the cash spend, what's happening there. I think the other piece that we're obviously looking at and flagged through here is, you know, the next phase of the retail transformation. That's something we'll update the market on over the next 12 months as well.

Okay, look, that's great.

Thanks, Ian. Next up, we have Reinhard van der Waal from BAMWOL. Go ahead, Reinhard.

Good morning folks, thanks for taking my question. Just got a question on retail competition and electricity specifically. You mentioned that it's a challenging or it's a competitive market. Is this just the normal kind of tier one retailer competition that we always see or are we talking about smaller retailers maybe becoming more competitive in the market? I suppose related to that, are you expecting this kind of very limited discounting to the DMO to continue? into FY24-25.

Yeah, look, it's been quite an interesting competitive market over the last few months, particularly since July 1 price reset. We've seen a really broad spread in discounting across the market, and it's been very dynamic with offers changing across retailers quite substantially. I would say, though, in the last week or so, it started to stabilise. We're still seeing a couple of outliers, tier two retailers, discounting quite heavily. But as we did anticipate, there seems to be a bit more headroom in Victoria than in the DMO states. And yes, as I said earlier, it is really normal around the time of price change to see a lot of activity. This is very similar to what we saw in 18-19 when retail prices were high and we have our customer support package in place. We're driving that really hard along with retention programs and we do expect it to stabilize in the next couple of months.

Got it, thanks Jo, that's very helpful. And can I just check that big discounting that we're seeing in Victoria, it looks like you're pricing it, I think almost about a 20% discount to the VDO there. And I presume that the likes of EA would also be discounting similarly. Is that just because of the sort of relatively flat generation cost curve in Victoria? Or what's driving that increased discounting?

It's really just the competitive market. You know, the tier ones are all sitting at that place at the moment. And, you know, we see that change throughout the year depending on competition and what campaigns retailers have in place. But as I said, we did see a little bit more headroom in the video pricing than the DMO.

Got it. Perfect. Thanks a lot.

Thanks, Ron Hart. Next up, we have Tom Allen again from UBS. Go ahead, Tom.

Thanks for allowing me to take another question. Just thinking about AGL's return on capital employed into the future, can you provide some colour on whether reinvesting in those sites with big batteries can materially reduce the liabilities against those sites? And whether there's an opportunity to outperform AGL's current decarbonisation path with a staggered retirement plan that sees individual generation units decommissioned at those sites as batteries are installed?

At first, I would like to say, yes, we try to optimize our rehabilitation, but that will not fundamentally change our rehabilitation obligations. I think a typical example, we are looking to put a solar thermal plant on our ash dumps at Lidl. But still, the ash dumps have to be, at a certain point of time, rehabilitated and so on. Yes, we try to optimize the rehabilitation with new investment, but at the end of the day, there will be slight savings, but not huge savings.

I think the other thing, Tom, you've probably heard us say before, we'll continue to optimise that. What we saw, Liddell as an example, the scrap value of steel right now, it makes sense for us to go as quickly as we can because scrap metal prices are almost going to offset some of that demolition cost as an example. So we'll continue to optimise rehabilitation. It is a big spend for this organisation. We have a large team that is working on Liddell and we'll continue to drive that across the organisation.

Thanks, folks. And just on the second part there about the opportunity to outperform the decarbonisation path by taking individual units down as batteries are installed.

I think we are speaking about different things. For me, batteries are providing firming and flexibility. Our thermal generation units are providing baseload energy. Yes, there will be a bit of portfolio effects between these different generation assets, but I don't believe that at the moment firming capacity, which we are putting into the grid, is replacing our baseload generation. Thanks, Marcus.

Appreciate it.

Thanks, Tom. Next up, we have Dale again from Baron Joey. Go ahead, Dale.

Hi, guys. Thanks for the second question. Just, I guess, digging into the details on the strong performance on customer margin through the period which you've called out is around customer management. Just wondering if you could provide more detail what that specifically means how sustainable you've assumed it will be into FY24 guidance and what's the opportunity to sustain it longer term. Particularly looking at gas and elect margins.

Yeah, thanks, Dale. Yeah, look, we were really pleased with that result. And it's a combination of improved margins on the energy side and through our growth businesses. And I would say, you know, we were coming off years of, you know, quite low retail margins. So we do see this as a more sustainable level. And it's been through a combination of a focus on increasing customer lifetime value and as well as continued growth in customer services. So we do definitely see this as a more sustainable level.

So when you say services bundling in with EVs, demand management, everything else that's likely to continue going forward or...

Absolutely. And also just overall growth in energy services throughout the year. So we saw an average increase in services throughout the year, increase in some demand through gas, as Damien mentioned, and as well just improved value management through the portfolio in our recontracting strategies.

And just the other add maybe I did all that is we're really happy about some of the growth businesses continuing to improve in that space around telco, the CNI business as well. We saw commercial industrial business. We saw that step up through the year. So that's again, we'll continue to drive the growth through Joe's area also.

Okay, thanks. Thanks, Dale. Next up, we have Max Vickerson from Morgans. Go ahead, Max.

Thank you, guys. I just wanted to ask about electricity sources again. So just curious to know how the volume weighted view might look. I think you've used the time-lighted number in that slide. And then just secondly, I appreciate New South Wales and Victoria are probably the biggest markets and don't want to be too parochial here, but given you're talking about the summer outlook, how are you positioned in Queensland?

Max, your first part of your question broke up a bit. I didn't quite hear that. I'm just looking around the room and others didn't also. Could you just repeat the first part and then I've got your second part of your question.

Yeah, sure. Sorry, Damien. Just curious to know how the volume-weighted view on futures would look. I think you've used the time-weighted view on your slide there for the FY24-25 outlook. I appreciate FY24. Probably it's pretty solid, but just curious to know there's a difference between time-weighted and volume-weighted.

Marcus, have you got a view on that one you can talk to? And if not, we might take that one offline. We'll take that one away, Max, and come back to you. In terms of... Just remind me again, your second part of your question, that was...?

Just about your exposure to Queensland and maybe other states, particularly if you're looking at a potentially warmer summer and the... The gocks up here don't have a great performance history. I just wanted to know how you're covered.

Yeah, look, so we are... If I think about the Queensland, from a customer point of view, we are well positioned there from a supply perspective. We've obviously got both Cooper's Gap up there and other contracts and financial arrangements in place. So Queensland, we are comfortable there. On an SA perspective, that's the other state I think you mentioned. We've obviously got the portfolio of assets down there with both... Barker Inlet Power Station, and we're going to have the Torrens Island battery coming online as well. Plus, obviously, eventually the interconnector will come through. And then if I think about the volatility, I think, you know, over summer, again, it's going to be about, you know, making sure our plant is up over that period of time and, you know, continuing to drive that availability of plant over that period. But, you know, ultimately it will come down to just how volatile the you know, that summer period is and how many days in a row. It's not necessarily one warm day, it's a number of warm days that normally create the issues.

To your question, it's a time-weighted price. Do you hear that, Max?

Yeah, no, I got that. I was just wondering if the volume-weighted number might be different to the time-weighted, but that's okay?

Most probably a bit, yes.

Okay, thanks, Max. Next up, we have Reinhardt again. Go ahead, Reinhardt.

Hi there, folks. Thanks for the second question. Just very quick ones. Just on battery EPC costs, I know six to 12 months ago, we saw those EPC quotes were bouncing around quite a bit. Have you seen pricing stabilize a little bit in recent months? And then just a quick second question. I know it's a while away, but Bayswater Coal Recontracting, when do you think you're going to go into the market to start doing the work on recontracting coal?

Maybe let's start with the first one. I think, yes, you are fully right. EPC contracts or EPC pricing for batteries have stabilized. So maybe even slightly decreased compared to the hype which we have seen before. And the second part, for sure, we are already in the market to look for opportunities to recontract. Also looking who can offer, what is the competition in the market? What is the pricing? What is the flexibility in the contracts? Yes, we are already there.

Got it. Thanks, Marcus.

Thanks, Reinhardt. And lastly, we have Rob Coe from Morgan Stanley. Go ahead, Rob.

Hello again. Thank you. I'm just looking at the remuneration report and just noticed the long-term incentive, the target includes a 30% weighting to the climate transition metrics one of which is a gigawatt deployed type metric, which is obviously linked to your installation targets. Just wondering, how does that work? Is that based on commissioning of those gigawatts? And how does the return on investment flow through to that, please?

Yeah, thanks, Rob. So what you can see there, from a LTI perspective, we increased the component linked to, if you like, the transition from 25% to 30%, broken down between emissions, between deployment of assets, as you said, and also those assets under management. So when you think about those assets that we deploy, clearly it won't be anything that doesn't meet the required hurdles of this business. So it will always be hurdle driven. It won't be us simply deploying assets into the marketplace. And obviously when we come out with FID, we'll be providing an update then at that point as to those assets. But what's important for us is about building both our pipeline, a pipeline of assets over the coming years and continue to develop that out, but then actually seeing the reality of that pipeline being delivered into the marketplace.

Is the criteria FID or being in operation? Thank you.

Okay, great. Thank you very much.

Thank you, Rob. As there are no further questions, this concludes our question and answer session. Thank you all for listening.

Thank you all.